20230331Natural Gas IRP Appendices.pdf

2 0 2 3
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 Credits

Primary Natural Gas IRP Team
Name Title Contribution
James Gall Manager of Integrated Resource Planning IRP Core Team
Tom Pardee Natural Gas Planning Manager IRP Core Team
Michael Brutocao Natural Gas Analyst IRP Core Team
John Lyons Sr. Policy Analyst IRP Core Team
Lori Hermanson Sr. Power Supply Analyst IRP Core Team
Mike Hermanson Sr. Power Supply Analyst IRP Core Team
Grant Forsyth Chief Economist Load Forecast
Ryan Finesilver Mgr. of Energy Efficiency, Planning & Analysis Energy Efficiency
Lisa McGarity Energy Efficiency Program Manager Oregon Energy Efficiency
Leona Haley Energy Efficiency Program Manager Demand Response
Terrence Browne Sr. System Planning Engineer Gas Engineering
Justin Dorr Natural Gas Resources Manager Power Supply

Natural Gas IRP Contributors
Name Title Contribution
Scott Kinney VP of Energy Resources Power Supply
Kevin Holland Director of Energy Supply Power Supply
Clint Kalich Sr. Manager of Resource Analysis Power Supply
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory
Amanda Ghering Regulatory Affairs Analyst Regulatory
Annie Gannon Communications Manager Communications
Mary Tyrie Manager Corporate Communications Communications
Jeff Webb Manager of Gas Design, Measuring and Planning Gas Engineering
Michael Whitby Renewable Natural Gas Program Manager Clean Energy

Contact contributors via email by placing their names in this email address format:
[e-mail]

2021 Natural Gas IRP Appendices
TABLE OF CONTENTS: APPENDICES
Appendix 0.1 TAC Member List ....................................................................... Page 1
0.2 OPUC Comments and Responses to the 2023 IRP ............................. 5
0.3 WUTC Comments and Responses to the 2023 IRP………………… .. 23
Appendix 1.1 Avista Corporation 2023 Natural Gas IRP Work Plan ......................... 33
1.2 IRP Guideline Compliance Summaries .............................................. 37
Appendix 2.1 Economic Outlook and Demand ......................................................... 51
2.2 Customer Forecasts by Region .......................................................... 67
2.3 Demand Coefficient Calculations ....................................................... 71
2.4 Heating Degree Day Data .................................................................. 74
2.5 Annual Demand, Avg Day & Peak Day Demand (Net of DSM) .......... 83
2.6 Demand Before and After DSM .......................................................... 88
2.9 Detailed Demand Data ....................................................................... 91
Appendix 3.1a ID and WA Firm Customer CPA and Demand Response ................... 95
3.1b OR Firm Customer CPA ................................................................... 187
3.1c OR Low-Income CPA ....................................................................... 214
3.1d Interruptible and Transport CPA ....................................................... 220
3.2 Environmental Externalities .............................................................. 228
Appendix 4.1 Black and Veatch Study ................................................................... 231
4.2 Renewable Resource Development and Procurement Tree ............. 239
4.3 Renewable Resource Project Revenue Requirement Model ............ 242
4.4 Renewable Resource Project Rate Impact Analysis ......................... 244
Appendix 5.1 WA General Rate Case Compliance ................................................ 245
Appendix 6.1 Monthly Price Data by Basin ............................................................ 249
6.2 Weighted Average Cost of Capital ................................................... 261
6.3 Supply Side Resource Options ........................................................ 261
6.4 Annual Avoided Costs Detail ............................................................ 262
6.5 Winter Avoided Costs Detail ............................................................. 276
Appendix 8.1 Distribution System Modeling…………………………………………...290
Appendix 8.2 Distribution within the IRP……………………………………………….294
TAC Meeting #1…………………… ............................................................ 296
TAC Meeting #2 ........................................................................................ 358
TAC Meeting #3a………………………………………………………………...427
TAC Meeting #3b ...................................................................................... 487
TAC Meeting #4 ........................................................................................ 522
TAC Meeting #4 ........................................................................................ 651
APPENDIX - CHAPTER 0

APPENDIX 0.1: TAC MEMBER LIST
Organization Representatives

Applied Energy Group Kenneth Walter

Avista
Terrence Browne Heather
Rosentrater
Amanda Ghering Tom Pardee
Ryan Finesilver Michael Brutocao
Grant Forsyth Jason Thackston
James Gall Jaime Majure
Justin Dorr Michael Whitby
John Lyons Shawn Bonfield
Lisa McGarity Jeff Webb
Annette Brandon Annie Gannon
Clint Kalich Scott Kinney

Biomethane, LLC Kathlyn Kinney

Cascade Natural Gas Company
Ashton Davis Brian Robertson
Mark Sellers-
Vaughn

Citizens Utility Board of Oregon Sudeshna Pal Will Gehrke

Eastern Washington University Erik Budsberg

Energy Trust of Oregon Ben Cartwright Spencer
Moersfelder
Ted Light Hannah Cruz

Department of Energy Michael Freels

DEQ Nicole Singh

Energy Strategies Jeff Burks

Fortis Ken Ross

Idaho Public Utility Commission

Donn English Kevin Keyt
Terri Carlock Mike Louis
Joseph Terry Rick Keller
Taylor Thomas Jason Talford

APPENDIX - CHAPTER 0

Intermountain Gas Raycee Thompson Lori Blattner
Dave Swenson

Lewis and Clark Law School Carra Sahler

Northwest Energy Coalition Amy Wheeless

Northwest Gas Association Dan Kirschner

Northwest Natural Gas Michael Meyers

Northwest Power and Conservation Council Steve Simmons

Oregon Public Utility Commission JP Batmale Kim Herb
Sudeshna Pal Ted Drennan

RNG Coalition Vincent Morales

Sierra Club Jim Dennison

Washington State Office of the Attorney
General Shay Bauman Corey J Dahl
Chuck Murray
Washington Utilities and Transportation
Commission Jennifer Snyder Jim Woodward

OPUC Staff’s Avista 2023 Draft IRP Feedback
1 | P a g e

Appendix 0.2: OPUC Staff Draft Comments

Avista Draft 2023 IRP: OPUC Staff Feedback Comments
Staff wants to thank Avista for providing a Draft IRP for stakeholder comment. At a high level Staff is pleased
with the elements being considered in this IRP, including consideration of the IRP Guidelines, past orders,
and issues raised in UM 2178, such as electrification and applicable scenarios. We look forward to reviewing
the Final IRP and remind the Company that Staff’s review of the IRP will be delayed until the summer of
2023.
This document contains comments made by Oregon Public Utility Commission Staff (Staff) with regards to
Avista (the Company) 2023 Draft IRP (Draft). Grouped by topic, the comments mainly focus on Staff’s
suggestions and recommendations for the upcoming filed 2023 IRP.

General
Staff asks that the company plan to provide the workpapers for all tables in the IRP, including
appendices, with formulae intact, as well as all supporting graphs and charts exhibited in the IRP
upon filing the IRP.

Response: All workpapers have been provided with the final IRP.

Staff notices and appreciates Avista’s efforts to incorporate some of the IRP suggestions from
Docket No. UM 2178. Staff would appreciate the Company identifying which of the NGFF
recommendations it has incorporated in this IRP, as well as which ones will it not be incorporating
and why. See Table 2 in the Natural Gas Fact Finding Report and respond to at least each of the
following recommendations (table 2 in the report includes other recommendations that may not be
applicable):1

UM 2178
Topic
Recommendation Comments Avista Response

Protecting Customers
Estimated
ratepayer bill
impact
Staff appreciates the inclusion of the discussion on
rate impacts, and especially considering these from
a bill impact perspective, with regard to
electrification. Staff encourages Avista to include
further descriptions about how bill impacts are
considered across the different scenarios,
especially where scenario assumptions might
significantly alter cost of gas, fixed costs, and
compliance cost associated with transport
customers associated with compliance with CPP.
This would ideally include, at a minimum, general
approaches it is considering for rate spread as well
as $/GHG emission reduction, where possible.
Chapter 7 includes examples
by scenario
EE programs to
include transport
Staff looks forward to learning more about the
opportunities for EE programs for transport /
transportation customers in Oregon and
appreciates Avista’s activities described to date.
N/A
OPUC Staff’s Avista 2023 Draft IRP Feedback
2 | P a g e

Target IRA
Incentives
Consider including a section on how IRP incentives
are modeled and whether the Company is pursuing
federal incentives.
Chapters 3 and 5 describe
these assumptions
Align near-term
investments with
CPP compliance
Avista should include in the IRP whether and how
action plan items align with CPP compliance.
Chapter 6 for the preferred
resource selection and
Chapter 9 for Action Plan
1 See Docket No. UM 2178, Natural Gas Fact Finding Final Report, January 2023, page 2, available at:
https://edocs.puc.state.or.us/efdocs/HAU/um2178hau111621.pdf
UM 2178
Topic
Recommendation Comments Avista Response

Full Cost
Develop marginal
abatement cost
curve
Staff is interested in developing a
full understanding of the cost of
compliance with CPP of different
strategies. How does Avista
anticipate analyzing the cost of
compliance of different strategies,
and what value might the Company
see in developing marginal
abatement cost curves to illustrate
compliance cost and options?
Supply Curves included in Appendix 4. Future
outcome is dependent on customers and demand on
system.
Utilities articulate
electrification
assumption in IRPs
Staff greatly appreciates Avista’s
work in characterizing electrification
cost and assumptions, and
especially its work on having
electrification be a selectable
resource. Staff will be very
interested in engaging closely with
the company on electrification
assumptions and the impact it had
on resource selection in the various
scenarios. Staff will be interested in
understanding limitations of this
approach, especially with regard to
modeling in territories for which
Avista is not the utility providing
electricity.
N/A
Electrification info
and data from DSP
As applicable, Avista should work
with Oregon investor-owned
electric utilities with which the
Company has overlapping territory
to develop electrification
assumptions aligned with
information and data being
submitted in electric utility
Distribution System Planning
efforts.
Not included in the 2023 IRP, need more information
prior to development and inclusion in future IRP
OPUC Staff’s Avista 2023 Draft IRP Feedback
3 | P a g e

Decarb
Planning &
Cost-
Recovery
Gas system maps
with infrastructure
age and
depreciation
information
Avista should provide, in digital
map format, the location, age, size
and type of pipe, as well as
information indicating where
distribution system upgrades are
being considered and why.
Not included in 2023 IRP. Maps of the distribution
system are not publicly available because they include
sensitive/customer/confidential information. By
suggesting this information be required to be made
publicly available poses serious safety and security
concerns. Overlaying depreciation data on maps does
not provide additional information due to the use by
utilities of mass (group) asset accounting. Distribution
assets are accounted for at the jurisdictional level,
thus depreciation rates and composite remaining life
are identical for Company assets across Oregon.
Lists of infrastructure and associated depreciation
schedules can possibly be provided in the future,
outside of the IRP, by general categorization but would
be consistent with publicly available data from the
Company’s depreciation study, provided to the
Commission and parties every five years.
CPP as an
acknowledgeable
item in IRPs
Avista should ensure that the IRP
demonstrates incremental progress
toward meeting CPP GHG
emission reductions through the
actions taken in this IRP and
should seek acknowledgement of
these actions as those taken to
meet CPP compliance.
These are included in Chapter 9 Action Plan
Exploring IRP
guidance from UM
2178
Avista should review Appendix B of
the NGFF Final Report and identify
which of the IRP recommendations
it has incorporated, will incorporate,
or plans to incorporate in this IRP.
Which ones will it not be
incorporating and why?
Included in Appendix

Monitoring,
Tracking, and
Reporting
Annual PUC report
based on DEQ
compliance filings
Avista should demonstrate
progress toward meeting CPP
compliance through the plans
articulated in the IRP with annual
reports based on DEQ compliance
filings and referencing associated
action plan items as appropriate.
These reports should also include
the associated costs. These
reports, where applicable, can be
Avista will include information on its CPP compliance
within its IRP update and future IRPs.
Utilities host annual
utility report on CPP
compliance filings
OPUC Staff’s Avista 2023 Draft IRP Feedback
4 | P a g e

Enhance tracking of
alternative supply of
actual costs and
report to planning
submitted as part of an IRP Update
when the timing accommodates
this or as a separate report. This
report should clearly track and
delineate alternative supply actual
costs.
Incentivize
GHG
reduction
pathways
Explore use of SB
844 for emerging
technologies
Avista should include a description
of any/all SB 844 related activities.
Not included in the 2023 IRP. Avista will share in all
future IRPs
Pilot or joint pilots
with electric utilities
proposal by 2025
Avista should share opportunities it
envisions, or progress made on
pilots.
Not included in the 2023 IRP. Avista will share in all
future IRPs
OPUC Staff’s Avista 2023 Draft IRP Feedback
5 | P a g e

Chapter 1: Planning Environment
Staff very much appreciates Avista’s inclusion of Table 1.2 showing the Summary of Changes
from the 2021 IRP.

Response: N/A

Chapter 2: Demand Forecast
Avista forecasts an average annual load-growth of 1.1 percent in the Draft IRP. That is an
increase from 1.0 percent in the previous IRP. While Staff has yet to see Appendix 2.1, Staff has
three concerns regarding how this growth is considered in the IRP: 1) its reliance on the Status
Quo 2) the impact of this assumption on near- and long-term planning, and 3) the additional
compliance obligation and stranded asset risk that accompanies this growth.

Similar to Staff’s concerns in response to NW Natural’s 2022 IRP,2 Avista’s customer count
predictions appear to use historical trends without regard to new clean energy policies and
uncertainty. Page 2-2 notes that the “…forecasts reflect the “status quo” and do not fully reflect
emerging natural gas connection restrictions in Washington and Oregon.” Staff will be interested
in understanding how status quo growth assumptions impact the Preferred Resource Strategy
(PRS or preferred portfolio) and near- and long- term actions and whether the assumptions of
status quo growth are reasonable.

Response: With a lack of building codes or policies to guide a different future level of growth in
Oregon, Avista addressed this uncertainty through a variety of scenarios including electrification
with three sets of different conversion costs and a hybrid scenario, among others. An end use
model may help better forecast these unknown futures as discussed in action items in Chapter 9.

The Company should develop a sensitivity, to include in the filed IRP, that reflects the potential
for declining customer counts, not just a decline in growth rates.
Response: Please refer to response 4a. scenarios to illustrate a loss of customers can be
seen in the electrification scenarios and the hybrid scenario.

Additionally, Staff has expressed concerns in other gas IRP and in NW Natural’s most recent
General Rate Case UG 435 about how utilities are considering and addressing the impact of
increased customer counts on CPP compliance risk. Please see Staff’s Opening Comments
Section 4.2.3

Response: Until such time clarification is provided in legislation or policy, Avista shares this
concern and will attempt to address through scenarios. Increased customers are something
Avista does not have direct control over at this time.

Given the CPP coverage of Transport Customers, please ensure either the body of the IRP or
Appendix 3 includes Avista’s plan for reducing these emissions and explain how it anticipates
the costs of these emission reductions might affect cost of service customers.
Response: Avista is exploring new energy efficiency programs for transport customers to help
find carbon emissions savings. As the State of Oregon sees these emissions as under Avista’s
control or obligation, costs of compliance will be spread across the system on a per therm basis.

OPUC Staff’s Avista 2023 Draft IRP Feedback
6 | P a g e

Check Figure 2.2 to confirm that all customers are represented in the chart, it appears to show
only two colors.
Response: Customers are accurately depicted in Figure 2.2. Industrial customers in both
Oregon and Washington are small in comparison to Residential and Commercial customers.
Please refer to Figure 1.3 for a detailed understanding of these customers.

Chapter 3: Demand Side Resources
While the Draft describes the Low-Income EE potential and references an appendix with more
detail, the filed IRP should go a step further and include a description of the Company’s plans, if
any, to integrate these activities with Avista’s programs designed to reduce energy burden.

Response: The IRP is not the document to discuss Avista’s plans for programs designed to
reduce energy burden. The IRP is focused on ensuring that the Company has adequate supply
to deliver to its customers while meeting CPP compliance targets. Discussions of programs
intended to reduce energy burden are best suited within the framework of HB 2475, the
Company’s Low-Income Rate Assistance Program (LIRAP), and the Company’s annual report
out on its Avista Oregon Low Income Energy Efficiency Program (AOLIEE).

Staff would appreciate the Company explaining in the filed IRP the extent to which PLEXOS
could be allowed to select greater levels of energy efficiency – beyond Energy Trust’s forecasts
– versus RNG as part of a least-cost/least-risk portfolio. It may be helpful to review Staff’s comments on
this topic in NW Natural’s 2022 IRP.4

Response: Avista will explore this in the 2025 IRP. Market saturation, costs, and other
assumptions will be key to obtain from the Energy Trust of Oregon to model within Plexos.

Please explain why interruptible and transport energy efficiency potential are grouped (see Table
3.7).
Response: These results were completed under the same CPA. A detailed description and set
of results can be found in the Appendix under Chapter 3.

Page 3-7 includes reference to demand response pilot programs. Please provide citations to
these studies.

Response: Updated in Final IRP.

2 See Docket No. LC 79, NW Natural 2022 IRP, Staff’s Opening Comments, December 30, 2022, page
83.
3 See Docket No. LC 79, NW Natural 2022 IRP, Staff’s Opening Comments, December 30, 2022, Section
4.2.
4 See Docket No. LC 79, NW Natural 2022 IRP, Staff’s Opening Comments, December 30, 2022, Section
3
OPUC Staff’s Avista 2023 Draft IRP Feedback
7 | P a g e

Table 3.9 shows NGDR participation rates. If available, please include information about how
these participation rates compare to other regions. It would be helpful to understand if these are
high, average, or low participation rates.

Response: Additional detail can be found in the CPA included in the Appendix for Chapter 3.
The results are specific to Avista territories, but methodology and details are further explained.

Please provide references or sources for the information provided in Figure 3.2 – Space Heat
Efficiency by Degrees Fahrenheit and Fuel.

Response: Estimates were obtained from internal subject matter experts based on knowledge
and data seen in the industry and through multiple years of studies, experience, and data from
sources such as Applied Energy Group (AEG).

Staff is grateful for the detail included regarding Conversion Costs. Staff has many questions
about the assumptions and expects the IRP to include significant detail about the assumptions.
Please provide this in workbook format and where possible, document the incentives considered
that result in the final prices.

Response: A description is included in Chapter 3 in addition to Chapter 5 for the Inflation
Reduction Act. Final prices in Figure 3.4 share a detailed breakout by end source. These end
sources assume a consumer saving 50% of the “Total to Remodeler”. Estimates and study
reference are also included with these chapters of reference.

Please consider a scenario where just water and space heating conversions are done, or where
the customer chooses to stay and use dual fuel heat pump and heat pump water heaters, but
keep other gas appliances, if they have them.

Response: This is essentially the Hybrid Case. A very small portion of demand is estimated in
the residential class for “Other” appliances such as stoves.
Regarding Rate Impacts, please clarify whether the model makes any assumptions about
cooling.

Response: Avista does not forecast cooling in as it would be assumed cooling is supplied by the
electric providers.

See Figure 3.6 – How do these bills compare to baseline? It would be valuable to see energy
used, GHG emissions, and associated cost differences between pre and post conversion.

Response: Impacts by scenario have been added to the Final IRP in Chapter 4.

Regarding Figure 3.7 - is the 2032 increase associated with HB 2021 clean energy goals? Will
modeling show bill impacts? Will there be any targeted electrification - or a distinction between
the difference in moving from resistance to heat pump vs gas to heat pump? Has the Company
identified the optimal conversion scenarios and associated costs? e.g., space heating costs
deltas are A for resistance to heat pump, B for gas to heat pump, etc. and assumptions about
OPUC Staff’s Avista 2023 Draft IRP Feedback
8 | P a g e

changes in summer load regarding air conditioning, e.g., fans vs. window unit vs. other.

Response: This increase in 2032 is due to the IRA expiration. Modeling will show bill impacts.
Electrification is not targeted in any of these scenarios as discussed in chapter 7. It is simply a
demand side choice to the model. Varying levels of conversion have not been considered in the
2023 IRP.

Chapter 4: Current & New Resources

Renewable Natural Gas
Staff expects that a conversation about the Company’s forecasted cost trajectories and
availability for RNG, Hydrogen, and other emerging technologies will be an important part of the
IRP review process. Supporting information that Avista can provide in the IRP document itself to
help facilitate this conversation will be appreciated. If possible, a study and discussion of the
risks and opportunities of a scenario with higher cost trajectories would be of interest to Staff,
especially where technology readiness levels are low.

Response: Updated in Final IRP and supply curves added to Appendix 4.

When evaluating RNG and hydrogen availability, please include a discussion about the
economic sectors competing for this resource and assumptions about availability to the power
sector. What economic factors cause the company to expect RNG and hydrogen to be available
to the power sector even while demand from other sectors is high?

Response: All sectors, including transportation, may be competing for these resources.
Hydrogen being the most abundant element may help to alleviate this competition though the
creation of hydrogen and the technology to do so may be the areas most constrained. RNG has
been shown through multiple studies to contain enough resource potential to provide some level
of clean fuels to programs and states containing these goals. Not all States have clean goals or
programs so the availability of these fuels may be more available depending on this trajectory.

Per OAR 860-150-0400, Avista must file a petition to participate in the PUC RNG’s program and
Staff’s understanding is that the methodology can be approved in an IRP process. Staff is
unclear if the filed IRP’s action plan can be acknowledgeable without this filing and Commission
approval, given the levels of RNG acquisition the IRP calls for. The filed IRP should discuss how
this filing will be made if the Company if it is not filing for acknowledgment of this methodology in
this IRP. Further, it would be helpful to explore the rate cap it will attempt to establish in their
petition filing.
Response: Avista will follow all rules as needed to bring on new resources under SB 98 if it
pursues this path. If SB 98 is not used as the reason to acquire a new resource, filing a petition
to participate in this process will not be necessary.

Staff appreciates the model notes of the proposed RNG Cost Effectiveness calculation. Avista
should consider including additional information about the change in carbon compliance costs
over time and how that could be reflected in the cost-effectiveness evaluation methodology.
Response: Changing carbon compliance costs are evaluated in comparison to RNG and other
OPUC Staff’s Avista 2023 Draft IRP Feedback
9 | P a g e

resource costs in the Plexos model to understand RNG cost effectiveness.
Staff appreciates the inclusion of a conversation regarding buying versus building RNG projects.
Staff requests that this section be expanded to include more discussion regarding whether and
how risk is captured when considering RNG project type and finding ways to ensure that
ratepayers are not negatively impacted by Avista’s choice of deal structure.5 Further, consider
discussing whether there other risk mitigation aspects that a build option presents; and how
customers are afforded equal, or increased protection from risks.6

Response: Updated in Final IRP.

Regarding Purchase Projects,7 the descriptions include project design and construction aspects.
Staff would also appreciate additional discussion regarding:
Avista’s role in designing and building these projects and whether there are O&M costs;
The procurement process for these projects; and
If possible, the emissions impacts from these projects - both in terms of CPP compliance and
carbon intensity - and the anticipated or known end use of the gas.
Response: Avista has not, to date, bought any project. Emissions from these projects per the
CPP is all directly available through the program language itself as if a project is certified as
RNG, it meets the compliance goals of offsetting an equivalent of natural gas meaning it gets
excluded from emissions totals. Carbon intensity is not a part of the CPP in its current design.

For all RNG projects, please provide additional description about the benefits these projects
provide to Avista and Avista’s Oregon customers and which ones have Environmental Attributes
that will apply to CPP compliance.
Response: All RNG as modeled in the IRP are considered a bundled product. Renewable
Thermal Credits (RTCs), if purchased, would require a source of energy such as natural gas.
RTCs offset the energy and carbon in a dekatherm of natural gas and all would apply toward
CPP compliance.

Avista references some of the same sources for cost and availability used by NW Natural in its
2022 IRP. As Staff provided substantial comments on the cost and availability assumptions of
RNG and Hydrogen in its comments in NW Natural’s case,8 it may be helpful to review Staff’s
comments to see if there are concerns or questions raised in that docket that are applicable to
Avista and that the Company could address with additional clarification in its filed IRP.

Response: Avista utilized RNG curves from multiple sources. The supply curves included in the
Appendix Chapter 4 include estimated supply availability from a consultant to Avista and are
population weighted. An RFP was conducted and volumes in response to the RFP support and
even eclipse these estimated totals in the IRP.

In the Draft, it appears the company anticipates acquiring more RNG for WA than for OR.9 This
was surprising to see given the constraints around environmental attributes in WA. Please
provide more explanation about the difference in RNG potential volumes in WA and OR.

Response: Avista does not have RNG as a resource option in WA in the PRS. Oregon,
however, has the highest demand for RNG in all scenarios for the 2023 IRP.

OPUC Staff’s Avista 2023 Draft IRP Feedback
10 | P a g
e

5 See Docket No. LC 79, NW Natural 2022 IRP, Staff’s Opening Comments, December 30, 2022, pages
49-51.
6 Avista Natural Gas Corporation 2023 Integrated Resource Plan Draft, January 5, 2023, pages 4-18.
7 Avista Natural Gas Corporation 2023 Integrated Resource Plan Draft, January 5, 2023, pages 4-11 to 4-
13.
8 See Docket No. LC 79, NW Natural 2022 IRP, Staff’s Opening Comments, December 30, 2022, Section
11, pages 64-72.
9 Avista Natural Gas Corporation 2023 Integrated Resource Plan Draft, January 5, 2023, Figure 4-4, page
4-16.

Synthetic Methane
Staff and CUB provided substantial comments in Opening Comments in LC 79 regarding
synthetic methane assumptions. Concerns were around price and availability assumptions and
the resulting modeling with the use of those assumptions.10

Response: Avista shares those concerns as it is a proven technology, but not readily available or
used on a large scale. External studies were used to develop assumptions such as those from
Lazards, Bloomberg, Black and Veach and others. The IRA should help to boost technology
uptake, yet the quantity and availability is a risk as with any new technology.

Other
Recognizing that GTN Xpress has garnered attention from advocacy groups, please consider
additional information about the role this project plays in the Company’s planning, any
anticipated impacts if this project didn’t manifest, and alternative ways to meet the need this
project addresses.

Response: Avista did not consider GTN Xpress in resource options as resources to deliver
natural gas are long and nothing is needed to meet capacity. Emissions constraints drive the
resource needs considered in the 2023 IRP. However, without GTN Xpress, the region may
become resource constrained and the ability to meet a regional peak along with extreme price
volatility has seen an increase in recent years. GTN does not serve solely one jurisdiction with a
single climate policy, but rather crosses multiple jurisdictions with various climate policies. Idaho
is Avista’s fastest growing jurisdiction and does not have, nor is it expected to have, a climate
policy in the future. With policy in California reducing operating storage fields, if a pipeline or gas
infrastructure unexpectedly fails, the ability to provide energy demand is at serious risk.
Regarding Strategic Initiatives and the primary roles of the Energy Resources Department, Staff
may be interested to hear more about how, if at all, the Company factors in new customers in its
consideration of risk to serving existing load. When the company describes its strategic initiative
with a primary role of serving load - is there differentiation drawn between existing and future
load?

Response: Serving load, both existing and new, is a requirement to having a monopoly service
in Oregon. Avista will follow all procedures, rules, and regulations in providing energy through its
pipeline infrastructure. Until such time the requirement to serve new customers is removed,
Avista is obligated to serve these customers. As such, Avista has not factored new customers in
its consideration of risk to serving existing load.

OPUC Staff’s Avista 2023 Draft IRP Feedback
11 | P a g
e

On page 4-31 the company describes ongoing activity of optimizing underutilized resources to
help reduce costs to customers. Can you provide more detail on the types of activities this
includes?

Response: Optimization of these resources includes releasing pipeline capacity when it is not
required. It also includes using the basin spreads to capture value between demand regions.
This can include purchasing at the lower priced basin and selling at the highest priced basin.
This would consider all costs and fuel to move the energy from one point to the next.

Chapter 5: Policy Issues
Staff really appreciates the level of detail provided around Direct Carbon Capture Facilities
incentives. Staff would like to understand whether and how this incentive information is captured
in modeling. Similarly, Staff will be interested in understanding how incentives for conversions
from natural gas to electric are modeled and whether this policy is reflected in future load and
customer growth.

Response: The expected costs of the IRA are included in conversion costs by end use. These
costs are estimated as saving as much as 50 % of the total costs to convert. Load growth uses
historic figures to estimate future load growth. Until an end use model is developed or obtained,
understanding elasticity and future load growth based on the IRA is not directly available in the
analysis. This is an action item in the 2023 IRP Action Plan to obtain an end use model.

Staff notes that the Company is also subject to Securities and Exchange Commission GHG and
Climate-related Risk Disclosure. While Staff isn’t suggesting that the Company include additional
information in the IRP, it should anticipate that Staff will be interested in seeing any filings of the
Company, either in the IRP itself or through the discovery process.

Response: Avista will provide all materials of interest that have been made publicly available, if
requested to do so.

Chapter 6: Preferred Resource Strategy
Chapter 6 includes several charts that have little or no additional text explaining the importance
of the information they contain.

Response: Avista has attempted to address this comment throughout the document and
specifically Chapter 6.

Regarding Lead Time Requirements - please consider adding language about the lead time and
information necessary to consider non-pipe alternatives to distribution system investments.

Response: Updated in Final IRP.

Regarding competition for RNG resources - Staff appreciates this mention and asks that the
company explain and demonstrate how this competition is reflected in its availability and cost
assumptions.

Response: The current market for competition dictates a price for RNG in the LCFS and RIN
markets as discussed in Chapter 5. Prices analyzed by source provide estimates of a cost of
OPUC Staff’s Avista 2023 Draft IRP Feedback
12 | P a g
e

ownership structure. Without ownership, costs of RNG may lean to a market based structure
where competition is around compliance. Both pose risks as a cost risk may be evident in place
of a loss risk if projects don’t materialize as expected.

10 Docket No. LC 79, Staff Opening Comments, December 30, 2022 Section 11.
https://edocs.puc.state.or.us/efdocs/HAC/lc79hac162626.pdf and CUB Opening Comments, December
30, 2022

Regarding Risk and Uncertainty - consider the feedback provided to NWN regarding risk and
uncertainty in Staff’s Opening Comments in LC 79 and the assumptions used to represent
conservative approaches.11 Where assumptions stray from a conservative approach, provide the
rationale and support for the assumptions used.
Response: Avista analyzed risk and uncertainty using factors specific to its specific system.
There are many risks included in the 2023 IRP, more than any previous IRP, but in simple terms
it all comes down to supply, demand and cost risks. Natural gas sources are abundant in our
region so supply risk pending an unexpected outage is navigable. New carbon free resources
present mostly a cost risk at this point as some technology is not scaled up and costs are still
higher when compared to natural gas. Demand risk in Oregon and Washington is likely the
greatest risk. For this we have to rely on estimates of how demand may shift based on the
known facts. Electrification may take place at a faster level than anticipated. Electrification may
take place at a slower level than anticipated. Policy may imply a fundamental change, but one
that never takes place. Chapter 2 helps to describe these potential outcomes based on
stochastic futures. More work is needed in future IRPs to understand these risks and have been
added to the Action Plan.

Please provide more explanation for the information provided in figure 6.16.

Response: Updated and moved to Chapter 3-1.

Consider providing additional information about what is happening in table 6.2 and 6.3. In
particular, please speak to the change(s) that occurs between 2035 and 2036.
Response: Updated in final IRP.
OPUC Staff’s Avista 2023 Draft IRP Feedback
13 | P a g
e

See page 6-24. Please explain and provide associated workpapers demonstrating about why
synthetic methane appears before hydrogen in the Oregon PRS.
Response: Hydrogen can only provide 1/3 the energy for the same amount of space in the
pipeline. Synthetic methane requires the same amount of space as natural gas meaning an
equal amount of energy can be provided when needed. This insinuates an additional pipeline or
expanded distribution would need to be created in order to utilize hydrogen to provide an equal
amount of energy demand.

See page 6-24. Regarding Natural Gas Basin Least Cost, to what extent are the volumes
procured via multi year contracts. Please consider explaining how these contracts reflect
reductions in volume associated with CPP compliance.

Response: Natural gas supply basins are procured on a least cost basis where Avista has the
ability to move natural gas from the supply point to city gate stations in its service territories.
Volumes can be procured into the future as much as 36 months. Avista does not have multi-
year contracts in its portfolio and procures hedges against average volumes in winter strips
(November-March), summer strips (April – October), or in individual months. Avista does not
have any RNG, synthetic methane, hydrogen, or other clean fuel on the system, but when these
supplies are secured, they will be removed from average volume hedge plan targeted hedges.
They would directly reduce obligations for energy in the form of natural gas. Program offsets
would still be required if natural gas is purchased in compliance to the CCA and CPP where
volumes are above the program cap.

See table 6.4. Considering the remarkable trajectory of synthetic methane acquisition, what are
the consequences of this not materializing?
Response: Like all forms of clean energy, these supplies will take time and investments to
materialize as expected. In the event these costs and available volume acquisition do not
materialize, Avista will look to other forms of clean energy resources to meet customer demand.
These could include RNG, hydrogen, carbon capture, among others.

Regarding Figure 6.21 – consider providing additional detail about what influences the ranges.

Response: Updated in final IRP.

Regarding Price Impacts on page 6-32 – the Company notes that these are a “commodity only
estimate.” Does this mean that this does not reflect the full anticipated bill impact? Please
provide more explanation about what these values include or do not include.

Response: Updated in final IRP.

Avoided Costs
OPUC Staff’s Avista 2023 Draft IRP Feedback
14 | P a g
e

Staff looks forward to seeing more detail about Avista’s avoided costs methodology and
understanding the extent to which it captures the increased costs from RNG. To the extent that
cost could be avoided by energy efficiency, would it be found in the methodology’s Commodity
Cost or in the Environmental Compliance Costs? If the preferred portfolio’s forecasted 2028
RNG costs are not accounted for in energy efficiency’s avoided costs, the filed IRP should detail
the reasons.

Response: avoided costs include emissions compliance costs and energy costs. Any resource
available, as outlined in Chapter 4, make up these costs. They are all included in the model
which provides the avoided costs to AEG and ETO for evaluation.

Chapter 7: Alternative Scenarios
Consider a reorganization of the Tables in Chapter 7, with the categories in the first column and
the scenarios and years in the following columns, like the Company did in the scenario
comparisons in UM 2178. This would facilitate comparisons across the scenarios. Please also
consider including the units in the tables themselves, instead of in the narratives about the
tables.

Response: Additional comparisons have been provided in Chapter 7 to provide reference points
across all scenarios.

Staff would like to have any easy way to compare key findings of the different scenarios in one
place instead of flipping between scenarios (a summary table with key metrics – like what you
did in UM 2178)

Response: Additional comparisons have been provided in Chapter 7 to provide reference points
across all scenarios.

Regarding the Electrification Scenarios
Do they capture emission reductions and bill impacts? Is there any consideration of the payback
on the conversion costs when considering energy saved on the gas side and
energy consumed on the electric side? To the extent possible, it would be helpful to understand the shifts
in costs and emissions or make it explicitly clear where those are not captured in the modeling.

Response: The electricity is considered green, though one could argue that maybe premature
depending on the year selected combined with the electric provider. Avista does not know the
source of power for the electricity provided to crossover areas. Emission reductions are captured
and illustrated in Chapter 7, Figure 7.13. Conversion costs are assumed to have a payback of 5
years and charged in an annuity type monthly fee. Any customer loss to the electric provide
helps meet emissions goals on the natural gas system as less demand is required to find a clean
fuel or procure a CCI.

OPUC Staff’s Avista 2023 Draft IRP Feedback
15 | P a g
e

This section notes that Chapter 2 explains the methodology to remove demand from the gas system.
Please consider including an additional discussion about how it considered reductions in O&M and
infrastructure costs where demand on the gas side is reduced.

Response: Depending on where the line and customers are located, pruning of the system may
created a cost savings in O&M. This is a detailed analysis where a SCADA system would be
required in combination with software used to plan the distribution system. This is a good reason
why Avista chose to only include cost impacts on the commodity rather than as an bill.

Be sure the electrifications cost clearly indicate how IRA and other federal incentives are considered.
Response: Updated in final IRP.

Staff is unclear about the Hybrid case. Please consider expanding the description of this
scenario and the role it plays in this IRP modeling.
The Company says it assumes “immediate conversion.” Please explain more about why this is
reasonable.
This section would benefit from more explanation about what technologies are considered and
support for the timeline of adoption considered.

Response: Avista agrees with this initial case and has adjusted the case to allow for a declining
use or conversion of customers as in the electrification scenarios.

Electrification Selected as Resource – Staff is pleased to see the Company including
electrification as a selectable resource. The outcomes of including electrification as a selected
resource are interesting and warrant more explanation about the drivers and implications. For
example, the Company notes that “electrification was selected in the first year, but not again
after.” It is not clear to Staff why or what this might mean. Please consider opining on this further.
Response: Updated in final IRP.

Interrupted Supply - please explain how this scenario plays out over the course of the planning

horizon. Is the 50 percent constraint over the entire planning horizon?
Response: In the scenario it is assumed the pipeline capacity is reduced by 50% from Sumas
south at Northwest pipeline (NWP) and Westcoast pipeline which brings in supply from station 2.
This is paired with a constraint at the Rockies point on NWP down to 75% of capacity. Both
constraints are for the 23 year timeframe on a daily basis. The primary reason to not just model
a daily outage is due to the models ability to just use storage to meet demand. These scenarios
also have a hard time and are at a disadvantage as these expected futures would impact the
region so the ability for the region to meet these capacity constraints would likely tell a more
accurate story as to best mix of cost and risk.

Social Cost of Carbon - Please explain what is meant that the SCC overrides the cost of
OPUC Staff’s Avista 2023 Draft IRP Feedback
16 | P a g
e

compliance in CCA and CPP. It's not entirely clear how this scenario handles the SCC as
considered already.

Response: The social cost of carbon is higher than the program cost of carbon in both the CCA
and CPP. To understand the costs of using the SCC for compliance rather than the costs as
found in the CCA and CPP, an “override” of the costs in these programs are necessary. Another
way to say this is the SCC is the cost of carbon in place of those costs included in the CCA and
CPP to compare resource selections.

Oregon CCI Investments - please provide more explanation about why SCC scenario results in
higher acquisition of renewable fuels and removes the need for more CCIs. Figure 7.8 The CCI
demand by scenarios are very interesting, please consider providing a more discussion opining
on these, including how they influence the PRS.

Response: Additional explanation has been provided to help add more detail to selections.

See Figure 7.9: System Emissions by Scenario by 2030 - Please provide more discussion
around the emissions outcomes in figure 7.9. In particular, consider more discussion around the
carbon intensity scenario and the hybrid case scenario.

Response: Updated in final IRP.

Chapter 8: Distribution System Planning (DSP)
Distribution system ‘pruning’ and electrification may be topics of conversation in the IRP review
process. Any context the Company is inclined to provide on these issues could help develop a
shared framework and knowledge base for this discussion.

Response: Avista would like to be part of the pruning and electrification discussion to learn more
about how this potential strategy may mitigate near-term distribution constraints.

For future distribution system projects presented in an IRP Action Plan, Staff recommends Avista
follow the Commission’s endorsement, in Commission’s Order 23-023, of encouraging the use of
Attachment A in the Staff’s Report when such projects appear in an IRP Action Plan. Staff uses
the set of questions in Attachment A for requesting specific information that help build an
analytical framework to be used for the assessment of proposed distribution system projects.

Response: Avista will review Commission Order 23-023 and consider the use of Attachment A in
future IRP Action Plans for distribution system projects.
OPUC Staff’s Avista 2023 Draft IRP Feedback
17 | P a g
e

Non-Pipe Alternatives
On page 8-5 the company references “longer-term, targeted energy efficiency programs” that
could offset constrained areas. Staff is interesting understanding how much advance lead time
Avista would need to consider targeted energy efficiency or non-pipe alternatives, to mitigate the
need for other distribution system constraints. Consider including more information about how
non-pipe alternative are considered as options (or not) and why.

Response: As shown in Table 8.2 (City Gate Station Upgrades), Avista has some city gate
stations that are reviewed periodically to determine the need and timing of any upgrade. Avista
is exploring the possibility of using a targeted energy efficiency alternative as a means to
mitigate or eliminate an upgrade project. However, until the need becomes imminent, it is
prudent to wait before Avista dedicates resources to a targeted energy efficiency program or
non-pipe alternative solution.

Table 8.2 shows City Gate Station Upgrades and lists two Oregon projects with TBD dates and
notes that the Company is monitoring these constraints. Please describe the nature of the issues
being monitored and whether non-pipe alternatives could address the issues. Please also
explain why a location would be monitored and what characteristics warrant monitoring.

Response: The list in Table 8.2 (City Gate Station Upgrades), with TBD dates reflect those city
gate stations that have projected capacities near to slightly above the physical capacity of the
station. To determine if and when an upgrade is necessary, Avista continues to monitor peak-
hour capacity flows during cold weather conditions. Non-pipe alternatives and targeted energy
efficiency programs may be able to address the city gate station’s physical capacity constraint.
Avista feels it may be prudent to continue monitoring to determine the need and timing of any
upgrade before dedicating resources to evaluate a non-pipe alternative solution.

Page 8-8 includes a description of the evaluation of non-pipe alternatives. Please describe
whether and how stranded asset risks are considered in the evaluation of non-pipe alternatives.

Response: Avista has yet to employ a non-pipe alternative that involves the evaluation of
stranded assets. When the first case is studied, the appropriate departments will be included
(Regulatory, Property Accounting, and Engineering) to ensure the full financial impacts are
included in the analysis.

Chapter 9: Action Plan
Staff expects the action plan to cover four years.

Response: The action plan is intended to cover four years.
Regarding Action Item 3 – please provide more details in the IRP about the ETO program for
interruptible customers or reference program details in an appendix.

Response: Updated in the final IRP
OPUC Staff’s Avista 2023 Draft IRP Feedback
18 | P a g
e

Please provide more detail about the Company’s anticipated RNG projects for 2023 and the
pipeline of projects in development, as applicable.

Response: Avista is currently in an RFP and under an NDA. Currently Avista is evaluating
options including bundled and unbundled RNG. Avista will inform each commission in its service
territory as projects or resources are further considered.

Regarding Action Item 10 - specifically, the construction of gas infrastructure associated with
growth. The Company lists these as a potential necessary capital investments that are not
referenced in the IRP. This is disconcerting, especially regarding Staff’s concerns about growth
related investments and CPP risk. Please provide more discussion about these types of possible
projects and please see Staff’s Opening Comments in LC 79, section 4.2, and Order No. 23-023.

Response: The specific language was a carryover from prior IRPs. The line regarding
expansions based on growth has been removed and is now accurately depicted in the Action
Plan in Chapter 9.

12 See Docket No. LC 76, Cascade’s 2020 IRP Update, Staff Report, October 7, 2022, pages 19

Appendix 0.3: WUTC Staff Draft Comments
A table of contents with embedded links
would be helpful.
Avista will include a table of contents in the final
IRP.
Ch. 1 Introduction and Planning environment
Fig 1.4 – Please make colors for each class
match across states.
Primary colors match across each area and state
now.
Ch. 2 Demand Forecasts
Page 2-2, “However, it is important to
understand these forecasts reflect the “status
quo” and do not fully reflect emerging natural
gas connection restrictions in Washington and
Oregon. After the completion of this forecast
Washington added restrictions to new
residential and commercial natural gas
connects through new construction building
codes. It is unclear at this point how those
new codes will impact the accumulation of
new gas customers.” Please indicate when
Avista will provide this analysis.
Additional dialogue has been added to help
explain assumptions in the final IRP. Also, Avista
will carefully follow implications for these codes
changes and incorporate them into the 2025 IRP.

The last sentence on page 2-3 is incomplete.
Please include an internal link to the further
discussion.
This has been addressed within the final IRP in
section 2-3.
Page 2-5, Figure 2.3, staff would appreciate
additional narrative explanation for the
different HDD responses by region. Is this
driven mostly by the number of users, end use
load types, etc.?
See page 2-5 for additional narrative. This figure
is intended to show how linear the relationship in
usage is with increased HDDs but may look
skewed as it considers total load by area instead
of a use per customer per HDD.
Page 2-5, “This forecast uses three-years of
historical city gate data, sorted by service
territory/temperature zone, and then by
month. The three-year coefficient most
closely aligns with economic expectations and
use within Avista’s territories in the short-
term forecasting in Idaho and Washington.
Oregon territories include a five-year demand
coefficient based on the OPUC staff’s
recommendation 1 discussed in Chapter 9.”
Why did Avista choose to use only 3 years of
data for Washington and Idaho instead of
aligning with Oregon? What differences are
seen with 5 years of data?
This forecast considers up to five years of
historical city gate data, sorted by service
territory/temperature zone, and then by month.
The three-year coefficient most closely aligns
with economic expectations and use within short-
term forecasting in Idaho, Oregon, and
Washington. However, Oregon territories include
a five-year demand coefficient based on the
OPUC staff’s recommendation 1 discussed in
Chapter 9. Specifically, the Oregon five-year
coefficient is lower than expected usage by over
four hundred thousand dekatherms annually
from 2023 to 2027. Without this action item,
Avista would have utilized a three-year
coefficient across all jurisdictions.

Page 2-5, “Avista assumes the average usage
based on the historic baseline in each
program. Figure 2.4 is an example of demand
for transport customers from the PLEXOS®
model” What does the historic trend/baseline
look like?
This has been updated in the final IRP to show
historic use for transport customers for Oregon
and Washington
Page 2-7, “Given the sheer volume of data, a
method to select a representative set from the
172 modeling combinations was needed.
Fortunately, BPA conducted this exercise and
selected a subset of modeling combinations
representing a sufficient cross section of
outcomes to calculate generation.” What is
the method? If possible provide link to BPA
study.
The description of BPA’s selection of 19 scenarios
can be found in the following document:
“Climate and Hydrology Datasets for RMJOC
Long-Term Planning Studies: Second Edition
(RMJOC-II)
Part II: Columbia River Reservoir Regulation and
Operations—Modeling and Analyses”
Page 2-7, “The subset represents 19 modeling
combinations for both RCP 4.5 and RCP 8.5.”
How many of each?
There are 19 scenarios for RCP 4.5 and 19
scenarios for RCP 8.5.
Page 2-8, “Given the RCP 8.5 is at the high
end of potential future GHG emissions where
there are significant worldwide efforts to
mitigate GHG emissions removes this future
as a realistic option.” NWPCC relies on RCP
8.5. Other than occasional dips correlated
with economic crises, can Avista point to a
global downward trend in emissions to
support this position?
Avista chose to use the RCP4.5 Scenario because
it represents a reasonable increase in GHG
emissions over the planning horizon of interest.
The Intergovernmental Panel on Climate Change
(IPCC) describes the Representative
Concentration Pathways (RCP) as follows:
(https://ar5-
syr.ipcc.ch/topic_futurechanges.php):
• RCP2.6 – stringent mitigation scenario
• RCP4.5 and RCP 6.5 – intermediate
scenarios
• RCP8.5 – very high GHG emissions.
RCP 4.5 and RCP 6.0 represent growth in
greenhouse gas emissions, but the growth is
lower in comparison to RCP8.5 due to mitigation
strategies. In the time horizon of the IRP the
increase in global mean surface temperature for
RCP4.5 and RCP6.5 are 1.4 and 1.3 degrees
Celsius, respectively, and therefore have a similar
impact on the IRP analysis.
Page 2-8, “Figure 2.6 presents the net change
in load resulting from using the RCP 4.5 data
in the forecast model compared to using the
most recent 20-year average held constant
over all future years.” How does the figure
differ under an RCP 8.5 model? How does
this model combine with figure 2.2 and
customer preference for furnaces over
heatpumps?
As discussed, Avista did not model RCP 8.5 within
this IRP. The method was selected based on an
exercise conducted by BPA as discussed on page
2-8. Looking into these varying RCP data sets is a
time intensive exercise and Avista chose to follow
others in the Pacific Northwest rather than
analyze every possible future. Understanding
possible future changes will be addressed in the
2025 IRP as the timeseries methodology of
forecasting use per customer no longer provides
the necessary detail and nuances needed to
analyze such an outcome.
Page 2-14, “For example, the Medford
weather pattern over the 500 20-year draws
(i.e, 10,000 years) HDDs at or above peak
weather (53.3 HDDs) occur 4,986 times or
once every two years.” Please explain how
peak weather can happen every other year?
Does this suggest something is wrong with
the model?
The correct way to read the chart would be to
consider the total possible days in a year
combined with 500 draws. The total days with a
possible peak day for 2023 would be roughly 248
occurrences in 182,625 days or 0.14% of days.
Avista believes the model is stochastically
analyzing peak days correctly.
Page 2-21, “Scenario Analysis” It’s not clear
to Staff how demand goes up in most
scenarios despite the Washington building
code changes. The “hybrid case” scenario
needs explanation, especially how it starts
with such low demand.
Avista has tried to address this question
throughout the final IRP. The basic explanation is
that we do not know what to expect from
building code changes. The changes occurred
toward the end of the technical advisory
committee meetings, and because the codes do
not begin until July 2023, additional
understanding of this fundamental shift and
future customer expectations is necessary.
Scenario analysis is an accepted form of
measuring unknown futures to help address this
concern of customer growth. Avista has included
14 total scenarios in the 2023 IRP to try to
account for the various pathways of demand and
future supply.

The Hybrid Case was reanalyzed based on these
similar concerns from Avista and is addressed in
Chapter 7.
Page 2-21, “Electrification Expected
Conversion Costs – Expected conversion
costs case to show the risk involved with
energy delivered through the natural gas
infrastructure moving to the electric system”
Please explain the particular risks involved
that are shown in this scenario.
The risk of electrification is expecting a level of
demand on the natural gas system while and
investing in resources to serve this expected
demand. If fewer customers remain on the
system than expected, fewer customers will pay
for a greater share of the overall costs.
Page 2-22, Table 2.8 – Why is hybrid demand
so much lower than electrification demand in
2025? (Explained on page 7-5, please provide
explanation and/or embedded link in chapter
2)
The Hybrid Case was re-analyzed based on these
similar concerns from Avista and is addressed in
Chapter 7.
What does “PRS” mean? Please expand the
acronym for the table or provide a footnote
for easy reference.
PRS means “Preferred Resource Strategy”.
Chapter 6 goes into full detail of the strategy
Avista is considering in the 2023 IRP.
Does the Electrification scenario consider
IRA subsidies, cap and invest spending, and
other subsidies that might ease electrification?
What is the connection between
“Electrification” here on Table 2.8 (decrease
of 18% of demand) and Figure 2.2 (decrease
of 33% of customers)?
The IRA is discussed in Chapter 3 and is included
in expected costs as a degradation to the costs of
electrification.

The connection between Table 2.8 and Figure 2.2
shows the summary of decreasing 33% of
customers by 2045 and the energy expected to
serve load with future weather expectations net
of these customer losses.
Ch. 3 Demand Side Resources
Pg 3-1, “The resulting avoided costs are
compared to those obtained from the previous
iteration of PLEXOS® avoided costs. This
process continues until the differential
between the avoided cost streams of the most
recent and the immediately previous iteration
becomes immaterial.” Staff requests Avista
add a layperson-friendly explanation. This
comment is applicable in many places, but we
won’t detail every instance. Please give a read
through with an eye to, where possible,
adding plain talk descriptions that are more
widely accessible.
The IRP document is technical in nature, so is
difficult to add in plain talk descriptions. We have
added clarifications in the final IRP where
possible.
Pg 3-4, Table 3.2, please provide a link in this
text to the appendices and/or workpapers that
contain data for each year.
A link has been provided to reference the
appendices.
Pg 3-11, “This IRP does not include fuel
switching in the demand forecast, but rather
includes specific fuel use electrification as a
resource option for both commercial and
residential customers.” Is this modelling
assumption based on evidence? Are there any
studies that consider what portion of
customers are more likely to selectively swap
out appliances or to electrify all at once?
This modeling assumption was a methodology to
address electrification while providing the model
an apples-to-apples comparison to switching over
when valuing least cost options to serve
customers demand and emissions compliance.
Pg 3-11, “Industrial customers are not
considered in this analysis.” Please include an
explanation of why?
Avista has very few industrial customers and
some customers end use needs require natural
gas. Also, end use by industrial customers is not
straight forward, rather depends on the specific
industrial process itself.
Pg 3-11, “Further, customers may find
extrinsic value in natural gas for resilience
benefits and its superior performance
compared to electric options.” Do you mean
intrinsic? Does Avista consider these values
for cost-effectiveness of electrification?
Extrinsic is the correct terminology in this case.
Intrinsic would refer to a customer finding
natural gas rewarding because it is natural gas.
Extrinsic refers to outside feelings or perceptions
of a product, such as the use of a natural gas
stove by a chef simply because others use them.
Resiliency when electricity is out is another
example.

These values would be considered non-energy
indicators and will be developed in the 2025 IRP
process.
Pg 3-12, “The estimated values for these
sources are used from the CPA studies
provided by AEG and ETO.” Please provide
the source for heatpump/electric heating
efficiency?
These efficiencies have been developed by
experts at Avista and confirmed when possible by
outside persons and technical advisory members.
Pg 3-12, Figure 3.2, why is the graph a
stepwise function and not a continuous
function? What assumptions underly the
shape of the blue stepwise function? “The
second set of assumptions is built around
demand variability and certain sets of
temperature groupings. As an example, if a
customer’s furnace is running constantly at 65
Heating Degree Days (HDD’s), it does not
run more if the HDD’s increase with colder
temperatures.” Please add additional context.
Figure 3.2 includes a stepwise function based on
assumptions built by our energy efficiency
engineers and staff. A linear nature was not
chosen, though could be, as different set points
are estimated rather than an exact model by end
unit type to understand how a unit may respond
to 44 HDDs as compared to 43 HDDs. These
assumptions assume it is roughly similar and
mostly changes in steps.
Pg 3-12, “Efficiency is considered as a
generic value across equipment and does not
represent ultra-high efficiency units or old
lower-efficiency units.” Did Avista consider a
scenario that looked at the savings and costs
of highly efficient units?
Avista did not consider such a scenario in this IRP.
Pg 3-14, “The Washington territory estimates
include 75% of natural gas customers moving
to Avista for their electricity needs and 25%
lost to other public power providers such as
Inland Power & Light.” Even quarters always
elicit questions, is this an accurate estimate?
The estimate of 75% and 25% for the Washington
territory is the best estimate available by Avista.
Understanding where a gas customer would
switch to would require a SCADA type system
that geographically locates customers and their
electric provider. Avista did not have this ability
at the time of the analysis and would need to rely
on the external entities to provide further detail
if available.
Pg 3-14 and 15, Figure 3.5, what are the
sources for “The assumed escalation curves
for energy per kWh”?
Escalation curves include an expected inflation
through time.
Pg 3-15, Figure 3.5, Why is there a larger
jump in 2036?
This is an added cost based on Avista electric
system upgrades needed to adhere to CETA
requirements. This price increase is included in
Oregon due to similar programs toward carbon
reductions on the electric grid.
Pg 3-15 “When pairing the cost of energy
with the conversion rate in the initial 5 years,
a consistent monthly charge even when
energy is not being used.” This sentence
could use editing.
This has been updated within the final IRP.
Pg 3-16, Figure 3.7, why is there a sizable
jump in 2032?
As discussed in this section, the IRA is expected to
expire making costs more expensive to covert as
the incentives remove half of the cost of
conversion.
Figures 3.7 to 3.10 - levelized cost per
MMBTU – it is unclear if this is step 5 of the
primary analysis detailed on page 3-16 or the
combined single analysis.
A levelized cost is step 5 of the overall analysis
outcome.
Ch. 4 Current Resources and New Resource
Options

Pg 4-4, “For this IRP, Avista 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.” How representative is
this assumption?
This is accurate to the methodologies employed
in the natural gas hedging plan. Please see
Purchased Gas Adjustment (PGA) filings by Avista.
A retrospective hedging report is included in
these annual filings. It provides great detail
around the program and annual adjustments to
help keep Avista gas customers rates as low as
possible.
Pg 4-16, table 4.3, please explain the carbon
intensity scores in more detail. What does a
score of –276.24 mean? Does a percentage
reduction of –452% mean that use of dairy-
sourced RNG results in even more net
emissions than not collecting the fuel?
This has been updated in Chapter 4. A negative
carbon intensity indicates net benefit by
collecting the RNG rather than allowing the RNG
to emit directly into the air. The CCA nor CPP
currently provide credit for the carbon intensity
score, but other programs such as those in
California do.
Pg 4-19, “Figure 4.9 illustrates the number of
participants by state in Avista’s voluntary
RNG program, as of November 2022” Does
Avista currently have RNG resources to meet
this voluntary demand? Could Avista please
provide narrative for the shape of the lines in
the charts? Why do they increase and then
flatten out instead of continuing to increase
more steadily over time? Did Avista reach
market saturation in 2 months?
These are the actual customers by jurisdiction by
month. Avista contracts these volumes from the
Roosevelt landfill through Puget Sound Energy
owned volumes. Uptake in each jurisdiction was
strong in the beginning months but has now
leveled off. Whether customers will increase
demand for this voluntary program is unknown,
however, it may be an indicator of actual demand
to these emission reducing programs as Avista
has seen similar results on the electric side
program for green energy.
Pg 4-19, “Avista is developing a methodology
to evaluate RNG projects.” When does Avista
The current methodology is provided in Chapter
4. Projects are included in the Plexos model used
for the IRP to evaluate against all options.
expect this methodology be
finalized/workable?
Page 4-23, figure 4.12, Is the research from
Black and Veatch available? Why do the
prices go up over time?
This is included in the Appendix. Avista utilized
this analysis to determine an estimated cost by
RNG type. Prices go up in general due to
inflation.
Page 4-23, “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,” What evidence does Avista rely upon
for this claim? What percentage? Staff has
seen this claim repeated across the industry
without citation.
Some sources include:
1. Layout 1 (osti.gov)
2. Injection of gaseous hydrogen into a
natural gas pipeline - ScienceDirect
3. SoCalGas Among First in the Nation to
Test Hydrogen Blending in Real-World
Infrastructure and Appliances in Closed
Loop System (prnewswire.com)
Page 4-23, “The high cost of hydrogen has
been the primary barrier to an accelerated use
and adoption." Does Avista see evidence this
cost will come down?
Yes, please refer to Figure 4.4 and dialogue on
page 4-23.
Page 4-23, “to produce methane” will
system/fugitive emissions of synthetic
methane hinder CCA compliance? Will
hydrogen fugitive emissions hinder CCA
compliance?
Avista submits yearly volumes of throughput in
each of its jurisdictions. Further analysis will be
required to understand resources chosen. In the
current estimated PRS case, Synthetic methane is
not selected in Washington until past the 20-year
IRP timeframe, which will allow Avista to
continue to research and estimate costs and risks
of long-term resources.
Page 4-23, “separate water” How much water
could be needed to meet demand? Will
permits be needed to pump that volume of
water? What about disposal of post-
electrolysis precipitates/waste/biosolids?
4 gallons of water per kilogram will be necessary.
Additional full lifecycle analysis will take place
and is mentioned in the Action Plan in Chapter 9.

Page 4-24, “The process would use a form of
carbon capture” What form(s)?
The process would use air capture.
Page 4-24, “The potential size of this resource
is limited to the quantity of hydrogen
available, a carbon source and cost.” Is
synthetic methane production not also limited
by carbon capture technology?
This has been updated to correct this missed
piece of critical technology.
Page 4-24, “Carbon capture costs are
estimated between $94 and $414 per
MTCO2e depending on source and
technology” Is this expensive? Staff would
appreciate additional context or analysis.
In comparison to compliance in CCA programs or
CPP programs, it helps to provide perspective if
other forms of compliance are not available such
as allowances or offsets (CCA) or community
climate investments (CPP). Depending on the
penalty cost in the thousands of dollars per
MTCO2e above the cap and how the state would
apply this fine (daily or annually), this would still
be considered least cost. It should be noted that
carbon paired with hydrogen is not selected as
least cost until the 2030’s in Oregon and past the
20-year IRP planning horizon in Washington. This
indicates other methods for compliance are
preferred.
Page 4-24, “Synthetic methane is a
combination of green hydrogen and carbon
capture costs per dekatherm.” Does Avista not
account for the cost of combining hydrogen
and CO2? The calculus appears to be the
production cost of Hydrogen plus the cost of
capturing CO2, without considering the
further cost of combining these two products
together.
The chemistry of hydrogen and carbon bonding is
not discussed and requires more analysis to
understand methods and additional costs not
considered in the 2023 IRP. An action item is
included in Chapter 9 to address this point.
Page 4-24, “This fuel can also help bridge the
gap for excess electricity and act as a storage
of energy to a period of higher demand.” This
sounds like a non-gas utility service. Does
Avista consider competing/more efficient end
uses for these fuels?
The IRP only considers ways to reduce demand or
provide energy to natural gas customers
considering a variety of pathways to test resource
needs and potential supply side resources.
Page 4-25, figure 4.14, What is the cost
estimate of hydrogen? Why does the cost of
synthetic methane increase in 2032?
Please refer to the updated Figure 4.14 for H2
only cost estimate. The IRA impacts costs
beginning in 2032 when the program is set to
expire.
Page 4-25, table 4.4, by 2045 the marginal
cost difference between hydrogen and
synthetic methane is $2.65. This represents an
80% reduction in cost of carbon capture
technology from 2025 to 2045. This reduction
is, proportionately, greater than any other
fuel’s cost reduction. What is the basis for this
assumption?
Refer to Page 4-25 and the associated studies
indicated as footnotes.
Page 4-25, table 4.4, If offsets and auctions
etc are included, what is the unit cost of
natural gas?
Please refer to chapter 5, 6 and 7 for assumptions
on the full price of natural gas by scenario and
how these costs change. The model pairs
allowances, environmental attributes, offsets,
community climate investments with natural gas
in its selection of least cost.
Ch. 5 Policy Issues
Page 5-2, “assumes these emissions are
measured at the standard 100-year Global
Warming Potential (GWP) meaning a 34
multiplier of methane from natural gas for the
same mass of carbon dioxide.” Please provide
a citation.
A citation can be found on page 5-2.
Page 5-2, Did Avista consider other fugitive
emission estimates? Is there any risk that
This is a two-part answer:

actual emissions are considerably different
than the assumptions in this IRP?
The risk of emissions is a sizeable one in the 2023
IRP. Emissions from fuel burned by our customers
is considered through stochastic variability.
Fugitive emissions is considered in the carbon
intensity scenario. The compliance to climate
programs in Oregon and Washington relies on
throughput of natural gas and do not include
fugitive emissions unless from within Avista
owned distribution.
Utilities are asked to consider the social cost
of greenhouse gases in their planning. How
did Avista’s incorporation of the SCGHG
interact with the CCA? Did Avista apply the
SCGHG the carbon intensity scores of RNG?
Avista utilized the SCGHG to value energy
efficiency. Avista utilized the estimated costs of
compliance through an allowance to value the
costs to comply with the CCA. The CCA values
RNG as either meeting the criteria for renewable
natural gas or not. Carbon intensity is not
considered as there is not applicable value in the
program for such scores in either the CCA or CPP.
Page 5-12, Any update on where the process
for developing RNG standards are?
RNG pipeline standards should meet pipeline
quality by tariff by pipeline.
Page 5-14, it would be helpful to have a table
of IRA impacts included in this IRP, how
certain they are, and a general time frame of
when and how we will know with more
certainty (waiting for Treasury guidance,
waiting for Commerce).
Impacts can be seen in the electrification
scenario conversion costs, the cost of hydrogen
and synthetic methane. Additional implications
to resources and impacts from the IRA will be
included in future IRPs.
Ch. 6 Preferred Resource Strategy
Page 6-20 refers to using the utility cost test
for WA but Chapter 3 indicates a total
resource cost test for WA. Please clarify that
in this IRP Avista has moved to the TRC for
WA gas.
Avista moved to the TRC in WA. It has been
corrected in the text.
Ch. 7 Alternate Scenarios
Figure 7.9, Average case appears to be higher
cost than PRS but the narrative below states
that average case is lower cost. Also, please
address why the hybrid case appears much
lower.
This has been updated in the final IRP.
Ch. 8 Distribution Planning
Page 8-8, has Avista ever identified a non-
pipe alternative in an IRP?
Avista has not mentioned any non-pipe
alternatives to eliminate near-term
distribution constraints. Near-term
distribution constraints and their
respective proposed reinforcements
mentioned in current and past IRP’s were
aimed at specific parts of the distribution
system that were capacity constrained
and were not possible candidates for
non-pipe alternative solutions.

APPENDIX - CHAPTER 1

APPENDIX 1.1: AVISTA CORPORATION 2023 NATURAL GAS INTEGRATED
RESOURCE PLAN WORK PLAN
IRP WORK PLAN REQUIREMENTS
Section 480-90-238 (4), of the natural gas Integrated Resource Plan (“IRP”) rules, specify
requirements for the IRP Work Plan:
Not later than twelve months prior to the due date of a plan, the utility must
provide a work plan for informal commission review. The work plan must
outline the content of the integrated resource plan to be developed by the
utility and the method for assessing potential resources.
Additionally, Section 480-90-238 (5) of the WAC states:
The work plan must outline the timing and extent of public participation.
OVERVIEW
This Work Plan outlines the process Avista will follow to complete its 2023 Natural Gas
IRP by April 1, 2023. Avista uses a public process to obtain technical expertise and
guidance throughout the planning period via Technical Advisory Committee (TAC)
meetings. The TAC will be providing input into assumptions, scenarios, and modeling
techniques.
PROCESS
This Work Plan is submitted in compliance with the Washington Utilities and
Transportation Commission’s Integrated Resource Planning (IRP) rules (WAC 480-90-
238). It outlines the process Avista will follow to develop its 2023 IRP for filing with
Washington, Idaho and Oregon Commissions by April 1, 2023. Avista uses a public
process to solicit technical expertise and feedback throughout the development of the
IRP through a series of public Technical Advisory Committee (TAC) meetings. Avista held
its first TAC meeting for the 2023 IRP on February 16, 2022.

The 2023 IRP process will include a new linear modeling software, Plexos®, to model its
natural gas system. This model includes the available supply basins for natural gas
combined with the transportation of this supply to Avista’s demand regions. Scenarios will
help measure risk of outcomes in addition to the expected demand from our service
territories on a peak day. The Plexos® model also includes the Climate Commitment Act
(CCA) and new zero carbon resources options to help meet emissions requirements
under this new rule. The model will use stochastic analysis to help select the Preferred
Resource Strategy (PRS).

Avista will use both detailed site-specific and generic resource assumptions in
development of the 2023 IRP. The assumptions combine Avista’s research of similar
supply-side resources, engineering studies and two third-party consultant analyses. This
APPENDIX - CHAPTER 1

IRP will study environmental costs, weather planning standard, peaking requirements and
resource adequacy, energy efficiency programs, demand response programs, and
renewable resources.

Avista will test the PRS against a range of scenarios and potential futures. The TAC
meetings will help to develop and determine the underlying assumptions used in the
scenarios and futures. The IRP process is very technical and data intensive; public
comments are welcome but timely input and participation will be necessary for inclusion
into the process so the plan can be submitted according to the tentative schedule
identified in this Work Plan.

Additionally, Avista intends to incorporate action plan items identified in the 2021 Natural
Gas IRP, including selecting resources to meet a zero-carbon future as laid out in the
CCA and exploring the feasibility of using projected future weather conditions. Further
details about Avista’s process for determining the risk adjusted least-cost resource mix is
shown in Exhibit 1.

The following topics and meeting times may change depending on the availability of
presenters and requests for additional topics from the TAC members. The tentative
timeline for the agenda and TAC schedule is as follows:
APPENDIX - CHAPTER 1

TIMELINE
The following is Avista’s 2023 Natural Gas IRP timeline:
Major Milestone Date Topics
TAC 1 2/16/2022
RNG Discussion, compliance to EO 20-04,
policy, Peak Day weather planning standard
TAC 2 4/19/2022
Use per customer, planned scenarios, Customer
Forecast, current Supply Side Resources,
Plexos Model Overview
TAC 3 8/10/2022 AEG results and Survey Results
TAC 4 9/27/2022
Future Supply Side Resource Options, ETO -
CPA, CCA Overview, Market Dynamics, Climate
Change Weather, load forecast
TAC 5 12/15/2022
Final Results / Stochastics, scenario results,
distribution, energy efficiency comparison, DR
External Draft
Feedback 1/25/2023
Draft Feedback Due 2/25/2023
File 3/31/2023

Major Milestone Date Topics
TAC 1 May-2024 Use per customer, Policy, 2021 Action Item
Review, price elasticity
TAC 2 July-2024 Customer Forecast, price forecast
TAC 3 Aug-2024 sensitivities, distribution, model overview
TAC 4 Sept-2024 Renewable Resources, New and Existing
Resources, Demand Side Resources (CPA)
TAC 5 Nov-2024 Results / Stochastics, Action Items
Write IRP Draft Dec-2024
Draft Feedback
Due
Feb-2025
File Apr-2025

APPENDIX - CHAPTER 1

EXHIBIT 1: AVISTA’S 2021 NATURAL GAS IRP MODELING PROCESS

Process
Model Inputs
Plexos®
Solves least cost resource as a
system
Linear Optimization
Stochastic Analysis
Outputs
Enter all future resource options:•Demand-Side (DSM, DR)•Supply-Side
-RNG-H2-Synthetic methane
-Electrification-Other•Compliance mechanisms-CCI-Allowance
-Offset
Scenario Analysis•Customer Counts
•Use per customer•Emissions•Risk Analysis•Other
Demand Forecast by area and class•Customer counts•Use per customer per HDD•Expected energy demand
Existing Supply-Side Resources•Costs•Operational Characteristics
Resource Considerations•Resource Cost•Peak vs. Base Load•Lead Time Requirements•Resource Usefulness•“Lumpiness” of Resource Options•Carbon Intensity•Ownvs. contracted
Weather•20 year NOAA average by area
plus Peak Day weather planning standard
Commodity/Compliance Prices•Basis differential•Volatility•Seasonal Spreads•Commodity prices by supply type•Compliance price
Policy•Climate Committment Act•Climate Protection Plans•Company Environmental Goals•Cost of Carbon•Other
Conservation
Potential
Assessment
(CPA)
From AEG and
ETO
Marginal
Costs
Integrated
Resource Plan
Determine
Preferred
Resource
Strategy
APPENDIX - CHAPTER 1

APPENDIX 1.2: WASHINGTON PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – WAC 480-90-238
Rule Requirement Plan
Citation
WAC 480-90-238(4) Work plan filed no later than 12
months before next IRP due date.
Work plan submitted to the WUTC
on April 1, 2022, See attachment
to this Appendix 1.1.
WAC 480-90-238(4) Work plan outlines content of IRP. See work plan attached to this
Appendix 0.1.
WAC 480-90-238(4) Work plan outlines method for
assessing potential resources. (See
LRC analysis below)
See Appendix 1.1.
WAC 480-90-238(5) Work plan outlines timing and extent of
public participation.
See Appendix 1.1.
WAC 480-90-238(4) Integrated resource plan submitted
within two years of previous plan.
Last Integrated Resource Plan was
submitted on April 1, 2021
WAC 480-90-238(5) Commission issues notice of public
hearing after company files plan for
review.
TBD
WAC 480-90-238(5) Commission holds public hearing. TBD
WAC 480-90-238(2)(a) Plan describes mix of natural gas
supply resources.
See Chapter 4 on New and
Existing Resources
WAC 480-90-238(2)(a) Plan describes conservation supply. See Chapter 3 on Demand Side
Resources
WAC 480-90-238(2)(a) Plan addresses supply in terms of
current and future needs of utility and
ratepayers.
See Chapter 4 on New and
Existing Resources and Chapter 6
Preferred Resource Selection and
Risk
WAC 480-90-
238(2)(a)&(b)
Plan uses lowest reasonable cost
(LRC) analysis to select mix of
resources.
See Chapters 3 and 4 for Demand
and New and Existing Resources.
Chapters 6 and 7 details how
Demand and Supply come
together to select the least
cost/best risk portfolio for
ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers resource
costs.
See Chapters 3 and 4 for Demand
and New and Existing Resources.
Chapters 6 and 7 details how
Demand and Supply come
together to select the least
cost/best risk portfolio for
ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers market-
volatility risks.
See Chapter 4 on New and
Existing Resources
WAC 480-90-238(2)(b) LRC analysis considers demand side
uncertainties.
See Chapter 2 Demand
Forecasting
WAC 480-90-238(2)(b) LRC analysis considers resource
effect on system operation.
See Chapter 4 and Chapter 6
WAC 480-90-238(2)(b) LRC analysis considers risks
imposed on ratepayers.
See Chapter 4 procurement plan
section. We seek to minimize but
cannot eliminate price risk for our
customers. Chapter 6 and 7.
APPENDIX - CHAPTER 1

WAC 480-90-238(2)(b) LRC analysis considers public
policies regarding resource preference
adopted by Washington state or
federal government.
See Chapter 2 demand scenarios
WAC 480-90-238(2)(b) LRC analysis considers cost of risks
associated with environmental effects
including emissions of carbon dioxide.
See Chapters 2 and 6 on demand
scenarios and Integrated Resource
Portfolio
WAC 480-90-238(2)(b) LRC analysis considers need for
security of supply.
See Chapter 4 on New and
Existing Resources
Rule Requirement Plan Citation
WAC 480-90-238(2)(c) Plan defines conservation as any
reduction in natural gas consumption
that results from increases in the
efficiency of energy use or distribution.
See Chapter 3 on Demand Side
Resources
WAC 480-90-238(3)(a) Plan includes a range of forecasts of
future demand.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using
methods that examine the effect of
economic forces on the consumption
of natural gas.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using
methods that address changes in the
number, type and efficiency of natural
gas end-uses.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(b) Plan includes an assessment of
commercially available conservation,
including load management.
See Chapter 3 on Demand Side
Management including demand
response section.
WAC 480-90-238(3)(b) Plan includes an assessment of
currently employed and new policies
and programs needed to obtain the
conservation improvements.
See Chapter 3 and Appendix 3.1.
WAC 480-90-238(3)(c) Plan includes an assessment of
conventional and commercially
available nonconventional gas
supplies.
See Chapter 4 on New and
Existing Resources
WAC 480-90-238(3)(d) Plan includes an assessment of
opportunities for using company-
owned or contracted storage.
See Chapter 4 on New and
Existing Resources
WAC 480-90-238(3)(e) Plan includes an assessment of
pipeline transmission capability and
reliability and opportunities for
additional pipeline transmission
resources.
See Chapter 4 on New and
Existing Resources
WAC 480-90-238(3)(f) Plan includes a comparative evaluation
of the cost of natural gas purchasing
strategies, storage options, delivery
resources, and improvements in
conservation using a consistent
method to calculate cost-effectiveness.
See Chapter 3 on Demand Side
Resources and Chapter 4 on New
and Existing Resources
WAC 480-90-238(3)(g) Plan includes at least a 10 year long-
range planning horizon.
Our plan is a comprehensive 20
year plan.
WAC 480-90-238(3)(g) Demand forecasts and resource
evaluations are integrated into the long
range plan for resource acquisition.
Chapter 6 Integrated Resource
Portfolio details how demand and
supply come together to form the
least cost/best risk portfolio.
WAC 480-90-238(3)(h) Plan includes a two-year action plan
that implements the long range plan.
See Section 9 Action Plan
APPENDIX - CHAPTER 1

WAC 480-90-238(3)(i) Plan includes a progress report on the
implementation of the previously filed
plan.
See Section 9 Action Plan
WAC 480-90-238(5) Plan includes description of
consultation with commission staff.
(Description not required)
See Section 1 Introduction
WAC 480-90-238(5) Plan includes description of completion
of work plan. (Description not required)
See Appendix 1.1.

APPENDIX - CHAPTER 1

APPENDIX 1.2: IDAHO PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – ORDER NO. 2534
DESCRIPTION OF REQUIREMENT FULLFILLMENT OF REQUIREMENT
1 Purpose and Process. Each gas utility regulated by
the Idaho Public Utilities Commission with retail
sales of more than 10,000,000,000 cubic feet in a
calendar year (except gas utilities doing business
in Idaho that are regulated by contract with a
regulatory commission of another State) has the
responsibility to meet system demand at least cost
to the utility and its ratepayers. Therefore, an
‘‘integrated resource plan’’ shall be developed by
each gas utility subject to this rule.
Avista prepares a comprehensive 20 year
Integrated Resource Plan every two years.
Avista will be filing its 2023 IRP on or before
April 1, 2023.
2 Definition. Integrated resource planning.
‘‘Integrated resource planning’’ means planning by
the use of any standard, regulation, practice, or
policy to undertake a systematic comparison
between demand-side management measures and
the supply of gas by a gas utility to minimize life-
cycle costs of adequate and reliable utility services
to gas customers. Integrated resource planning
shall take into account necessary features for
system operation such as diversity, reliability,
dispatchability, and other factors of risk and shall
treat demand and supply to gas consumers on a
consistent and integrated basis.
Avista's IRP brings together dynamic
demand forecasts and matches them against
demand-side and New and Existing
Resources in order to evaluate the least
cost/best risk portfolio for its core customers.
While the primary focus has been to ensure
customer's needs are met under peak or
design weather conditions, this process also
evaluates the resource portfolio under
normal/average operating conditions. The
IRP provides the framework and
methodology for evaluating Avista's natural
gas demand and resources.
3 Elements of Plan. Each gas utility shall submit to
the Commission on a biennial basis an integrated
resource plan that shall include:
The last IRP was filed on April 1, 2021.
A range of forecasts of future gas demand in firm
and interruptible markets for each customer class
for one, five, and twenty years using methods that
examine the effect of economic forces on the
consumption of gas and that address changes in
the number, type and efficiency of gas end-uses.
See Chapter 2 - Demand Forecasts and
Appendix 2 et.al. for a detailed discussion of
how demand was forecasted for this IRP.
An assessment for each customer class of the
technically feasible improvements in the efficient
use of gas, including load management, as well as
the policies and programs needed to obtain the
efficiency improvements.
See Chapter 3 - Demand Side
Management and DSM Appendices 3 et.al.
for detailed information on the DSM potential
evaluated and selected for this IRP and the
operational implementation process.
APPENDIX - CHAPTER 1

An analysis for each customer class of gas supply
options, including: (1) a projection of spot market
versus long-term purchases for both firm and
interruptible markets; (2) an evaluation of the
opportunities for using company-owned or
contracted storage or production; (3) an analysis of
prospects for company participation in a gas futures
market; and (4) an assessment of opportunities for
access to multiple pipeline suppliers or direct
purchases from producers.
See Chapter 4 - New and Existing
Resources for details about the market,
storage, and pipeline transportation as well
as other resource options considered in this
IRP. See also the procurement plan section
in this same chapter for supply procurement
strategies.
A comparative evaluation of gas purchasing
options and improvements in the efficient use of
gas based on a consistent method for calculating
cost-effectiveness.
See Methodology section of Chapter 3 -
Demand-Side Resources where we
describe our process on how demand-side
and New and Existing Resources are
compared on par with each other in the
PLEXOS® model. Chapter 3 also includes
how results from the IRP are then utilized to
create operational business plans.
Operational implementation may differ from
IRP results due to modeling assumptions.
The integration of the demand forecast and
resource evaluations into a long-range (e.g.,
twenty-year) integrated resource plan describing
the strategies designed to meet current and future
needs at the lowest cost to the utility and its
ratepayers.
See Chapter 6 – Preferred Resource
Selection and Risk for details on how we
model demand and supply coming together
to provide the least cost/best risk portfolio of
resources.
A short-term (e.g., two-year) plan outlining the
specific actions to be taken by the utility in
implementing the integrated resource plan.
See Chapter 9 - Action Plan for actions to
be taken in implementing the IRP.
4 Relationship Between Plans. All plans following the
initial integrated resource plan shall include a
progress report that relates the new plan to the
previously filed plan.
Avista strives to meet at least bi-annually with
Staff and/or Commissioners to discuss the
state of the market, procurement planning
practices, and any other issues that may
impact resource needs or other analysis
within the IRP.
5 Plans to Be Considered in Rate Cases. The
integrated resource plan will be considered with
other available information to evaluate the
performance of the utility in rate proceedings before
the Commission.
We prepare and file our plan in part to
establish a public record of our plan.
6 Public Participation. In formulating its plan, the gas
utility must provide an opportunity for public
participation and comment and must provide
methods that will be available to the public of
validating predicted performance.
Avista held five Technical Advisory
Committee meetings beginning in February
and ending in December. See Chapter 1 -
Introduction for more detail about public
participation in the IRP process.
APPENDIX - CHAPTER 1

7 Legal Effect of Plan. The plan constitutes the base
line against which the utility's performance will
ordinarily be measured. The requirement for
implementation of a plan does not mean that the
plan must be followed without deviation. The
requirement of implementation of a plan means that
a gas utility, having made an integrated resource
plan to provide adequate and reliable service to its
gas customers at the lowest system cost, may and
should deviate from that plan when presented with
responsible, reliable opportunities to further lower
its planned system cost not anticipated or identified
in existing or earlier plans and not undermining the
utility's reliability.
See section titled "Avista's Procurement
Plan" in Chapter 4 - New and Existing
Resources. Among other details we discuss
plan revisions in response to changing
market conditions.
8 In order to encourage prudent planning and prudent
deviation from past planning when presented with
opportunities for improving upon a plan, a gas
utility's plan must be on file with the Commission
and available for public inspection. But the filing of
a plan does not constitute approval or disapproval
of the plan having the force and effect of law, and
deviation from the plan would not constitute
violation of the Commission's Orders or rules. The
prudence of a utility's plan and the utility's prudence
in following or not following a plan are matters that
may be considered in a general rate proceeding or
other proceedings in which those issues have been
noticed.
See also section titled "Alternate Supply-Side
Scenarios" in Chapter 6 – Preferred
Resource Selection and Risk where we
discuss different supply portfolios that are
responsive to changing assumptions about
resource alternatives.

APPENDIX - CHAPTER 1

APPENDIX 1.2: OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND
GUIDELINES – ORDER 07- 002
Guideline 1: Substantive Requirements
1.a.1 All resources must be evaluated on
a consistent and comparable basis.
All resource options considered, including demand-
side and supply-side are modeled in PLEXOS®
utilizing the same common general assumptions,
approach, and methodology.
1.a.2 All known resources for meeting the
utility’s load should be considered,
including supply-side options which
focus on the generation, purchase
and transmission of power – or gas
purchases, transportation, and
storage – and demand-side options
which focus on conservation and
demand response.
Avista considered a range of resources including
demand-side management, distribution system
enhancements, capacity release recalls, interstate
pipeline transportation, interruptible customer supply,
renewable natural gas by source, hydrogen,
electrification by end source and synthetic methane.
Chapter 3 and Appendix 3.1 documents Avista’s
demand-side management resources considered.
Chapter 4 and Appendix 6.3 documents New and
Existing Resources. Chapter 6 and 7 documents how
Avista developed and assessed each of these
resources.

1.a.3 Utilities should compare different
resource fuel types, technologies,
lead times, in-service dates,
durations and locations in portfolio
risk modeling.
Avista considered various combinations of
technologies, lead times, in-service dates, durations,
and locations. Chapter 6 provides details about the
modeling methodology and results. Chapter 4
describes resource attributes and Appendix 6.3
summarizes the resources’ lead times, in-service
dates and locations.
1.a.4 Consistent assumptions and
methods should be used for
evaluation of all resources.
Appendix 6.2 documents general assumptions used in
Avista’s PLEXOS® modeling software. All portfolio
resources both demand and supply-side were
evaluated within PLEXOS® using the same sets of
inputs.
1.a.5 The after-tax marginal weighted-
average cost of capital (WACC)
should be used to discount all future
resource costs.
(See general assumptions at Appendix 6.2)
1.b.1 Risk and uncertainty must be
considered. Electric utilities only
Not Applicable
1.b.2 Risk and uncertainty must be
considered. Natural gas utilities
should consider demand (peak,
swing and base-load), commodity
supply and price, transportation
availability and price, and costs to
comply with any regulation of
greenhouse gas (GHG) emissions.
Risk has been considered as illustrated in chapter 2,
4, 5, 6 & 7. Risk is a cornerstone to Integrated
Resource Planning and one measured in many facets
including weather risk, commodity risk by source and
policy risk including electrification or building code
restrictions.
Utilities should identify in their plans
any additional sources of risk and
uncertainty.
Risk has been considered as illustrated in chapter 2,
4, 5, 6 & 7. Risk is a cornerstone to Integrated
Resource Planning and one measured in many facets
including weather risk, commodity risk by source and
policy risk including electrification or building code
restrictions.
APPENDIX - CHAPTER 1

1c The primary goal must be the
selection of a portfolio of resources
with the best combination of
expected costs and associated risks
and uncertainties for the utility and
its customers.
Avista evaluated cost/risk tradeoffs for each of the risk
analysis portfolios considered. See Chapter 6 and 7
plus supporting information in Appendix 2.6 for
Avista’s portfolio risk analysis and determination of the
preferred portfolio.
The planning horizon for analyzing
resource choices should be at least
20 years and account for end
effects. Utilities should consider all
costs with a reasonable likelihood of
being included in rates over the long
term, which extends beyond the
planning horizon and the life of the
resource.
Avista used a 23-year study period for portfolio
modeling. Avista contemplated possible costs beyond
the planning period that could affect rates including
end effects such as infrastructure decommission costs
and concluded there were no significant costs
reasonably likely to impact rates under different
resource selection scenarios.
Utilities should use present value of
revenue requirement (PVRR) as the
key cost metric. The plan should
include analysis of current and
estimated future costs of all long-
lived resources such as power
plants, gas storage facilities and
pipelines, as well as all short-lived
resources such as gas supply and
short-term power purchases.
Avista’s PLEXOS® modeling software utilizes a PVRR
cost metric methodology applied to both long and
short-lived resources.
To address risk, the plan should
include at a minimum: 1) Two
measures of PVRR risk: one that
measures the variability of costs and
one that measures the severity of
bad outcomes. 2) Discussion of the
proposed use and impact on costs
and risks of physical and financial
hedging.
Avista, through its stochastic analysis, modeled 500
twenty three year futures via Monte Carlo iterations
developing a distribution of Total 23 year cost
estimates utilizing PLEXOS®’s PVRR methodology.
Chapter 2 further describes this analysis. The
variability of costs is plotted against the Expected
Case while the scenarios beyond the 95th percentile
capture the severity of outcomes. Chapter 4 discusses
Avista’s physical and financial hedging methodology.
The utility should explain in its plan
how its resource choices
appropriately balance cost and risk.
Chapter 4, 5, 6, and 7 describe various specific
resource considerations and related risks, and
describes what criteria we used to determine what
resource combinations provide an appropriate balance
between cost and risk.
1d The plan must be consistent with
the long-run public interest as
expressed in Oregon and federal
energy policies.
Avista considered current and expected state and
federal energy policies in portfolio modeling. Chapter
5 and 6 describe the decision process used to derive
portfolios, which includes consideration of state
resource policy directions.
Guideline 2: Procedural Requirements
2a The public, including other utilities,
should be allowed significant
involvement in the preparation of the
IRP. Involvement includes
opportunities to contribute
information and ideas, as well as to
receive information. Parties must
have an opportunity to make
relevant inquiries of the utility
formulating the plan.
Chapter 1 provides an overview of the public process
and documents the details on public meetings held for
the 2023 IRP. Avista encourages participation in the
development of the plan, as each party brings a
unique perspective and the ability to exchange
information and ideas makes for a more robust plan.
APPENDIX - CHAPTER 1

While confidential information must
be protected, the utility should make
public, in its plan, any non-
confidential information that is
relevant to its resource evaluation
and action plan.
The entire IRP, as well as the TAC process, and
website includes all of the non-confidential information
the company used for portfolio evaluation and
selection. Avista also provided stakeholders with non-
confidential information to support public meeting
discussions via email. The document and appendices
will be available on the company website for viewing.
The utility must provide a draft IRP
for public review and comment prior
to filing a final plan with the
Commission.
Avista distributed a draft IRP document for external
review to all TAC members on January 25, 2023 and
requested comments by February 25, 2023. All
comments and responses are included in Appendix 1
Guideline 3: Plan Filing, Review and Updates
3a Utility must file an IRP within two
years of its previous IRP
acknowledgement order.
The 2021 IRP was filed April 1, 2021 with
acknowledgement in October 2021. The 2023 IRP will
be filed March 31, 2023.
3b Utility must present the results of its
filed plan to the Commission at a
public meeting prior to the deadline
for written public comment.
Avista will work with Staff to fulfill this guideline
following filing of the IRP.
3c Commission staff and parties should
complete their comments and
recommendations within six months
of IRP filing
Pending
3d The Commission will consider
comments and recommendations on
a utility’s plan at a public meeting
before issuing an order on
acknowledgment. The Commission
may provide the utility an
opportunity to revise the plan before
issuing an acknowledgment order
Pending
3e The Commission may provide
direction to a utility regarding any
additional analyses or actions that
the utility should undertake in its
next IRP.
Pending
3f Each utility must submit an annual
update on its most recently
acknowledged plan. The update is
due on or before the
acknowledgment order anniversary
date. Once a utility anticipates a
significant deviation from its
acknowledged IRP, it must file an
update with the Commission, unless
the utility is within six months of
filing its next IRP. The utility must
summarize the update at a
Commission public meeting. The
utility may request acknowledgment
of changes in proposed actions
identified in an update
A waiver was requested as Avista was in process of
IRP completion within 6 months between
acknowledged 2021 IRP and 2023 IRP submittal date.
3g Unless the utility requests
acknowledgement of changes in
The updates described in 3f above explained changes
since acknowledgment of the 2021 IRP and an update
APPENDIX - CHAPTER 1

proposed actions, the annual update
is an informational filing that:
 Describes what actions the utility
has taken to implement the plan;
 Provides an assessment of what
has changed since the
acknowledgment order that
affects the action plan, including
changes in such factors as load,
expiration of resource contracts,
supply-side and demand-side
resource acquisitions, resource
costs, and transmission
availability; and
 Justifies any deviations from the
acknowledged action plan.
of emerging planning issues. The updates did not
request acknowledgement of any changes.

Guideline 4: Plan Components
At a minimum, the plan must include
the following
elements:

4a An explanation of how the utility met
each of the substantive and
procedural requirements.
This table summarizes guideline compliance by
providing an overview of how Avista met each of the
substantive and procedural requirements for a natural
gas IRP.
4b Analysis of high and low load growth
scenarios in addition to stochastic
load risk analysis with an
explanation of major assumptions.
Chapter 2 describes the demand forecast data and
risk analysis of demand. Chapter 4 describes price
risk. Chapter 7 provides the scenario and risk analysis
results.
4c For electric utilities only Not Applicable
4d A determination of the peaking,
swing and base-load gas supply and
associated transportation and
storage expected for each year of
the plan, given existing resources;
and identification of gas supplies
(peak, swing and base-load),
transportation and storage needed
to bridge the gap between expected
loads and resources.
Chapter 2 and 6 describe peak demand expectations
and resource selection.
4e Identification and estimated costs of
all supply-side and demand-side
resource options, taking into
account anticipated advances in
technology
Chapter 3 and Appendix 3.1 identify the demand-side
potential included in this IRP. Chapter 4, 5 & 6 and
Appendix 6.3 identify the New and Existing
Resources.
4f Analysis of measures the utility
intends to take to provide reliable
service, including cost-risk tradeoffs.
Chapter 6 and 7 discuss the modeling tools, customer
growth forecasting and cost-risk considerations used
to maintain and plan a reliable gas delivery system.
These Chapters also capture a summary of the
reliability analysis process demonstrated in the four
TAC meetings.
Chapter 4 discusses the diversified infrastructure and
multiple supply basin approach that acts to mitigate
certain reliability risks.
4g Identification of key assumptions
about the future (e.g. fuel prices and
environmental compliance costs)
Chapter 7 considers alternative scenarios and future
cost variability.
APPENDIX - CHAPTER 1

and alternative scenarios
considered.
4h Construction of a representative set
of resource portfolios to test various
operating characteristics, resource
types, fuels and sources,
technologies, lead times, in-service
dates, durations and general
locations - system-wide or delivered
to a specific portion of the system.
This Plan documents the development and results for
portfolios evaluated in chapter 6 and 7.
4i Evaluation of the performance of the
candidate portfolios over the range
of identified risks and uncertainties.
We evaluated our candidate portfolio by performing
stochastic analysis using PLEXOS® varying price
under 500 different scenarios. Additionally, we test
the portfolio of options with the use of PLEXOS®
under deterministic scenarios where demand and
price vary.
4j Results of testing and rank ordering
of the portfolios by cost and risk
metric, and interpretation of those
results.
Chapter 7 illustrates cost and risk variability of the 14
modeled scenarios in the 2023 IRP.
4k Analysis of the uncertainties
associated with each portfolio
evaluated
See the responses to 1.b above.
4l Selection of a portfolio that
represents the best combination of
cost and risk for the utility and its
customers
Avista evaluated cost/risk tradeoffs for each of the risk
analysis in Chapter 6 and 7.
4m Identification and explanation of any
inconsistencies of the selected
portfolio with any state and federal
energy policies that may affect a
utility's plan and any barriers to
implementation
This IRP is presumed to have no inconsistencies.
4n An action plan with resource
activities the utility intends to
undertake over the next two to four
years to acquire the identified
resources, regardless of whether
the activity was acknowledged in a
previous IRP, with the key attributes
of each resource specified as in
portfolio testing.
Chapter 9 presents the IRP Action Plan with focus on
the following areas:
 Modeling
 Policy
 Supply/capacity/distribution
 Forecasting
 Regulatory communication
 DSM
 Distribution and/or capital needs
Guideline 5: Transmission
5 Portfolio analysis should include
costs to the utility for the fuel
transportation and electric
transmission required for each
resource being considered. In
addition, utilities should consider
fuel transportation and electric
transmission facilities as resource
options, taking into account their
value for making additional
purchases and sales, accessing
less costly resources in remote
Not applicable to Avista’s gas utility operations.
APPENDIX - CHAPTER 1

locations, acquiring alternative fuel
supplies, and improving reliability.
Guideline 6: Conservation
6a Each utility should ensure that a
conservation potential study is
conducted periodically for its entire
service territory.
ETO and AEG both performed a conservation
potential assessment study for our 2023 IRP. A
discussion of the study is included in Chapter 3. Each
full study document is in Appendix 3.1. Avista
incorporates a comprehensive assessment of the
potential for utility acquisition of energy-efficiency
resources into the regularly-scheduled Integrated
Resource Planning process.
6b To the extent that a utility controls
the level of funding for conservation
programs in its service territory, the
utility should include in its action
plan all best cost/risk portfolio
conservation resources for meeting
projected resource needs,
specifying annual savings targets.
A discussion on the treatment of conservation
programs is included in Chapter 3 while selection
methodology is documented in Chapter 6. The action
plan details conservation targets, if any, as developed
through the operational business planning process.
These targets are updated annually, with the most
current avoided costs. Given the challenge of the low
cost environment, current operational planning and
program evaluation is still underway and targets for
Oregon have not yet been set.
6c To the extent that an outside party
administers conservation programs
in a utility's service territory at a
level of funding that is beyond the
utility's control, the utility should: 1)
determine the amount of
conservation resources in the best
cost/ risk portfolio without regard to
any limits on funding of conservation
programs; and 2) identify the
preferred portfolio and action plan
consistent with the outside party's
projection of conservation
acquisition.
Not applicable. See the response for 6.b above.
Guideline 7: Demand Response
7 Plans should evaluate demand response resources,
including voluntary rate programs, on par with other
options for meeting energy, capacity, and transmission
needs (for electric utilities) or gas supply and
transportation needs (for natural gas utilities).
Avista has periodically evaluated
conceptual approaches to
meeting capacity constraints
using demand-response and
similar voluntary programs.
Technology, customer
characteristics and cost issues
are hurdles for developing
effective programs.
Guideline 8: Environmental Costs
8 Utilities should include, in their base-case analyses, the
regulatory compliance costs they expect for CO2, NOx,
SO2, and Hg emissions. Utilities should analyze the
range of potential CO2 regulatory costs in Order No. 93-
695, from $0 - $40 (1990$). In addition, utilities should
perform sensitivity analysis on a range of reasonably
possible cost adders for NOx, SO2, and Hg, if applicable.
Discussed in Chapter 5. The
Environmental Externalities
discussion in Appendix 3.2
describes our analysis
performed. See also the
guidelines addendum reflecting
revised guidance for
environmental costs per Order
08-339.
APPENDIX - CHAPTER 1

Guideline 9: Direct Access Loads
9 An electric utility's load-resource balance should exclude
customer loads that are effectively committed to service
by an alternative electricity supplier.
Not applicable to Avista’s gas
utility operations.
Guideline 10: Multi-state utilities
10 Multi-state utilities should plan their generation and
transmission systems, or gas supply and delivery, on an
integrated-system basis that achieves a best cost/risk
portfolio for all their retail customers.
The 2023 IRP conforms to the
multi-state planning approach
with a specific cost of compliance
to Oregon and Washington for
their respective climate
compliance programs as
discussed throughout the IRP.
Guideline 11: Reliability
11 Electric utilities should analyze reliability within the risk
modeling of the actual portfolios being considered. Loss
of load probability, expected planning reserve margin,
and expected and worst-case unserved energy should
be determined by year for top-performing portfolios.
Natural gas utilities should analyze, on an integrated
basis, gas supply, transportation, and storage, along with
demand-side resources, to reliably meet peak, swing,
and base-load system requirements. Electric and natural
gas utility plans should demonstrate that the utility’s
chosen portfolio achieves its stated reliability, cost and
risk objectives.
Avista’s storage and transport
resources while planned around
meeting a peak day planning
standard, also provides
opportunities to capture off
season pricing while providing
system flexibility to meet swing
and base-load requirements.
Diversity in our transport options
enables at least dual fuel source
options in event of a transport
disruption. For areas with only
one fuel source option the cost of
duplicative infrastructure is not
feasible relative to the risk of
generally high reliability
infrastructure.

Guideline 12: Distributed Generation
12 Electric utilities should evaluate distributed
generation technologies on par with other New and
Existing Resources and should consider, and quantify
where possible, the additional benefits of distributed
generation.
Not applicable to Avista’s gas
utility operations.
Guideline 13: Resource Acquisition
13a An electric utility should: identify its proposed acquisition
strategy for each resource in its action plan; Assess the
advantages and disadvantages of owning a resource
instead of purchasing power from another party; identify
any Benchmark Resources it plans to consider in
competitive bidding.
Chapter 4 and 9 discuss resource
need and ownership advantages
and disadvantages.
13b Natural gas utilities should either describe in the IRP
their bidding practices for gas supply and transportation,
or provide a description of those practices following IRP
acknowledgment.
A discussion of Avista’s
procurement practices is detailed
in Chapter 4.
Guideline 8: Environmental Costs
APPENDIX - CHAPTER 1

a. BASE CASE AND OTHER COMPLIANCE SCENARIOS:
The utility should construct a base-case scenario to
reflect what it considers to be the most likely regulatory
compliance future for carbon dioxide (CO2), nitrogen
oxides, sulfur oxides, and mercury emissions. The utility
also should develop several compliance scenarios
ranging from the present CO2 regulatory level to the
upper reaches of credible proposals by governing
entities. Each compliance scenario should include a time
profile of CO2 compliance requirements. The utility
should identify whether the basis of those requirements,
or “costs”, would be CO2 taxes, a ban on certain types of
resources, or CO2 caps (with or without flexibility
mechanisms such as allowance or credit trading or a
safety valve). The analysis should recognize significant
and important upstream emissions that would likely have
a significant impact on its resource decisions. Each
compliance scenario should maintain logical consistency,
to the extent practicable, between the CO2 regulatory
requirements and other key inputs.
Chapters 5, 6 and 7 summarize
these environmental costs.

The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

b. TESTING ALTERNATIVE PORTFOLIOS AGAINST THE
COMPLIANCE SCENARIOS: The utility should
estimate, under each of the compliance scenarios, the
present value of revenue requirement (PVRR) costs and
risk measures, over at least 20 years, for a set of
reasonable alternative portfolios from which the preferred
portfolio is selected. The utility should incorporate end-
effect considerations in the analyses to allow for
comparisons of portfolios containing resources with
economic or physical lives that extend beyond the
planning period. The utility should also modify projected
lifetimes as necessary to be consistent with the
compliance scenario under analysis. In addition, the
utility should include, if material, sensitivity analyses on a
range of reasonably possible regulatory futures for
nitrogen oxides, sulfur oxides, and mercury to further
inform the preferred portfolio selection.
The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

Chapter 7

APPENDIX - CHAPTER 2

APPENDIX 2.1: ECONOMIC OUTLOOK AND CUSTOMER COUNT FORECAST
I. Service Area Economic Performance and Outlook

Avista’s core service area for natural gas includes Eastern Washington, Northern Idaho, and Southwest
Oregon. Smaller service islands are also located in rural South-Central Washington and Northeast
Oregon. Our service area is dominated by four metropolitan statistical areas (MSAs): the Spokane-
Spokane Valley, WA MSA (Spokane-Stevens counties); the Coeur d’Alene, ID MSA (Kootenai County);
the Lewiston-Clarkson, ID-WA MSA (Nez Perce-Asotin counties); the Medford, OR MSA (Jackson
County); and Grants Pass, OR MSA (Josephine County). These five MSAs represent the primary
demand for Avista’s natural gas and account for 75% of both customers (i.e., meters) and load. The
remaining 25% of customers and load are spread over low density rural areas in all three states.

Figure 1: Employment and Population Recovery, February 2020- December 2022

Data source: Employment from the BLS, OR Labor, and WA ESD; population from the U.S. Census.

-16%
-12%
-8%
-4%
0%
4%
8%
12%
Fe
b
-
2
0
Ma
r
-
2
0
Ap
r
-
2
0
Ma
y
-
2
0
Ju
n
-
2
0
Ju
l
-
2
0
Au
g
-
2
0
Se
p
-
2
0
Oc
t
-
2
0
No
v
-
2
0
De
c
-
2
0
Ja
n
-
2
1
Fe
b
-
2
1
Ma
r
-
2
1
Ap
r
-
2
1
Ma
y
-
2
1
Ju
n
-
2
1
Ju
l
-
2
1
Au
g
-
2
1
Se
p
-
2
1
Oc
t
-
2
1
No
v
-
2
1
De
c
-
2
1
Ja
n
-
2
2
Fe
b
-
2
2
Ma
r
-
2
2
Ap
r
-
2
2
Ma
y
-
2
2
Ju
n
-
2
2
Ju
l
-
2
2
Au
g
-
2
2
Se
p
-
2
2
Oc
t
-
2
2
No
v
-
2
2
De
c
-
2
2
Ye
a
r
-ov
e
r
-Ye
a
r
,

S
a
m
e

M
o
n
t
h

S
e
a
s
o
n
a
l
l
y

A
d
j
.
Non-Farm Employment Growth (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
85
90
95
100
105
Fe
b
-
2
0
Ma
r
-
2
0
Ap
r
-
2
0
Ma
y
-
2
0
Ju
n
-
2
0
Ju
l
-
2
0
Au
g
-
2
0
Se
p
-
2
0
Oc
t
-
2
0
No
v
-
2
0
De
c
-
2
0
Ja
n
-
2
1
Fe
b
-
2
1
Ma
r
-
2
1
Ap
r
-
2
1
Ma
y
-
2
1
Ju
n
-
2
1
Ju
l
-
2
1
Au
g
-
2
1
Se
p
-
2
1
Oc
t
-
2
1
No
v
-
2
1
De
c
-
2
1
Ja
n
-
2
2
Fe
b
-
2
2
Ma
r
-
2
2
Ap
r
-
2
2
Ma
y
-
2
2
Ju
n
-
2
2
Ju
l
-
2
2
Au
g
-
2
2
Se
p
-
2
2
Oc
t
-
2
2
No
v
-
2
2
De
c
-
2
2
No
n
-Fa
r
m

E
m
p
l
o
y
m
e
n
t

F
e
b

2
0
2
0
=
1
0
0
Non-Farm Employment Level (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
APPENDIX - CHAPTER 2

Figure 1 shows Avista’s service areas did not escape the employment impacts of COIVD-19 induced
recession at the start of 2020. Historically, service area population growth has slowed in one or more
years following an employment shock; however, this did not occur in the case of the pandemic shock. In-
migration to our service territory, especially in WA and ID, remained strong through the pandemic. This
supported population growth, and therefore customer growth, from 2020 to 2022 (Figure 2). By the end
of 2022, service area employment was 2% higher than the pre-pandemic level of February 2020.

Figure 2: Avista MSA Annual Population Growth, 2005-2022

Figure 3 shows that compared to the 2021 IRP, actual average customer growth in WA-ID over the 2021-
2022 period was considerably higher than forecasted. This reflects (1) a stronger than expected
economic recovery from the pandemic induced recession in 2020 and (2) stronger than expected
population growth over this period. In contrast, OR’s actual growth rate is slightly lower than forecast
over the same period. This reflects lower than expected population growth in OR. Figure 4 shows since
the 2021 IRP, customer growth has significantly exceeded population growth, which reflects customer
growth from existing homes converting to gas in addition to new construction installing gas.

Compared to the 2021 IRP, this IRP shows a system-wide upward revision of approximately 22,000
customers by 2045. This reflects the net impact of a 17,000-customer increase in WA-ID and 5,000
decrease in OR. Overall, the upward revision in all three jurisdiction reflects the stronger than expected
economic recovery from the pandemic induced recession, higher than expected in-migration since the
2021 IRP, and higher expected long-run population growth. Figure 5 and Table 1 show the change in the
customer forecast by for the system and by class between the 2021 and 2023 IRPs.

1.6%1.6%1.6%
1.2%
0.9%
0.8%
0.7%0.6%
0.8%
1.1%
1.3%
1.7%1.8%
1.6%1.5%
1.3%1.3%
1.2%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2.0%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
APPENDIX - CHAPTER 2

Figure 3: Comparison of 2021 IRP Customer Growth Forecasts to Actuals, 2021-2022
Data source: Company data.

0.9%
1.2%
1.1%
1.9%
1.6%
1.7%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2.0%
2021 2022 2021-2022 Average
WA-ID Forecasted vs. Actual Customer Growth Rates
WA-ID 2021 IRP Forecast WA-ID Actual
1.0%
1.1%1.0%
0.7%
0.9%
0.8%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
2021 2022 2021-2022 Average
OR Forecasted vs. Actual Customer Growth Rates
OR 2021 IRP Forecast OR Actual
APPENDIX - CHAPTER 2

Figure 4: Customer and Population Growth, 2005-2022
Data source: Company data.

0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
OR Population Growth vs. Residential Customer Growth
OR Customer Growth OR Population Growth
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
WA-ID Population Growth vs. Residential Customer Growth
WA-ID Customer Growth WA-ID Population Growth
APPENDIX - CHAPTER 2

Table 1: Change in Forecast between the 2021 IRP and 2023 IRP in 2045
Area Residential Commercial Industrial Total Change
WA-ID 16,352 1,053 -11 17,394
OR 5,030 90 2 5,121
System 21,382 1,142 -9 22,516

Figure 5: Comparison IRP Forecasted Customer Growth in WA-ID and OR, 2023-2045
Data source: Company data.

In past IRPs, the modeling approach for the majority of commercial customers assumed that residential
customer growth (WA-ID schedule 101 and OR schedule 410 in Medford and Klamath Falls regions) is a
driver of commercial customer growth (WA-ID schedule 101 and OR schedule 420 in Medford and
Klamath Falls). The use of residential customers as a forecast driver for commercial customers reflects
the historically high correlation between residential and commercial customer growth rates. However,
because of the LEAP program, schedule 101 residential customers are no longer the primary driver in the
commercial forecast in WA. The LEAP program altered the historical relationship between residential and
commercial customers because the program was not offered to commercial customers. As a result,
population has replaced residential customers as the primary driver of commercial customer forecast.
This is also the case for ID, but for different reasons. In ID, the relationship between residential and
commercial customers is changing such that using population directly produces better model diagnostics.

The forecast for system-wide industrial customers is lower compared to the 2021 IRP. Approximately
90% of industrial customers are in WA-ID. Figure 6 (top graph) shows total system-wide firm industrial
customers since 2004. Following a sharp drop over the 2004-2006 period, firm industrial customers
started to decline starting in 2016. It should be noted that some of the decline between 2019 and 2022
reflects a reclassification of some WA-ID customers to firm commercial schedules. This reclassification
reflects customers that were incorrectly placed in firm industrial schedules in years past. Separating out
WA-ID and OR (middle graph), the number of firm customers in WA-ID continuously fell over the 2004-
2011 period; stabilized over the 2012-15; and then started to decline again. In contrast, OR customers
increased over the 2004-2011 period (bottom graph). However, after a period of stability during the 2011-
2014 period, customers declined modestly. Therefore, like the 2021 IRP, the current IRP forecast shows
a declining base.Figure 7: Industrial Customer Count, 2004-2022
300,000
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
480,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
WA-ID-OR-Base 2021 IRP WA-ID-OR-Base 2023 IRP
APPENDIX - CHAPTER 2

Data source: Company data.

II. IRP Forecast Process and Methodology

150
170
190
210
230
250
270
290
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
WA-ID-OR Firm Industrial Customers
150
170
190
210
230
250
270
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
WA-ID Firm Industrial Customers
0
5
10
15
20
25
30
35
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
OR Firm Industrial Customers
APPENDIX - CHAPTER 2

The customer forecasts are generated from forecasting models that are either regression models with
ARIMA error corrections or simple smoothing models. The ARIMA error correction models are estimated
using SAS/ETS software. The customer forecasts are used as input into Plexos® to generate the IRP
load forecasts.

Population growth is the key driver for the residential and commercial customer forecasts. Other variables
include (1) seasonal dummy variables and (2) outlier dummy variables that control for extreme customer
counts associated with double billing, software conversions, and customer movements from one billing
schedule to another.

As noted above, the population growth forecast is the key driver behind the customer forecast for WA-ID
residential schedules 101 and OR residential schedule 410. These two schedules represent the majority
of customers and, therefore, drive overall residential customer growth. Because of their size and growth
potential, a multi-step forecasting process has been developed for the Spokane-Spokane Valley, Coeur
d’Alene, and Medford+Grants Pass MSAs. The process for forecasting population growth starts with a
medium-term forecast horizon (2021-2026). This medium-term forecast is typically used for the annual
financial forecast. However, during IRP years, this medium-term forecast is augmented with third party
forecasts that cover the next twenty years. Starting with Figure 8, the five-year population forecast is a
multi-step process that begins with a GDP forecast that drives the regional employment forecast, which in
turn, drives a five-year population forecast.

Figure 8: Forecasting Population Growth, 2021-2026

The forecasting models for regional employment growth are:

[1] 𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾= 𝜗0 +𝜗1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+𝜗2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+𝜗3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐾𝐶,1998−2000=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 +𝜖𝑡,𝑦

[2] 𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛿0 +𝛿1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+𝛿2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+𝛿3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1+ 𝜔𝑂𝐿𝐷2009=1 + 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 +𝜖𝑡,𝑦

[3] 𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆= 𝜙0 +𝜙1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+𝜙2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+𝜙3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2005=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,0,0)(0,0,0)12

SPK is Spokane, WA (Spokane MSA), KOOT is Kootenai, ID (Coeur d’Alene MSA), and JACK+JOS is for
the combination of Jackson County, OR (Medford MSA) and Josephine County, OR (Grants Pass MSA).
GEMPy is employment growth in year y, GGDPy,US is U.S. real GDP growth in year y. DKC is a dummy
variable for the collapse of Kaiser Aluminum in Spokane, and DHB, is a dummy for the housing bubble,
specific to each region. The average GDP forecasts are used in the estimated model to generate five-
year employment growth forecasts. The employment forecasts are then averaged with IHS’s forecasts for
the same counties so that:

[4] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝐼𝐻𝑆𝐸𝑀𝑃)𝑦,𝑆𝑃𝐾)
2
Average GDP Growth
Forecasts:
•IMF, FOMC,
Bloomberg, etc.
•Average forecasts
out 5-yrs from
2021.
Non-farm Employment
Growth Model:
•Model links year y, y-1,
and y-2 GDP growth to
year y regional
employment growth.
•Forecast out 5-yrs from
2021.
•Averaged with GI
forecasts.

Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year
y county population growth.
•Forecast out 5-yrs from 2020 for
Spokane, WA; Kootenai, ID; and
Jackson+Josephine, OR.
•Averaged with IHS forecasts in ID,
OR, and WA.
•Growth rates used to generate
population forecasts for customer
forecasts for residential schedules 1,
101, and 410.
EMP GDP
APPENDIX - CHAPTER 2

[5] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐼𝐻𝑆𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇)
2

[6] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆 )+𝐹(𝐺𝐼𝐻𝑆𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)
2

Averaging reduces the systematic errors of a single-source forecast. The averages [8.4] through [8.6] are
used to generate the population growth forecasts, which are described next.

The forecasting models for regional population growth are:

[7] 𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾= 𝜅0 +𝜅1𝐺𝐸𝑀𝑃𝑦−1,𝑆𝑃𝐾+𝜅2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷2001=1+𝜖𝑡,𝑦

[8] 𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛼0 +𝛼1𝐺𝐸𝑀𝑃𝑦−1,𝐾𝑂𝑂𝑇+𝛼2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1 + 𝜔𝑂𝐿𝐷2002=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2007↑=1 +𝜖𝑡,𝑦

[9] 𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆= 𝜓0 +𝜓1𝐺𝐸𝑀𝑃𝑦−1,𝐽𝐴𝐶𝐾+𝐽𝑜𝑠+𝜓2𝐺𝐸𝑀𝑃𝑦−2,𝐶𝐴+ 𝜔𝑂𝐿𝐷1991=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2006=1 +𝜖𝑡,𝑦

D2001=1 and D1991=1 are a dummy variables for recession impacts. GEMPy-1,US is U.S. employment growth
in year y-1 and GEMPy-2, and CA is California Employment growth in year y-1. Because of its close
proximity to CA, CA employment growth is better predictor of Jackson, OR employment growth than U.S.
growth. The averages [8.4] through [8.6] are used in [7] through [9] to generate population growth
forecasts. These forecasts are combined with IHS’s forecasts for Kootenai, ID; Jackson, OR; Josephine,
OR, and the Office for Financial Management (OFM) for Spokane, WA in the form of a simple average:

[10] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)= 𝐹(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝐼𝐻𝑆𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)
2

[11] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇)= 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐼𝐻𝑆𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇)
2

[12] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)= 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆 )+𝐹(𝐺𝐼𝐻𝑆𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆)
2

Here, FAvg(GPOPy) is used to forecast population to forecast residential customers in WA-ID 101 and OR
410 schedules for the Spokane, Kootenai, and Jackson+Josephine areas. The population growth
forecasts for the Douglas (Roseburg), Klamath (Klamath Falls); and Union (La Grande) counties come
directly from IHS. Since all forecasted growth rates are annualized, they are converted to monthly rates.
By way of example, the following is regression model for residential 101 customers for the Spokane
region:

𝐶𝑡,𝑦,𝑊𝐴101.𝑟=𝛼0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝑆𝑒𝑝 2018=1↑ +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2016=1
+𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2018=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2018=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2020=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

Where:

tPOPt,y,SPK = t is the coefficient to be estimated and POPt,y,SPK is the interpolated population level in
month t, in year y, for Spokane. The monthly interpolation of historical data assumes that between
years, population accumulates following the standard population growth model: POPy,SPK = POPy-
1,SPKer.

wSDDt,y = wSD is a vector of seasonal dummy (SD) coefficients to be estimated and Dt,y is a vector
monthly seasonal dummies to account of customer seasonality. Dt,y = 1 for the relevant month.

wOLDOct 2015=1 = wOL outlier (OL) coefficient to be estimated and D is a dummy that equals 1 for
October 2015. There are three additional outlier dummies that follow August 2010. In some cases,
the dummy variable may be a structural change (SC) dummy that takes the form, for example,
wSCDSep 2018↑=1; in this case, the dummy takes the value of 1 for September 2018 forward.
APPENDIX - CHAPTER 2

ARIMAet,y(12,1,0)(0,0,0)12 = is the error correction applied to the model’s initial error structure. This
term follows the following from ARIMAet,y (p,d,q)(pk,dk,qk)k. The term p is the autoregressive (AR)
order, d is the differencing order, and q is the moving average (MA) order. The term pk is the order
of seasonal AR terms, dk is the order of seasonal differencing, and qk is the seasonal order of MA
terms. The seasonal values are related to “k,” which is the frequency of the data. With the current
data set, k = 12.

The customer forecast is generated by inputting forecasted values of POPt,y,SPK into the model estimated
with historical data. All customer forecast equations are shown in the last section of this appendix.

The above describes the medium-term population forecast to 2025. For IRPs, the medium-term customer
forecasts must be extended an additional 15+ years. This is done using the IHS population forecast for
Kootenai, Spokane, Jackson+Josephine, Douglas, Klamath, and Union counties. That is, IHS is the sole
source for forecasted population growth beyond the medium-term forecast horizon by [10] through [12].
For firm schedules without explicit regression drivers like population, the forecast model run to cover the
entire forecast period of the IRP.

Figure 9: Annual Customer Growth for the Three Rate Classes, 2005-2022

Data source: Company data.

Figure 9 demonstrates that residential and commercial growth rates are highly correlated over the long-
run. Over the period shown, residential and commercial averaged about 1.6% and 1.0%, respectively.
Residential growth is, on average, higher than population growth because of existing households
converting to natural gas at the same time new construction is installing gas. However, by 2009, with the
Great Recession and increased natural gas saturation, the difference between customer growth and
population growth almost disappears. As the economy improved in the 2015-2019 period, residential and
commercial growth accelerated due to an improved economy and gas conversion incentives in
Washington in the 2016-2019 period.

In contrast, the behavior of Industrial customer growth looks quite different. Customer growth is both
lower and more volatile. The average growth rate since 2005 is -1.9%, reflecting a trend of nearly flat or
slowly declining customers, depending on the jurisdiction. In addition, the standard deviation of year-
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Residential Commercial Industrial
APPENDIX - CHAPTER 2

over-year growth is 3% compared to 0.8% for residential and 0.6% for commercial growth. The current
IRP forecast reflects this historical trend of weak growth.

Establishing High-Low Cases for IRP Customer Forecast

The customer forecasts for this IRP include high and low cases that set the expected bounds around the
base-case. Table 2 shows the base, low, and high customer forecasts along with the underlying
population growth assumption. The underlying population forecast is the primary driver for each of the
three cases.

Table 2: Alternative Growth Cases, 2023-2045
Area Low Growth Base Growth High Growth
WA-ID:
WA-ID Customers 0.8% 1.2% 1.5%
WA Population 0.2% 0.6% 0.8%
ID Population 1.0% 1.7% 2.1%
WA-ID Population 0.9% 0.9% 1.2%

OR:
OR Customers 0.6% 0.9% 1.1%
OR Population 0.2% 0.4% 0.6%

System:
System Customers 0.7% 1.1% 1.4%
System Population 0.3% 0.9% 0.9%

III. IRP Customer Forecast Equations

1. WA residential customer forecast models:

[1] 𝐶𝑡,𝑦,𝑊𝐴101.𝑟=𝛼0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝑆𝑒𝑝 2018=1↑ +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2016=1 +
𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2018=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2018=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2020=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

[1] Model notes:
1. WA schedule 2 customers are schedule 1 customers that have been moved to a new low-income schedule.
2. SC dummy controls for step-up in customers starting September 2018.

[2] 𝐶𝑡,𝑦,𝑊𝐴102.𝑟= 𝐶𝑡−1 +∆̅,𝑤ℎ𝑒𝑟𝑒 ∆̅ = ∑(𝐶𝑡,𝑦−𝐶𝑡−1,𝑦)
𝑁𝑓𝑜𝑟 𝑁 𝑚𝑜𝑛𝑡ℎ𝑠 𝑏𝑒𝑡𝑤𝑒𝑒𝑛 𝑁𝑜𝑣𝑒𝑚𝑏𝑒𝑟 2015−
𝐷𝑒𝑐𝑒𝑚𝑏𝑒𝑟 2021

[2] Model notes:
1. WA schedule 102 customers are schedule 101 customers that have been moved to a new low-income schedule. The schedule
started in October 2015, so there is insufficient data for a more complicated model. In the first years of the program, the number of
customers in this schedule started slowly declining under the original cap of 300 customers. However, this schedule has had its cap
removed and the number of customers has started to increase. In the spring 2022 forecast the average Δ = 5.

[3] 𝐶𝑡,𝑦,𝑊𝐴111.𝑟=𝛼0 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2011↑=1 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2013↑=1 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2018↑=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (8,1,0)(0,0,0)12 𝑓𝑜𝑟 𝑡,𝑦=
𝑆𝑒𝑝𝑡𝑒𝑚𝑏𝑒𝑟 2010 ↑

[3] Model notes:
1. SC dummies control for a step-up in customers starting in October 2011, October 2013, and October 2018.
2. Model restricted to September 2010↑ because of a significant change in trend and behavior starting in 2010.

2. ID residential customer forecast models:
APPENDIX - CHAPTER 2

[4] 𝐶𝑡,𝑦,𝐼𝐷101.𝑟=𝛽0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝐾𝑂𝑂𝑇+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2007↑=1 +𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 +
+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1+𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2011=1 +
𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2011=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2021=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12

[4] Model notes:
1. SC dummies and ramping time trend control for a change in the time-path of customer growth staring in January 2007.
2. The large number of OL dummies controls for a range of factors including changes in billing cycles, billing errors, and software
changes.
3. May need to average June 2020 as an outlier in the next forecast; could be a billing error.

[5] 𝐶𝑡,𝑦,𝐼𝐷111.𝑟=1
12 ∑𝐶𝑡−𝑗12𝑗=1

[5] Model notes:
1. Model changed to a 12-month moving average in fall 2020. There has been no customer growth since 2012.

3. WA commercial customer forecast models:

[6] 𝐶𝑡,𝑦,𝑊𝐴101.𝑐= 𝛼0 + 𝛼1𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+ 𝝎𝑺𝑫𝑫𝒕,𝒚+𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2010 + 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2015 ↑=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2005=1 +
𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2013=1 ++𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2013=1 +𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2017=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2020=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,1,0)(0,0,0)12

[6] Model notes: 1. In the June 2017 forecast, Ct,y,WA101.r (residential customers from residential schedule 101) was replaced with POP for Spokane.
This was done to account for a new hookup tariff for residential gas customers in WA’s LEAP program. This tariff is more generous
than the previous long-standing tariff. In addition, any savings in the hookup process could be passed on to the customer for
equipment purchases or replacement. Since this tariff change excluded commercial and industrial customers, this significantly
accelerated residential hookups but not commercial hookups. As a result, this historical relationship between residential and
commercial customer growth has been altered. See also Tables 5.1 and 5.2.
2. RAMP variable was added in June 2019 because of increasing evidence that the sensitivity of commercial customer growth to
population growth fell after 2009. SC dummies control for step-ups in customers in starting in December 2015 and December 2018.
3. There is no SC dummy for the in-migration of customers from industrial schedule 101 starting in October 2020. The in-migration
was relatively small to the total number of customers in commercial schedule 101. See also notes for UPC model.
4. May need to be adjusted for billing errors in the fall 2022 forecast.

[7] 𝐶𝑡,𝑦,𝑊𝐴111.𝑐= 𝛼0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+𝛾𝑅𝐴𝑀𝑃𝑇𝐴𝑝𝑟 2016 +𝛾𝑅𝐴𝑀𝑃𝑇𝑀𝑎𝑟 2018 +𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1 +
𝜔𝑆𝐶𝐷𝐴𝑝𝑟 2016↑=1 +𝜔𝑆𝐶𝐷𝑀𝑎𝑟 2018↑=1 +𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2013=1 +𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2017=1 +
𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2018=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2019=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2019=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12

[7] Model notes:
1. SC dummies and RAMP variables control for a complex set of steps and slope changes in the customer count.

4. ID commercial customer forecast models:

[8] 𝐶𝑡,𝑦,𝐼𝐷101.𝑐= 𝛽0 + 𝛽1𝑃𝑂𝑃𝑡,𝑦,𝐾𝑜𝑜𝑡+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2005↑=1+𝜔𝑆𝐶𝐷𝑆𝑒𝑝 2006↑=1+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2007↑=1 +𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 +
𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2005=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1 +𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007=1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 +
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (5,1,0)(3,1,0)12

[8] Model notes:
1. In the spring 2020 forecast, Ct,y,ID101.r (residential customers from residential schedule 101) was replaced with POP for Kootenai.
This was done because POP produced a model with slightly improved diagnostic tests. Previously, Ct,y,ID101.r was being used as a
forecast driver because of the historical positive correlation between residential and commercial customer growth. See Tables 5.1
and 5.2.
2. SC dummies control for a step-up in customers in November 2005, September 2006, and November 2007.
3. There is no SC dummy for the in-migration of customers from industrial schedule 101 starting in October 2020. The in-migration
was relatively small to the total number of customers in commercial schedule 101. See also notes for UPC model.

[9] 𝐶𝑡,𝑦,𝐼𝐷111.𝑐= 𝛽0 +𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2012 +𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2008↑=1+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1+𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2012↑=1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2011=1 +
𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12

APPENDIX - CHAPTER 2

[9] Model notes:
1. SC dummies control for a large step-up in customers starting in November 2008 and November 2011.
2. Ramping time trend and SC dummy starting in Jan 2012 control for a slowdown in customer growth.

5. WA industrial customer forecasts models:

[10] 𝐶𝑡,𝑦,𝑊𝐴101.𝑖= 1
6 ∑𝐶𝑡−𝑗6𝑗=1

[10] Model notes:
1. In late 2020 there was a large customer out-migration to schedule 1010 commercial. As with the electric side, this was due to
customers not generating enough load to get the industrial rate. Number of customers dropped from around 70 to 16. Until a
longer time-series is available, a simple averaging model will be used. See also notes for UPC model.

[11] 𝐶𝑡,𝑦,𝑊𝐴111.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[11] Model notes:
1. In January 2019, all three customers in schedule 121 industrial were moved to schedule 111, in addition to Boise Cascade Arden,
WA (under the company name Columbia Cedar) from schedule 146. This change of four customers falls within the normal variation
of customers in schedule 111; therefore, no explicit adjustment is made to the model [7.40] to account for this shift. The customer
count is now changing very slowly over time, so a 12-month moving average was applied starting with the winter 2020 forecast.

6. ID industrial customer forecast models:

[12] 𝐶𝑡,𝑦,𝐼𝐷101.𝑖=1
6 ∑𝐶𝑡−𝑗6𝑗=1

[12] Model notes:
1. In late 2020 there was a large customer out-migration to schedule 1010 commercial. As with the electric side, this was due to
customers not generating enough load to get the industrial rate. Number of customers dropped from around 50 to 30. Until a
longer time-series is available, a simple averaging model will be used. See also notes for UPC model.

[13] 𝐶𝑡,𝑦,𝐼𝐷111.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[13] Model notes:
1. Period of restriction reflects the restriction on the UPC model for this schedule.
2. Customer count stabilized in 2012; customer count fluctuates between 31 and 34 without any clear trend or seasonality.

[14] 𝐶𝑡,𝑦,𝐼𝐷112.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[14] Model notes:
1. Customer count tends to increase in steps following prolonged periods of stability. No clear seasonality present.

7. Medford, OR forecasting models:

The forecasting models for the Medford region (Jackson County) are given below for the residential,
commercial, and industrial sectors:

Residential Sector, Customers:

[15] 𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟= 𝛼0 +𝛼1𝑃𝑂𝑃𝑡,𝑦,𝐽𝐴𝐶𝐾+𝐽𝑂𝑆+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷+ 𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2004↑ =1 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2020↑ =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005 =1 +
𝜔𝑂𝐿𝐷𝑆𝑒𝑝 2020 =1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(1,0,0)12

[15] Model notes:
APPENDIX - CHAPTER 2

1. SC dummy and ramping time trend for January 2008 control for a change in the time-path of customer growth staring in January
2008. SC dummy for 2004↑ controls for a step-up in customers; SC dummy for October 2020↑ and OL dummy for September 2020
control for the impact of the 2020 wildfires which destroyed around 1,000 customers (both residential and commercial) in the
Medford region.
2. POP is Jackson plus Josephine counties.

Commercial Sector, Customers:

[16] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑐= 𝛼0 +𝛼1𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐹𝑒𝑏 2016↑ =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2016 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑦 2020 =1 +
𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2020 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (8,1,0)(0,0,0)12

[16] Model notes:
1. Ct,y,MED410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the
historical positive correlation between residential and commercial customer growth. See Tables 5.1 and 5.2. However, in the
future, POP may become a better driver. Model results with POP are fairly close to model shown above.
2. OL dummies for May and June may reflect short-term impacts of the COVID shock.
3. Because the impact of the wildfires is reflected in Ct,y,MED410, they are controlled for through that variable and not an SC dummy.

[17] 𝐶𝑦,𝑀𝐸𝐷424.𝑐= 𝐶𝑦−1 +(𝛼0̂+𝛼1̂∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦)

[17] Model notes:
1. This model reflects a recommendation by Oregon staff in the 2016 rate case to include employment as an economic driver for
schedule 424 commercial customers. The estimated equation in parenthesis reflects the regression estimated of ∆𝐶𝑦,𝑀𝐸𝐷424.𝑐=
𝛼0 +𝛼1∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦+𝜀𝑡 using annual customer data since 2004. Annual data is used to smooth over the sometimes volatile
changes in the monthly customer number. In addition, customer increases and decreases around the long-run trend tend to occur
in steps. The combination of steps and month-to-month volatility creates significant economic problems when trying to model
around the monthly data. For example, even with intervention variables, tests for error normality always indicated non-normal error
terms with the use of monthly data.
2. ∆𝐶𝑦,𝑀𝐸𝐷424.𝑐 is the change in customers in year y (customer change between year y and y-1) and ∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦 is the change
in total non-farm employment in Jackson+Josephine, Klamath, and Douglas counties in year y-1 (employment change between year
y-1 and y-2). Staff originally suggested lagged total employment for Oregon, but the correlation between schedule 424 customers
and employment for the four-county area is higher. The forecasted employment values for Jackson+Josephine County are derived
from the employment growth forecasts used in the Jackson+Josephine County population forecast. The forecasts for Douglas and
Klamath counties come from IHS. In IRP years, IHS forecasts all counties will be used for the out years.
3. The annual forecast value for each year, F(∙), is assumed to hold for each month of that year. That is: 𝐹(𝐶𝑦,𝑀𝐸𝐷424.𝑐)=
𝐹(𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑐). Given the step-like behavior of the monthly series, this is a reasonable assumption.
4. The forecast and regressions for this schedule can be found in the Excel file folder “OR 4County Sch 424c Cus.”

[18] 𝐶𝑡,𝑦,𝑀𝐸𝐷444.𝑐= 1 𝑖𝑓 (𝑇𝐻𝑀/𝐶𝑡,𝑦)𝑀𝐸𝐷,444.𝑐>0

[18] Model notes:
1. There is typically only one customer served by this schedule. Therefore, the customer forecast is automatically set to one whenever the load
forecast is greater than zero.

Industrial Sector, Customers:

[19] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[19] Model notes:
1. Data starts November 2006. Excluding outliers in November 2006, November 2009, and February 2011, the customer count
fluctuates between 9 and 16 without any clear trend or seasonality. Changes in the customer count occur in steps between
prolonged periods of stability.

[20] 𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑖=1
12∑𝐶𝑡−𝑗12𝑗=1

APPENDIX - CHAPTER 2

[21] Model notes:
1. Data starts January 2009. Excluding a January 2009 outlier, the customer count fluctuates between 1 and 3 without any clear
trend or seasonality. In March 2019, the schedule 447b (biomass plant) moved to schedule 424.

8. Roseburg, OR forecasting models:

The forecasting models for the Roseburg region (Douglas County) are given below for the residential,
commercial, and industrial sectors:

Residential Sector, Customers:

[22] 𝐶𝑡,𝑦,𝑅𝑂𝑆410.𝑟= 𝜑0+𝜑1𝑃𝑂𝑃𝑡,𝑦,𝐷𝑂𝑈𝐺𝐿𝐴𝑆+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2005↑ =1 +𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2005↑ =1 +𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2006↑ =1 +
𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2004 =1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2007 =1 +𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2008 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2018 =1 +
𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2019 =1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2020 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

[22] Model notes:
1. POP is population for Douglas County, OR.
2. SC dummies control for large step-ups in customers in 2005 and 2006.

Commercial Sector, Customers:

[23] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑐= 𝜑0 +𝜑1𝑃𝑂𝑃𝑡,𝑦,𝐷𝑂𝑈𝐺𝐿𝐴𝑆+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2005↑ =1 +𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2005 =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2008 =1 +
𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2019=1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12 𝑓𝑜𝑟 𝑦=2005 ↑

[23] Model notes:
1. Model does not use schedule 410 customers as driver. This reflects the lack of correlation between residential 410 and
commercial 420 customer growth. However, POP was added for the 2018 gas IRP and was significant at the 10% level; however,
by the time of the spring 2022 forecast it had become insignificant but still consistently positive, so it was left in.
2. The lack of correlation noted above could reflect Roseburg’s position between larger cities that offer a range of commercial
activities. Competition from these cities may be inhibiting commercial growth in Roseburg. However, as noted above, it now
appears the linkage to population is also weakening.
3. Model restricted to 2005↑ because the inclusion of the pre-2005 period produced unstable models starting in the spring 2022
forecast.4. SC dummy controls for a significant step-up in customers starting in December 2005.

[24] 𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑐= 𝐶𝑦−1 +(𝜑0̂+𝜑1̂∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦)

[24] Model notes:
1. This model reflects a recommendation by Oregon staff in the 2016 rate case to include employment as an economic driver for
schedule 424 commercial customers. The estimated equation in parenthesis reflects the regression estimated of ∆𝐶𝑦,𝑅𝑂𝑆424.𝑐=
𝛼0 +𝛼1∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦+𝜀𝑡 using annual customer data since 2004. Annual data is used to smooth over the sometimes volatile
changes in the monthly customer number. In addition, customer increases and decreases around the long-run trend tend to occur
in steps. The combination of steps and month-to-month volatility creates significant economic problems when trying to model
around the monthly data. For example, even with intervention variables, tests for error normality always indicated non-normal error
terms with the use of monthly data.
2. ∆𝐶𝑦,𝑅𝑂𝑆424.𝑐 is the change in customers in year y (customer change between year y and y-1) and ∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦 is the change in
total non-farm employment in Jackson+Josephine, Klamath, and Douglas counties in year y-1 (employment change between year y-
1 and y-2). Staff originally suggested lagged total employment for Oregon, but the correlation between schedule 424 customers and
employment for the four-county area is higher. The forecasted employment values for Jackson+Josephine County are derived from
the employment growth forecasts used in the Jackson+Josephine County population forecast. The forecasts for Douglas and
Klamath counties come from IHS. In IRP years, IHS forecasts for all counties will be used for the out years.
3. The annual forecast value for each year, F(∙), is assumed to hold for each month of that year. That is: 𝐹(𝐶𝑦,𝑅𝑂𝑆424.𝑐)=
𝐹(𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑐). Given the step-like behavior of the monthly series, this is a reasonable assumption.
4. The forecast and regressions for this schedule can be found in the Excel file file folder “OR 4County Sch 424c Cus.”

APPENDIX - CHAPTER 2

Industrial Sector, Customers:

[25] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑖= 1
12∑𝐶𝑡−𝑗12𝑗=1

[25] Model notes:
1. Data starts September 2009. Excluding a February 2015 outlier, the customer count fluctuates between 1 and 2 without any clear
trend or seasonality.
2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a
double counting of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers.

9. Klamath Falls, OR forecasting models:

The forecasting models for the Klamath Falls region (Klamath County) are given below for the residential,
commercial, and industrial sectors:

Residential Sector, Customers:

[26] 𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟= 𝛽0 +𝛽1𝑃𝑂𝑃𝑡,𝑦,𝐾𝐿𝐴𝑀𝐴𝑇𝐻+𝝎𝑺𝑫𝑫𝒕,𝒚 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (6,1,0)(0,0,0)12

[26] Model notes:
1. POP is for Klamath County, OR.

Commercial Sector, Customers:

[27] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑐= 𝛽0 +𝛽1𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚+𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(1,0,0)12

[27] Model notes: 1. Ct,y,KLM410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the
historical positive correlation between residential and commercial customer growth. See Tables 5.1 and 5.2. However, in as of the
June 2019 forecast, the coefficient on Ct,y,KLM410.r is positive but no longer statistically significant.

[28] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑐= 𝐶𝑦−1 +(𝛽0̂+𝛽1̂∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦)

[28] Model notes:
1. This model reflects a recommendation by Oregon staff in the 2016 rate case to include employment as an economic driver for
schedule 424 commercial customers. The estimated equation in parenthesis reflects the regression estimated of ∆𝐶𝑦,𝐾𝐿𝑀424.𝑐=
𝛼0 +𝛼1∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦+𝜀𝑡 using annual customer data since 2004. Annual data is used to smooth over the sometimes volatile
changes in the monthly customer number. In addition, customer increases and decreases around the long-run trend tend to occur
in steps. The combination of steps and month-to-month volatility creates significant economic problems when trying to model
around the monthly data. For example, even with intervention variables, tests for error normality always indicated non-normal error
terms with the use of monthly data.
2. ∆𝐶𝑦,𝐾𝐿𝑀424.𝑐 is the change in customers in year y (customer change between year y and y-1) and ∆𝐸𝑀𝑃𝑦−1,4𝐶𝑜𝑢𝑛𝑡𝑦 is the change
in total non-farm employment in Jackson, Josephine, Klamath, and Douglas counties in year y-1 (employment change between year
y-1 and y-2). Staff originally suggested lagged total employment for Oregon, but the correlation between schedule 424 customers
and employment for the four-county area is higher. The forecasted employment values for Jackson+Josephine County are derived
from the employment growth forecasts used in the Jackson+Josephine County population forecast. The forecasts for Douglas and
Klamath counties come from IHS. In IRP years, IHS forecasts for all counties will be used for the out years.
3. The annual forecast value for each year, F(∙), is assumed to hold for each month of that year. That is: 𝐹(𝐶𝑦,𝐾𝐿𝑀424.𝑐)=
𝐹(𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑐). Given the step-like behavior of the monthly series, this is a reasonable assumption.
4. The forecast and regressions for this schedule can be found in the Excel file folder “OR 4County Sch 424c Cus.”

Industrial Sector, Customers:

[29] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

APPENDIX - CHAPTER 2

[29] Model notes:
1. Data starts December 2006. The customer count fluctuates between 4 and 9 without any clear trend or seasonality.

[30] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[30] Model notes:
1. Data starts April 2009. The customer count fluctuates between 1 and 4 without any clear trend or seasonality.

10. La Grande, OR forecasting models:

The forecasting models for the La Grande region (Union County) are given below for the residential,
commercial, and industrial sectors:

Residential Sector, Customers:

[31] 𝐶𝑡,𝑦,𝐿𝑎𝐺410.𝑟= 𝜃0 +𝜃1𝑃𝑂𝑃𝑡,𝑦,𝑈𝑁𝐼𝑂𝑁+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2004=1 +𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2006=1 +𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2009=1 +
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(1,0,0)12

[31] Model notes:
1. POP is population for Union County, OR.

Commercial Sector, Customers:

[32] 𝐶𝑡,𝑦,𝐿𝑎𝐺420.𝑐= 𝜃0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2005 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2008 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2011 =1 +
𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2011 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2019 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (13,1,0)(0,0,0)12

[32] Model notes:
1. Ct,y,LaG410.r, residential customers from residential schedule 410, are no longer used as a forecast driver. The estimated coefficient
on Ct,y,LaG410.r was no longer statistically significant and its sign flips between positive and negative, depending on the form of the
model. POP for union county was also tried as a driver, but had the same issues as Ct,y,LaG410.r.

[33] 𝐶𝑡,𝑦,𝐿𝑎𝐺424.𝑐= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[33] Model notes:
1. Data starts January 2007. The customer count fluctuates between 2 and 4 without any clear trend or seasonality. Changes in
the customer count appear as steps after prolonged periods of stability.

Industrial Sector, Customers:

[34] 𝐶𝑡,𝑦,𝐿𝑎𝐺420.𝑖=1
12∑𝐶𝑡−𝑗12𝑗=1

[34] Model notes:
1. Since these customers appeared approximately, there has been no load activity. As a result, they have never been included in a
forecast prior to fall 2021; it was assumed this schedule was simply a revenue reporting error. However, subsequent research of
billing activity indicates the customers are paying fixed charges. The current forecast assumes no load over the forecast horizon.

[35] 𝐶𝑡,𝑦,𝐿𝑎𝐺444.𝑖 = 1
𝑁∑𝐶𝑡,𝑦−𝑗𝑁𝑗=1 𝑓𝑜𝑟 𝑦−𝑗=2014 ↑
𝑢𝑝 𝑡𝑜 𝑡ℎ𝑒 𝑚𝑜𝑠𝑡 𝑟𝑒𝑐𝑒𝑛𝑡 𝑚𝑜𝑛𝑡ℎ,𝑡ℎ𝑒𝑛 𝑟𝑒𝑝𝑒𝑎𝑡 𝑓𝑜𝑟𝑒𝑐𝑎𝑠𝑡 𝑣𝑎𝑙𝑢𝑒𝑠.

[35] Model notes:
1. Even in the presence of seasonality, customer count can be highly erratic. Regression models produced poor diagnostics and
required many OL dummies. As a result, a historical monthly average is used as the forecast.
2. Restricted to 20124 ↑ because of a significant change in behavior starting in 2014.
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY SCENARIO EXPECTED

EXPECTED 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
WA_Res_Current 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664
WA_Res_New 1,075 3,313 5,534 7,719 9,813 11,886 13,966 16,048 18,130 20,211 22,285 24,351
WA_Com_Current 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241
WA_Com_New 36 108 179 250 321 391 462 532 603 673 743 814
WA_Ind 93 93 93 93 93 93 93 93 93 93 93 93
ID_Res 84,955 86,657 88,289 89,881 91,376 92,844 94,298 95,736 97,187 98,647 100,112 101,591
ID_Com 9,623 9,739 9,845 9,923 9,990 10,059 10,120 10,171 10,223 10,276 10,324 10,370
ID_Ind 68 68 68 68 68 68 68 68 68 68 68 68
Medford_Res_Current 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611
Medford_Res_New 325 1,109 1,933 2,752 3,539 4,315 5,085 5,849 6,604 7,351 8,089 8,818
Medford_Com_Current 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108
Medford_Com_New 28 96 167 238 305 373 438 503 568 633 695 758
Medford_Ind 14 14 14 14 14 14 14 14 14 14 14 14
Roseburg_Res_Current 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252
Roseburg_Res_New 30 104 180 256 330 403 477 551 621 690 758 826
Roseburg_Com_Current 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212
Roseburg_Com_New 2 7 11 16 20 24 29 33 37 41 45 50
Roseburg_Ind 2 2 2 2 2 2 2 2 2 2 2 2
Klamath Falls_Res_Current 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601
Klamath Falls_Res_New 56 186 319 442 550 652 749 841 931 1,023 1,114 1,203
Klamath Falls_Com_Current 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809
Klamath Falls_Com_New 6 18 28 40 51 61 71 82 91 102 112 123
Klamath Falls_Ind 6 6 6 6 6 6 6 6 6 6 6 6
LaGrande_Res_Current 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890
LaGrande_Res_New 14 51 89 128 168 208 249 290 331 371 411 451
LaGrande_Com_Current 943 943 943 943 943 943 943 943 943 943 943 943
LaGrande_Com_New 2 6 11 15 19 24 28 32 37 41 45 50
LaGrande_Ind 4 4 4 4 4 4 4 4 4 4 4 4
EXPECTED 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
WA_Res_Current 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664 161,664
WA_Res_New 26,406 28,455 30,494 32,523 34,542 36,555 38,562 40,555 42,547 44,532 46,514
WA_Com_Current 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241 15,241
WA_Com_New 884 954 1,024 1,094 1,164 1,234 1,304 1,374 1,444 1,514 1,583
WA_Ind 93 93 93 93 93 93 93 93 93 93 93
ID_Res 103,074 104,564 106,060 107,559 109,063 110,564 112,075 113,604 115,155 116,722 118,386
ID_Com 10,415 10,458 10,497 10,534 10,569 10,601 10,630 10,659 10,687 10,715 10,752
ID_Ind 68 68 68 68 68 68 68 68 68 68 68
Medford_Res_Current 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611 57,611
Medford_Res_New 9,538 10,252 10,960 11,658 12,349 13,034 13,713 14,386 15,055 15,719 16,366
Medford_Com_Current 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108 7,108
Medford_Com_New 819 880 940 999 1,058 1,116 1,173 1,230 1,286 1,343 1,396
Medford_Ind 14 14 14 14 14 14 14 14 14 14 14
Roseburg_Res_Current 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252 14,252
Roseburg_Res_New 892 957 1,023 1,089 1,156 1,222 1,287 1,352 1,416 1,480 1,543
Roseburg_Com_Current 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212 2,212
Roseburg_Com_New 54 57 62 65 70 74 77 82 85 90 93
Roseburg_Ind 2 2 2 2 2 2 2 2 2 2 2
Klamath Falls_Res_Current 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601 15,601
Klamath Falls_Res_New 1,290 1,376 1,463 1,551 1,641 1,730 1,816 1,899 1,979 2,057 2,135
Klamath Falls_Com_Current 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809 1,809
Klamath Falls_Com_New 132 142 153 163 172 183 193 203 213 223 233
Klamath Falls_Ind 6 6 6 6 6 6 6 6 6 6 6
LaGrande_Res_Current 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890 6,890
LaGrande_Res_New 491 530 568 607 645 683 721 759 797 835 873
LaGrande_Com_Current 943 943 943 943 943 943 943 943 943 943 943
LaGrande_Com_New 54 58 63 67 72 76 80 85 89 93 98
LaGrande_Ind 4 4 4 4 4 4 4 4 4 4 4
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY SCENARIO HIGH

HIGH 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
WA_Res_Current 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189
WA_Res_New 1,250 3,846 6,435 8,998 11,478 13,947 16,433 18,930 21,438 23,953 26,472 28,991
WA_Com_Current 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291
WA_Com_New 52 157 262 366 470 575 680 785 891 997 1,103 1,210
WA_Ind 97 99 101 103 105 107 109 111 113 115 117 119
ID_Res 85,757 87,878 89,946 91,990 93,951 95,901 97,852 99,802 101,782 103,787 105,815 107,872
ID_Com 9,714 9,876 10,029 10,156 10,271 10,391 10,501 10,603 10,706 10,811 10,912 11,011
ID_Ind 70 71 72 73 74 75 76 77 78 79 80 81
Medford_Res_Current 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718
Medford_Res_New 361 1,216 2,115 3,012 3,877 4,733 5,586 6,434 7,276 8,110 8,938 9,759
Medford_Com_Current 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121
Medford_Com_New 32 109 189 269 346 423 498 574 648 722 796 869
Medford_Ind 15 15 16 16 17 17 18 18 19 19 20 20
Roseburg_Res_Current 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318
Roseburg_Res_New 51 169 290 411 530 650 771 892 1,010 1,127 1,244 1,361
Roseburg_Com_Current 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222
Roseburg_Com_New 6 17 28 39 50 62 73 84 96 107 118 129
Roseburg_Ind 3 3 4 4 5 5 6 6 7 7 8 8
Klamath Falls_Res_Current 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673
Klamath Falls_Res_New 79 258 441 614 773 926 1,075 1,220 1,364 1,510 1,656 1,801
Klamath Falls_Com_Current 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817
Klamath Falls_Com_New 9 26 43 60 76 93 109 125 141 158 174 191
Klamath Falls_Ind 7 7 8 8 9 9 10 10 11 11 12 12
LaGrande_Res_Current 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920
LaGrande_Res_New 24 81 139 198 258 319 381 444 507 570 632 694
LaGrande_Com_Current 947 947 947 947 947 947 947 947 947 947 947 947
LaGrande_Com_New 3 10 17 25 32 39 46 53 61 68 75 83
LaGrande_Ind 5 6 6 7 7 8 8 9 9 10 10 11
HIGH 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
WA_Res_Current 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189 162,189
WA_Res_New 31,510 34,032 36,553 39,074 41,594 44,118 46,644 49,167 51,697 54,230 56,770
WA_Com_Current 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291 15,291
WA_Com_New 1,317 1,424 1,532 1,640 1,748 1,857 1,966 2,075 2,185 2,295 2,405
WA_Ind 121 123 125 127 129 131 133 135 137 139 141
ID_Res 109,952 112,055 114,183 116,330 118,501 120,686 122,898 125,150 127,443 129,774 132,230
ID_Com 11,110 11,207 11,301 11,393 11,484 11,571 11,657 11,742 11,828 11,913 12,010
ID_Ind 82 83 84 85 86 87 88 89 90 91 92
Medford_Res_Current 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718 57,718
Medford_Res_New 10,572 11,382 12,186 12,983 13,774 14,560 15,342 16,120 16,896 17,668 18,424
Medford_Com_Current 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121 7,121
Medford_Com_New 941 1,012 1,083 1,154 1,223 1,293 1,362 1,430 1,498 1,566 1,632
Medford_Ind 21 21 22 22 23 23 24 24 25 25 26
Roseburg_Res_Current 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318 14,318
Roseburg_Res_New 1,477 1,593 1,710 1,828 1,946 2,065 2,184 2,303 2,421 2,539 2,658
Roseburg_Com_Current 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222 2,222
Roseburg_Com_New 141 152 163 174 186 198 209 221 232 244 255
Roseburg_Ind 9 9 10 10 11 11 12 12 13 13 14
Klamath Falls_Res_Current 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673 15,673
Klamath Falls_Res_New 1,945 2,088 2,231 2,378 2,528 2,676 2,823 2,967 3,108 3,249 3,389
Klamath Falls_Com_Current 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817 1,817
Klamath Falls_Com_New 208 224 241 258 275 292 309 326 343 360 377
Klamath Falls_Ind 13 13 14 14 15 15 16 16 17 17 18
LaGrande_Res_Current 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920 6,920
LaGrande_Res_New 757 819 881 943 1,006 1,068 1,131 1,194 1,257 1,320 1,383
LaGrande_Com_Current 947 947 947 947 947 947 947 947 947 947 947
LaGrande_Com_New 90 97 105 112 120 128 135 143 151 158 166
LaGrande_Ind 11 12 12 13 13 14 14 15 15 16 16
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY SCENARIO ELECTRIFICATION

ELECTRIFICATION 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
WA_Res_Current 162,739 164,977 161,677 158,444 155,275 152,169 149,126 146,144 143,221 140,356 137,549 134,798
WA_Res_New - - - - - - - - - - - -
WA_Com_Current 15,241 15,241 14,936 14,638 14,345 14,058 13,777 13,501 13,231 12,967 12,707 12,453
WA_Com_New - - - - - - - - - - - -
WA_Ind 93 93 91 89 88 86 84 83 81 79 78 76
ID_Res 84,955 86,657 88,289 89,881 91,376 92,844 94,298 95,736 97,187 98,647 100,112 101,591
ID_Com 9,623 9,739 9,845 9,923 9,990 10,059 10,120 10,171 10,223 10,276 10,324 10,370
ID_Ind 68 68 68 68 68 68 68 68 68 68 68 68
Medford_Res_Current 57,937 58,720 57,546 56,395 55,267 54,161 53,078 52,017 50,976 49,957 48,958 47,978
Medford_Res_New - - - - - - - - - - - -
Medford_Com_Current 7,136 7,204 7,060 6,918 6,780 6,645 6,512 6,382 6,254 6,129 6,006 5,886
Medford_Com_New - - - - - - - - - - - -
Medford_Ind 14 14 14 13 13 13 13 12 12 12 12 11
Roseburg_Res_Current 14,282 14,355 14,068 13,787 13,511 13,241 12,976 12,717 12,462 12,213 11,969 11,729
Roseburg_Res_New - - - - - - - - - - - -
Roseburg_Com_Current 2,213 2,218 2,174 2,131 2,088 2,046 2,005 1,965 1,926 1,887 1,850 1,813
Roseburg_Com_New - - - - - - - - - - - -
Roseburg_Ind 2 2 2 2 2 2 2 2 2 2 2 2
Klamath Falls_Res_Current 15,656 15,787 15,471 15,161 14,858 14,561 14,270 13,985 13,705 13,431 13,162 12,899
Klamath Falls_Res_New - - - - - - - - - - - -
Klamath Falls_Com_Current 1,815 1,826 1,789 1,754 1,719 1,684 1,650 1,617 1,585 1,553 1,522 1,492
Klamath Falls_Com_New - - - - - - - - - - - -
Klamath Falls_Ind 6 6 6 6 6 6 5 5 5 5 5 5
LaGrande_Res_Current 6,904 6,941 6,802 6,666 6,533 6,402 6,274 6,149 6,026 5,905 5,787 5,671
LaGrande_Res_New - - - - - - - - - - - -
LaGrande_Com_Current 945 949 930 912 893 875 858 841 824 807 791 775
LaGrande_Com_New - - - - - - - - - - - -
LaGrande_Ind 4 4 4 4 4 4 4 4 3 3 3 3
ELECTRIFICATION 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
WA_Res_Current 132,102 129,460 126,871 124,334 121,847 119,410 117,022 114,681 112,388 110,140 107,937
WA_Res_New - - - - - - - - - - -
WA_Com_Current 12,204 11,960 11,721 11,486 11,257 11,032 10,811 10,595 10,383 10,175 9,972
WA_Com_New - - - - - - - - - - -
WA_Ind 75 73 72 70 69 67 66 65 63 62 61
ID_Res 103,074 104,564 106,060 107,559 109,063 110,564 112,075 113,604 115,155 116,722 118,386
ID_Com 10,415 10,458 10,497 10,534 10,569 10,601 10,630 10,659 10,687 10,715 10,752
ID_Ind 68 68 68 68 68 68 68 68 68 68 68
Medford_Res_Current 47,019 46,079 45,157 44,254 43,369 42,501 41,651 40,818 40,002 39,202 38,418
Medford_Res_New - - - - - - - - - - -
Medford_Com_Current 5,768 5,653 5,540 5,429 5,320 5,214 5,110 5,007 4,908 4,809 4,713
Medford_Com_New - - - - - - - - - - -
Medford_Ind 11 11 11 11 10 10 10 10 10 9 9
Roseburg_Res_Current 11,495 11,265 11,040 10,819 10,603 10,390 10,183 9,979 9,779 9,584 9,392
Roseburg_Res_New - - - - - - - - - - -
Roseburg_Com_Current 1,776 1,741 1,706 1,672 1,638 1,606 1,574 1,542 1,511 1,481 1,451
Roseburg_Com_New - - - - - - - - - - -
Roseburg_Ind 2 2 2 2 1 1 1 1 1 1 1
Klamath Falls_Res_Current 12,641 12,388 12,140 11,898 11,660 11,426 11,198 10,974 10,754 10,539 10,328
Klamath Falls_Res_New - - - - - - - - - - -
Klamath Falls_Com_Current 1,462 1,433 1,404 1,376 1,348 1,321 1,295 1,269 1,244 1,219 1,195
Klamath Falls_Com_New - - - - - - - - - - -
Klamath Falls_Ind 5 5 5 5 4 4 4 4 4 4 4
LaGrande_Res_Current 5,558 5,447 5,338 5,231 5,126 5,024 4,923 4,825 4,728 4,634 4,541
LaGrande_Res_New - - - - - - - - - - -
LaGrande_Com_Current 760 745 730 715 701 687 673 660 647 634 621
LaGrande_Com_New - - - - - - - - - - -
LaGrande_Ind 3 3 3 3 3 3 3 3 3 3 3
APPENDIX - CHAPTER 2

APPENDIX 2.2: CUSTOMER FORECASTS BY SCENARIO HYBRID

HYBRID 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
WA_Res_Current 162,739 164,977 161,677 158,444 155,275 152,169 149,126 146,144 143,221 140,356 137,549 134,798
WA_Res_New - - 5,521 10,939 16,202 21,381 26,504 31,568 36,574 41,519 46,400 51,217
WA_Com_Current 15,241 15,241 14,936 14,638 14,345 14,058 13,777 13,501 13,231 12,967 12,707 12,453
WA_Com_New 36 108 484 854 1,217 1,575 1,926 2,272 2,613 2,947 3,277 3,602
WA_Ind 93 93 91 89 88 86 84 83 81 79 78 76
ID_Res 84,955 86,657 88,289 89,881 91,376 92,844 94,298 95,736 97,187 98,647 100,112 101,591
ID_Com 9,623 9,739 9,845 9,923 9,990 10,059 10,120 10,171 10,223 10,276 10,324 10,370
ID_Ind 68 68 68 68 68 68 68 68 68 68 68 68
Medford_Res_Current 57,937 58,720 57,546 56,395 55,267 54,161 53,078 52,017 50,976 49,957 48,958 47,978
Medford_Res_New - - 1,998 3,969 5,883 7,765 9,618 11,443 13,239 15,005 16,742 18,451
Medford_Com_Current 7,136 7,204 7,060 6,918 6,780 6,645 6,512 6,382 6,254 6,129 6,006 5,886
Medford_Com_New - - 215 428 633 836 1,035 1,230 1,423 1,612 1,797 1,981
Medford_Ind 14 14 14 13 13 13 13 12 12 12 12 11
Roseburg_Res_Current 14,282 14,355 14,068 13,787 13,511 13,241 12,976 12,717 12,462 12,213 11,969 11,729
Roseburg_Res_New - - 364 721 1,071 1,414 1,753 2,086 2,411 2,729 3,041 3,348
Roseburg_Com_Current 2,213 2,218 2,174 2,131 2,088 2,046 2,005 1,965 1,926 1,887 1,850 1,813
Roseburg_Com_New - - 49 97 144 189 235 280 323 366 407 449
Roseburg_Ind 2 2 2 2 2 2 2 2 2 2 2 2
Klamath Falls_Res_Current 15,656 15,787 15,471 15,161 14,858 14,561 14,270 13,985 13,705 13,431 13,162 12,899
Klamath Falls_Res_New - - 449 881 1,293 1,691 2,079 2,457 2,827 3,192 3,552 3,905
Klamath Falls_Com_Current 1,815 1,826 1,789 1,754 1,719 1,684 1,650 1,617 1,585 1,553 1,522 1,492
Klamath Falls_Com_New - - 48 95 141 185 229 273 315 357 398 439
Klamath Falls_Ind 6 6 6 6 6 6 5 5 5 5 5 5
LaGrande_Res_Current 6,904 6,941 6,802 6,666 6,533 6,402 6,274 6,149 6,026 5,905 5,787 5,671
LaGrande_Res_New - - 177 352 525 696 865 1,031 1,195 1,356 1,514 1,670
LaGrande_Com_Current 945 949 930 912 893 875 858 841 824 807 791 775
LaGrande_Com_New - - 24 46 69 91 113 134 156 176 197 217
LaGrande_Ind 4 4 4 4 4 4 4 4 3 3 3 3
HYBRID 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
WA_Res_Current 132,102 129,460 126,871 124,334 121,847 119,410 117,022 114,681 112,388 110,140 107,937
WA_Res_New 55,968 60,659 65,287 69,853 74,359 78,809 83,204 87,538 91,823 96,056 100,241
WA_Com_Current 12,204 11,960 11,721 11,486 11,257 11,032 10,811 10,595 10,383 10,175 9,972
WA_Com_New 3,921 4,235 4,545 4,849 5,149 5,444 5,734 6,020 6,302 6,580 6,853
WA_Ind 75 73 72 70 69 67 66 65 63 62 61
ID_Res 103,074 104,564 106,060 107,559 109,063 110,564 112,075 113,604 115,155 116,722 118,386
ID_Com 10,415 10,458 10,497 10,534 10,569 10,601 10,630 10,659 10,687 10,715 10,752
ID_Ind 68 68 68 68 68 68 68 68 68 68 68
Medford_Res_Current 47,019 46,079 45,157 44,254 43,369 42,501 41,651 40,818 40,002 39,202 38,418
Medford_Res_New 20,131 21,785 23,414 25,016 26,592 28,144 29,673 31,179 32,664 34,128 35,559
Medford_Com_Current 5,768 5,653 5,540 5,429 5,320 5,214 5,110 5,007 4,908 4,809 4,713
Medford_Com_New 2,159 2,335 2,508 2,678 2,846 3,010 3,172 3,330 3,487 3,642 3,791
Medford_Ind 11 11 11 11 10 10 10 10 10 9 9
Roseburg_Res_Current 11,495 11,265 11,040 10,819 10,603 10,390 10,183 9,979 9,779 9,584 9,392
Roseburg_Res_New 3,649 3,944 4,235 4,522 4,805 5,083 5,356 5,625 5,888 6,148 6,403
Roseburg_Com_Current 1,776 1,741 1,706 1,672 1,638 1,606 1,574 1,542 1,511 1,481 1,451
Roseburg_Com_New 489 528 567 605 643 680 715 751 785 820 853
Roseburg_Ind 2 2 2 2 1 1 1 1 1 1 1
Klamath Falls_Res_Current 12,641 12,388 12,140 11,898 11,660 11,426 11,198 10,974 10,754 10,539 10,328
Klamath Falls_Res_New 4,250 4,589 4,923 5,254 5,582 5,904 6,218 6,526 6,825 7,119 7,408
Klamath Falls_Com_Current 1,462 1,433 1,404 1,376 1,348 1,321 1,295 1,269 1,244 1,219 1,195
Klamath Falls_Com_New 478 518 557 596 633 670 707 743 778 813 847
Klamath Falls_Ind 5 5 5 5 4 4 4 4 4 4 4
LaGrande_Res_Current 5,558 5,447 5,338 5,231 5,126 5,024 4,923 4,825 4,728 4,634 4,541
LaGrande_Res_New 1,823 1,973 2,121 2,266 2,409 2,550 2,688 2,824 2,959 3,091 3,221
LaGrande_Com_Current 760 745 730 715 701 687 673 660 647 634 621
LaGrande_Com_New 237 256 276 294 313 332 349 367 385 402 419
LaGrande_Ind 3 3 3 3 3 3 3 3 3 3 3
APPENDIX - CHAPTER 2

APPENDIX 2.3: HEAT DEMAND COEFFICIENTS

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Klamath Falls_Com 0.0314 0.0302 0.0271 0.0181 0.0140 0.0088 0.0047 0.0045 0.0112 0.0235 0.0279 0.0305
Klamath Falls_Ind 0.0904 0.0986 0.0585 0.0133 0.0296 0.0450 0.0852 0.2446 0.2895 0.4587 0.3168 0.2842
Klamath Falls_Res 0.0086 0.0083 0.0075 0.0056 0.0048 0.0032 0.0013 0.0002 0.0017 0.0051 0.0076 0.0083
LaGrande_Com 0.0408 0.0398 0.0329 0.0237 0.0170 0.0061 0.0003 0.0163 0.0017 0.0223 0.0324 0.0382
LaGrande_Ind - - - - - - 4.5258 2.2558 1.6580 2.5837 0.0003 -
LaGrande_Res 0.0091 0.0089 0.0074 0.0059 0.0049 0.0030 0.0010 0.0030 0.0002 0.0049 0.0082 0.0089
Medford_Com 0.0473 0.0455 0.0372 0.0276 0.0207 0.0202 0.0258 0.0904 0.0227 0.0420 0.0422 0.0435
Medford_Ind 0.0375 0.0546 0.0231 0.0198 0.0505 0.1270 0.1993 1.3995 0.2539 0.3423 0.1410 0.0544
Medford_Res 0.0118 0.0112 0.0097 0.0083 0.0062 0.0053 0.0090 0.0108 0.0039 0.0083 0.0100 0.0112
Roseburg_Com 0.0613 0.0487 0.0371 0.0353 0.0237 0.0169 0.0006 0.0790 0.0286 0.0342 0.0386 0.0405
Roseburg_Ind 0.0355 0.0411 0.0026 0.0723 0.1453 0.2113 0.1925 0.7885 0.2225 0.1446 0.0274 0.0029
Roseburg_Res 0.0139 0.0115 0.0095 0.0085 0.0062 0.0049 0.0015 0.0104 0.0065 0.0093 0.0109 0.0108
ID_Com 0.0420 0.0437 0.0381 0.0256 0.0185 0.0206 0.0038 0.0148 0.0232 0.0308 0.0341 0.0411
ID_Ind 0.2266 0.2060 0.2007 0.2185 0.3854 0.2479 0.1907 0.0506 0.1722 0.2098 0.2401 0.2024
ID_Res 0.0106 0.0105 0.0089 0.0079 0.0056 0.0032 0.0026 0.0009 0.0032 0.0079 0.0097 0.0099
WA_Com 0.0594 0.0595 0.0519 0.0357 0.0257 0.0149 0.0045 0.0083 0.0210 0.0444 0.0486 0.0551
WA_Ind 0.1669 0.1865 0.1875 0.1898 0.1515 0.2054 0.0242 0.2696 0.2536 0.2258 0.1862 0.1750
WA_Res 0.0103 0.0104 0.0083 0.0072 0.0045 0.0034 0.0014 0.0014 0.0031 0.0072 0.0093 0.0097
Klamath Falls_Com 0.0323 0.0312 0.0282 0.0200 0.0146 0.0077 0.0050 0.0040 0.0150 0.0242 0.0278 0.0308
Klamath Falls_Ind 0.0920 0.1060 0.0627 0.0214 0.0420 0.0314 0.0606 0.1882 0.3807 0.4084 0.3605 0.2396
Klamath Falls_Res 0.0087 0.0084 0.0077 0.0060 0.0049 0.0030 0.0012 0.0002 0.0023 0.0055 0.0075 0.0084
LaGrande_Com 0.0420 0.0409 0.0347 0.0265 0.0171 0.0055 0.0013 0.0201 0.0049 0.0244 0.0323 0.0386
LaGrande_Ind - - - - 1.9182 2.0468 4.6388 1.7754 1.9218 2.5342 0.1874 -
LaGrande_Res 0.0092 0.0090 0.0076 0.0063 0.0049 0.0025 0.0009 0.0033 0.0005 0.0054 0.0079 0.0089
Medford_Com 0.0450 0.0447 0.0367 0.0274 0.0205 0.0158 0.0172 0.0603 0.0235 0.0400 0.0417 0.0423
Medford_Ind 0.0263 0.0513 0.0224 0.0185 0.0479 0.0861 0.1329 0.9330 0.2694 0.2727 0.1164 0.0445
Medford_Res 0.0114 0.0110 0.0096 0.0080 0.0058 0.0041 0.0060 0.0072 0.0036 0.0082 0.0099 0.0108
Roseburg_Com 0.0556 0.0564 0.0389 0.0392 0.0193 0.0197 0.0009 0.0771 0.0311 0.0349 0.0415 0.0434
Roseburg_Ind 0.0397 0.0456 0.0017 0.0483 0.1199 0.2149 0.1283 0.5257 0.1917 0.1094 0.0252 0.0023
Roseburg_Res 0.0129 0.0132 0.0096 0.0091 0.0053 0.0044 0.0010 0.0090 0.0063 0.0095 0.0112 0.0114
ID_Com 0.0418 0.0432 0.0389 0.0266 0.0181 0.0182 0.0096 0.0127 0.0256 0.0310 0.0354 0.0402
ID_Ind 0.2061 0.1907 0.2128 0.2193 0.2912 0.2234 0.1932 0.0905 0.1851 0.1939 0.2355 0.2065
ID_Res 0.0104 0.0103 0.0090 0.0078 0.0055 0.0032 0.0022 0.0007 0.0037 0.0082 0.0097 0.0099
WA_Com 0.0581 0.0595 0.0512 0.0382 0.0248 0.0172 0.0095 0.0098 0.0280 0.0443 0.0515 0.0560
WA_Ind 0.1527 0.1756 0.1848 0.1668 0.1386 0.1656 0.0162 0.1805 0.2713 0.1832 0.1700 0.1633
WA_Res 0.0101 0.0102 0.0086 0.0071 0.0046 0.0029 0.0014 0.0011 0.0037 0.0076 0.0094 0.0096
Klamath Falls_Com 0.0311 0.0307 0.0276 0.0207 0.0129 0.0089 0.0037 0.0028 0.0153 0.0223 0.0273 0.0313
Klamath Falls_Ind 0.0721 0.0955 0.0549 0.0445 0.0267 0.0459 0.0364 0.1169 0.3357 0.3034 0.2657 0.1936
Klamath Falls_Res 0.0084 0.0082 0.0076 0.0061 0.0045 0.0030 0.0008 0.0001 0.0021 0.0053 0.0075 0.0084
LaGrande_Com 0.0431 0.0418 0.0360 0.0283 0.0133 0.0071 0.0008 0.0538 0.0046 0.0228 0.0326 0.0393
LaGrande_Ind 0.0033 - - - 1.1509 1.2281 11.1715 4.6440 2.6618 2.3656 0.1126 -
LaGrande_Res 0.0093 0.0090 0.0078 0.0066 0.0053 0.0027 0.0005 0.0086 0.0004 0.0051 0.0080 0.0090
Medford_Com 0.0430 0.0426 0.0359 0.0273 0.0184 0.0149 0.0103 0.0362 0.0210 0.0350 0.0392 0.0410
Medford_Ind 0.0214 0.0428 0.0229 0.0244 0.0327 0.0799 0.0797 0.5598 0.2331 0.2198 0.1062 0.0396
Medford_Res 0.0111 0.0107 0.0097 0.0079 0.0057 0.0037 0.0036 0.0043 0.0031 0.0074 0.0095 0.0106
Roseburg_Com 0.0495 0.0495 0.0369 0.0335 0.0157 0.0132 0.0005 0.0463 0.0202 0.0281 0.0374 0.0424
Roseburg_Ind 0.0239 0.0275 0.0040 0.0524 0.0799 0.1379 0.0770 0.3154 0.1166 0.0797 0.0355 0.0134
Roseburg_Res 0.0117 0.0116 0.0091 0.0080 0.0042 0.0029 0.0006 0.0054 0.0041 0.0080 0.0103 0.0110
ID_Com 0.0419 0.0423 0.0382 0.0281 0.0187 0.0194 0.0087 0.0223 0.0225 0.0283 0.0352 0.0403
ID_Ind 0.1933 0.2113 0.1848 0.1842 0.2640 0.2046 0.1772 0.1154 0.2189 0.1558 0.2098 0.1859
ID_Res 0.0102 0.0100 0.0091 0.0080 0.0052 0.0028 0.0018 0.0005 0.0037 0.0080 0.0096 0.0099
WA_Com 0.0566 0.0578 0.0501 0.0396 0.0254 0.0185 0.0085 0.0163 0.0272 0.0406 0.0503 0.0544
WA_Ind 0.1485 0.1649 0.1698 0.1573 0.1416 0.1530 0.0266 0.1193 0.2650 0.1362 0.1478 0.1410
WA_Res 0.0101 0.0099 0.0088 0.0075 0.0046 0.0028 0.0013 0.0016 0.0037 0.0075 0.0093 0.0097
2-Year
3-Year
5-Year
APPENDIX - CHAPTER 2

APPENDIX 2.3: RESIDENTIAL BASE COEFFICIENT CALCULATION

APPENDIX 2.3: COMMERCIAL BASE COEFFICIENT CALCULATION

Idaho Klamath
Falls
La
Grande Medford Roseburg Washington
2017 3,140 458 439 2,596 486 6,574
2018 3,506 495 478 2,603 474 7,074
2019 3,568 562 457 2,647 667 7,133
2020 4,122 599 456 3,463 977 7,514
2021 3,653 533 348 3,199 890 6,745
2017 72,686 14,397 6,565 53,920 13,337 145,535
2018 74,722 14,619 6,660 54,837 13,518 149,924
2019 76,651 14,823 6,695 55,737 13,685 153,598
2020 78,641 15,207 6,778 56,659 13,973 155,954
2021 80,962 15,400 6,837 56,521 14,106 158,518
2 Year 0.0487 0.0370 0.0591 0.0589 0.0665 0.0453
3 Year 0.0480 0.0373 0.0621 0.0551 0.0606 0.0457
5 Year 0.0469 0.0355 0.0650 0.0523 0.0509 0.0459
Residential Base Coefficients
Average Residential Demand (July & August)
Average Residential Customers (July & August)
Idaho Klamath
Falls
La
Grande Medford Roseburg Washington
2017 3,464 361 338 2,487 628 5,380
2018 3,328 401 367 2,481 597 5,605
2019 3,663 448 359 2,633 817 5,979
2020 3,198 417 269 2,929 988 5,020
2021 3,311 420 266 3,110 1,080 5,339
2017 8,881 1,762 914 6,850 2,141 14,551
2018 8,958 1,753 916 6,906 2,146 14,721
2019 9,092 1,770 923 6,987 2,150 14,863
2020 9,215 1,781 938 7,051 2,187 14,945
2021 9,365 1,791 932 6,952 2,188 15,120
2 Year 0.3503 0.2345 0.2864 0.4313 0.4728 0.3446
3 Year 0.3676 0.2408 0.3202 0.4132 0.4423 0.3637
5 Year 0.3727 0.2312 0.3459 0.3926 0.3802 0.3682
Commercial Base Coefficients
Average Commercial Demand (July & August)
Average Commercial Customers (July & August)
APPENDIX - CHAPTER 2

APPENDIX 2.3: INDUSTRIAL BASE COEFFICIENT CALCULATION

Idaho Klamath
Falls
La
Grande Medford Roseburg Washington
2017 495 26 202 68 5 427
2018 520 28 86 49 3 421
2019 520 27 159 58 5 410
2020 424 25 126 65 11 424
2021 365 31 147 66 11 445
2017 93 7 3 15 2 133
2018 92 7 3 14 1 130
2019 91 6 4 14 2 129
2020 87 6 3 14 2 128
2021 69 6 4 14 2 96
2 Year 5.0548 4.6530 39.0120 4.7388 5.6583 3.8875
3 Year 5.3096 4.6222 41.1053 4.5284 4.6714 3.6325
5 Year 5.3835 4.2819 46.4154 4.3175 4.0766 3.4596
Industrial Base Coefficients
Average Industrial Demand (July & August)
Average Industrial Customers (July & August)
APPENDIX - CHAPTER 2

APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES

WA/ID Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
2023 1,093 1,030 829 546 292 133 16 23 164 532 870 1,145 6,672
2024 1,097 1,094 794 541 287 133 16 23 162 535 856 1,141 6,681
2025 1,090 1,020 831 543 284 132 15 22 159 536 854 1,140 6,626
2026 1,088 1,019 831 542 283 127 15 20 152 536 851 1,132 6,596
2027 1,097 1,010 824 538 282 128 14 19 149 532 848 1,125 6,566
2028 1,099 1,072 792 534 283 124 14 17 144 528 841 1,122 6,571
2029 1,091 1,007 818 524 282 119 14 14 144 527 842 1,106 6,488
2030 1,087 1,001 809 517 279 117 13 13 144 517 841 1,097 6,436
2031 1,092 1,002 808 514 270 109 11 11 139 517 835 1,094 6,402
2032 1,089 1,056 770 502 263 102 9 11 141 514 828 1,090 6,375
2033 1,090 990 799 500 259 98 8 10 142 512 827 1,089 6,323
2034 1,077 983 799 498 260 92 8 10 137 507 824 1,078 6,274
2035 1,080 973 799 494 261 89 8 9 139 512 819 1,077 6,260
2036 1,077 1,038 771 490 267 94 8 9 132 517 817 1,078 6,296
2037 1,079 981 806 502 270 92 6 9 128 513 822 1,064 6,270
2038 1,065 970 803 497 269 91 7 8 122 508 819 1,056 6,215
2039 1,073 961 797 492 276 88 6 7 117 504 814 1,053 6,189
2040 1,074 1,004 749 487 278 86 5 6 110 490 811 1,056 6,158
2041 1,079 942 781 486 275 83 3 5 111 487 808 1,057 6,115
2042 1,082 929 780 484 272 80 3 3 107 484 809 1,050 6,084
2043 1,076 924 777 486 269 76 3 3 107 482 810 1,039 6,052
2044 1,079 983 743 486 267 75 2 3 103 479 811 1,038 6,071
2045 1,083 926 777 485 267 71 2 2 102 477 809 1,038 6,040
Medford Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
2023 771 607 529 368 180 59 8 9 60 294 602 903 4,389
2024 778 624 530 364 185 69 14 16 71 302 596 906 4,456
2025 779 602 539 371 192 79 21 24 80 308 593 905 4,491
2026 777 604 543 374 199 84 28 30 89 314 591 907 4,539
2027 778 601 538 375 209 94 35 38 97 318 591 906 4,580
2028 771 617 542 378 218 103 42 45 104 320 588 904 4,631
2029 767 596 536 377 225 110 50 51 116 325 589 897 4,639
2030 764 595 535 377 234 119 57 57 126 327 584 891 4,666
2031 773 597 535 375 235 124 63 63 134 334 583 894 4,709
2032 771 613 533 371 235 131 70 70 146 339 581 887 4,746
2033 769 591 530 375 242 136 78 77 158 346 582 887 4,771
2034 762 584 534 381 253 144 84 83 165 347 582 871 4,789
2035 761 586 540 388 263 153 90 89 175 358 585 875 4,864
2036 761 611 548 392 274 162 96 96 184 369 583 880 4,956
2037 766 595 552 404 285 170 102 102 193 372 588 874 5,003
2038 760 594 554 406 294 177 108 109 200 376 586 873 5,037
2039 764 587 552 407 305 185 113 115 208 381 586 869 5,073
2040 767 597 551 413 314 193 120 121 214 380 588 868 5,126
2041 770 576 548 420 321 200 126 127 224 389 584 870 5,155
2042 771 571 548 426 330 207 132 134 233 392 584 868 5,194
2043 766 568 545 426 327 206 130 132 233 390 584 861 5,170
2044 767 588 547 426 326 205 130 131 232 390 586 863 5,190
2045 768 572 546 427 326 202 129 130 230 388 583 862 5,163
APPENDIX - CHAPTER 2

La Grande Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
2023 1,007 923 776 551 334 152 28 43 200 512 785 1,045 6,358
2024 1,013 977 745 549 335 161 36 53 208 517 777 1,045 6,415
2025 1,008 910 784 551 335 168 45 60 211 518 776 1,046 6,411
2026 1,009 908 786 553 339 170 53 67 215 519 774 1,039 6,433
2027 1,014 900 782 551 343 178 62 74 219 515 774 1,033 6,446
2028 1,006 960 753 552 349 184 71 81 223 517 770 1,030 6,495
2029 999 905 780 545 352 186 79 88 229 517 774 1,020 6,474
2030 995 904 774 541 354 192 85 94 238 511 772 1,013 6,475
2031 1,001 903 772 539 350 194 91 100 242 512 768 1,011 6,482
2032 996 956 736 531 346 194 98 107 253 510 760 1,004 6,491
2033 998 896 768 534 347 197 106 115 260 508 762 1,002 6,493
2034 986 892 770 533 351 201 113 123 266 501 761 990 6,486
2035 985 889 772 531 354 205 120 129 275 509 754 992 6,515
2036 983 950 746 530 360 215 127 136 278 515 749 991 6,581
2037 985 897 779 539 366 220 133 143 282 515 756 973 6,590
2038 968 894 782 538 369 226 141 151 285 510 754 964 6,581
2039 976 887 777 537 378 230 147 155 285 506 746 958 6,582
2040 978 932 734 534 382 234 153 162 288 492 741 958 6,587
2041 981 874 763 533 383 237 159 168 295 490 736 957 6,574
2042 981 862 757 531 383 244 165 171 299 489 735 952 6,570
2043 976 858 756 531 381 242 165 169 298 488 736 942 6,540
2044 981 913 725 531 380 241 164 167 296 487 737 943 6,564
2045 982 860 755 532 380 238 162 166 295 485 735 942 6,532
APPENDIX - CHAPTER 2

Roseburg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
2023 679 563 506 371 202 81 12 11 67 290 538 822 4,143
2024 691 582 511 370 208 90 18 18 78 298 536 827 4,225
2025 698 561 519 375 214 97 25 26 86 304 537 832 4,273
2026 701 563 525 378 219 102 32 32 94 311 538 837 4,331
2027 708 561 521 379 226 111 38 39 103 314 540 840 4,381
2028 704 581 526 381 232 117 45 46 109 317 537 844 4,439
2029 703 562 523 379 237 121 52 52 119 322 543 842 4,454
2030 703 562 521 378 245 129 59 58 128 325 544 840 4,493
2031 715 568 521 376 247 133 65 64 136 330 548 847 4,551
2032 721 585 522 373 246 138 72 71 147 334 548 845 4,600
2033 726 564 520 376 251 142 79 77 158 341 553 849 4,636
2034 724 562 527 383 260 150 85 84 165 344 556 841 4,679
2035 728 567 534 389 270 157 90 90 176 356 562 847 4,765
2036 735 594 543 393 280 167 97 96 183 368 564 856 4,876
2037 742 582 549 405 290 173 102 103 193 375 573 855 4,940
2038 741 581 551 406 298 179 108 109 200 378 575 856 4,984
2039 751 578 550 409 308 186 114 115 208 384 577 857 5,037
2040 754 592 550 415 317 195 120 122 214 383 578 861 5,100
2041 765 573 548 422 324 201 126 127 224 390 579 865 5,144
2042 771 571 548 426 330 207 132 134 233 392 584 868 5,194
2043 766 568 545 426 327 206 130 132 233 390 584 861 5,170
2044 767 588 547 426 326 205 130 131 232 390 586 863 5,190
2045 768 572 546 427 326 202 129 130 230 388 583 862 5,163
APPENDIX - CHAPTER 2

Klamath Falls Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
2023 1,045 860 808 651 422 205 40 61 231 563 854 1,202 6,940
2024 1,054 886 804 639 421 212 46 68 238 564 844 1,198 6,973
2025 1,049 850 809 639 418 217 53 73 239 561 838 1,196 6,942
2026 1,042 849 808 633 416 212 61 80 238 557 835 1,194 6,925
2027 1,041 841 795 627 418 218 68 86 240 552 830 1,189 6,906
2028 1,035 866 794 622 422 221 76 93 240 545 826 1,177 6,916
2029 1,023 822 784 613 420 221 85 98 246 543 826 1,165 6,847
2030 1,024 820 778 603 422 223 91 103 253 536 805 1,156 6,814
2031 1,026 820 771 594 413 222 96 108 252 536 797 1,156 6,791
2032 1,023 838 765 583 402 219 101 116 261 531 788 1,150 6,777
2033 1,019 804 761 580 401 217 108 123 270 529 785 1,144 6,742
2034 1,002 795 761 579 404 221 115 127 270 520 783 1,126 6,704
2035 1,002 795 762 577 404 223 122 133 277 522 781 1,128 6,726
2036 1,007 827 764 572 406 232 129 140 277 525 774 1,125 6,778
2037 1,004 803 765 578 408 237 132 146 277 519 775 1,116 6,760
2038 991 801 764 573 410 241 140 154 278 512 772 1,112 6,748
2039 997 791 756 568 416 244 146 159 278 506 767 1,109 6,737
2040 999 806 750 568 416 248 151 167 276 496 764 1,105 6,745
2041 1,002 778 744 569 419 251 156 174 282 495 756 1,104 6,730
2042 1,002 771 739 566 418 255 164 178 284 489 753 1,099 6,718
2043 998 767 741 565 412 255 162 177 284 487 753 1,095 6,695
2044 1,001 792 743 565 408 253 160 174 282 488 756 1,097 6,719
2045 1,001 769 740 565 408 251 161 174 280 485 754 1,097 6,685
APPENDIX - CHAPTER 2

APPENDIX 2.4: AVERAGE DAILY HEATING DEGREE DAY BY MOTH BY AREA

WA/ID Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
1 36 34 59 21 14 4 1 0 1 11 23 31
2 36 33 41 20 12 5 1 0 2 12 23 31
3 37 32 29 19 12 4 1 0 2 12 23 32
4 35 31 28 20 11 5 0 0 2 13 24 34
5 35 31 27 19 10 5 1 0 3 12 25 35
6 34 31 27 19 11 5 0 0 3 12 25 35
7 34 31 28 18 11 5 0 0 2 12 25 35
8 34 31 28 18 10 5 1 0 3 13 25 36
9 34 32 27 19 11 5 0 0 2 14 26 36
10 34 32 26 18 11 5 0 0 2 15 26 34
11 35 32 24 20 10 4 0 0 3 16 27 33
12 34 31 24 20 10 3 0 0 3 16 28 34
13 35 32 24 19 11 4 0 0 3 15 29 34
14 35 32 24 19 9 5 0 0 3 16 27 34
15 36 31 24 19 9 5 0 0 3 16 28 35
16 36 30 23 17 8 5 0 0 5 15 28 35
17 35 31 24 16 8 4 0 0 5 16 28 35
18 34 32 23 17 8 3 0 0 5 17 29 34
19 36 31 23 16 8 3 0 0 6 17 29 34
20 37 32 22 15 9 3 0 0 7 17 29 35
21 36 32 22 14 9 2 0 0 7 18 30 35
22 34 31 23 14 9 1 0 1 6 19 30 35
23 34 32 23 14 8 2 0 1 6 19 30 36
24 35 32 23 15 7 2 0 1 5 19 30 36
25 35 32 22 16 7 2 0 1 5 20 31 37
26 36 48 23 14 7 1 0 1 6 20 30 39
27 36 64 22 13 6 1 0 1 8 21 31 38
28 35 80 22 14 5 1 0 1 8 21 31 37
29 34 63 22 13 5 1 0 1 8 23 32 36
30 34 21 14 5 2 0 1 9 23 31 37
31 32 21 4 0 2 22 39
APPENDIX - CHAPTER 2

Medford Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
1 26 22 20 16 11 5 3 2 4 8 14 24
2 26 22 19 15 10 5 3 2 4 8 15 23
3 27 22 20 15 9 5 3 2 4 9 15 24
4 26 22 20 14 9 5 2 2 4 10 16 24
5 25 21 20 14 9 5 2 2 4 10 17 25
6 25 20 20 14 10 6 3 2 5 9 17 24
7 25 20 21 14 9 6 3 3 4 9 18 26
8 24 20 20 14 9 6 3 2 4 9 18 25
9 25 21 18 14 9 6 3 2 4 10 19 24
10 25 22 18 14 9 6 3 2 4 10 18 25
11 25 21 17 14 9 6 2 2 4 11 19 26
12 24 21 16 14 9 5 2 2 4 11 19 25
13 25 21 17 14 8 5 2 2 5 11 19 25
14 26 21 18 15 8 5 2 2 4 11 19 25
15 26 19 17 14 8 5 2 2 5 11 19 26
16 25 20 17 13 8 5 2 3 5 11 20 26
17 26 21 17 12 8 5 2 3 5 10 20 26
18 25 21 17 12 8 4 3 2 6 11 22 36
19 25 21 16 12 8 4 3 2 6 12 21 45
20 26 22 16 12 8 4 3 2 6 12 21 54
21 25 22 15 12 9 4 2 2 6 12 21 45
22 24 22 17 12 9 4 2 2 6 12 22 36
23 23 22 18 12 8 4 2 2 6 13 21 26
24 24 21 17 12 7 4 2 3 6 13 22 27
25 24 21 17 12 8 4 2 3 6 13 21 27
26 24 22 17 12 7 3 2 3 5 13 22 28
27 24 21 16 11 7 3 2 3 6 14 23 27
28 24 20 16 11 6 3 2 2 6 14 23 26
29 23 20 16 11 6 3 2 3 7 14 24 26
30 23 16 11 6 4 3 3 7 14 24 26
31 23 16 6 3 4 14 28
APPENDIX - CHAPTER 2

La Grande Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
1 34 30 54 21 16 7 4 2 6 13 21 28
2 34 30 38 20 14 7 5 3 6 13 20 28
3 34 29 27 20 14 7 4 4 6 13 21 30
4 34 28 27 19 13 7 3 3 6 15 22 30
5 33 28 25 19 13 7 3 3 7 15 22 31
6 33 27 26 19 14 8 3 3 7 14 23 31
7 31 28 26 18 13 8 4 3 7 14 24 31
8 30 28 26 19 13 8 4 4 7 15 23 32
9 31 29 26 19 14 8 3 3 7 15 24 32
10 31 29 25 19 13 9 3 3 7 15 24 31
11 32 29 23 20 12 8 3 3 8 17 24 31
12 32 29 22 20 12 6 3 4 8 17 24 31
13 32 29 22 20 12 7 4 3 8 15 26 31
14 32 28 23 20 12 8 3 3 8 15 25 32
15 33 28 22 19 12 8 3 3 8 16 25 32
16 32 27 22 19 11 8 3 4 9 15 27 33
17 32 28 23 17 10 7 3 4 8 15 26 33
18 31 30 23 17 11 7 3 4 9 16 26 32
19 32 29 23 18 11 7 5 4 10 16 26 32
20 32 29 22 17 12 6 3 3 10 15 27 32
21 32 29 21 17 12 7 3 4 10 17 28 31
22 32 29 22 15 12 5 3 3 10 18 27 33
23 31 29 23 16 11 6 3 4 10 18 27 34
24 32 29 22 17 11 6 3 4 10 19 28 34
25 32 29 22 17 10 5 3 5 10 18 28 34
26 32 44 22 16 10 5 3 5 10 19 28 34
27 33 58 21 15 9 5 3 5 10 20 28 34
28 33 73 21 15 9 5 3 5 11 19 29 33
29 31 57 21 16 8 4 3 4 11 20 29 34
30 31 22 16 8 5 3 5 11 20 29 34
31 30 21 8 3 6 20 37
APPENDIX - CHAPTER 2

Roseburg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
1 25 21 20 15 11 6 3 2 4 8 14 23
2 25 21 19 15 10 5 3 2 4 9 14 23
3 25 21 20 15 10 6 3 2 4 9 15 22
4 25 21 19 14 10 6 2 2 4 10 15 23
5 24 20 19 14 10 6 3 2 4 10 16 24
6 23 19 20 13 10 6 3 3 5 9 16 24
7 23 19 20 14 10 6 3 3 4 9 18 24
8 23 19 19 14 10 6 3 2 4 9 17 24
9 24 20 17 14 9 6 3 2 5 10 18 23
10 24 21 18 14 9 7 3 2 5 11 18 24
11 24 19 16 15 9 6 2 2 5 11 18 24
12 23 20 16 14 9 5 2 2 5 11 18 24
13 24 21 17 14 9 5 2 2 5 11 18 24
14 25 20 17 15 9 5 2 2 4 11 18 24
15 25 19 16 14 9 6 2 2 5 11 18 25
16 24 20 17 13 8 6 2 3 5 11 19 25
17 24 19 17 12 8 5 2 3 5 11 19 25
18 23 21 17 12 8 5 3 2 6 11 20 35
19 24 21 16 12 9 4 3 2 6 11 19 45
20 25 21 16 12 8 4 3 2 6 11 20 54
21 24 21 15 12 9 4 2 3 6 12 20 44
22 23 21 16 12 9 4 2 2 6 12 21 35
23 22 21 17 12 8 4 2 2 6 13 20 25
24 23 21 16 12 7 4 2 3 6 13 21 26
25 23 21 16 12 8 4 2 3 6 13 20 26
26 23 21 16 12 7 4 2 3 5 13 20 27
27 23 20 16 11 7 3 2 3 6 14 22 25
28 23 20 15 11 7 3 2 2 6 13 22 25
29 22 20 16 11 6 3 2 3 7 14 23 25
30 21 16 12 6 4 3 3 7 14 22 25
31 22 16 6 3 4 14 26
APPENDIX - CHAPTER 2

Klamath Falls Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
1 35 30 28 22 17 8 5 3 6 14 21 30
2 35 30 28 22 16 8 4 3 6 14 23 30
3 34 29 29 22 14 8 4 3 6 14 22 30
4 34 29 27 21 14 9 3 3 6 15 24 31
5 33 28 26 21 14 9 3 4 7 15 25 32
6 34 27 28 20 15 9 4 4 7 13 24 32
7 33 28 28 21 15 10 5 4 6 14 25 32
8 31 27 28 20 14 10 5 3 7 15 25 33
9 34 28 27 21 15 10 4 3 6 15 26 32
10 33 29 26 21 15 9 4 3 7 16 25 32
11 34 28 24 21 14 8 3 3 7 17 26 33
12 33 29 23 21 13 8 4 3 7 17 26 32
13 33 29 24 22 13 9 4 3 8 16 25 32
14 34 29 24 22 14 9 3 3 8 16 25 33
15 34 28 24 21 14 10 3 4 9 16 26 33
16 33 28 24 20 13 9 3 3 10 15 27 34
17 33 30 25 19 14 8 3 4 10 16 27 34
18 32 30 24 19 14 8 4 3 11 17 28 46
19 32 29 23 19 14 7 4 4 11 17 27 58
20 33 31 23 19 14 7 4 4 11 17 27 70
21 33 29 22 17 15 6 3 4 11 18 28 58
22 32 29 24 17 14 6 3 4 11 18 28 47
23 31 30 25 17 13 5 3 5 11 19 28 35
24 31 29 24 19 12 6 3 5 10 19 29 35
25 33 29 24 20 13 7 2 5 10 19 28 35
26 33 30 24 18 12 5 3 5 10 19 29 37
27 33 30 23 17 12 5 3 5 10 21 30 35
28 32 29 22 18 10 5 3 4 10 21 30 35
29 31 29 23 18 9 5 3 5 11 22 31 35
30 31 23 18 9 5 3 6 12 21 30 35
31 31 23 9 4 7 21 37
APPENDIX - CHAPTER 2

APPENDIX 2.5: ANNUAL, AVERAGE DAY, AND PEAK DAY DEMAND (MDTH, NET
OF DSM) – CASE PRS

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 1,453 3.98 14.47 898 2.46 8.37 5,742 15.73 56.07 1,505 4.12 15.43
2024 1,468 4.01 14.58 908 2.48 8.42 5,856 16.00 56.72 1,527 4.17 15.47
2025 1,469 4.02 14.68 910 2.49 8.47 5,930 16.25 57.37 1,536 4.21 15.51
2026 1,475 4.04 14.77 915 2.51 8.51 6,027 16.51 58.00 1,551 4.25 15.55
2027 1,478 4.05 14.86 920 2.52 8.55 6,110 16.74 58.59 1,562 4.28 15.59
2028 1,486 4.06 14.94 929 2.54 8.59 6,208 16.96 59.17 1,578 4.31 15.62
2029 1,477 4.05 15.02 928 2.54 8.63 6,252 17.13 59.73 1,580 4.33 15.66
2030 1,476 4.05 15.09 932 2.55 8.68 6,320 17.31 60.29 1,588 4.35 15.69
2031 1,479 4.05 15.16 936 2.57 8.72 6,410 17.56 60.84 1,604 4.39 15.72
2032 1,484 4.05 15.24 942 2.57 8.76 6,498 17.76 61.38 1,619 4.42 15.75
2033 1,481 4.06 15.32 944 2.59 8.80 6,555 17.96 61.91 1,625 4.45 15.78
2034 1,479 4.05 15.39 947 2.59 8.84 6,613 18.12 62.44 1,634 4.48 15.81
2035 1,487 4.07 15.47 953 2.61 8.88 6,724 18.42 62.96 1,654 4.53 15.85
2036 1,503 4.11 15.54 964 2.63 8.92 6,864 18.75 63.49 1,683 4.60 15.88
2037 1,503 4.12 15.62 966 2.65 8.96 6,943 19.02 64.00 1,697 4.65 15.91
2038 1,506 4.13 15.70 969 2.65 9.00 7,019 19.23 64.50 1,707 4.68 15.95
2039 1,509 4.13 15.77 973 2.66 9.05 7,097 19.44 65.00 1,721 4.72 15.98
2040 1,518 4.15 15.85 979 2.67 9.09 7,200 19.67 65.49 1,739 4.75 16.01
2041 1,518 4.16 15.92 979 2.68 9.12 7,261 19.89 65.97 1,748 4.79 16.04
2042 1,521 4.17 16.00 982 2.69 9.17 7,342 20.11 66.45 1,762 4.83 16.08
2043 1,536 4.21 16.13 990 2.71 9.24 7,430 20.36 67.18 1,776 4.86 16.18
2044 1,551 4.24 16.20 999 2.73 9.28 7,524 20.56 67.64 1,790 4.89 16.21
2045 1,550 4.25 16.26 998 2.73 9.31 7,550 20.68 68.08 1,787 4.90 16.24
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 9,597 26.29 90.11 19,436 53.25 219.89 10,441 28.61 111.89 39,475 108.15 378.37
2024 9,759 26.67 90.96 19,604 53.56 221.98 10,644 29.08 113.86 40,007 109.31 382.50
2025 9,845 26.97 91.76 19,549 53.56 224.00 10,724 29.38 115.68 40,118 109.91 387.11
2026 9,968 27.31 92.59 19,620 53.75 226.17 10,855 29.74 117.40 40,443 110.80 391.42
2027 10,069 27.59 93.25 19,657 53.85 228.09 10,956 30.02 118.91 40,682 111.46 395.42
2028 10,202 27.87 94.03 19,816 54.14 230.01 11,118 30.38 120.40 41,136 112.39 398.71
2029 10,237 28.05 94.62 19,675 53.90 231.84 11,128 30.49 121.83 41,040 112.44 402.47
2030 10,316 28.26 95.36 19,652 53.84 233.77 11,192 30.66 123.22 41,159 112.76 406.13
2031 10,429 28.57 95.94 19,726 54.04 235.75 11,295 30.95 124.63 41,451 113.56 410.08
2032 10,544 28.81 96.58 19,821 54.15 237.77 11,422 31.21 126.10 41,786 114.17 413.76
2033 10,604 29.05 97.24 19,790 54.22 239.76 11,475 31.44 127.55 41,869 114.71 417.06
2034 10,672 29.24 97.91 19,785 54.21 241.80 11,549 31.64 129.02 42,006 115.09 421.29
2035 10,819 29.64 98.65 19,864 54.42 243.83 11,665 31.96 130.49 42,348 116.02 425.34
2036 11,014 30.09 99.23 20,122 54.98 245.85 11,867 32.42 131.97 43,003 117.49 429.59
2037 11,109 30.44 99.89 20,130 55.15 247.83 11,947 32.73 133.42 43,186 118.32 433.40
2038 11,201 30.69 100.46 20,082 55.02 249.84 12,005 32.89 134.87 43,289 118.60 436.76
2039 11,300 30.96 101.13 20,128 55.14 251.80 12,106 33.17 136.32 43,533 119.27 439.47
2040 11,436 31.25 101.86 20,209 55.22 253.75 12,216 33.38 137.75 43,861 119.84 442.56
2041 11,507 31.53 102.55 20,173 55.27 255.68 12,270 33.62 139.15 43,950 120.41 446.40
2042 11,607 31.80 103.14 20,193 55.32 257.58 12,356 33.85 140.55 44,155 120.97 450.20
2043 11,732 32.14 104.08 20,210 55.37 259.53 12,440 34.08 141.99 44,382 121.59 454.17
2044 11,864 32.41 104.65 20,424 55.80 261.44 12,624 34.49 143.42 44,912 122.71 457.25
2045 11,885 32.56 105.23 20,398 55.89 263.32 12,698 34.79 144.92 44,981 123.24 460.21
System
RoseburgKlamath Falls La Grande Medford
Oregon Washington Idaho
APPENDIX - CHAPTER 2

APPENDIX 2.5: ANNUAL, AVERAGE DAY, AND PEAK DAY DEMAND (MDTH, NET
OF DSM) – CASE AVERAGE

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 1,434 3.93 8.56 884 2.42 4.89 5,632 15.43 31.75 1,468 4.02 8.31
2024 1,452 3.97 8.63 892 2.44 4.92 5,726 15.64 32.12 1,481 4.05 8.35
2025 1,455 3.99 8.69 893 2.45 4.94 5,770 15.81 32.53 1,479 4.05 8.38
2026 1,465 4.01 8.75 897 2.46 4.96 5,840 16.00 32.95 1,484 4.07 8.41
2027 1,474 4.04 8.80 901 2.47 4.99 5,907 16.18 33.35 1,489 4.08 8.44
2028 1,490 4.07 8.85 909 2.48 5.01 5,999 16.39 33.72 1,501 4.10 8.47
2029 1,490 4.08 8.89 909 2.49 5.04 6,034 16.53 34.09 1,499 4.11 8.50
2030 1,498 4.10 8.94 913 2.50 5.06 6,096 16.70 34.45 1,503 4.12 8.53
2031 1,505 4.12 8.98 917 2.51 5.08 6,159 16.87 34.81 1,508 4.13 8.55
2032 1,521 4.15 9.03 925 2.53 5.11 6,250 17.08 35.17 1,520 4.15 8.58
2033 1,521 4.17 9.07 925 2.53 5.13 6,282 17.21 35.52 1,517 4.16 8.61
2034 1,529 4.19 9.12 929 2.55 5.16 6,343 17.38 35.88 1,522 4.17 8.64
2035 1,537 4.21 9.17 933 2.56 5.18 6,406 17.55 36.23 1,527 4.18 8.67
2036 1,552 4.24 9.22 941 2.57 5.21 6,499 17.76 36.59 1,540 4.21 8.70
2037 1,553 4.25 9.27 942 2.58 5.23 6,530 17.89 36.94 1,538 4.21 8.73
2038 1,561 4.28 9.31 946 2.59 5.26 6,591 18.06 37.29 1,543 4.23 8.76
2039 1,569 4.30 9.36 951 2.60 5.28 6,651 18.22 37.64 1,548 4.24 8.79
2040 1,586 4.33 9.41 959 2.62 5.31 6,742 18.42 37.98 1,561 4.26 8.82
2041 1,586 4.34 9.46 959 2.63 5.33 6,769 18.55 38.31 1,558 4.27 8.84
2042 1,594 4.37 9.51 963 2.64 5.35 6,828 18.71 38.65 1,564 4.28 8.88
2043 1,613 4.42 9.61 974 2.67 5.41 6,935 19.00 39.21 1,583 4.34 8.97
2044 1,628 4.45 9.65 982 2.68 5.44 7,025 19.19 39.54 1,595 4.36 9.00
2045 1,627 4.46 9.69 982 2.69 5.46 7,047 19.31 39.86 1,592 4.36 9.03
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 9,417 25.80 52.48 19,125 52.40 113.87 10,284 28.18 59.52 38,827 106.38 225.87
2024 9,550 26.09 53.00 19,315 52.77 114.87 10,498 28.68 60.49 39,364 107.55 228.36
2025 9,596 26.29 53.52 19,329 52.95 115.84 10,610 29.07 61.35 39,534 108.31 230.70
2026 9,687 26.54 54.02 19,454 53.30 116.93 10,766 29.49 62.22 39,907 109.33 233.17
2027 9,771 26.77 54.50 19,547 53.55 117.83 10,897 29.86 62.99 40,216 110.18 235.32
2028 9,899 27.05 54.96 19,729 53.90 118.74 11,073 30.25 63.73 40,701 111.21 237.43
2029 9,932 27.21 55.41 19,728 54.05 119.62 11,151 30.55 64.45 40,811 111.81 239.48
2030 10,010 27.43 55.85 19,829 54.33 120.57 11,275 30.89 65.18 41,114 112.64 241.60
2031 10,088 27.64 56.28 19,938 54.62 121.57 11,404 31.24 65.94 41,430 113.51 243.80
2032 10,215 27.91 56.72 20,140 55.03 122.58 11,586 31.66 66.71 41,941 114.59 246.02
2033 10,244 28.07 57.16 20,166 55.25 123.63 11,672 31.98 67.50 42,082 115.29 248.30
2034 10,323 28.28 57.60 20,286 55.58 124.69 11,809 32.35 68.31 42,419 116.22 250.61
2035 10,403 28.50 58.05 20,408 55.91 125.76 11,947 32.73 69.12 42,757 117.14 252.92
2036 10,533 28.78 58.50 20,619 56.34 126.80 12,136 33.16 69.92 43,288 118.27 255.22
2037 10,562 28.94 58.94 20,643 56.56 127.84 12,222 33.48 70.73 43,427 118.98 257.51
2038 10,641 29.15 59.38 20,762 56.88 128.89 12,358 33.86 71.53 43,761 119.89 259.80
2039 10,719 29.37 59.82 20,876 57.20 129.91 12,492 34.22 72.31 44,087 120.79 262.04
2040 10,847 29.64 60.25 21,083 57.60 130.91 12,677 34.64 73.08 44,607 121.88 264.23
2041 10,872 29.79 60.67 21,098 57.80 131.91 12,755 34.94 73.85 44,724 122.53 266.44
2042 10,948 29.99 61.10 21,204 58.09 132.88 12,883 35.30 74.62 45,036 123.39 268.59
2043 11,104 30.42 61.93 21,320 58.41 133.91 13,017 35.66 75.41 45,442 124.50 271.25
2044 11,230 30.68 62.34 21,529 58.82 134.89 13,207 36.08 76.21 45,966 125.59 273.44
2045 11,249 30.82 62.74 21,534 59.00 135.85 13,292 36.42 77.08 46,075 126.23 275.68
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.5: ANNUAL, AVERAGE DAY, AND PEAK DAY DEMAND (MDTH, NET
OF DSM) – CASE HIGH GROWTH

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 1,464 4.01 14.59 914 2.51 8.46 5,758 15.77 56.25 1,516 4.15 15.55
2024 1,483 4.05 14.75 945 2.58 8.53 5,879 16.06 56.96 1,543 4.21 15.64
2025 1,492 4.09 14.91 951 2.61 8.65 5,963 16.34 57.69 1,558 4.27 15.73
2026 1,502 4.12 15.06 977 2.68 8.71 6,067 16.62 58.39 1,577 4.32 15.82
2027 1,512 4.14 15.20 987 2.70 8.83 6,160 16.88 59.07 1,596 4.37 15.91
2028 1,525 4.17 15.33 1,017 2.78 8.89 6,267 17.12 59.73 1,617 4.42 15.99
2029 1,523 4.17 15.47 1,022 2.80 9.00 6,320 17.31 60.37 1,625 4.45 16.08
2030 1,527 4.18 15.60 1,047 2.87 9.07 6,396 17.52 61.01 1,639 4.49 16.16
2031 1,537 4.21 15.74 1,057 2.90 9.19 6,497 17.80 61.64 1,661 4.55 16.25
2032 1,547 4.23 15.87 1,085 2.96 9.25 6,595 18.02 62.26 1,682 4.60 16.33
2033 1,550 4.25 16.01 1,092 2.99 9.36 6,662 18.25 62.89 1,695 4.64 16.42
2034 1,552 4.25 16.13 1,117 3.06 9.43 6,729 18.44 63.50 1,710 4.68 16.50
2035 1,569 4.30 16.28 1,129 3.09 9.55 6,852 18.77 64.12 1,738 4.76 16.59
2036 1,589 4.34 16.41 1,164 3.18 9.62 7,003 19.13 64.73 1,774 4.85 16.67
2037 1,597 4.37 16.55 1,172 3.21 9.73 7,094 19.43 65.33 1,794 4.92 16.76
2038 1,604 4.40 16.68 1,198 3.28 9.80 7,180 19.67 65.93 1,811 4.96 16.85
2039 1,615 4.42 16.83 1,208 3.31 9.92 7,270 19.92 66.52 1,833 5.02 16.94
2040 1,630 4.45 16.96 1,238 3.38 9.99 7,385 20.18 67.10 1,858 5.08 17.02
2041 1,636 4.48 17.11 1,244 3.41 10.10 7,458 20.43 67.69 1,874 5.14 17.11
2042 1,644 4.50 17.24 1,271 3.48 10.17 7,550 20.68 68.26 1,895 5.19 17.20
2043 1,667 4.57 17.44 1,283 3.52 10.32 7,650 20.96 69.08 1,916 5.25 17.36
2044 1,688 4.61 17.57 1,315 3.59 10.38 7,756 21.19 69.64 1,937 5.29 17.44
2045 1,694 4.64 17.71 1,319 3.61 10.50 7,794 21.35 70.18 1,941 5.32 17.53
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 9,651 26.44 90.61 19,519 53.48 220.72 10,542 28.88 112.77 39,712 108.80 380.29
2024 9,850 26.91 91.67 19,715 53.87 223.29 10,799 29.50 115.30 40,363 110.28 385.56
2025 9,963 27.30 92.69 19,689 53.94 225.79 10,932 29.95 117.69 40,584 111.19 391.39
2026 10,124 27.74 93.74 19,787 54.21 228.46 11,119 30.46 120.00 41,030 112.41 396.90
2027 10,254 28.09 94.61 19,854 54.40 230.90 11,277 30.89 122.12 41,385 113.38 402.18
2028 10,426 28.49 95.62 20,045 54.77 233.34 11,499 31.42 124.24 41,970 114.67 406.71
2029 10,490 28.74 96.43 19,928 54.60 235.69 11,565 31.69 126.31 41,983 115.02 411.81
2030 10,608 29.06 97.40 19,932 54.61 238.17 11,688 32.02 128.36 42,228 115.69 416.77
2031 10,752 29.46 98.21 20,039 54.90 240.69 11,853 32.47 130.44 42,644 116.83 422.11
2032 10,908 29.80 99.08 20,163 55.09 243.27 12,043 32.90 132.60 43,114 117.80 427.14
2033 10,999 30.13 99.97 20,162 55.24 245.83 12,157 33.31 134.76 43,317 118.68 431.88
2034 11,108 30.43 100.88 20,184 55.30 248.43 12,293 33.68 136.95 43,585 119.41 437.52
2035 11,288 30.93 101.86 20,294 55.60 251.05 12,476 34.18 139.15 44,058 120.71 443.07
2036 11,530 31.50 102.69 20,593 56.26 253.66 12,752 34.84 141.39 44,874 122.61 448.79
2037 11,657 31.94 103.58 20,630 56.52 256.25 12,899 35.34 143.62 45,186 123.80 454.15
2038 11,794 32.31 104.40 20,606 56.45 258.86 13,022 35.68 145.86 45,422 124.44 459.02
2039 11,926 32.67 105.31 20,681 56.66 261.45 13,193 36.14 148.11 45,800 125.48 463.31
2040 12,110 33.09 106.30 20,796 56.82 264.02 13,376 36.55 150.36 46,282 126.45 467.95
2041 12,213 33.46 107.24 20,787 56.95 266.59 13,498 36.98 152.60 46,499 127.39 473.44
2042 12,359 33.86 108.09 20,836 57.09 269.14 13,657 37.42 154.86 46,852 128.36 478.87
2043 12,516 34.29 109.28 20,881 57.21 271.75 13,815 37.85 157.18 47,212 129.35 484.55
2044 12,696 34.69 110.12 21,138 57.75 274.33 14,085 38.48 159.50 47,919 130.93 489.28
2045 12,748 34.93 110.95 21,140 57.92 276.88 14,234 39.00 161.91 48,121 131.84 493.98
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.5: ANNUAL, AVERAGE DAY, AND PEAK DAY DEMAND (MDTH, NET
OF DSM) – CASE ELECTRIFICATION

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 1,453 3.98 14.47 898 2.46 8.37 5,742 15.73 56.07 1,505 4.12 15.43
2024 1,468 4.01 14.58 908 2.48 8.42 5,856 16.00 56.72 1,527 4.17 15.47
2025 1,429 3.91 14.28 889 2.43 8.25 5,739 15.72 55.50 1,499 4.11 15.14
2026 1,396 3.82 13.99 872 2.39 8.09 5,643 15.46 54.31 1,477 4.05 14.82
2027 1,362 3.73 13.71 855 2.34 7.92 5,542 15.18 53.14 1,453 3.98 14.50
2028 1,335 3.65 13.43 841 2.30 7.72 5,456 14.91 51.99 1,433 3.92 14.18
2029 1,290 3.53 13.13 820 2.25 7.56 5,324 14.59 50.86 1,400 3.84 13.87
2030 1,256 3.44 12.86 801 2.19 7.41 5,215 14.29 49.75 1,374 3.76 13.57
2031 1,227 3.36 12.60 781 2.14 7.26 5,128 14.05 48.68 1,355 3.71 13.28
2032 1,200 3.28 12.34 766 2.09 7.11 5,041 13.77 47.62 1,335 3.65 12.99
2033 1,167 3.20 12.09 748 2.05 6.96 4,932 13.51 46.59 1,309 3.59 12.71
2034 1,135 3.11 11.85 733 2.01 6.82 4,825 13.22 45.58 1,285 3.52 12.44
2035 1,114 3.05 11.61 721 1.97 6.69 4,762 13.05 44.61 1,271 3.48 12.17
2036 1,097 3.00 11.37 712 1.94 6.55 4,718 12.89 43.66 1,263 3.45 11.91
2037 1,070 2.93 11.14 697 1.91 6.42 4,633 12.69 42.73 1,243 3.41 11.66
2038 1,045 2.86 10.92 684 1.87 6.30 4,548 12.46 41.82 1,222 3.35 11.41
2039 1,019 2.79 10.68 669 1.83 6.17 4,464 12.23 40.93 1,201 3.29 11.16
2040 999 2.73 10.47 658 1.80 6.05 4,400 12.02 40.05 1,186 3.24 10.92
2041 975 2.67 10.26 644 1.76 5.92 4,311 11.81 39.20 1,164 3.19 10.69
2042 952 2.61 10.05 629 1.72 5.81 4,235 11.60 38.36 1,146 3.14 10.46
2043 943 2.58 9.91 620 1.70 5.72 4,187 11.47 37.80 1,133 3.10 10.31
2044 929 2.54 9.71 612 1.67 5.61 4,120 11.26 36.99 1,116 3.05 10.09
2045 906 2.48 9.51 595 1.63 5.50 4,020 11.01 36.20 1,089 2.98 9.88
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 9,597 26.29 90.11 19,459 53.31 219.89 10,441 28.61 111.89 39,498 108.21 378.37
2024 9,759 26.67 90.96 19,681 53.77 221.74 10,644 29.08 113.86 40,085 109.52 382.26
2025 9,556 26.18 89.02 19,118 52.38 217.12 10,724 29.38 115.68 39,398 107.94 378.84
2026 9,389 25.72 87.18 18,700 51.23 212.78 10,855 29.74 117.40 38,944 106.70 375.26
2027 9,211 25.24 85.25 18,254 50.01 208.37 10,956 30.02 118.91 38,420 105.26 371.59
2028 9,064 24.77 83.44 17,930 48.99 204.07 11,118 30.38 120.40 38,112 104.13 367.37
2029 8,834 24.20 81.55 17,359 47.56 199.78 11,128 30.49 121.83 37,321 102.25 363.73
2030 8,646 23.69 79.84 16,910 46.33 195.68 11,192 30.66 123.22 36,748 100.68 360.11
2031 8,490 23.26 78.07 16,536 45.30 191.70 11,295 30.95 124.63 36,322 99.51 356.83
2032 8,342 22.79 76.37 16,202 44.27 187.84 11,422 31.21 126.10 35,965 98.27 353.47
2033 8,155 22.34 74.75 15,770 43.21 184.05 11,475 31.44 127.55 35,400 96.99 349.93
2034 7,978 21.86 73.16 15,379 42.13 180.37 11,549 31.64 129.02 34,906 95.63 347.19
2035 7,867 21.55 71.69 15,061 41.26 176.79 11,665 31.96 130.49 34,593 94.77 344.45
2036 7,789 21.28 70.13 14,857 40.59 173.27 11,867 32.42 131.97 34,514 94.30 341.93
2037 7,643 20.94 68.66 14,499 39.72 169.80 11,947 32.73 133.42 34,090 93.40 339.18
2038 7,499 20.54 67.18 14,129 38.71 166.42 12,005 32.89 134.87 33,633 92.15 336.22
2039 7,353 20.15 65.76 13,819 37.86 163.09 12,106 33.17 136.32 33,278 91.17 332.94
2040 7,243 19.79 64.45 13,530 36.97 159.81 12,216 33.38 137.75 32,988 90.13 330.01
2041 7,093 19.43 63.15 13,184 36.12 156.61 12,270 33.62 139.15 32,547 89.17 327.65
2042 6,962 19.07 61.81 12,882 35.29 153.45 12,356 33.85 140.55 32,200 88.22 325.35
2043 6,883 18.86 60.89 12,589 34.49 150.39 12,440 34.08 141.99 31,912 87.43 323.41
2044 6,776 18.51 59.60 12,402 33.89 147.38 12,624 34.49 143.42 31,803 86.89 320.86
2045 6,609 18.11 58.32 12,095 33.14 144.40 12,698 34.79 144.92 31,401 86.03 318.37
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.5: ANNUAL, AVERAGE DAY, AND PEAK DAY DEMAND (MDTH, NET
OF DSM) – CASE HYBRID

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 1,453 3.98 14.47 898 2.46 8.37 5,742 15.73 56.07 1,505 4.12 15.43
2024 1,468 4.01 14.58 908 2.48 8.42 5,856 16.00 56.72 1,527 4.17 15.47
2025 1,451 3.98 14.65 898 2.46 8.45 5,779 15.83 57.18 1,501 4.11 15.47
2026 1,440 3.94 14.72 891 2.44 8.47 5,718 15.67 57.61 1,481 4.06 15.48
2027 1,425 3.90 14.78 883 2.42 8.49 5,655 15.49 58.02 1,460 4.00 15.48
2028 1,417 3.87 14.84 878 2.40 8.47 5,596 15.29 58.42 1,442 3.94 15.48
2029 1,387 3.80 14.87 865 2.37 8.49 5,492 15.05 58.81 1,412 3.87 15.48
2030 1,371 3.76 14.92 855 2.34 8.52 5,400 14.80 59.19 1,387 3.80 15.48
2031 1,356 3.71 14.97 843 2.31 8.54 5,360 14.69 59.56 1,376 3.77 15.47
2032 1,343 3.67 15.03 836 2.28 8.56 5,291 14.46 59.94 1,361 3.72 15.47
2033 1,321 3.62 15.08 827 2.27 8.58 5,210 14.27 60.30 1,339 3.67 15.47
2034 1,305 3.57 15.13 818 2.24 8.61 5,057 13.85 60.66 1,315 3.60 15.47
2035 1,297 3.55 15.19 813 2.23 8.63 5,014 13.74 61.03 1,305 3.58 15.47
2036 1,297 3.54 15.24 813 2.22 8.66 5,015 13.70 61.40 1,302 3.56 15.48
2037 1,285 3.52 15.30 805 2.21 8.68 4,970 13.62 61.76 1,285 3.52 15.48
2038 1,272 3.48 15.35 798 2.19 8.71 4,897 13.42 62.11 1,264 3.46 15.48
2039 1,258 3.45 15.39 789 2.16 8.73 4,816 13.20 62.46 1,258 3.45 15.49
2040 1,252 3.42 15.45 787 2.15 8.76 4,828 13.19 62.80 1,255 3.43 15.49
2041 1,237 3.39 15.50 778 2.13 8.78 4,775 13.08 63.14 1,249 3.42 15.49
2042 1,229 3.37 15.56 771 2.11 8.81 4,711 12.91 63.48 1,243 3.41 15.50
2043 1,229 3.37 15.67 767 2.10 8.86 4,631 12.69 64.06 1,224 3.35 15.57
2044 1,232 3.37 15.72 767 2.09 8.89 4,585 12.53 64.38 1,211 3.31 15.58
2045 1,220 3.34 15.76 754 2.06 8.91 4,517 12.38 64.69 1,190 3.26 15.58
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 9,597 26.29 90.11 19,467 53.33 219.89 10,441 28.61 111.89 39,505 108.23 378.37
2024 9,759 26.67 90.96 19,706 53.84 222.09 10,644 29.08 113.86 40,110 109.59 382.61
2025 9,630 26.38 91.48 19,476 53.36 223.80 10,724 29.38 115.68 39,830 109.12 385.87
2026 9,530 26.11 92.04 19,371 53.07 225.68 10,855 29.74 117.40 39,756 108.92 388.86
2027 9,423 25.82 92.44 19,245 52.73 227.33 10,956 30.02 118.91 39,623 108.56 391.59
2028 9,333 25.50 92.91 19,239 52.57 228.98 11,118 30.38 120.40 39,690 108.44 393.62
2029 9,157 25.09 93.23 18,927 51.86 230.52 11,128 30.49 121.83 39,212 107.43 396.12
2030 9,013 24.69 93.71 18,734 51.33 232.20 11,192 30.66 123.22 38,939 106.68 398.59
2031 8,935 24.48 94.05 18,665 51.14 233.92 11,295 30.95 124.63 38,895 106.56 401.32
2032 8,831 24.13 94.45 18,595 50.81 235.67 11,422 31.21 126.10 38,848 106.14 403.84
2033 8,697 23.83 94.88 18,429 50.49 237.43 11,475 31.44 127.55 38,601 105.76 406.12
2034 8,495 23.27 95.30 18,271 50.06 239.21 11,549 31.64 129.02 38,314 104.97 409.14
2035 8,429 23.09 95.82 18,205 49.88 241.01 11,665 31.96 130.49 38,300 104.93 412.06
2036 8,426 23.02 96.17 18,348 50.13 242.78 11,867 32.42 131.97 38,642 105.58 415.12
2037 8,345 22.86 96.61 18,221 49.92 244.54 11,947 32.73 133.42 38,513 105.52 417.87
2038 8,231 22.55 96.97 18,008 49.34 246.31 12,005 32.89 134.87 38,244 104.78 420.29
2039 8,120 22.25 97.39 17,914 49.08 248.06 12,106 33.17 136.32 38,140 104.49 422.28
2040 8,122 22.19 97.91 17,872 48.83 249.78 12,216 33.38 137.75 38,210 104.40 424.57
2041 8,040 22.03 98.40 17,705 48.51 251.50 12,270 33.62 139.15 38,015 104.15 427.38
2042 7,953 21.79 98.78 17,591 48.20 253.20 12,356 33.85 140.55 37,900 103.84 430.16
2043 7,852 21.51 99.53 17,470 47.86 254.93 12,440 34.08 141.99 37,762 103.46 433.26
2044 7,795 21.30 99.89 17,579 48.03 256.65 12,624 34.49 143.42 37,997 103.82 435.62
2045 7,681 21.04 100.23 17,426 47.74 258.33 12,698 34.79 144.92 37,805 103.58 437.93
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.6: ANNUAL, AVERAGE DAY, AND PEAK DAY DSM – EXPECTED PRICES
AND EXPECTED VOLUMES (MDTH)

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 8.194 0.022 0.042 4.466 0.012 0.023 34.932 0.096 0.179 9.956 0.027 0.051
2024 8.504 0.023 0.044 4.635 0.013 0.024 36.253 0.099 0.186 10.333 0.028 0.053
2025 8.864 0.024 0.045 4.831 0.013 0.025 37.785 0.104 0.194 10.770 0.030 0.055
2026 9.008 0.025 0.046 4.909 0.013 0.025 38.401 0.105 0.197 10.945 0.030 0.056
2027 9.431 0.026 0.048 5.140 0.014 0.026 40.203 0.110 0.206 11.459 0.031 0.059
2028 10.110 0.028 0.052 5.510 0.015 0.028 43.098 0.118 0.221 12.284 0.034 0.063
2029 10.914 0.030 0.056 5.948 0.016 0.031 46.525 0.127 0.239 13.261 0.036 0.068
2030 11.614 0.032 0.060 6.330 0.017 0.032 49.511 0.136 0.254 14.112 0.039 0.072
2031 12.288 0.034 0.063 6.697 0.018 0.034 52.386 0.144 0.269 14.931 0.041 0.077
2032 12.839 0.035 0.066 6.997 0.019 0.036 54.732 0.150 0.281 15.600 0.043 0.080
2033 13.263 0.036 0.068 7.228 0.020 0.037 56.541 0.155 0.290 16.115 0.044 0.083
2034 13.521 0.037 0.069 7.369 0.020 0.038 57.638 0.158 0.296 16.428 0.045 0.084
2035 13.307 0.036 0.068 7.252 0.020 0.037 56.729 0.155 0.291 16.169 0.044 0.083
2036 13.059 0.036 0.067 7.117 0.019 0.037 55.669 0.152 0.286 15.867 0.043 0.081
2037 12.805 0.035 0.066 6.979 0.019 0.036 54.588 0.150 0.280 15.559 0.043 0.080
2038 12.610 0.035 0.065 6.872 0.019 0.035 53.757 0.147 0.276 15.322 0.042 0.079
2039 12.375 0.034 0.063 6.744 0.018 0.035 52.756 0.145 0.271 15.037 0.041 0.077
2040 12.210 0.033 0.063 6.654 0.018 0.034 52.050 0.142 0.267 14.835 0.041 0.076
2041 12.032 0.033 0.062 6.557 0.018 0.034 51.293 0.141 0.263 14.620 0.040 0.075
2042 11.753 0.032 0.060 6.405 0.018 0.033 50.104 0.137 0.257 14.281 0.039 0.073
2043 - - - - - - - - - - - -
2044 - - - - - - - - - - - -
2045 - - - - - - - - - - - -
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 57.549 0.158 0.295 111.991 0.307 0.646 46.414 0.127 0.259 214.988 0.589 1.033
2024 59.725 0.163 0.306 122.712 0.335 0.708 52.700 0.144 0.294 274.085 0.749 1.241
2025 62.249 0.171 0.319 137.682 0.377 0.795 59.890 0.164 0.335 294.063 0.806 1.340
2026 63.264 0.173 0.325 123.902 0.339 0.715 55.234 0.151 0.309 287.251 0.787 1.301
2027 66.232 0.181 0.340 139.450 0.382 0.805 64.711 0.177 0.362 307.982 0.844 1.413
2028 71.002 0.194 0.364 152.821 0.418 0.882 74.970 0.205 0.418 334.019 0.913 1.537
2029 76.647 0.210 0.393 171.273 0.469 0.988 83.106 0.228 0.464 361.911 0.992 1.667
2030 81.566 0.223 0.418 177.730 0.487 1.026 89.337 0.245 0.499 382.914 1.049 1.765
2031 86.302 0.236 0.443 175.688 0.481 1.014 91.496 0.251 0.511 395.143 1.083 1.817
2032 90.168 0.246 0.463 171.846 0.470 0.992 90.704 0.248 0.506 402.949 1.101 1.852
2033 93.147 0.255 0.478 160.872 0.441 0.928 85.561 0.234 0.478 397.414 1.089 1.825
2034 94.955 0.260 0.487 146.895 0.402 0.848 78.470 0.215 0.438 385.361 1.056 1.768
2035 93.458 0.256 0.479 131.483 0.360 0.759 71.431 0.196 0.399 363.892 0.997 1.667
2036 91.711 0.251 0.470 119.970 0.328 0.692 64.587 0.176 0.360 347.810 0.950 1.585
2037 89.930 0.246 0.461 107.079 0.293 0.618 56.419 0.155 0.315 320.985 0.879 1.457
2038 88.561 0.243 0.454 91.981 0.252 0.531 49.196 0.135 0.275 289.605 0.793 1.316
2039 86.913 0.238 0.446 82.345 0.226 0.475 43.787 0.120 0.245 260.047 0.712 1.187
2040 85.750 0.234 0.440 76.356 0.209 0.441 40.163 0.110 0.224 243.000 0.664 1.108
2041 84.503 0.232 0.433 67.940 0.186 0.392 35.109 0.096 0.196 219.832 0.602 1.001
2042 82.543 0.226 0.423 64.851 0.178 0.374 34.459 0.094 0.193 211.475 0.579 0.961
2043 - - - 51.673 0.142 0.298 30.149 0.083 0.168 57.270 0.157 0.305
2044 - - - 45.830 0.125 0.265 28.295 0.077 0.158 54.393 0.149 0.291
2045 - - - 42.857 0.117 0.247 27.538 0.075 0.154 53.751 0.147 0.287
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.6: ANNUAL, AVERAGE DAY, AND PEAK DAY DSM – LOW PRICES AND
LOW VOLUMES (MDTH)

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 8.194 0.022 0.042 4.466 0.012 0.023 34.932 0.096 0.179 9.956 0.027 0.051
2024 8.504 0.023 0.044 4.635 0.013 0.024 36.253 0.099 0.186 10.333 0.028 0.053
2025 8.864 0.024 0.045 4.831 0.013 0.025 37.785 0.104 0.194 10.770 0.030 0.055
2026 9.008 0.025 0.046 4.909 0.013 0.025 38.401 0.105 0.197 10.945 0.030 0.056
2027 9.431 0.026 0.048 5.140 0.014 0.026 40.203 0.110 0.206 11.459 0.031 0.059
2028 10.110 0.028 0.052 5.510 0.015 0.028 43.098 0.118 0.221 12.284 0.034 0.063
2029 10.914 0.030 0.056 5.948 0.016 0.031 46.525 0.127 0.239 13.261 0.036 0.068
2030 11.614 0.032 0.060 6.330 0.017 0.032 49.511 0.136 0.254 14.112 0.039 0.072
2031 12.288 0.034 0.063 6.697 0.018 0.034 52.386 0.144 0.269 14.931 0.041 0.077
2032 12.839 0.035 0.066 6.997 0.019 0.036 54.732 0.150 0.281 15.600 0.043 0.080
2033 13.263 0.036 0.068 7.228 0.020 0.037 56.541 0.155 0.290 16.115 0.044 0.083
2034 13.521 0.037 0.069 7.369 0.020 0.038 57.638 0.158 0.296 16.428 0.045 0.084
2035 13.307 0.036 0.068 7.252 0.020 0.037 56.729 0.155 0.291 16.169 0.044 0.083
2036 13.059 0.036 0.067 7.117 0.019 0.037 55.669 0.152 0.286 15.867 0.043 0.081
2037 12.805 0.035 0.066 6.979 0.019 0.036 54.588 0.150 0.280 15.559 0.043 0.080
2038 12.610 0.035 0.065 6.872 0.019 0.035 53.757 0.147 0.276 15.322 0.042 0.079
2039 12.375 0.034 0.063 6.744 0.018 0.035 52.756 0.145 0.271 15.037 0.041 0.077
2040 12.210 0.033 0.063 6.654 0.018 0.034 52.050 0.142 0.267 14.835 0.041 0.076
2041 12.032 0.033 0.062 6.557 0.018 0.034 51.293 0.141 0.263 14.620 0.040 0.075
2042 11.753 0.032 0.060 6.405 0.018 0.033 50.104 0.137 0.257 14.281 0.039 0.073
2043 - - - - - - - - - - - -
2044 - - - - - - - - - - - -
2045 - - - - - - - - - - - -
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 57.549 0.158 0.295 103.866 0.285 0.599 39.165 0.107 0.219 206.679 0.566 0.986
2024 59.725 0.163 0.306 113.002 0.309 0.652 44.550 0.122 0.249 264.859 0.724 1.189
2025 62.249 0.171 0.319 126.073 0.345 0.728 50.578 0.139 0.283 283.647 0.777 1.281
2026 63.264 0.173 0.325 110.587 0.303 0.638 45.961 0.126 0.257 276.830 0.758 1.242
2027 66.232 0.181 0.340 124.397 0.341 0.718 54.512 0.149 0.305 296.578 0.813 1.350
2028 71.002 0.194 0.364 136.261 0.372 0.786 63.784 0.174 0.356 322.386 0.881 1.472
2029 76.647 0.210 0.393 145.375 0.398 0.839 71.380 0.196 0.399 349.720 0.958 1.598
2030 81.566 0.223 0.418 151.288 0.414 0.873 77.633 0.213 0.434 370.680 1.016 1.696
2031 86.302 0.236 0.443 150.738 0.413 0.870 80.537 0.221 0.450 383.616 1.051 1.753
2032 90.168 0.246 0.463 150.290 0.411 0.867 80.504 0.220 0.449 392.175 1.072 1.792
2033 93.147 0.255 0.478 143.926 0.394 0.831 76.701 0.210 0.429 388.001 1.063 1.772
2034 94.955 0.260 0.487 135.240 0.371 0.781 70.810 0.194 0.396 377.199 1.033 1.722
2035 93.458 0.256 0.479 124.138 0.340 0.716 64.929 0.178 0.363 356.938 0.978 1.628
2036 91.711 0.251 0.470 115.815 0.316 0.668 59.092 0.161 0.330 342.007 0.934 1.552
2037 89.930 0.246 0.461 104.797 0.287 0.605 51.757 0.142 0.289 316.245 0.866 1.430
2038 88.561 0.243 0.454 90.953 0.249 0.525 45.314 0.124 0.253 285.790 0.783 1.294
2039 86.913 0.238 0.446 81.607 0.224 0.471 40.492 0.111 0.226 256.938 0.704 1.170
2040 85.750 0.234 0.440 75.886 0.207 0.438 37.118 0.101 0.207 240.270 0.656 1.093
2041 84.503 0.232 0.433 67.701 0.185 0.391 32.719 0.090 0.183 217.858 0.597 0.991
2042 82.543 0.226 0.423 64.803 0.178 0.374 32.156 0.088 0.180 209.660 0.574 0.951
2043 - - - 51.769 0.142 0.299 28.171 0.077 0.157 55.810 0.153 0.297
2044 - - - 46.021 0.126 0.266 26.337 0.072 0.147 52.961 0.145 0.283
2045 - - - 43.100 0.118 0.249 25.585 0.070 0.143 52.309 0.143 0.279
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.6: ANNUAL, AVERAGE DAY, AND PEAK DAY DSM – HIGH PRICES AND
HIGH VOLUMES (MDTH)

Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 8.196 0.022 0.042 4.467 0.012 0.023 34.938 0.096 0.179 9.958 0.027 0.051
2024 8.506 0.023 0.044 4.636 0.013 0.024 36.261 0.099 0.186 10.335 0.028 0.053
2025 8.865 0.024 0.045 4.832 0.013 0.025 37.793 0.104 0.194 10.772 0.030 0.055
2026 9.010 0.025 0.046 4.910 0.013 0.025 38.409 0.105 0.197 10.947 0.030 0.056
2027 9.431 0.026 0.048 5.140 0.014 0.026 40.202 0.110 0.206 11.458 0.031 0.059
2028 10.250 0.028 0.053 5.586 0.015 0.029 43.697 0.119 0.224 12.455 0.034 0.064
2029 11.183 0.031 0.057 6.095 0.017 0.031 47.673 0.131 0.245 13.588 0.037 0.070
2030 11.999 0.033 0.062 6.540 0.018 0.034 51.154 0.140 0.262 14.580 0.040 0.075
2031 12.676 0.035 0.065 6.908 0.019 0.035 54.036 0.148 0.277 15.401 0.042 0.079
2032 13.314 0.036 0.068 7.256 0.020 0.037 56.759 0.155 0.291 16.177 0.044 0.083
2033 13.740 0.038 0.070 7.488 0.021 0.038 58.572 0.160 0.300 16.694 0.046 0.086
2034 14.072 0.039 0.072 7.669 0.021 0.039 59.988 0.164 0.308 17.098 0.047 0.088
2035 13.833 0.038 0.071 7.539 0.021 0.039 58.971 0.162 0.303 16.808 0.046 0.086
2036 13.639 0.037 0.070 7.433 0.020 0.038 58.144 0.159 0.298 16.572 0.045 0.085
2037 13.379 0.037 0.069 7.292 0.020 0.037 57.036 0.156 0.293 16.256 0.045 0.083
2038 13.285 0.036 0.068 7.240 0.020 0.037 56.635 0.155 0.291 16.142 0.044 0.083
2039 13.034 0.036 0.067 7.103 0.019 0.036 55.563 0.152 0.285 15.837 0.043 0.081
2040 12.967 0.035 0.067 7.067 0.019 0.036 55.278 0.151 0.284 15.756 0.043 0.081
2041 12.863 0.035 0.066 7.010 0.019 0.036 54.836 0.150 0.281 15.629 0.043 0.080
2042 12.635 0.035 0.065 6.886 0.019 0.035 53.862 0.148 0.276 15.352 0.042 0.079
2043 - - - - - - - - - - - -
2044 - - - - - - - - - - - -
2045 - - - - - - - - - - - -
Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day Annual Daily Peak Day
2023 57.559 0.158 0.295 116.782 0.320 0.674 81.479 0.223 0.455 250.316 0.686 1.230
2024 59.738 0.163 0.306 128.765 0.352 0.743 93.750 0.256 0.523 315.510 0.862 1.472
2025 62.262 0.171 0.319 145.821 0.400 0.842 108.215 0.296 0.605 343.347 0.941 1.615
2026 63.277 0.173 0.325 133.918 0.367 0.773 107.617 0.295 0.601 340.876 0.934 1.600
2027 66.231 0.181 0.340 154.203 0.422 0.890 123.992 0.340 0.693 368.902 1.011 1.754
2028 71.989 0.197 0.369 171.870 0.470 0.992 140.425 0.384 0.783 402.753 1.100 1.921
2029 78.539 0.215 0.403 187.574 0.514 1.083 154.764 0.424 0.865 438.194 1.201 2.092
2030 84.272 0.231 0.432 198.537 0.544 1.146 164.028 0.449 0.917 463.602 1.270 2.214
2031 89.021 0.244 0.457 200.106 0.548 1.155 164.883 0.452 0.921 475.080 1.302 2.263
2032 93.506 0.255 0.480 199.700 0.546 1.153 159.950 0.437 0.892 479.825 1.311 2.280
2033 96.494 0.264 0.495 191.143 0.524 1.103 147.576 0.404 0.825 467.622 1.281 2.216
2034 98.826 0.271 0.507 178.759 0.490 1.032 131.539 0.360 0.735 447.706 1.227 2.115
2035 97.152 0.266 0.498 163.955 0.449 0.946 116.488 0.319 0.651 418.085 1.145 1.969
2036 95.788 0.262 0.491 153.985 0.421 0.889 103.396 0.283 0.577 395.973 1.082 1.852
2037 93.963 0.257 0.482 139.444 0.382 0.805 90.323 0.247 0.505 363.913 0.997 1.695
2038 93.303 0.256 0.479 121.922 0.334 0.704 77.917 0.213 0.435 327.564 0.897 1.526
2039 91.537 0.251 0.470 110.153 0.302 0.636 69.678 0.191 0.389 295.003 0.808 1.381
2040 91.068 0.249 0.467 101.423 0.277 0.585 64.112 0.175 0.358 276.188 0.755 1.292
2041 90.338 0.248 0.463 90.776 0.249 0.524 56.924 0.156 0.318 250.972 0.688 1.173
2042 88.735 0.243 0.455 84.966 0.233 0.490 55.459 0.152 0.310 241.874 0.663 1.128
2043 - - - 70.480 0.193 0.407 49.282 0.135 0.275 79.216 0.217 0.428
2044 - - - 64.969 0.178 0.375 47.953 0.131 0.268 76.977 0.210 0.417
2045 - - - 62.260 0.171 0.359 47.656 0.131 0.266 76.892 0.211 0.416
Klamath Falls La Grande Medford Roseburg
Oregon Washington Idaho System
APPENDIX - CHAPTER 2

APPENDIX 2.7: DETAILED DEMAND DATA (MDTH, NET OF DSM) – CASE PRS

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 3,607 3,660 3,671 3,690 3,702 3,734 3,716 3,714 3,722 3,740 3,733 3,733
ID_Ind 226 227 226 225 225 225 224 223 222 222 221 221
ID_Res 6,607 6,758 6,827 6,940 7,029 7,158 7,188 7,255 7,350 7,460 7,520 7,595
Klamath Falls_Com_Current 475 476 473 472 470 470 465 463 461 461 458 455
Klamath Falls_Com_New 2 5 7 10 13 16 18 21 23 26 29 31
Klamath Falls_Ind 14 15 14 15 15 15 15 15 15 15 15 15
Klamath Falls_Res_Current 958 960 954 951 946 945 934 927 924 921 913 907
Klamath Falls_Res_New 4 12 20 27 34 40 45 51 56 61 66 71
LaGrande_Com_Current 318 320 319 319 319 320 319 318 318 319 318 317
LaGrande_Com_New 1 2 4 5 6 8 9 11 13 14 15 17
LaGrande_Ind 83 85 85 86 86 87 88 88 89 90 90 91
LaGrande_Res_Current 495 497 495 495 495 497 494 492 492 492 490 489
LaGrande_Res_New 1 4 7 10 13 16 19 22 25 28 30 33
Medford_Com_Current 2,178 2,194 2,194 2,201 2,206 2,217 2,210 2,211 2,219 2,228 2,226 2,225
Medford_Com_New 9 30 52 75 96 118 138 159 180 201 220 240
Medford_Ind 22 23 23 23 24 24 24 25 25 25 26 26
Medford_Res_Current 3,515 3,541 3,541 3,555 3,562 3,578 3,561 3,559 3,572 3,581 3,574 3,569
Medford_Res_New 19 68 120 172 221 271 318 366 414 462 508 553
OR_Tport 4,441 4,425 4,424 4,424 4,423 4,421 4,420 4,419 4,418 4,418 4,419 4,420
Roseburg_Com_Current 662 669 670 673 676 680 679 680 684 689 689 691
Roseburg_Com_New 1 2 3 5 6 7 9 10 11 13 14 16
Roseburg_Ind 2 3 2 3 3 3 3 3 3 3 3 3
Roseburg_Res_Current 838 847 849 854 857 863 860 861 866 871 872 873
Roseburg_Res_New 2 6 11 16 20 25 30 34 39 43 47 52
WA_Com_Current 7,084 7,100 7,040 7,026 6,998 7,017 6,938 6,898 6,884 6,882 6,834 6,801
WA_Com_New 7 25 43 59 77 95 109 123 141 157 172 186
WA_Ind 227 227 226 226 225 225 224 223 222 222 221 221
WA_Res_Current 12,077 12,113 12,007 11,987 11,941 11,972 11,826 11,756 11,734 11,737 11,658 11,603
WA_Res_New 41 138 233 322 415 506 578 651 744 823 904 974
WA_Tport 2,479 2,451 2,448 2,448 2,448 2,443 2,435 2,430 2,426 2,424 2,425 2,427
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 3,746 3,786 3,788 3,787 3,796 3,808 3,803 3,804 3,805 3,831 3,826
ID_Ind 221 221 221 220 220 220 219 218 219 220 219
ID_Res 7,698 7,860 7,939 7,999 8,090 8,188 8,248 8,333 8,416 8,573 8,652
Klamath Falls_Com_Current 456 458 457 455 454 455 453 452 453 455 453
Klamath Falls_Com_New 33 36 39 41 43 46 49 51 53 56 58
Klamath Falls_Ind 15 15 15 15 15 15 15 15 15 15 15
Klamath Falls_Res_Current 907 912 907 904 901 901 897 893 901 905 901
Klamath Falls_Res_New 76 81 86 91 96 101 105 110 114 119 123
LaGrande_Com_Current 317 320 319 318 318 319 318 317 317 319 317
LaGrande_Com_New 18 20 21 23 24 26 27 28 30 31 33
LaGrande_Ind 92 92 93 93 94 94 95 95 95 95 95
LaGrande_Res_Current 489 493 491 490 489 490 488 487 490 493 490
LaGrande_Res_New 36 39 42 44 47 50 52 55 58 61 63
Medford_Com_Current 2,241 2,265 2,269 2,274 2,280 2,293 2,293 2,299 2,302 2,312 2,302
Medford_Com_New 261 283 303 322 342 362 381 400 417 437 453
Medford_Ind 26 26 26 26 27 27 27 27 28 28 28
Medford_Res_Current 3,594 3,635 3,643 3,649 3,656 3,677 3,676 3,685 3,712 3,730 3,713
Medford_Res_New 602 655 701 747 793 841 885 930 970 1,018 1,055
OR_Tport 4,422 4,423 4,425 4,427 4,430 4,431 4,432 4,433 4,457 4,457 4,457
Roseburg_Com_Current 697 706 709 712 715 720 721 725 725 728 725
Roseburg_Com_New 17 18 20 21 23 24 25 27 28 29 30
Roseburg_Ind 3 3 3 3 3 3 3 3 3 3 3
Roseburg_Res_Current 881 894 899 902 906 912 914 919 927 931 927
Roseburg_Res_New 56 61 66 70 75 80 84 89 93 97 101
WA_Com_Current 6,796 6,841 6,816 6,784 6,776 6,775 6,743 6,725 6,708 6,741 6,707
WA_Com_New 202 223 238 248 262 278 290 303 315 335 346
WA_Ind 221 221 221 220 219 219 218 218 219 219 219
WA_Res_Current 11,593 11,672 11,618 11,546 11,516 11,501 11,428 11,390 11,353 11,415 11,358
WA_Res_New 1,053 1,164 1,237 1,285 1,354 1,435 1,494 1,557 1,615 1,714 1,769
WA_Tport 2,432 2,434 2,440 2,450 2,461 2,466 2,473 2,474 2,510 2,510 2,510
APPENDIX - CHAPTER 2

APPENDIX 2.7: DETAILED DEMAND DATA (MDTH, NET OF DSM) – CASE AVERAGE

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 3,557 3,613 3,634 3,662 3,683 3,720 3,723 3,738 3,754 3,787 3,789 3,807
ID_Ind 225 226 225 225 225 226 225 225 225 226 225 225
ID_Res 6,502 6,660 6,751 6,879 6,989 7,127 7,204 7,313 7,425 7,573 7,658 7,777
Klamath Falls_Com_Current 469 471 469 469 469 471 469 468 468 471 468 468
Klamath Falls_Com_New 2 5 7 10 13 16 19 21 24 27 29 32
Klamath Falls_Ind 14 14 14 14 14 15 15 15 15 15 15 15
Klamath Falls_Res_Current 945 950 945 945 944 948 943 942 942 946 941 940
Klamath Falls_Res_New 3 12 20 27 34 40 46 51 57 63 68 73
LaGrande_Com_Current 313 314 313 313 313 314 313 313 312 314 312 312
LaGrande_Com_New 1 2 4 5 6 8 9 11 12 14 15 17
LaGrande_Ind 83 83 83 83 83 83 83 83 83 83 83 83
LaGrande_Res_Current 486 488 486 486 486 488 485 485 484 486 484 484
LaGrande_Res_New 1 4 7 10 13 16 19 21 24 27 30 33
Medford_Com_Current 2,142 2,151 2,141 2,141 2,140 2,149 2,139 2,138 2,138 2,147 2,138 2,138
Medford_Com_New 8 29 51 73 93 114 134 153 173 193 212 231
Medford_Ind 21 23 23 23 23 23 24 24 24 24 24 24
Medford_Res_Current 3,442 3,457 3,439 3,439 3,437 3,451 3,431 3,429 3,426 3,441 3,422 3,420
Medford_Res_New 18 66 116 166 213 261 306 352 397 444 486 530
OR_Tport 4,441 4,425 4,424 4,424 4,423 4,421 4,420 4,419 4,418 4,418 4,419 4,420
Roseburg_Com_Current 648 651 648 648 647 650 647 647 647 650 647 647
Roseburg_Com_New 0 2 3 5 6 7 8 10 11 12 13 15
Roseburg_Ind 2 3 2 3 3 3 3 3 3 3 3 3
Roseburg_Res_Current 816 819 815 815 814 818 813 812 811 815 810 809
Roseburg_Res_New 2 6 11 15 19 24 28 32 36 40 44 48
WA_Com_Current 6,974 6,997 6,961 6,964 6,957 6,983 6,947 6,944 6,943 6,972 6,943 6,945
WA_Com_New 8 25 43 61 78 96 113 130 148 166 182 200
WA_Ind 225 226 225 225 225 226 225 225 225 226 225 225
WA_Res_Current 11,877 11,927 11,865 11,875 11,867 11,911 11,844 11,842 11,844 11,904 11,860 11,871
WA_Res_New 42 139 235 329 420 512 599 688 778 873 957 1,046
WA_Tport 2,479 2,451 2,448 2,448 2,448 2,443 2,435 2,430 2,426 2,424 2,425 2,427
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 3,826 3,862 3,866 3,886 3,905 3,938 3,938 3,950 3,963 3,991 3,988
ID_Ind 225 226 225 225 225 226 225 225 226 227 226
ID_Res 7,896 8,048 8,131 8,247 8,362 8,513 8,591 8,708 8,828 8,989 9,078
Klamath Falls_Com_Current 469 471 469 470 470 472 470 470 473 475 473
Klamath Falls_Com_New 34 37 40 42 45 48 50 53 55 58 61
Klamath Falls_Ind 15 15 15 15 15 15 15 15 15 15 15
Klamath Falls_Res_Current 940 945 940 940 940 945 940 940 949 954 949
Klamath Falls_Res_New 79 84 89 94 100 106 110 116 120 126 130
LaGrande_Com_Current 313 314 313 313 313 315 314 314 315 316 315
LaGrande_Com_New 18 20 21 22 24 25 27 28 30 31 32
LaGrande_Ind 83 83 83 83 83 83 83 83 83 84 83
LaGrande_Res_Current 484 486 483 483 483 485 483 483 489 491 489
LaGrande_Res_New 36 39 41 44 47 50 52 55 57 60 63
Medford_Com_Current 2,140 2,151 2,142 2,144 2,145 2,155 2,146 2,147 2,156 2,166 2,156
Medford_Com_New 249 269 286 304 322 340 356 373 391 410 424
Medford_Ind 24 25 24 25 25 25 25 25 26 26 26
Medford_Res_Current 3,420 3,436 3,419 3,419 3,418 3,435 3,418 3,419 3,459 3,476 3,459
Medford_Res_New 573 619 658 700 742 786 823 864 904 948 982
OR_Tport 4,422 4,423 4,425 4,427 4,430 4,431 4,432 4,433 4,457 4,457 4,457
Roseburg_Com_Current 647 651 648 648 649 652 649 649 652 655 652
Roseburg_Com_New 16 17 18 19 21 22 23 24 25 26 27
Roseburg_Ind 3 3 3 3 3 3 3 3 3 3 3
Roseburg_Res_Current 809 813 809 809 809 813 809 809 820 824 820
Roseburg_Res_New 52 56 59 63 67 71 75 78 82 86 89
WA_Com_Current 6,951 6,987 6,965 6,975 6,984 7,021 6,999 7,003 7,009 7,040 7,010
WA_Com_New 217 236 252 269 286 306 321 338 355 375 390
WA_Ind 225 226 225 225 226 226 226 226 227 228 227
WA_Res_Current 11,880 11,941 11,891 11,896 11,896 11,949 11,895 11,895 11,900 11,959 11,909
WA_Res_New 1,134 1,230 1,310 1,397 1,484 1,581 1,657 1,743 1,828 1,926 1,999
WA_Tport 2,432 2,434 2,440 2,450 2,461 2,466 2,473 2,474 2,510 2,510 2,510
APPENDIX - CHAPTER 2

APPENDIX 2.7: DETAILED DEMAND DATA (MDTH, NET OF DSM) – CASE
ELECTRIFICATION

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 3,607 3,660 3,671 3,690 3,702 3,734 3,716 3,714 3,722 3,740 3,733 3,733
ID_Ind 226 227 226 225 225 225 224 223 222 222 221 221
ID_Res 6,607 6,758 6,827 6,940 7,029 7,158 7,188 7,255 7,350 7,460 7,520 7,595
Klamath Falls_Com_Current 477 481 468 457 446 437 424 413 404 395 385 375
Klamath Falls_Com_New - - - - - - - - - - - -
Klamath Falls_Ind 14 15 14 15 15 15 12 12 12 12 12 12
Klamath Falls_Res_Current 962 972 946 924 901 882 854 831 811 792 770 749
Klamath Falls_Res_New - - - - - - - - - - - -
LaGrande_Com_Current 319 322 315 308 302 297 290 283 278 272 266 260
LaGrande_Com_New - - - - - - - - - - - -
LaGrande_Ind 83 85 85 84 83 81 80 78 73 72 70 71
LaGrande_Res_Current 496 501 489 480 470 462 450 439 430 422 412 402
LaGrande_Res_New - - - - - - - - - - - -
Medford_Com_Current 2,187 2,224 2,179 2,143 2,104 2,072 2,023 1,983 1,951 1,919 1,878 1,840
Medford_Com_New - - - - - - - - - - - -
Medford_Ind 22 23 23 22 22 22 23 21 21 22 22 20
Medford_Res_Current 3,534 3,609 3,537 3,479 3,416 3,362 3,278 3,210 3,156 3,101 3,032 2,965
Medford_Res_New - - - - - - - - - - - -
OR_Tport 4,441 4,425 4,424 4,424 4,423 4,421 4,420 4,419 4,418 4,418 4,419 4,420
Roseburg_Com_Current 663 671 658 648 638 629 615 604 595 587 575 565
Roseburg_Com_New - - - - - - - - - - - -
Roseburg_Ind 2 3 2 3 3 3 3 3 3 3 3 3
Roseburg_Res_Current 840 854 838 826 813 801 782 767 757 745 730 717
Roseburg_Res_New - - - - - - - - - - - -
WA_Com_Current 7,084 7,100 6,898 6,745 6,582 6,466 6,264 6,101 5,965 5,842 5,684 5,541
WA_Com_New - - - - - - - - - - - -
WA_Ind 227 227 221 216 213 208 202 199 194 189 185 180
WA_Res_Current 12,148 12,353 11,999 11,739 11,458 11,256 10,894 10,611 10,378 10,172 9,901 9,658
WA_Res_New - - - - - - - - - - - -
WA_Tport 2,479 2,451 2,448 2,448 2,448 2,443 2,435 2,430 2,426 2,424 2,425 2,427
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 3,746 3,786 3,788 3,787 3,796 3,808 3,803 3,804 3,805 3,831 3,826
ID_Ind 221 221 221 220 220 220 219 218 219 220 219
ID_Res 7,698 7,860 7,939 7,999 8,090 8,188 8,248 8,333 8,416 8,573 8,652
Klamath Falls_Com_Current 368 362 354 346 338 332 324 316 312 307 299
Klamath Falls_Com_New - - - - - - - - - - -
Klamath Falls_Ind 12 12 12 12 10 10 10 10 10 10 10
Klamath Falls_Res_Current 734 722 704 687 671 658 641 626 621 612 597
Klamath Falls_Res_New - - - - - - - - - - -
LaGrande_Com_Current 255 252 247 241 236 232 226 221 218 214 209
LaGrande_Com_New - - - - - - - - - - -
LaGrande_Ind 71 71 71 71 70 70 70 68 66 66 62
LaGrande_Res_Current 394 389 380 371 363 356 347 340 337 332 323
LaGrande_Res_New - - - - - - - - - - -
Medford_Com_Current 1,816 1,798 1,766 1,734 1,704 1,679 1,646 1,617 1,590 1,564 1,527
Medford_Com_New - - - - - - - - - - -
Medford_Ind 20 20 20 21 19 19 19 19 20 18 18
Medford_Res_Current 2,926 2,899 2,847 2,794 2,742 2,702 2,646 2,599 2,577 2,537 2,475
Medford_Res_New - - - - - - - - - - -
OR_Tport 4,422 4,423 4,425 4,427 4,430 4,431 4,432 4,433 4,457 4,457 4,457
Roseburg_Com_Current 559 555 546 537 529 522 512 504 495 488 476
Roseburg_Com_New - - - - - - - - - - -
Roseburg_Ind 3 3 3 3 1 1 1 1 2 2 2
Roseburg_Res_Current 709 705 694 682 671 662 650 640 636 626 611
Roseburg_Res_New - - - - - - - - - - -
WA_Com_Current 5,426 5,352 5,227 5,099 4,993 4,893 4,774 4,667 4,563 4,493 4,381
WA_Com_New - - - - - - - - - - -
WA_Ind 178 173 170 165 162 157 154 152 148 146 143
WA_Res_Current 9,457 9,331 9,102 8,865 8,664 8,479 8,256 8,063 7,877 7,763 7,570
WA_Res_New - - - - - - - - - - -
WA_Tport 2,432 2,434 2,440 2,450 2,461 2,466 2,473 2,474 2,510 2,510 2,510
APPENDIX - CHAPTER 2

APPENDIX 2.7: DETAILED DEMAND DATA (MDTH, NET OF DSM) – CASE HYBRID

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 3,607 3,660 3,671 3,690 3,702 3,734 3,716 3,714 3,722 3,740 3,733 3,733
ID_Ind 226 227 226 225 225 225 224 223 222 222 221 221
ID_Res 6,607 6,758 6,827 6,940 7,029 7,158 7,188 7,255 7,350 7,460 7,520 7,595
Klamath Falls_Com_Current 477 481 468 457 446 437 424 413 404 395 385 375
Klamath Falls_Com_New - - 6 12 18 24 28 33 38 42 45 50
Klamath Falls_Ind 14 15 14 15 15 15 12 12 12 12 12 12
Klamath Falls_Res_Current 962 972 946 924 901 882 854 831 811 792 770 749
Klamath Falls_Res_New - - 16 31 45 59 69 81 91 101 109 119
LaGrande_Com_Current 319 322 315 308 302 297 290 283 278 272 266 260
LaGrande_Com_New - - 3 7 10 14 17 20 23 26 29 31
LaGrande_Ind 83 85 85 84 83 81 80 78 73 72 70 71
LaGrande_Res_Current 496 501 489 480 470 462 450 439 430 422 412 402
LaGrande_Res_New - - 6 12 18 24 29 34 39 45 50 54
Medford_Com_Current 2,187 2,224 2,179 2,143 2,104 2,072 2,023 1,983 1,951 1,919 1,878 1,840
Medford_Com_New - - 12 22 33 41 49 55 68 73 82 68
Medford_Ind 22 23 23 22 22 22 23 21 21 22 22 20
Medford_Res_Current 3,534 3,609 3,537 3,479 3,416 3,362 3,278 3,210 3,156 3,101 3,032 2,965
Medford_Res_New - - 28 53 80 99 119 131 164 176 196 164
OR_Tport 4,441 4,425 4,424 4,424 4,423 4,421 4,420 4,419 4,418 4,418 4,419 4,420
Roseburg_Com_Current 663 671 658 648 638 629 615 604 595 587 575 565
Roseburg_Com_New - - 1 1 2 3 4 4 7 9 10 10
Roseburg_Ind 2 3 2 3 3 3 3 3 3 3 3 3
Roseburg_Res_Current 840 854 838 826 813 801 782 767 757 745 730 717
Roseburg_Res_New - - 1 3 4 6 8 8 14 17 20 20
WA_Com_Current 7,084 7,100 6,898 6,745 6,582 6,466 6,264 6,101 5,965 5,842 5,684 5,541
WA_Com_New 7 25 119 207 298 388 461 533 618 693 767 832
WA_Ind 227 227 221 216 213 208 202 199 194 189 185 180
WA_Res_Current 12,148 12,353 11,999 11,739 11,458 11,256 10,894 10,611 10,378 10,172 9,901 9,658
WA_Res_New - - 239 464 694 921 1,107 1,291 1,510 1,701 1,892 2,060
WA_Tport 2,479 2,451 2,448 2,448 2,448 2,443 2,435 2,430 2,426 2,424 2,425 2,427
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 3,746 3,786 3,788 3,787 3,796 3,808 3,803 3,804 3,805 3,831 3,826
ID_Ind 221 221 221 220 220 220 219 218 219 220 219
ID_Res 7,698 7,860 7,939 7,999 8,090 8,188 8,248 8,333 8,416 8,573 8,652
Klamath Falls_Com_Current 368 362 354 346 338 332 324 316 312 307 299
Klamath Falls_Com_New 54 59 63 67 71 75 78 82 85 90 93
Klamath Falls_Ind 12 12 12 12 10 10 10 10 10 10 10
Klamath Falls_Res_Current 734 722 704 687 671 658 641 626 621 612 597
Klamath Falls_Res_New 129 141 151 160 168 178 185 194 201 213 221
LaGrande_Com_Current 255 252 247 241 236 232 226 221 218 214 209
LaGrande_Com_New 34 37 40 42 44 47 49 52 54 57 59
LaGrande_Ind 71 71 71 71 70 70 70 68 66 66 62
LaGrande_Res_Current 394 389 380 371 363 356 347 340 337 332 323
LaGrande_Res_New 59 64 68 72 76 81 85 90 93 98 100
Medford_Com_Current 1,816 1,798 1,766 1,734 1,704 1,679 1,646 1,617 1,590 1,564 1,527
Medford_Com_New 74 87 99 102 103 125 136 139 130 136 145
Medford_Ind 20 20 20 21 19 19 19 19 20 18 18
Medford_Res_Current 2,926 2,899 2,847 2,794 2,742 2,702 2,646 2,599 2,577 2,537 2,475
Medford_Res_New 178 210 238 246 249 303 328 336 315 329 352
OR_Tport 4,422 4,423 4,425 4,427 4,430 4,431 4,432 4,433 4,457 4,457 4,457
Roseburg_Com_Current 559 555 546 537 529 522 512 504 495 488 476
Roseburg_Com_New 12 13 15 15 20 24 30 34 32 33 35
Roseburg_Ind 3 3 3 3 1 1 1 1 2 2 2
Roseburg_Res_Current 709 705 694 682 671 662 650 640 636 626 611
Roseburg_Res_New 23 25 27 28 37 45 56 64 59 62 66
WA_Com_Current 5,426 5,352 5,227 5,099 4,993 4,893 4,774 4,667 4,563 4,493 4,381
WA_Com_New 902 999 1,063 1,106 1,166 1,234 1,283 1,335 1,382 1,463 1,505
WA_Ind 178 173 170 165 162 157 154 152 148 146 143
WA_Res_Current 9,457 9,331 9,102 8,865 8,664 8,479 8,256 8,063 7,877 7,763 7,570
WA_Res_New 2,243 2,492 2,659 2,773 2,929 3,108 3,237 3,374 3,499 3,713 3,826
WA_Tport 2,432 2,434 2,440 2,450 2,461 2,466 2,473 2,474 2,510 2,510 2,510
1 | APPENDIX 3.1: ID AND WA FIRM-CUSTOMERS CPA

Prepared For: Avista Corporation
By: Applied Energy Group, Inc.
Date: December 21, 2022
AEG Key Contact: Eli Morris

AVISTA NATURAL GAS CONSERVATION
POTENTIAL ASSESSMENT FOR 2023-2045

This work was performed by
Applied Energy Group, Inc. (AEG)
2300 Clayton Road, Suite 1370
Concord, CA 94520
Project Director: E. Morris
Project Manager: A. Hudson

Project Team:
K. Marrin
K. Walter
F. Nguyen
T. Williams
K. Billeci
S. Chen
L. Khan
C. Struthers

Applied Energy Group, Inc. | appliedenergygroup.com 1
CONTENTS
1 | INTRODUCTION ........................................................................................................ 1
Summary of Report Contents.............................................................................................................. 1
Abbreviations and Acronyms .............................................................................................................. 3
2 | ENERGY EFFICIENCY ANALYSIS APPROACH AND DATA DEVELOPMENT .............................. 4
Overview of Analysis Approach .......................................................................................................... 4
Data Development. 11
Data Application………………………………………………………………………………………………………………………………13
3 | ENERGY EFFICIENCY MARKET CHARACTERIZATION ...................................................... 18
Energy Use Summary ....................................................................................................................... 18
Residential Sector.. 19
Commercial Sector. 25
Industrial Sector….. 30
4 | BASELINE PROJECTION ............................................................................................ 33
Overall Baseline Projection .............................................................................................................. 33
Residential Sector… 34
Commercial Sector. 36
Industrial Sector….. 38
5 | CONSERVATION POTENTIAL ..................................................................................... 41
Washington Overall Energy Efficiency Potential ................................................................................ 41
Idaho Overall Energy Efficiency Potential .......................................................................................... 43
6 | SECTOR-LEVEL ENERGY EFFICIENCY POTENTIAL .......................................................... 46
Residential Sector.. 46
Commercial Sector. 51
Industrial Sector….. 57
7 | DEMAND RESPONSE POTENTIAL ............................................................................... 63
Study Approach…… 63
Market Characterization ................................................................................................................... 63
Baseline Forecast… 64
Characterize Demand Response Program Options ............................................................................. 65
Integrated DR Potential Results ........................................................................................................ 68
DEMAND RESPONSE POTENTIAL APPENDIX ................................................................ 73
Equipment End Use Saturation ......................................................................................................... 73
Mechanism and Event Hours ............................................................................................................ 74

Applied Energy Group, Inc. | appliedenergygroup.com 2
LIST OF FIGURES
Figure 2-1 LoadMAP Analysis Framework ............................................................................................. 6
Figure 2-2 Approach for Measure Development ................................................................................. 10
Figure 3-1 Avista Sector-Level Natural Gas Use (2021) ........................................................................ 18
Figure 3-2 Residential Natural Gas Use by Segment, Washington, 2021 ............................................... 19
Figure 3-3 Residential Natural Gas Use by End Use, Washington, 2021 ................................................ 20
Figure 3-4 Residential Energy Intensity by End Use and Segment, Washington, 2021 ............................ 21
Figure 3-5 Residential Natural Gas Use by Segment, Idaho, 2021 ......................................................... 22
Figure 3-6 Residential Natural Gas Use by End Use, Idaho, 2021 .......................................................... 23
Figure 3-7 Residential Energy Intensity by End Use and Segment, Idaho, 202021 (Annual Therms/HH) .. 23
Figure 3-8 Commercial Natural Gas Use by Segment, Washington, 2021 .............................................. 26
Figure 3-9 Commercial Sector Natural Gas Use by End Use, Washington, 2021 ..................................... 26
Figure 3-10 Commercial Energy Usage Intensity by End Use and Segment, Washington, 2021 ................. 27
Figure 3-11 Commercial Natural Gas Use by Segment, Idaho, 2021 ........................................................ 28
Figure 3-12 Commercial Sector Natural Gas Use by End Use, Idaho, 2021 .............................................. 29
Figure 3-13 Commercial Energy Usage Intensity by End Use and Segment, Idaho, 2021 .......................... 29
Figure 3-14 Industrial Natural Gas Use by End Use, Washington, 2021 ................................................... 31
Figure 3-15 Industrial Natural Gas Use by End Use, Idaho, 2021 ............................................................ 32
Figure 4-1 Baseline Projection Summary by Sector, Washington .......................................................... 33
Figure 4-2 Baseline Projection Summary by Sector, Idaho ................................................................... 34
Figure 4-3 Residential Baseline Projection by End Use, Washington ..................................................... 35
Figure 4-4 Residential Baseline Projection by End Use, Idaho .............................................................. 36
Figure 4-5 Commercial Baseline Projection by End Use, Washington .................................................... 37
Figure 4-6 Commercial Baseline Projection by End Use, Idaho ............................................................. 38
Figure 4-7 Industrial Baseline Projection by End Use, Washington ....................................................... 39
Figure 4-8 Industrial Baseline Projection by End Use, Idaho ................................................................ 40
Figure 5-1 Cumulative Energy Efficiency Potential as % of Baseline Projection, Washington .................. 42
Figure 5-2 Baseline Projection and Energy Efficiency Forecasts, Washington ........................................ 43
Figure 5-3 Cumulative Energy Efficiency Potential as % of Baseline Projection, Idaho ........................... 44
Figure 5-4 Baseline Projection and Energy Efficiency Forecasts, Idaho ................................................. 45
Figure 6-1 Cumulative Residential Potential as % of Baseline Projection, Washington .......................... 46
Figure 6-2 Residential TRC Achievable Economic Potential – Cumulative Savings by End Use, Washington.
47
Figure 6-3 Cumulative Residential Potential as % of Baseline Projection, Idaho ................................... 49
Figure 6-4 Residential UCT Achievable Economic Potential – Cumulative Savings by End Use,
Idaho…………………………………………………………………………………………………………………………………50
Figure 6-5 Cumulative Commercial Potential as % of Baseline Projection, Washington ......................... 52
Figure 6-6 Commercial TRC Achievable Economic Potential – Cumulative Savings by End Use,
Washington…. .................................................................................................................. 53
Figure 6-7 Cumulative Commercial Potential as % of Baseline Projection, Idaho .................................. 55
Figure 6-8 Commercial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Idaho………………………………………………………………………………………………………………………………….56

Applied Energy Group, Inc. | appliedenergygroup.com 3
Figure 6-9 Cumulative Industrial Potential as % of Baseline Projection, Washington ............................ 58
Figure 6-10 Industrial TRC Achievable Economic Potential – Cumulative Savings by End Use, Washington
……………………………………………………………………………………………………………………….59
Figure 6-11 Cumulative Industrial Potential as % of Baseline Projection, Idaho ...................................... 61
Figure 6-12 Industrial UCT Achievable Economic Potential – Cumulative Savings by End Use,
Idaho…………………………………………………………………………………………………………………………………62
Figure 7-1 Demand Response Analysis Approach ................................................................................ 63
Figure 7-2 Coincident Peak Load Forecast by State (Winter) ................................................................ 65
Figure 7-3 Summary of Integrated Potential (Dekatherms @Generator) ............................................... 68
Figure 7-4 Summary of Potential by Option – (Dekatherms @Generator) ............................................. 69
Figure 7-5 Potential by Class – (Dekatherms @Generator), Washington ............................................... 70
Figure 7-6 Potential by Class – (Dekatherms @Generator), Idaho ........................................................ 71
Figure 7-7 Potential by Class – (Dekatherms @Generator), Idaho ........................................................ 71
Figure A-1 Summary of Potential by Option – Stand Alone (Dekatherms @Generator) ......................... 75

Applied Energy Group, Inc. | appliedenergygroup.com 4
LIST OF TABLES
Table 1-1 Explanation of Abbreviations and Acronyms ........................................................................ 3
Table 2-1 Overview of Avista Analysis Segmentation Scheme............................................................... 8
Table 2-2 Number of Measures Evaluated ......................................................................................... 11
Table 2-3 Data Applied for the Market Profiles ................................................................................. 14
Table 2-4 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP .................... 14
Table 2-7 Residential Natural Gas Equipment Standards .................................................................... 15
Table 2-8 Commercial and Industrial Natural Gas Equipment Standards ............................................. 15
Table 2-9 Data Needs for the Measure Characteristics in LoadMAP .................................................... 16
Table 3-1 Residential Sector Control Totals, 2021 .............................................................................. 18
Table 3-2 Residential Sector Control Totals, Washington, 2021 .......................................................... 19
Table 3-3 Average Market Profile for the Residential Sector, Washington, 2021 .................................. 20
Table 3-4 Residential Sector Control Totals, Idaho, 2021 .................................................................... 22
Table 3-5 Average Market Profile for the Residential Sector, Idaho 2021 ............................................ 23
Table 3-6 Commercial Sector Control Totals, Washington, 2021 ......................................................... 25
Table 3-7 Average Market Profile for the Commercial Sector, Washington, 2021 ................................. 27
Table 3-8 Commercial Sector Control Totals, Idaho, 2021 ................................................................... 28
Table 3-9 Average Market Profile for the Commercial Sector, Idaho, 2021 .......................................... 30
Table 3-10 Industrial Sector Control Totals, 2021 ................................................................................ 30
Table 3-11 Average Natural Gas Market Profile for the Industrial Sector, Washington, 2021 .................. 31
Table 3-13 Average Natural Gas Market Profile for the Industrial Sector, Idaho, 2021 ........................... 32
Table 4-1 Baseline Projection Summary by Sector, Washington (dtherms) .......................................... 33
Table 4-2 Baseline Projection Summary by Sector, Idaho (dtherms) ................................................... 34
Table 4-3 Residential Baseline Projection by End Use, Washington (dtherms) ..................................... 35
Table 4-4 Residential Baseline Projection by End Use, Idaho (dtherms) .............................................. 36
Table 4-5 Commercial Baseline Projection by End Use, Washington (dtherms) .................................... 37
Table 4-6 Commercial Baseline Projection by End Use, Idaho (dtherms) ............................................. 38
Table 4-7 Industrial Baseline Projection by End Use, Washington (dtherms) ....................................... 39
Table 4-8 Industrial Baseline Projection by End Use, Idaho (dtherms) ................................................ 40
Table 5-1 Summary of Energy Efficiency Potential, Washington .......................................................... 42
Table 5-2 Summary of Energy Efficiency Potential, Idaho ................................................................... 44
Table 6-1 Residential Energy Conservation Potential Summary, Washington ....................................... 46
Table 6-2 Residential Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Washington.
48
Table 6-3 Residential Energy Conservation Potential Summary, Idaho ................................................ 49
Table 6-4 Residential Top Measures in 2023 and 2035, TRC Achievable Economic Potential,
Idaho………………………………………………………………………………………………………………………………….51
Table 6-5 Commercial Energy Conservation Potential Summary, Washington ...................................... 52
Table 6-6 Commercial Top Measures in 2023 and 2035, TRC Achievable Economic Potential,
Washington…. .................................................................................................................. 54
Table 6-7 Commercial Energy Conservation Potential Summary, Idaho ............................................... 55

Applied Energy Group, Inc. | appliedenergygroup.com 5
Table 6-8 Commercial Top Measures in 2023 and 2035, TRC Achievable Economic Potential,
Idaho………………………………………………………………………………………………………………………………….57
Table 6-9 Industrial Energy Conservation Potential Summary, Washington ......................................... 58
Table 6-10 Industrial Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Washington.60
Table 6-11 Industrial Energy Conservation Potential Summary, Idaho .................................................. 61
Table 6-12 Industrial Top Measures in 2023 and 2035, UCT Achievable Economic Potential,
Idaho………………………………………………………………………………………………………………………………….62
Table 7-1 Market Segmentation ....................................................................................................... 64
Table 7-2 Baseline Customer Forecast by Customer Class, Washington ............................................... 64
Table 7-3 Baseline Customer Forecast by Customer Class, Idaho ........................................................ 64
Table 7-4 Baseline Customer Forecast by Customer Class, Oregon ...................................................... 64
Table 7-5 Baseline February Winter System Peak Forecast (Dth @Generation) by State ....................... 65
Table 7-6 Steady-State Participation Rate Assumptions (% of eligible customers) ............................... 67
Table 7-7 DSM Per Participant Impact Assumptions........................................................................... 67
Table 7-8 Summary of Integrated Potential (Dekatherms @ Generator) .............................................. 68
Table 7-9 Summary of Potential by Option – (Dekatherms @ Generator) ............................................ 69
Table 7-10 Potential by Class – Dekatherms @Generator, Washington ................................................. 70
Table 7-11 Potential by Class – Dekatherms @Generator, Idaho ........................................................... 70
Table 7-12 Potential by Class – Dekatherms @Generator, Oregon ........................................................ 70
Table 7-13 Levelized Program Costs and Potential (TOU Opt-In Winter) ................................................ 72
Table A-1 End Use Saturations by Customer Class and State ............................................................... 74
Table A-2 DSM Program Event Hours ................................................................................................ 75
Table A-3 Summary of Potential by Option – Stand Alone (Dekatherms @ Generator) ........................ 75

Applied Energy Group, Inc. | appliedenergygroup.com 1
2 | INTRODUCTION
In October 2021, Avista Corporation (Avista) engaged Applied Energy Group (AEG) to conduct a Conservation
Potential Assessment (CPA) for its Washington and Idaho service areas. AEG first performed an electric CPA for
Avista in 2013; since then, AEG has performed both electric and natural gas CPAs for Avista’s planning cycles.
This study represents the first assessment of the potential for natural gas demand response resources within
Avista’s service area, including Oregon. The CPA is a 20-year study of electric and natural gas conservation
potential, performed in accordance with Washington Initiative 937 and associated Washington Administrative
Code provisions. This study provides data on conservation resources to support the development of Avista’s
2023 Integrated Resource Plan (IRP). For reporting purposes, the potential results are separated by fuel. This
report documents the natural gas CPA.
Notable updates from prior CPAs include:
• The analysis base year was brought forward from 2019 to 2021.
• For the residential sector, the study still incorporates Avista’s GenPOP residential saturation survey from
2012, which provides a more localized look at Avista’s customers than regional surveys. The survey provided
the foundation for the base year market characterization and energy market profiles. The Northwest Energy
Efficiency Alliance’s (NEEA’s) 2016 Residential Building Stock Assessment II (RBSA) supplemented the
GenPOP survey to account for trends in the intervening years.
• The residential segmentation was expanded to include household counts and energy characteristics of low-
income customers by dwelling type.
• For the commercial sector, the analysis was performed for the major building types in the service territory.
Results from NEEA’s 2019 Commercial Building Stock Assessment (CBSA), including hospital and university
data, provided useful information for this analysis.
• The list of energy conservation measures was updated with research from the Regional Technical Forum
(RTF).
• Measure characterizations, which previously relied on data from the Northwest Power and Conservation
Council’s (NWPCC or Council) Seventh Power Plan, is now updated to the 2021 Power Plan, including
measure data, adoption rates, and updated measure applicability.
• The study incorporates updated forecasting assumptions that align with the most recent Avista load
forecast.
Summary of Report Contents
Volume 1, Final Report
The report is divided into seven chapters. Chapters 2 through 6 describe the analysis approach taken and the
data sources used to develop the energy efficiency potential estimates and Chapter 7 discusses the demand
response analysis.
• Chapter 2 – Energy Efficiency Analysis Approach and Data Development. A detailed description
of AEG’s approach to estimating the energy efficiency potential and documentation of data sources used.
• Chapter 3 – Energy Efficiency Market Characterization presents how Avista’s customers use
natural gas today and what equipment is currently being used.
• Chapter 4 – Energy Efficiency Baseline Projection presents the baseline end-use projections
developed for each sector and state as well as a summary.
• Chapter 5 – Conservation Potential. Energy efficiency potential results for each state across all
sectors and separately for each sector.
2022-2045 Avista Conservation Potential Assessment | Introduction

Applied Energy Group, Inc. | appliedenergygroup.com 2
• Chapter 6 - Sector-Level Energy Efficiency Potential. Summary of energy efficiency potential for
each market sector within Avista’s service territory for both Washington and Idaho. This chapter includes a
detailed breakdown of potential by measure type, vintage, market segment, end use, and state.
• Chapter 7 – Demand Response Potential. Demand response potential results for each state across
all sectors and separately for each sector.
Volume 2, Appendices
The appendices for this report are provided in separate spreadsheets accompanying the delivery of this report
and consist of the following:
• Market Profiles. Detailed market profiles for each market segment. Includes equipment saturation, unit
energy consumption or energy usage index, energy intensity, and total consumption.
• Customer Adoption Factors. Documentation of the ramp rates used in this analysis. These were
adapted from the 2021 Power Plan electrical power conservation supply curve workbooks for the
estimation of achievable natural gas potential.
• Measure List. List of measures, along with example baseline definitions and efficiency options by market
sector analyzed.
• Detailed Measure Assumptions. This dataset provides input assumptions, measure characteristics,
cost-effectiveness results, and potential estimates for each measure permutation analyzed within the
study.
2022-2045 Avista Conservation Potential Assessment | Introduction

Applied Energy Group, Inc. | appliedenergygroup.com 3
Abbreviations and Acronyms
Table 2-1 shows the abbreviations and acronyms used in this report, along with an explanation.
Table 2-1 Explanation of Abbreviations and Acronyms
Acronym Explanation
ACS U.S. Census American Community Study
AEG Applied Energy Group
AEO EIA’s Annual Energy Outlook
BEST AEG’s Building Energy Simulation Tool
C&I Commercial and Industrial
CBSA NEEA’s Commercial Building Stock Assessment
COMMEND EPRI’s Commercial End-Use Planning System
CPA Conservation Potential Assessment
DEEM AEG’s Database of Energy Efficiency Measures
DEER California Database for Energy Efficient Resources
DR Demand Response
DSM Demand Side Management
EIA Energy Information Administration
EPRI Electric Power Research Institute
EUI Energy Use Index
HDD Heating Degree Day
HVAC Heating Ventilation and Air Conditioning
IFSA NEEA’s Industrial Facilities Site Assessment
IRP Integrated Resource Plan
LoadMAP AEG’s Load Management Analysis and Planning™ tool
NEEA Northwest Energy Efficiency Alliance
NWPCC Northwest Power and Conservation Council
O&M Operations and Maintenance
RBSA NEEA’s Residential Building Stock Assessment
REEPS EPRI’s Residential End-Use Energy Planning System
RTF NWPCC’s Regional Technical Forum
TRC Total Resource Cost test
TRM Technical Reference Manual
UCT Utility Cost Test
UEC Unit Energy Consumption
WSEC 2015 Washington State Energy Code

Applied Energy Group, Inc. | appliedenergygroup.com 4
3 | ENERGY EFFICIENCY ANALYSIS APPROACH AND DATA
DEVELOPMENT
This section describes the analysis approach and the data sources used to develop the energy efficiency
potential estimates. The demand response analysis discussion can be found in Chapter 6.
Overview of Analysis Approach
AEG used a bottom-up approach to perform the potential analysis. The major steps are listed below and detailed
detail throughout this section.
1. Perform a market characterization to describe sector-level natural gas use for the residential, commercial,
and industrial sectors for the base year, 2021. The market characterization included extensive use of Avista
data and other secondary data sources from NEEA and the Energy Information Administration (EIA).
2. Develop a baseline projection of energy consumption by sector, segment, end use, and technology for 2023
through 2045.
3. Define and characterize several hundred energy efficiency measures to be applied to all sectors, segments,
and end uses.
4. Estimate technical, achievable technical, and achievable economic energy savings at the measure level for
2023 through 2045. Achievable economic potential was assessed using the Utility Cost Test (UCT) test for
Avista’s Idaho territory and the Total Resource Cost (TRC) test for Avista’s Washington territory.
Comparison with NWPCC Methodology
It is important to note that electricity is the primary focus of the regionwide potential assessed in the NWPCC’s
Plans. Natural gas impacts are typically assessed when they overlap with electricity measures (e.g., gas water
heating impacts in an electrically heated “Built Green Washington” home). Although Avista is a dual-fuel utility,
this study focuses on natural gas measures and programs, which exhibit noticeable differences from electric
programs, notably regarding avoided costs. To account for this, AEG sometimes adapted NWPCC methodologies
rather than using them directly from the source. This adaptation is especially relevant in the development of
ramp rates when achievability was determined not to be applicable to a specific natural gas measure or
program.
A primary objective of the study was to estimate natural gas potential consistent with the NWPCC’s analytical
methodologies and procedures for electric utilities. While developing Avista’s 2023- 2045 CPA, AEG relied on
an approach vetted and adapted through the successful completion of CPAs referencing the NWPCC’s Fifth,
Sixth, Seventh, and now 2021 Power Plans. Among other aspects, this approach involves using consistent:
• Data sources: Avista surveys, regional surveys, market research, and assumptions
• Measures and assumptions: Avista TRM, 2021 Power Plan supply curves and RTF work products
• Potential factors: 2021 Power Plan ramp rates
• Levels of potential: technical, achievable technical, and achievable economic
• Cost-effectiveness approaches: assessed potential under the UCT for Idaho and TRC for Washington,
including non-energy impacts (and non-gas energy impacts), which may be quantified and monetized, as
well as operations and maintenance (O&M) impacts within the TRC.
• Conservation credit: applied NWPCC 10% conservation credit to avoided energy costs in Washington
for energy benefits. This is incorporated into the TRC calculation.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 5
LoadMAP Model
AEG used its Load Management Analysis and Planning tool (LoadMAP™) version 5.0 to develop both the
baseline projection and the estimates of potential. AEG developed LoadMAP in 2007 and has enhanced it over
time, using it for the Electric Power Research Institute (EPRI) National Potential Study and numerous utility-
specific forecasting and potential studies since. Built in Excel, the LoadMAP framework (see Figure 3-1) is both
accessible and transparent and has the following key features:
• Embodies the basic principles of rigorous end-use models (such as EPRI’s Residential End-Use Energy
Planning System (REEPS) and Commercial End-Use Planning System (COMMEND)) but in a more simplified,
accessible form.
• Includes stock-accounting algorithms that treat older, less efficient appliance/equipment stock separately
from newer, more efficient equipment. Equipment is replaced according to the measure life and appliance
vintage distributions defined by the user.
• Balances the competing needs of simplicity and robustness by incorporating important modeling details
related to equipment saturations, efficiencies, vintage, and the like, where market data are available, and
treats end uses separately to account for varying importance and availability of data resources.
• Isolates new construction from existing equipment and buildings and treats purchase decisions for new
construction and existing buildings separately. This is especially relevant in the state of Washington where
the 2015 Washington State Energy Code (WSEC) substantially enhances the efficiency of the new
construction market.
• Uses a simple logic for appliance and equipment decisions. Other models available for this purpose em body
complex customer choice algorithms or diffusion assumptions. The model parameters tend to be difficult
to estimate or observe, and sometimes produce anomalous results that require calibration or even
overriding. The LoadMAP approach allows the user to drive the appliance and equipment choices year by
year directly in the model. This flexible approach allows users to import the results from diffusion models
or to input individual assumptions. The framework also facilitates sensitivity analysis.
• Includes appliance and equipment models customized by end use. For example, the logic for water heating
is distinct from furnaces and fireplaces.
• Can accommodate various levels of segmentation. Analysis can be performed at the sector level (e.g., total
residential) or for customized segments within sectors (e.g., housing type, state, or income level).
• Natively outputs model results in a detailed line-by-line summary file, allowing for review of input
assumptions, cost-effectiveness results, and potential estimates at a granular level. Also allows for the
development of IRP supply curves, both at the achievable technical and achievable economic potential
levels.
Consistent with the segmentation scheme and market profiles described below, LoadMAP provides projections
of baseline energy use by sector, segment, end use, and technology for existing and new buildings. It provides
forecasts of total energy use and energy efficiency savings associated with the various types of potential.1

1 The model computes energy forecasts for each type of potential for each end use as an intermediate calculation. Annual-energy savings are
calculated as the difference between the value in the baseline projection and the value in the potential forecast (e.g., the technical potential
forecast).
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 6
Figure 3-1 LoadMAP Analysis Framework

Definitions of Potential
AEG’s approach for this study adheres to the approaches and conventions outlined in the National Action Plan
for Energy Efficiency’s Guide for Conducting Potential Studies2 and is consistent with the methodology used by
the Northwest Power and Conservation Council to develop its regional power plans. The guide represents the
most credible and comprehensive industry practice for specifying conservation potential. Four types of
potential were developed as part of this effort:
• Technical Potential is the theoretical upper limit of conservation potential. It assumes that customers
adopt all feasible efficient measures regardless of their cost. At the time of existing equipment failure,
customers replace their equipment with the most efficient option available. In new construction, customers
and developers choose the efficient equipment option relative to applicable codes and standards. Non-
equipment measures, which may be realistically installed apart from equipment replacements, are
implemented according to ramp rates informed by the NWPCC 2021 Power Plan, applied to 100%
of the applicable market. This case is provided primarily for planning and informational purposes.
• Achievable Technical Potential refines Technical Potential by applying market adoption rates that
account for market barriers, customer awareness and attitudes, program maturity, and other factors that
may affect market penetration of energy efficiency measures. AEG used achievability assumptions from the
NWPCC’s 2021 Power Plan, adjusted for Avista’s recent program accomplishments, as the customer
adoption rates for this study. For the achievable technical case, ramp rates are applied to between 85% -
100% of the applicable market, per NWPCC methodology. This achievability factor represents potential that
all available mechanisms, including utility programs, updated codes and standards, and market
transformation, can reasonably acquire. Thus, the market applicability assumptions utilized in this study
include savings outside of utility programs.3 The market adoption factors can be found in Appendix B.

2 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for Change.
www.epa.gov/eeactionplan.
3 Council’s 7th Power Plan applicability assumptions reference an “Achievable Savings” report published August 1, 2007.
http://www.nwcouncil.org/reports/2007/2007-13/
Market Profiles
Base-Year Energy
Consumption
Projection Data
Energy-Efficiency
Analysis
Projection Results
Customer
segmentation
Market size
Equipment saturation
Technology shares
Vintage distribution
Unit energy
consumption
New construction
profile
By technology, end
use, segment, vintage,
sector, and state
Economic Data
Customer growth
Energy prices
Elasticities & HDD65s
Technology Data
Efficiency options
Codes and standards
Purchase shares
List of measures
Saturations
Ramp rates
Avoided cost
Cost-effectiveness
Baseline Projection
Energy-efficiency
Projections
Technical
Achievable Technical
Achievable Economic
(UCT and TRC)
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 7
o Note that the previous CPA used ramp rates from the NWPCC’s Seventh Power Plan, which assumed a
fixed 85% achievability for all measures. In the 2021 Power Plan, some measures have this limit
increased.
• UCT Achievable Economic Potential further refines achievable technical potential by applying a cost-
effectiveness screen. The UCT test assesses cost-effectiveness from the utility’s perspective. This test
compares lifetime energy benefits to the costs of delivering the measure through a utility program,
excluding monetized non-energy impacts. The costs are the incentive, as a percent of the incremental cost
of the given measure, relative to the relevant baseline (e.g., the federal standard for lost opportunity and
no action for retrofits), plus any administrative costs that are incurred by the program to deliver and
implement the measure. If the benefits outweigh the costs (that is, if the UCT ratio is greater than 1.0), a
given measure is included in the economic potential.
• TRC Achievable Economic Potential also refines achievable technical potential through cost-effectiveness
analysis. The TRC test assesses cost-effectiveness from a combined utility and participant perspective. As
such, this test includes the full cost of the measure and non-energy impacts realized by the customer (if
quantifiable and monetized). AEG also assessed the impacts of non-gas savings following the NWPCC
methodology. For the assessment, AEG used a calibration credit for space heating equipment consumption
to account for secondary heating equipment present in an average home as well as other electric end -use
impacts, such as cooling and interior lighting (as applicable), on a measure-by-measure basis.
Market Characterization
To estimate the savings potential from energy efficient measures, it is necessary to understand how much
energy is used today and what equipment is currently being used. The characterization begins with a
segmentation of Avista’s natural gas footprint to quantify energy use by sector, segment, end-use application,
and the current set of technologies. To complete this step, AEG relied on information from Avista, NEEA, and
secondary sources, as necessary.
Segmentation for Modeling Purposes
The market assessment first defined the market segments (building types, end uses, and other dimensions)
relevant to Avista’s service territory. The segmentation scheme is presented in Table 3-1.
Table 3-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description
0 State Washington and Idaho
1 Sector Residential, Commercial, Industrial
2 Segment
Residential: Single Family, Multifamily, and Mobile Home, by income group
Commercial: Office, Restaurant, Retail, Grocery, School, College, Health,
Lodging, Warehouse, Miscellaneous
Industrial: Total
3 Vintage Existing and new construction
4 End uses Heating, secondary heating, water heating, food preparation, process, and
miscellaneous (as appropriate by sector)
5 Appliances/end uses and
technologies
Technologies such as furnaces, water heaters, and process heating by
application, etc.
6 Equipment efficiency
levels for new purchases Baseline and higher-efficiency options as appropriate for each technology
With the segmentation scheme defined, we then performed a high-level market characterization of natural gas
sales in the base year, 2021. This information provided control totals at a sector level for calibrating the
LoadMAP model to known data for the base-year.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 8
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and technology. The
market profiles provide the foundation for the development of the baseline projection and the potential
estimates. A market profile includes the following elements:
• Market size represents the number of customers in the segment. For the residential sector, it is the number
of households. In the commercial sector, it is floor space measured in square feet. For the industrial sector,
it is the number of employees.
• Saturations indicate the share of the market that is served by a particular end use technology. Three types
of saturation definitions are commonly used:
o Conditioned space accounts for the fraction of each building that is conditioned by the end use,
applying to cooling and heating end uses.
o The whole-building approach measures shares of space in a building with an end use regardless of the
portion of each building served by the end use. Examples are commercial refrigeration, food service,
and domestic water heating and appliances.
o The 100% saturation approach applies to end uses generally present in every building or home and are
set to 100% in the base year.
• UEC (unit energy consumption) or EUI (energy use index) describes the amount of energy consumed in
2021 by a specific technology in buildings with the technology. UECs are expressed in therms/household
for the residential sector and EUIs are expressed in therms/square foot for the commercial sector or
therms/employee for the industrial sector.
• Annual Energy Intensity for the residential sector represents the average energy use for the technology
across all homes in 2021 and is the product of the saturation. The commercial and industrial sectors
represent the average use for the technology across all floor space or employees in 2021 and is the product
of the saturation and EUI.
• Annual Usage is the annual energy use by an end-use technology in the segment. It is the product of the
market size and intensity and is quantified in therms or dekatherms.
The market characterization and market profiles are presented in Chapter 3.
Baseline Projection
The next step was to develop the baseline projection of annual natural gas use for 2023 through 2045 by
customer segment and end use in the absence of new utility energy efficiency programs. The baseline
projection is the foundation for the analysis of savings in future conservation cases as well as the metric against
which potential savings are measured. The end-use projection includes the impacts of future codes and
standards that were effective as of May 2022.
Naturally occurring efficiency is energy conservation that is realized within the service area independent of
utility-sponsored programs. It was incorporated into the baseline projection consistent with the EIA’s Annual
Energy Outlook (AEO) for the Pacific region.
Inputs to the baseline projection include:
• Avista’s official forecast (Heating Degree Days base 65°F (HDD65)), calibrated to actual sales
• Current economic growth forecasts (i.e., customer growth, changes in weather (HDD65 normalization))
• Trends in fuel shares and equipment saturations
• Existing and approved changes to building codes and equipment standards
We present the baseline projection for the system as a whole and for each sector in Chapter 4.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 9
Washington HB 1444
Washington’s HB 1444 established energy efficiency standards around equipment that exceed federal
standards. These energy efficiency measures include but are not limited to showerheads, aerators, commercial
food service equipment, and office equipment. This study’s foundational setup included assumptions of HB-
1444’s impact on the available market for energy efficiency measures in Washington.
Conservation Measure Analysis
This section describes the framework used to assess conservation measures' savings, costs, and other
attributes. These characteristics form the basis for measure-level cost-effectiveness analyses and determining
measure-level savings. For all measures, AEG assembled information to reflect equipment performance,
incremental costs, and equipment lifetimes. We used this information combined with Avista’s avoided cost data
to inform the economic screens that determine economically feasible measures.
Conservation Measures
Figure 3-2 outlines the framework for conservation measure analysis. The framework involves identifying the
list of measures to include in the analysis, determining their applicability to each sector and segment, and fully
characterizing each measure. Finally, cost-effectiveness screening is performed. Avista provided feedback
during each step to ensure measure assumptions and results lined up with programmatic experience.
AEG compiled a robust list of conservation measures for each customer sector, drawing upon Avista’s Technical
Reference Manual (TRM) and program experience, the RTF’s Unit Energy Savings measure workbooks, and the
2021 Power Plan’s electric power conservation supply curves, as well as a variety of secondary sources. This
universal list of measures covers all major types of end use equipment, as well as devices and actions to reduce
energy consumption.
Figure 3-2 Approach for Measure Development

The selected measures are categorized into the following two types according to the LoadMAP taxonomy:
• Equipment measures are efficient energy-consuming pieces of equipment that save energy by providing
the same service with a lower energy requirement than a standard unit. An example is an ENERGY STAR®
residential water heater (UEF 0.64) that replaces a standard efficiency water heater (UEF 0.58). For
equipment measures, many efficiency levels may be available for a given technology, ranging from the
baseline unit (often determined by a code or standard) up to the most efficient product commercially
available. These measures are applied on a stock-turnover basis and are generally referred to as lost
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 10
opportunity measures by the NWPCC because once a purchase decision is made, there will not be another
opportunity to improve the efficiency of the equipment until its effective useful life is reached.
• Non-equipment measures save energy by reducing the need for delivered energy, but do not involve
replacement or purchase of major end-use equipment (such as a furnace or water heater). An example
would be low-flow showerheads that modify a household’s hot water consumption. The showerhead can
be replaced without waiting for the existing showerhead to malfunction, and saves energy used by the
water heating equipment. Non-equipment measures typically fall into one of the following categories:
o Building shell (windows, insulation, roofing material)
o Equipment controls (smart thermostats, water heater setback)
o Whole-building design (ENERGY STAR homes)
o Retrocommissioning and strategic energy management
We developed a preliminary list of efficient measures, which was distributed to Avista’s project team for review.
Once the measure list was finalized, AEG characterized measure savings, incremental cost, service life, non-
energy impacts, and other performance factors. Following the measure characterization, we performed an
economic screening of each measure, which serves as the basis for developing the economic and achievable
potential scenarios. Table 3-2 summarizes the number of measures evaluated within each sector.
Table 3-2 Number of Measures Evaluated
Sector Total Measures Measure Permutations
w/ 2 Vintages
Measure Permutations
w/ All Segments & States
Residential 61 122 1,464
Commercial 64 128 2,560
Industrial 34 68 136
Total Measures Evaluated 159 318 4,160
Data Development
This section details the data sources used in this study, followed by a discussion of how these sources were
applied. Data sources included Avista, Northwest, and well-vetted national or other regional secondary sources.
In general, data were adapted to local conditions, for example, by using local sources for measure data and
local weather for building simulations.
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
• Customer Data: Avista provided billing data for development of customer counts and energy use for each
sector. We also used the results of the Avista GenPOP survey, a residential saturation survey.
• Load Forecasts: Avista provided forecasts, by sector and state, of energy consumption, customer counts,
weather actuals for 2020 and 2021, as well as weather-normal HDD65.
• Economic Information: Avista provided a discount rate as well as avoided cost forecasts consistent with
those utilized in the IRP.
• Program Data: Avista provided information about past and current programs, including program
descriptions, goals, and achievements to date.
• Avista TRM: Avista provided energy conservation measure assumptions within current programs. We
utilized this as a primary source of measure information, supplemented secondary data.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 11
Northwest Energy Efficiency Alliance Data
The NEEA conducts research for the Northwest region. The NEEA surveys were used extensively to develop base
saturation and applicability assumptions for many of the non-equipment measures within the study.
The following studies were particularly useful:
• Residential Building Stock Assessment II, Single-Family Homes Report 2016-2017.
• Residential Building Stock Assessment II, Manufactured Homes Report 2016-2017.
• Residential Building Stock Assessment II, Multifamily Buildings Report 2016-2017.
• 2019 Commercial Building Stock Assessment, May 21, 2020.
• 2014 Industrial Facilities Site Assessment, December 29, 2014.
Northwest Power and Conservation Council Data
Several sources of data were used to characterize the conservation measures. We used the following regional
data sources and supplemented with AEG’s data sources to fill in any gaps.
• RTF Deemed Measures. The NWPCC RTF maintains databases of deemed measure savings data.
• NWPCC 2021 Power Plan and Regional Technical Forum Workbooks. To develop its Power Plan, the NWPCC
maintains workbooks with detailed information about measures.
• NWPCC, MC and Loadshape File, September 29, 2016. The Council’s load shape library was utilized to
convert CPA results into hourly conservation impacts for use in Avista’s IRP process.
AEG Data
AEG maintains several databases and modeling tools that we use for forecasting and potential studies. Relevant
data from these tools has been incorporated into the analysis and deliverables for this study.
• AEG Energy Market Profiles: AEG maintains regional profiles of end-use consumption. The profiles include
market size, fuel shares, unit consumption estimates, and annual energy use by fuel (electricity and natural
gas), customer segment and end use for 10 regions in the U.S. The EIA surveys (RECS, CBECS and MECS) as
well as state-level statistics and local customer research provide the foundation for these regional profiles.
• Building Energy Simulation Tool (BEST): AEG’s BEST is a derivative of the DOE 2.2 building simulation model,
used to estimate base-year UECs and EUIs, as well as measure savings for HVAC-related measures.
• AEG’s Database of Energy Efficiency Measures (DEEM): AEG maintains an extensive database of measure
data, drawing upon reliable sources including the California Database for Energy Efficient Resources (DEER),
the EIA Technology Forecast Updates – Residential and Commercial Building Technologies – Reference Case,
RS Means cost data, and Grainger Catalog Cost data.
• Recent studies: AEG has conducted numerous studies of energy efficiency potential in the last five years.
We checked our input assumptions and analysis results against the results from these other studies both
within the region and across the country.
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main sources include:
• AEO: Conducted each year by the U.S. EIA, the AEO presents yearly projections and analysis of energy
topics. For this study, we used data from the 2021 AEO.
• American Community Survey (ACS). The U.S. Census ACS is an ongoing survey that provides data every year
on household characteristics.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 12
• Local Weather Data: Weather from National Oceanic and Atmospheric Administration’s National Climatic
Data Center for Spokane, WA and Coure d’Alene in Idaho were used as the basis for building simulations.
• EPRI End-Use Models (REEPS and COMMEND): These models provide the elasticities we apply to prices,
household income, home size and heating and cooling.
• DEER: The California Energy Commission and California Public Utilities Commission sponsor this database,
which is designed to provide well-documented estimates of energy and peak demand savings values,
measure costs, and effective useful life for the state of California.
• Other relevant regional sources: These include reports from the Consortium for Energy Efficiency, the
Environmental Protection Agency, and the American Council for an Energy-Efficient Economy. This also
includes technical reference manuals from other states. When using data from outside the region,
especially weather-sensitive data, AEG adapted assumptions for use within Avista’s territory.

2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 13
Data Application
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of natural gas consumption and market size units
(households for residential, floor space for commercial, and employees for industrial), we primarily used
Avista’s billing data as well as secondary data from AEG’s Energy Market Profiles database.
• Residential Segments. Avista estimated the numbers of customers and average energy use per
customer for each of the three segments, based on its GenPOP survey matched to billing data for surveyed
customers. AEG compared the resulting segmentation with data from the ACS regarding housing types and
income and found that the Avista segmentation corresponded well with the ACS data.
• C&I Segments. We relied upon the allocation from the previous energy efficiency potential study. For the
previous study, customers and sales were allocated to building type based on SIC codes, with some
adjustments between the C&I sectors to better group energy use by facility type and predominate end uses.
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are shown in Table 3-3.
To develop the market profiles for each segment, we used the following approach:
1. Developed control totals for each segment. These include market size, segment-level annual natural gas
use, and annual intensity. Control totals were based on Avista’s actual sales and customer-level information
found in Avista’s customer billing database.
2. Developed existing appliance saturations and the energy characteristics of appliances, equipment, and
buildings using equipment flags within Avista’s billing data; NEEA’s RBSA, CBSA, and IFSA; U.S. EIA’s surveys
and AEO; AEG’s Energy Market Profile for the Pacific region; and the American Community Survey.
3. Ensured calibration to control totals for annual natural gas sales in each sector and segment.
4. Compare and cross-checked with other recent AEG studies.
5. Worked with Avista staff to vet the data against their knowledge and experience.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 14
Table 3-3 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings, commercial floor
space, and industrial employment
Avista 2020-2021 actual sales
Avista customer account database
Annual intensity
Residential: Annual use per household
Commercial: Annual use per square foot
Industrial: Annual use per employee
Avista customer account database
AEG’s Energy Market Profiles
NEEA RBSA and CBSA
AEO 2021
Other recent studies
Appliance/equipment
saturations
Fraction of dwellings with an appliance/technology
Percentage of C&I floor space/employment with
equipment/technology
Avista GenPOP Survey
RBSA, CBSA, and IFSA
ACS
AEG’s Energy Market Profiles
UEC/EUI for each
end-use technology
UEC: Annual natural gas use in homes and buildings
that have the technology
EUI: Annual natural gas use per square
foot/employee for a technology in floor space that
has the technology
HVAC uses: BEST simulations using
prototypes developed for Avista
Engineering analysis
AEG DEEM
AEO 2021
Recent AEG studies
Appliance/equipment
age distribution Age distribution for each technology RBSA, CBSA, and recent AEG studies
Efficiency options for
each technology
List of available efficiency options and annual energy
use for each technology
Avista current program offerings
AEG DEEM
AEO 2021
DEER
RTF and NWPCC 2021 Plan data
Recent AEG studies
Data Application for Baseline Projection
Table 3-4 summarizes the LoadMAP model inputs required for the baseline projection. These inputs are
required for each segment within each sector, as well as for new construction and existing dwellings /buildings.
Table 3-4 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP
Model Inputs Description Key Sources
Customer growth
forecasts
Forecasts of new construction in
residential, commercial, and industrial
sectors
Avista load forecast
Equipment
purchase shares for
baseline projection
For each equipment/technology, purchase
shares for each efficiency level; specified
separately for existing equipment
replacement and new construction
Shipment data from AEO and ENERGY STAR
AEO 2021 regional forecast assumptions4
Appliance/efficiency standards analysis
Avista program results and evaluation reports
Utilization model
parameters
Price elasticities, elasticities for other
variables (income, weather) EPRI’s REEPS and COMMEND models
In addition, we implemented assumptions for known future equipment standards as of May 2022, as shown in

4 We developed baseline purchase decisions using the EIA’s AEO report (2016), which utilizes the National Energy Modeling System to produce a
self-consistent supply and demand economic model. We calibrated equipment purchase options to match distributions/allocations of efficiency
levels to manufacturer shipment data for recent years.

Applied Energy Group, Inc. | appliedenergygroup.com 15
Table 3-5 and
End-Use Technology 2021 2022 2023 2024
Space Heating Furnace – Direct Fuel AFUE 80% AFUE 90%
Boiler – Direct Fuel AFUE 80%
Secondary Heating Fireplace N/A
Water Heating Water Heater <= 55 gal. UEF 0.58
Water Heater > 55 gal. UEF 0.76
Appliances
Clothes Dryer CEF 3.30
Stove/Oven N/A
Miscellaneous Pool Heater TE 0.82
Miscellaneous N/A

Table 3-6 Commercial and Industrial Natural Gas Equipment Standards
. The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.

Applied Energy Group, Inc. | appliedenergygroup.com 16
Table 3-5 Residential Natural Gas Equipment Standards5
End-Use Technology 2021 2022 2023 2024 2025
Space Heating Furnace – Direct Fuel AFUE 80% AFUE 90%
Boiler – Direct Fuel AFUE 80%
Secondary Heating Fireplace N/A
Water Heating Water Heater <= 55 gal. UEF 0.58
Water Heater > 55 gal. UEF 0.76
Appliances
Clothes Dryer CEF 3.30
Stove/Oven N/A
Miscellaneous Pool Heater TE 0.82
Miscellaneous N/A

Table 3-6 Commercial and Industrial Natural Gas Equipment Standards
End-Use Technology 2021 2022 2023 2024 2025
Space Heating
Furnace AFUE 80% / TE 0.80 TE 0.90
Boiler Average around AFUE 80% / TE 0.80 (varies by size)
Unit Heater Standard (intermittent ignition and power venting or automatic flue damper)
Water Heater Water Heating TE 0.80
Food Preparation Fryer N/A ENERGY STAR 3.0
Steamer N/A ENERGY STAR 1.2
Miscellaneous Pool Heater TE 0.82

7 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.

Applied Energy Group, Inc. | appliedenergygroup.com 17
Conservation Measure Data Application
Table 3-7 details the energy-efficiency data inputs to the LoadMAP model. It describes each input and identifies
the key sources used in the Avista analysis.
Table 3-7 Data Needs for the Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Energy Impacts
The annual reduction in consumption attributable to each
specific measure. Savings were developed as a percentage of
the energy end use that the measure affects.
Avista TRM
NWPCC workbooks, RTF
AEG BEST
AEG DEEM
AEO 2021
DEER
Other secondary sources
Costs
Equipment Measures: full cost of purchasing and installing the
equipment on a per-household, per-square-foot, or per
employee basis for the residential, commercial, and industrial
sectors, respectively.
Non-Equipment Measures: Existing buildings – full installed
cost. New Construction - costs may be either the full cost of the
measure or, as appropriate, the incremental cost of upgrading
from a standard level to a higher efficiency level.
Avista TRM
NWPCC workbooks, RTF
AEG DEEM
AEO 2021
DEER
RS Means
Other secondary sources
Measure Lifetimes
Estimates derived from the technical data and secondary data
sources that support the measure demand and energy savings
analysis.
Avista TRM
NWPCC workbooks, RTF
AEG DEEM
AEO 2021
DEER
Other secondary sources
Applicability
Estimate of the percentage of dwellings in the residential sector,
square feet in the commercial sector, or employees in the
industrial sector where the measure is applicable and where it is
technically feasible to implement.
RBSA, CBSA
WSEC for limitations on new
construction
AEG DEEM
DEER
Other secondary sources
On Market and Off
Market Availability
Expressed as years for equipment measures to reflect when the
technology is available or no longer available in the market.
AEG appliance standards
and building codes analysis
Data Application for Cost-effectiveness Screening
All cost and benefit values were analyzed as real dollars, converted from nominal provided by Avista. We applied
Avista’s long-term discount rate of 5.21% excluding inflation. LoadMAP is configured to vary this by market
sector (e.g., residential and commercial) if Avista develops alternative values in the future.
Estimates of Customer Adoption
Two parameters are needed to estimate the timing and rate of customer adoption in the potential forecasts.
• Technical diffusion curves for non -equipment measures. Equipment measures are installed when
existing units fail. Non-equipment measures do not have this natural periodicity, so rather than installing
all available non-equipment measures in the first year of the projection (instantaneous potential), they are
phased in according to adoption schedules that generally align with the diffusion of similar equipment
measures. For this analysis, we used the NWPCC’s retrofit ramp rates, labeled “Retro”.
• Adoption rates. Customer adoption rates or take rates are applied to technical potential to estimate
Technical Achievable Potential. For equipment measures, the NWPCC’s “Lost Opportunity” ramp rates were
applied to technical potential with a maximum achievability of 85%-100% depending on the measure. For
non-equipment measures, the NWPCC’s “Retrofit” ramp rates have already been applied to calculate
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Analysis Approach and Data Development

Applied Energy Group, Inc. | appliedenergygroup.com 18
technical diffusion. In this case, we multiply each of these by 85% (for most measures) to calculate Technical
Achievable Potential.

Applied Energy Group, Inc. | appliedenergygroup.com 19
4 | ENERGY EFFICIENCY MARKET CHARACTERIZATION
In this section, we describe how customers in the Avista service territory use natural gas in the base year of the
study, 2021. It begins with a high-level summary of energy use across all sectors and then delves into each
sector in more detail.
Energy Use Summary
Avista’s total natural gas consumption for the residential, commercial, and industrial sectors in 2021 was
27,285,801 dekatherms (dtherms or dth); 18,288,700 dtherms in Washington and 8,997,101 dtherms in Idaho.
As shown in Table 4-1 and Figure 4-1, the residential sector accounts for the largest share of annual energy use
at 62%, followed by the commercial sector at approximately 35%.
Table 4-1 Residential Sector Control Totals, 2021
Figure 4-1 Avista Sector-Level Natural Gas Use (2021)

Residential
62%
Commercial
35%
Industrial
3%
Idaho
Washington Idaho
Sector Natural Gas Usage
(Dth) % of Annual Use Natural Gas Usage
(Dth) % of Annual Use
Residential 11,356,811 62.1% 5,617,143 62.4%
Commercial 6,665,122 36.4% 3,149,752 35.0%
Industrial 266,766 1.5% 230,206 2.6%
Total 18,288,700 100% 8,997,101 100%
Residential
62%
Commercial
36%
Industrial
2%
Washington
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 20
Residential Sector
Washington Characterization
The total number of households and natural gas sales for the service territory were obtained from Avista’s
actual sales. In 2021, there were 157,808 households in the state of Washington that used a total of 11,356,811
dtherms, resulting in an average use per household of 720 therms per year. Table 4-2 and Figure 4-2 shows the
total number of households and natural gas sales in the six residential segments for each state. These values
represent weather actuals for 2021 and were adjusted within LoadMAP to normal weather using heating degree
day, base 65°F, using data provided by Avista.
Table 4-2 Residential Sector Control Totals, Washington, 2021
Segment Households Natural Gas Use
(dtherms)
Annual Use/Customer
(therms/HH)
Single Family 84,836 7,324,885 863
Multi-Family 8,705 431,675 496
Mobile Home 5,136 305,566 595
Low Income - Single Family 39,810 2,481,707 623
Low Income – Multi-Family 15,263 546,435 358
Low Income – Mobile Home 4,057 266,544 657
Total 157,808 11,356,811 720
Figure 4-2 Residential Natural Gas Use by Segment, Washington, 2021

Figure 4-3 and Table 4-3 show the distribution of annual natural gas consumption by end use for an average
residential household. Space heating comprises most of the load at 83%, followed by water heating at 12%.
Appliances, secondary heating, and miscellaneous loads make up the remaining portion (5%) of the total load.
The market profiles provide the foundation for development of the baseline projection and the potential
estimates. The average market profile for the residential sector is presented in Table 4-3.
Single Family
64%
Multi-Family
4%
Mobile Home
3%
LI -Single Family
22%
LI -Multi-Family
5%
LI -Mobile Home
2%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 21
Figure 4-3 Residential Natural Gas Use by End Use, Washington, 2021

Table 4-3 Average Market Profile for the Residential Sector, Washington, 2021
End Use Technology Saturation UEC
(therms)
Intensity
(therms/HH)
Usage
(dtherms)
Space Heating Furnace - Direct Fuel 84.8% 685 581 9,175,585
Boiler - Direct Fuel 2.4% 628 15 233,076
Secondary Heating Fireplace 5.1% 216 11 172,769
Water Heating Water Heater (<= 55 Gal) 55.1% 156 86 1,356,503
Water Heater (>55 Gal) 0.0% 148 0 457
Appliances Clothes Dryer 28.4% 23 6 101,141
Stove/Oven 58.6% 31 18 286,622
Miscellaneous Pool Heater 0.9% 106 1 15,120
Miscellaneous 100% 1 1 15,539
Total 720 11,356,811
Figure 4-4 presents average natural gas intensities by end use and housing type. Single family homes consume
substantially more energy in space heating because single family homes are larger and more walls are exposed
to the outside environment, compared to multifamily dwellings with many shared walls. Additional exposed
walls increase heat transfer, resulting in greater heating loads. Water heating consumption is also higher in
single family homes due to a greater number of occupants.
Space Heating
83%
Secondary
Heating
2%
Water
Heating
12%
Appliances
3%
Miscellaneous
0%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 22
Figure 4-4 Residential Energy Intensity by End Use and Segment, Washington, 2021

Idaho Characterization
In 2021, there were 80,127 households in Avista’s Idaho territory that used a total of 5,617,143 dtherms,
resulting in an average use per household of 701 therms per year. Table 4-4 and Figure 4-5 shows the total
number of households and natural gas sales in the six residential segments for each state.
0
100
200
300
400
500
600
700
800
900
1,000
Single Family Multi-Family Mobile Home LI - Single
Family
LI - Multi-
Family
LI - Mobile
Home
Average
Home
th
e
r
m
s
/
H
H
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 23
Table 4-4 Residential Sector Control Totals, Idaho, 2021
Segment Households Natural Gas Use
(dekatherms)
Annual Use/Customer
(therms/HH)
Single Family 55,954 4,471,261 799
Multi-Family 8,690 379,050 436
Mobile Home 5,585 261,344 468
Low Income – Single Family 6,505 377,733 581
Low Income – Multi-Family 2,685 85,112 317
Low Income – Mobile Home 708 42,642 603
Total 80,127 5,617,143 701
Figure 4-5 Residential Natural Gas Use by Segment, Idaho, 2021

Figure 4-6 and Table 4-5 show the distribution of annual natural gas consumption by end use for an average
residential household. Space heating comprises most of the load at 84%, followed by water heating at 12%.
Appliances, secondary heating, and miscellaneous loads make up the remaining portion (4%) of the total load.
Single Family
79%
Multi-Family
7%
Mobile Home
5%
LI -Single Family
7%
LI -Multi-Family
1%LI -Mobile Home
1%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 24
Figure 4-6 Residential Natural Gas Use by End Use, Idaho, 2021

Table 4-5 Average Market Profile for the Residential Sector, Idaho 2021
End Use Technology Saturation UEC
(therms)
Intensity
(therms/HH)
Usage
(dtherms)
Space Heating Furnace - Direct Fuel 88.0% 669 589 4,715,719
Boiler - Direct Fuel 0.0% - - -
Secondary Heating Fireplace 6.0% 225 14 108,339
Water Heating Water Heater (<= 55 Gal) 50.9% 152 77 618,978
Water Heater (>55 Gal) 4.3% 151 7 52,229
Appliances Clothes Dryer 16.2% 22 4 28,672
Stove/Oven 34.7% 30 11 84,402
Miscellaneous Pool Heater 0.3% 106 0 2,848
Miscellaneous 100% 1 1 5,958
Total 701 5,617,143

Figure 4-7 presents average natural gas intensities by end use and housing type. Single family homes consume
substantially more energy in space heating. Water heating consumption is higher in single family homes as well,
due to a greater number of occupants, which increases the demand for hot water.
Space Heating
84%
Secondary
Heating
2%
Water
Heating
12%
Appliances
2%
Miscellaneous
0%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 25

Figure 4-7 Residential Energy Intensity by End Use and Segment, Idaho, 2021 (Annual Therms/HH)

0
100
200
300
400
500
600
700
800
900
Single Family Multi-Family Mobile Home LI - Single
Family
LI - Multi-
Family
LI - Mobile
Home
Average
Home
th
e
r
m
s
/
H
H
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 26
Commercial Sector
Washington Characterization
The total natural gas consumed by commercial customers in Avista’s Washington service area in 2021 was
6,665,122 dtherm. The total number of non-residential accounts and natural gas sales for the Washington
service territory were obtained from Avista’s customer account database. AEG separated the commercial and
industrial accounts by analyzing the SIC codes and rate codes assigned in the billing system. Energy use from
accounts where the customer type could not be identified were distributed proportionally to all C&I segments.
Once the billing data was analyzed, the final segment control totals were derived by distributing the total 2021
non-residential load to the sectors and segments according to the proportions in the billing data.
Table 4-6 shows the final allocation of energy to each segment in the commercial sector, as well as the energy
intensity on a square-foot basis. Intensities for each segment were derived from a combination of the 2021
CBSA and equipment saturations extracted from Avista’s database.
Table 4-6 Commercial Sector Control Totals, Washington, 2021
Segment Description Intensity
(therms/Sq Ft)
Natural Gas Use
(dekatherms)
Office Traditional office-based businesses including finance,
insurance, law, government buildings, etc. 0.53 536,771
Restaurant Sit-down, fast food, coffee shop, food service, etc. 2.60 747,786
Retail Department stores, services, boutiques, strip malls etc. 0.79 1,547,664
Grocery Supermarkets, convenience stores, market, etc. 0.55 125,630
School Day care, pre-school, elementary, secondary schools 0.28 187,678
College College, university, trade schools, etc. 0.59 182,118
Health Health practitioner office, hospital, urgent care centers, etc. 0.99 243,745
Lodging Hotel, motel, bed and breakfast, etc. 0.67 370,063
Warehouse Large storage facility, refrigerated/unrefrigerated warehouse 0.57 688,567
Miscellaneous
Catchall for buildings not included in other segments,
includes churches, recreational facilities, public assembly,
correctional facilities, etc.
0.95 2,035,100
Total 0.78 6,665,122
Figure 4-8 shows the distribution of annual natural gas consumption by segment across all commercial
buildings. The three segments with the highest natural gas usage in 2021 are miscellaneous (30%), retail (23%),
and restaurant (11%).
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 27
Figure 4-8 Commercial Natural Gas Use by Segment, Washington, 2021

Figure 4-9 shows the distribution of natural gas consumption by end use for the entire commercial sector. Space
heating is the largest end use, followed by water heating and food preparation. The miscellaneous end use is
quite small, as expected.
Figure 4-9 Commercial Sector Natural Gas Use by End Use, Washington, 2021

Figure 4-10 presents average natural gas intensities by end use and segment. In Washington, restaurants use
the most natural gas in the service territory. Avista customer account data informed the market profile by
providing information on saturation of key equipment types. Secondary data was used to develop estimates of
energy intensity and square footage and fill in saturations for any equipment types not included in the database.
Office
8%
Restaurant
11%
Retail
23%
Grocery
2%School
3%College
3%
Health
4%
Lodging
6%
Warehouse
10%
Miscellaneous
30%
Space Heating
58%
Water Heating
22%
Food Preparation
14%
Miscellaneous
6%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 28
Figure 4-10 Commercial Energy Usage Intensity by End Use and Segment, Washington, 2021

Table 4-7 shows the average market profile for the commercial sector as a whole, representing a composite of
all segments and buildings.
Table 4-7 Average Market Profile for the Commercial Sector, Washington, 2021
End Use Technology Saturation EUI
(therms/ Sq Ft)
Intensity
(therms/Sq Ft)
Usage
(dtherms)
Space Heating
Furnace 52.4% 0.55 0.29 2,485,626
Boiler 21.9% 0.66 0.15 1,247,409
Unit Heater 5.9% 0.31 0.02 156,793
Water Heating Water Heater 58.7% 0.29 0.17 1,481,152
Food Preparation
Oven 11.3% 0.08 0.01 73,181
Conveyor Oven 5.6% 0.13 0.01 62,609
Double Rack Oven 5.6% 0.20 0.01 95,114
Fryer 8.0% 0.44 0.04 300,472
Broiler 13.3% 0.12 0.02 133,574
Griddle 17.5% 0.08 0.01 118,981
Range 17.8% 0.07 0.01 113,457
Steamer 1.9% 0.07 0.00 10,828
Commercial Food Prep Other 0.2% 0.02 0.00 221
Miscellaneous Pool Heater 1.0% 0.06 0.00 5,419
Miscellaneous 100% 0.04 0.04 383,287
Total 0.78 6,665,122
Idaho Characterization
The total natural gas consumed by commercial customers in Avista’s Idaho service area in 2021 was 3,149,752
dtherm. Table 4-8 shows the final allocation of energy to each segment in the commercial sector, as well as the
energy intensity on a square-foot basis. Intensities for each segment were derived from a combination of the
2021 CBSA and equipment saturations extracted from Avista’s database.
- 0.50 1.00 1.50 2.00 2.50 3.00
Office
Restaurant
Retail
Grocery
School
College
Health
Lodging
Warehouse
Miscellaneous
Average Bldg
therms/sq ft
Miscellaneous
Food Preparation
Water Heating
Space Heating
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 29
Table 4-8 Commercial Sector Control Totals, Idaho, 2021
Segment Description Intensity
(therms/Sq Ft)
Natural Gas Use
(dekatherms)
Office Traditional office-based businesses including finance,
insurance, law, government buildings, etc. 0.53 226,954
Restaurant Sit-down, fast food, coffee shop, food service, etc. 2.60 139,154
Retail Department stores, services, boutiques, strip malls etc. 0.79 959,894
Grocery Supermarkets, convenience stores, market, etc. 0.55 58,138
School Day care, pre-school, elementary, secondary schools 0.28 184,533
College College, university, trade schools, etc. 0.59 179,370
Health Health practitioner office, hospital, urgent care centers, etc. 1.01 102,436
Lodging Hotel, motel, bed and breakfast, etc. 0.67 170,255
Warehouse Large storage facility, refrigerated/unrefrigerated warehouse 0.57 334,864
Miscellaneous
Catchall for buildings not included in other segments,
includes churches, recreational facilities, public assembly,
correctional facilities, etc.
0.95 794,154
Total 0.70 3,149,752
Figure 4-11 shows the distribution of annual natural gas consumption by segment across all commercial
buildings. The three segments with the highest natural gas usage in 2021 are retail (31%), miscellaneous (25%),
and warehouse (11%).
Figure 4-11 Commercial Natural Gas Use by Segment, Idaho, 2021

Figure 4-12 shows the distribution of natural gas consumption by end use for the entire commercial sector.
Space heating is the largest end use, followed by water heating and food preparation. The miscellaneous end
use is quite small, as expected.
Office
7%
Restaurant
4%
Retail
31%
Grocery
2%School
6%
College
6%
Health
3%
Lodging
5%
Warehouse
11%
Miscellaneous
25%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 30
Figure 4-12 Commercial Sector Natural Gas Use by End Use, Idaho, 2021

Figure 4-13 presents average natural gas intensities by end use and segment. In Idaho, restaurants use the most
natural gas in the service territory. Avista customer account data informed the market profile by providing
information on saturation of key equipment types. Secondary data was used to develop estimates of energy
intensity and square footage and fill in saturations for any equipment types not included in the database.
Figure 4-13 Commercial Energy Usage Intensity by End Use and Segment, Idaho, 2021

Table 4-9 shows the average market profile for the commercial sector as a whole, representing a composite of
all segments and buildings.
Space Heating
60%
Water Heating
23%
Food Preparation
12%
Miscellaneous
5%
- 0.50 1.00 1.50 2.00 2.50 3.00
Office
Restaurant
Retail
Grocery
School
College
Health
Lodging
Warehouse
Miscellaneous
Average Bldg
therms/sq ft
Miscellaneous
Food Preparation
Water Heating
Space Heating
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 31
Table 4-9 Average Market Profile for the Commercial Sector, Idaho, 2021
End Use Technology Saturation EUI
(therms/ Sq Ft)
Intensity
(therms/Sq Ft)
Usage
(dtherms)
Space Heating
Furnace 50.1% 0.53 0.26 1,194,251
Boiler 24.5% 0.56 0.14 621,861
Unit Heater 6.2% 0.29 0.02 81,760
Water Heating Water Heater 60.5% 0.26 0.16 722,590
Food Preparation
Oven 9.7% 0.09 0.01 40,281
Conveyor Oven 4.8% 0.16 0.01 34,461
Double Rack Oven 4.8% 0.24 0.01 52,353
Fryer 6.8% 0.44 0.03 134,342
Broiler 11.1% 0.07 0.01 33,837
Griddle 15.2% 0.05 0.01 33,185
Range 16.0% 0.05 0.01 32,941
Steamer 2.6% 0.04 00.0 4,364
Commercial Food Prep Other 0.3% 0.01 0.00 118
Miscellaneous Pool Heater 0.9% 0.05 0.00 2,146
Miscellaneous 100% 0.04 0.04 161,261
Total 0.70 3,149,752
Industrial Sector
Table 4-10 Industrial Sector Control Totals, 2021
Segment Intensity
(therms/employee)
Natural Gas Usage
(dtherms)
Washington Industrial 1,699 266,766
Idaho Industrial 2,327 230,206
Washington Characterization
The total natural gas consumed by industrial customers in Avista’s Washington service area in 2021 was 266,766
dtherms. Like in the commercial sector, customer account data was used to allocate usage among segments.
Energy intensity was derived from AEG’s Energy Market Profiles database. Most industrial measures are
installed through custom programs, where the unit of measure is not as necessary to estimate potential.
Figure 4-14 shows the distribution of annual natural gas consumption by end use for all industrial customers.
Two major sources were used to develop this consumption profile. The first was AEG’s analysis of warehouse
usage as part of the commercial sector. We begin with this prototype as a starting point to represent non-
process loads. We then added in process loads using our Energy Market Profiles database, which summarizes
usage by end use and process type.
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 32
Figure 4-14 Industrial Natural Gas Use by End Use, Washington, 2021

Table 4-11 shows the composite market profile for the Washington industrial sector. Process cooling is very
small and represents niche technologies such as gas-driven absorption chillers.
Table 4-11 Average Natural Gas Market Profile for the Industrial Sector, Washington, 2021
End Use Technology Saturation EUI
(therms/ Sq Ft)
Intensity
(therms/ Sq Ft)
Usage
(dtherms)
Space Heating
Furnace 32.3% 103.12 33.3 5,230
Boiler 51.5% 103.12 53.2 8,346
Unit Heater 16.2% 103.12 16.7 2,615
Process
Process Boiler 100% 750.42 750.4 117,823
Process Heating 100% 686.11 686.1 107,725
Process Cooling 100% 6.65 6.7 1,045
Other Process 100% 70.14 70.1 11,012
Miscellaneous Miscellaneous 100% 82.61 82.6 12,971
Total 1,699.1 266,766
Idaho Characterization
The total natural gas consumed by industrial customers in Avista’s Idaho service area in 2021 was 230,206
dtherms.
Figure 4-15 shows the distribution of annual natural gas consumption by end use for all industrial customers.
Two major sources were used to develop this consumption profile. The first was AEG’s analysis of warehouse
usage as part of the commercial sector. We begin with this prototype as a starting point to represent non-
process loads. We then added in process loads using our Energy Market Profiles database, which summarizes
usage by end use and process type.
Space Heating
6%
Process
89%
Miscellaneous
5%
2022-2045 Avista Conservation Potential Assessment | Energy Efficiency Market Characterization

Applied Energy Group, Inc. | appliedenergygroup.com 33
Figure 4-15 Industrial Natural Gas Use by End Use, Idaho, 2021

Table 4-12 shows the composite market profile for the industrial sector. Process cooling is very small and
represents technologies such as gas-driven absorption chillers.
Table 4-12 Average Natural Gas Market Profile for the Industrial Sector, Idaho, 2021
End Use Technology Saturation EUI
(therms/ Sq Ft)
Intensity
(therms/ Sq Ft)
Usage
(dekatherms)
Space Heating Furnace 32.3% 141.24 45.6 4,513
Boiler 51.5% 141.24 72.8 7,203
Unit Heater 16.2% 141.24 22.8 2,257
Process Process Boiler 100.0% 1,027.79 1,027.8 101,675
Process Heating 100.0% 939.70 939.7 92,961
Process Cooling 100.0% 9.11 9.1 901
Other Process 100.0% 96.06 96.1 9,503
Miscellaneous Miscellaneous 100.0% 113.14 113.1 11,193
Total 2,327.0 230,206

Space Heating
6%
Process
89%
Miscellaneous
5%

Applied Energy Group, Inc. | appliedenergygroup.com 34
5 | BASELINE PROJECTION
Prior to developing estimates of energy efficiency potential, we developed a baseline end-use projection to
quantify the likely future consumption in absence of any future conservation programs. The savings from past
programs are embedded in the forecast, but the baseline projection assumes that those past programs cease
to exist in the future. Possible savings from future programs are captured by the potential estimates.
The baseline projection incorporates assumptions about:
• 2021 energy consumption based on the market profiles
• Customer forecast and population growth
• Appliance/equipment standards and building codes and purchase decisions
• Trends in fuel shares and appliance saturations and assumptions about miscellaneous natural gas growth
This chapter presents the annual baseline natural gas projections developed for each sector and state. Although
it aligns closely, the baseline projection is not Avista’s official load forecast. It was developed to serve as the
metric against which energy efficiency potentials are measured.
Overall Baseline Projection
Washington
Table 5-1 and Error! Reference source not found. summarize the baseline projection for annual use by sector
for Avista’s Washington service territory. The forecast shows modest annual growth, driven by the residential
and commercial sectors.
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 35
Table 5-1 Baseline Projection Summary by Sector, Washington (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Residential 11,356,811 12,274,400 12,387,892 12,501,697 13,948,186 15,683,198 38.10%
Commercial 6,665,122 7,069,971 7,101,191 7,136,906 7,720,617 8,594,749 28.95%
Industrial 266,766 287,959 293,150 296,345 298,131 298,267 11.81%
Total 18,288,700 19,632,329 19,782,233 19,934,947 21,966,934 24,576,214 34.38%
Figure 5-1 Baseline Projection Summary by Sector, Washington

Idaho
Table 5-2 and Figure 5-2 summarize the baseline projection for annual use by sector for Avista’s Idaho service
territory. The forecast shows modest annual growth, driven by the residential and commercial sectors.
0
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
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
Dt
h
Residential Commercial Industrial
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 36
Table 5-2 Baseline Projection Summary by Sector, Idaho (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Residential 5,617,143 6,215,422 6,300,557 6,382,522 7,499,611 8,929,190 58.96%
Commercial 3,149,752 3,342,401 3,368,913 3,397,011 3,778,711 4,299,692 36.51%
Industrial 230,206 223,967 223,982 223,868 222,921 222,119 -3.51%
Total 8,997,101 9,781,790 9,893,452 10,003,402 11,501,243 13,451,001 49.50%
Figure 5-2 Baseline Projection Summary by Sector, Idaho

Residential Sector
Washington Projection
Table 5-3 and Figure 5-3 present the baseline projection for natural gas at the end-use level for the residential
sector. Overall, residential use increases from 11,356,811 dtherms in 2021 to 15,683,198 dtherms in 2045
(38.1%). Factors affecting growth include a moderate increase in the number of households and customers as
well as a decrease in equipment consumption due to standards and naturally occurring efficiency.
We model gas-fired fireplaces as secondary heating. These consume energy and may heat a space but are rarely
used as the primary heating technology. As such, they are estimated to be more aesthetic and less weather-
dependent. This end use grows faster than others since new homes are more likely to install a unit, increasing
fireplace stock. Miscellaneous is a very small end use, including technologies with low penetration, such as gas
barbeques.
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
16,000,000
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
Dt
h
Residential Commercial Industrial
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 37
Table 5-3 Residential Baseline Projection by End Use, Washington (dtherms)
End Use 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Space Heating 9,408,661 10,290,384 10,391,860 10,493,546 11,739,189 13,126,445 39.5%
Secondary Heating 172,769 164,209 157,168 150,444 98,948 66,939 -61.3%
Water Heating 1,356,961 1,387,160 1,399,677 1,411,982 1,589,357 1,875,045 38.2%
Appliances 387,763 401,031 407,136 413,242 483,593 572,381 47.6%
Miscellaneous 30,658 31,616 32,051 32,482 37,100 42,388 38.3%
Total 11,356,811 12,274,400 12,387,892 12,501,697 13,948,186 15,683,198 38.1%
Figure 5-3 Residential Baseline Projection by End Use, Washington

Idaho Projection
Error! Reference source not found. and Figure 5-4 present the baseline projection for natural gas at the end-
use level for the residential sector. Overall, residential use increases from 5,617,143 dtherms in 2021 to
8,929,190 dtherms in 2045, an increase of 59.0%.
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
16,000,000
18,000,000
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
Dt
h
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 38
Table 5-4 Residential Baseline Projection by End Use, Idaho (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Space Heating 4,715,719 5,287,189 5,367,732 5,445,288 6,446,442 7,649,95
8 62.2%
Secondary Heating 108,339 96,535 88,722 81,446 34,921 15,001 -86.2%
Water Heating 671,206 701,265 710,412 718,910 841,874 1,033,89
9 54.0%
Appliances 113,073 121,097 124,167 127,175 164,577 215,963 91.0%
Miscellaneous 8,806 9,336 9,523 9,703 11,797 14,369 63.2%
Total 5,617,143 6,215,422 6,300,557 6,382,522 7,499,611 8,929,19
0 59.0%
Figure 5-4 Residential Baseline Projection by End Use, Idaho

Commercial Sector
Washington Projection
Annual natural gas use in the commercial sector grows 29.0% during the overall forecast horizon, starting at
6,665,122 dtherms in 2021, and increasing to 8,594,749 dtherms in 2045. Table 5-5 and Error! Reference source
not found. present the baseline projection at the end-use level for the commercial sector, as a whole. Similar
to the residential sector, market size is increasing and usage per square foot is decreasing slightly.
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
10,000,000
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
Dt
h
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 39
Table 5-5 Commercial Baseline Projection by End Use, Washington (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Space Heating 3,886,828 4,295,626 4,330,709 4,365,994 4,759,146 5,275,544 35.7%
Water Heating 1,481,152 1,467,668 1,461,346 1,458,458 1,563,969 1,770,182 19.5%
Appliances 908,437 903,690 900,737 898,613 925,243 1,009,887 11.2%
Miscellaneous 388,706 402,987 408,399 413,840 472,259 539,135 38.7%
Total 6,665,122 7,069,971 7,101,191 7,136,906 7,720,617 8,594,749 29.0%
Figure 5-5 Commercial Baseline Projection by End Use, Washington

Idaho Projection
Annual natural gas use in the Idaho commercial sector grows 36.5% during the forecast horizon, starting at
3,149,752 dtherms in 2021, and increasing to 4,299,692 dtherms in 2045. Table 5-6 and Figure 5-6 present the
baseline projection at the end-use level for the commercial sector. Similar to the residential sector, market size
is increasing and usage per square foot is decreasing slightly.
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
10,000,000
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
Dt
h
Space Heating
Water Heating
Food Preparation
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 40
Table 5-6 Commercial Baseline Projection by End Use, Idaho (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Space Heating 1,897,872 2,083,872 2,104,055 2,124,262 2,352,655 2,653,169 39.8%
Water Heating 722,590 713,016 711,324 711,267 778,543 899,018 24.4%
Food Preparation 365,882 377,145 382,602 387,980 446,014 513,408 40.3%
Miscellaneous 163,408 168,369 170,932 173,502 201,500 234,097 43.3%
Total 3,149,752 3,342,401 3,368,913 3,397,011 3,778,711 4,299,692 36.5%
Figure 5-6 Commercial Baseline Projection by End Use, Idaho

Industrial Sector
Washington Projection
Industrial sector usage increases throughout the planning horizon. Table 5-7 and Figure 5-7 present the
projection at the end-use level. Overall, industrial annual natural gas use increases from 266,766 dtherms in
2021 to 298,267 dtherms in 2040, an increase of 11.8%.
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
5,000,000
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
Dt
h
Space Heating
Water Heating
Food Preparation
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 41
Table 5-7 Industrial Baseline Projection by End Use, Washington (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Space Heating 16,191 18,321 18,519 18,611 17,961 17,407 7.5%
Process 237,604 255,680 260,415 263,357 265,667 266,323 12.1%
Miscellaneous 12,971 13,957 14,216 14,376 14,502 14,538 12.1%
Total 266,766 287,959 293,150 296,345 298,131 298,267 11.8%
Figure 5-7 Industrial Baseline Projection by End Use, Washington

Idaho Projection
Industrial annual natural gas use decreases from 230,206 dtherms in 2021 to 222,119 dtherms in 2045, a
decrease of 3.5%. Table 5-8 and Figure 5-8 present the projection at the end-use level.
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
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
Dt
h
Space Heating
Process
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Baseline Projection

Applied Energy Group, Inc. | appliedenergygroup.com 42
Table 5-8 Industrial Baseline Projection by End Use, Idaho (dtherms)
Sector 2021 2023 2024 2025 2035 2045 % Change
('21-'45)
Space Heating 13,972 14,459 14,392 14,317 13,624 13,111 -6.2%
Process 205,041 198,663 198,741 198,704 198,463 198,190 -3.3%
Miscellaneous 11,193 10,845 10,849 10,847 10,834 10,819 -3.3%
Total 230,206 223,967 223,982 223,868 222,921 222,119 -3.5%
Figure 5-8 Industrial Baseline Projection by End Use, Idaho

0
50,000
100,000
150,000
200,000
250,000
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
Dt
h
Space Heating
Process
Miscellaneous

Applied Energy Group, Inc. | appliedenergygroup.com 43
6 | CONSERVATION POTENTIAL
This chapter presents the conservation potential across all sectors for Avista’s Washington and Idaho territories.
Conservation potential includes every measure considered in the measure list, regardless of delivery
mechanism (program implementation, etc.). Year-by-year annual energy savings are available in the LoadMAP
model and measure assumption summary, provided to Avista at the conclusion of the study. Please note that
all savings are at the customer site.
Washington Overall Energy Efficiency Potential
Error! Reference source not found. and Figure 6-1 summarize the conservation savings in terms of annual
energy use for all measures for four levels of potential relative to the baseline projection.

Figure 6-2 displays the cumulative energy conservation forecasts, which reflect the effects of persistent savings
in prior years and new savings.
• Technical Potential reflects the adoption of all conservation measures regardless of cost-effectiveness.
Efficient equipment makes up all lost opportunity installations and all retrofit measures are installed,
regardless of achievability. First-year savings are 429,564 dtherms, or 2.2% of the baseline projection.
Cumulative savings in 2045 are 8,637,218 dtherms, or 35.1% of the baseline.
• Achievable Technical Potential refines Technical Potential by applying market adoption rates to each
measure. The market adoption rates estimate the percentage of customers who would be likely to select
each measure given market barriers, customer awareness and attitudes, program maturity, and other
factors that affect market penetration of conservation measures. First-year savings are 191,654 dtherms,
or 1.0% of the baseline projection. Cumulative savings in 2045 are 4,938,238 dtherms, or 20.1% of the
baseline.
• TRC Achievable Economic Potential refines Achievable Technical Potential by applying the TRC economic
cost-effectiveness screen, which compares lifetime energy benefits to the total customer and utility costs
of delivering the measure through a utility program, including monetized non-energy impacts. For the TRC,
AEG also applied (1) benefits for non-gas energy savings, such as electric HVAC savings for weatherization,
(2) the NWPCC’s calibration credit to space heating savings to reflect that additional fuels may be used as
a supplemental heat source within an average home, and (3) a 10% conservation credit to avoided costs
per the NWPCC methodologies. First-year savings are 111,992 dtherms, or 0.6% of the baseline projection.
Cumulative savings in 2045 are 2,497,540 dtherms, or 10.2% of the baseline.
0%
5%
10%
15%
20%
25%
30%
35%
40%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Conservation Potential

Applied Energy Group, Inc. | appliedenergygroup.com 44
Table 6-1 Summary of Energy Efficiency Potential, Washington
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (Dth) 19,632,329 19,782,233 19,934,947 21,966,934 24,576,214
Cumulative Savings (Dth)
TRC Achievable Economic Potential 111,992 225,734 361,485 1,833,863 2,497,540
Achievable Technical Potential 191,654 423,238 686,518 3,774,115 4,938,238
Technical Potential 429,564 884,194 1,375,956 6,455,295 8,637,218
Energy Savings (% of Baseline)
TRC Achievable Economic Potential 0.6% 1.1% 1.8% 8.3% 10.2%
Achievable Technical Potential 1.0% 2.1% 3.4% 17.2% 20.1%
Technical Potential 2.2% 4.5% 6.9% 29.4% 35.1%
Figure 6-1 Cumulative Energy Efficiency Potential as % of Baseline Projection, Washington

0%
5%
10%
15%
20%
25%
30%
35%
40%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Conservation Potential

Applied Energy Group, Inc. | appliedenergygroup.com 45
Figure 6-2 Baseline Projection and Energy Efficiency Forecasts, Washington

Idaho Overall Energy Efficiency Potential
Table 6-2 and Figure 6-3 summarize the conservation savings in terms of annual energy use for all measures for
four levels of potential relative to the baseline projection. Figure 6-4 displays the cumulative energy
conservation forecasts, which reflect the effects of persistent savings in prior years in addition to new savings.
• Technical Potential first-year savings in 2023 are 254,213 dtherms, or 2.6% of the baseline projection.
Cumulative savings in 2045 are 5,060,646 dtherms, or 37.6% of the baseline.
• Achievable Technical Potential first-year savings are 105,612 dtherms, or 1.1% of the baseline projection.
Cumulative savings in 2045 are 2,885,725 dtherms, or 21.5% of the baseline
• UCT Achievable Economic Potential first-year savings are 46,414 dtherms, or 0.5% of the baseline
projection. Cumulative savings in 2045 are 1,278,511 dtherms, or 9.5% of the baseline
0
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Dt
h
e
r
m
s
Baseline Forecast
Achievable Economic TRC Potential
Achievable Technical Potential
Technical Potential
2022-2045 Avista Conservation Potential Assessment | Conservation Potential

Applied Energy Group, Inc. | appliedenergygroup.com 46
Table 6-2 Summary of Energy Efficiency Potential, Idaho
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (Dth) 9,781,790 9,893,452 10,003,402 11,501,243 13,451,001
Cumulative Savings (Dth)
UCT Achievable Economic Potential 46,414 96,705 155,748 906,240 1,278,511
Achievable Technical Potential 105,612 228,853 371,295 2,144,539 2,885,725
Technical Potential 254,213 498,497 772,091 3,673,174 5,060,646
Energy Savings (% of Baseline)
UCT Achievable Economic Potential 0.5% 1.0% 1.6% 7.9% 9.5%
Achievable Technical Potential 1.1% 2.3% 3.7% 18.6% 21.5%
Technical Potential 2.6% 5.0% 7.7% 31.9% 37.6%
Figure 6-3 Cumulative Energy Efficiency Potential as % of Baseline Projection, Idaho

0%
5%
10%
15%
20%
25%
30%
35%
40%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic UCT Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Conservation Potential

Applied Energy Group, Inc. | appliedenergygroup.com 47
Figure 6-4 Baseline Projection and Energy Efficiency Forecasts, Idaho

0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
16,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Dt
h
e
r
m
s
Baseline Forecast
Achievable Economic UCT Potential
Achievable Technical Potential
Technical Potential

Applied Energy Group, Inc. | appliedenergygroup.com 48
7 | SECTOR-LEVEL ENERGY EFFICIENCY POTENTIAL
This chapter provides energy efficiency potential at the sector level.
Residential Sector
Washington Potential
Error! Reference source not found. and Figure 7-1 summarize the energy efficiency potential for the residential
sector. In 2023, TRC achievable economic potential is 54,479 dtherms, or 0.4% of the baseline projection. By
2040, cumulative savings are 1,187,145 dtherms, or 7.6% of the baseline.
Table 7-1 Residential Energy Conservation Potential Summary, Washington
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (Dth) 12,274,400 12,387,892 12,501,697 13,948,186 15,683,198
Cumulative Savings (Dth)
TRC Achievable Economic Potential 54,479 103,469 169,578 866,240 1,187,145
Achievable Technical Potential 111,343 254,601 423,501 2,522,674 3,258,916
Technical Potential 264,105 573,696 906,085 4,569,190 6,154,164
Energy Savings (% of Baseline)
TRC Achievable Economic Potential 0.4% 0.8% 1.4% 6.2% 7.6%
Achievable Technical Potential 0.9% 2.1% 3.4% 18.1% 20.8%
Technical Potential 2.2% 4.6% 7.2% 32.8% 39.2%
Figure 7-1 Cumulative Residential Potential as % of Baseline Projection, Washington

0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 49
Error! Reference source not found. presents the forecast of cumulative energy savings by end. Space heating
makes up a majority of potential followed by water heating.
Figure 7-2 Residential TRC Achievable Economic Potential – Cumulative Savings by End Use, Washington

Table 7-2 identifies the top 20 residential measures by cumulative 2023 and 2035 savings. Furnaces, learning
thermostats, insulation and water heating are the top measures.
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
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
Dt
h
Space Heating
Water Heating
Appliances
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 50

2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 51
Table 7-2 Residential Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Washington
Rank Measure / Technology
2023
Cumulative
dtherms
% of
Total
2035
Cumulative
dtherms
% of
Total
1 Gas Furnace - Maintenance 19,639 36.0% 53,786 6.2%
2 Furnace 13,294 24.4% 248,091 28.6%
3 Connected Thermostat - ENERGY STAR (1.0) 7,426 13.6% 236,408 27.3%
4 Building Shell - Whole-Home Aerosol Sealing 6,216 11.4% 127,435 14.7%
5 Insulation - Ceiling Installation 3,478 6.4% 72,298 8.3%
6 Clothes Washer - ENERGY STAR (8.0) 2,161 4.0% 20,175 2.3%
7 Gas Boiler - Steam Trap Maintenance 637 1.2% 3,474 0.4%
8 Boiler 408 0.7% 11,449 1.3%
9 Behavioral Programs 298 0.5% 9,308 1.1%
10 Insulation - Wall Sheathing 271 0.5% 5,770 0.7%
11 ENERGY STAR Home Design 212 0.4% 25,408 2.9%
12 Building Shell - Liquid-Applied Weather-Resistive Barrier 130 0.2% 15,425 1.8%
13 Gas Boiler - Pipe Insulation 79 0.1% 646 0.1%
14 Gas Boiler - Thermostatic Radiator Valves 67 0.1% 1,374 0.2%
15 Ducting - Repair and Sealing - Aerosol 52 0.1% 2,314 0.3%
16 Water Heater - Drain Water Heat Recovery 38 0.1% 10,190 1.2%
17 Windows - Low-e Storm Addition 24 0.0% 5,184 0.6%
18 Circulation Pump - Timer 11 0.0% 2,719 0.3%
19 Windows - High Efficiency (Class 22) 11 0.0% 2,195 0.3%
20 Windows - High Efficiency (Class 30) 9 0.0% 1,798 0.2%
Subtotal 54,462 100.0% 855,447 98.8%
Total Savings in Year 54,479 100.0% 866,240 100.0%
Idaho Potential
Table 7-3 and
Figure 7-3 summarize the energy efficiency potential for the residential sector. In 3, UCT achievable economic
potential is 27,232 dtherms, or 0.4% of the baseline projection. By 2045, cumulative savings are 658,730
dtherms, or 7.4% of the baseline.
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 52
Table 7-3 Residential Energy Conservation Potential Summary, Idaho
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (Dth) 6,215,422 6,300,557 6,382,522 7,499,611 8,929,190
Cumulative Savings (Dth)
Achievable Economic UCT Potential 27,232 55,524 90,790 455,114 658,730
Achievable Technical Potential 65,493 144,748 240,091 1,466,014 1,972,483
Technical Potential 165,889 331,905 520,749 2,640,710 3,686,728
Energy Savings (% of Baseline)
Achievable Economic UCT Potential 0.4% 0.9% 1.4% 6.1% 7.4%
Achievable Technical Potential 1.1% 2.3% 3.8% 19.5% 22.1%
Technical Potential 2.7% 5.3% 8.2% 35.2% 41.3%

Figure 7-3 Cumulative Residential Potential as % of Baseline Projection, Idaho
Figure 7-4 presents the forecast of cumulative energy savings by end use. Space heating makes up a majority
of potential followed by water heating.
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic UCT Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 53
Figure 7-4 Residential UCT Achievable Economic Potential – Cumulative Savings by End Use, Idaho

Table 7-4 identifies the top 20 residential measures by cumulative 2023 and 2035 savings. Furnaces, tankless
water heaters, windows, and insulation are the top measures.
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
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
Dt
h
Space Heating
Water Heating
Appliances
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 54
Table 7-4 Residential Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Idaho
Rank Measure / Technology
2023
Cumulative
dtherms
% of
Total
2035
Cumulative
dtherms
% of
Total
1 Gas Furnace - Maintenance 11,234 41.3% 11,234 41.3%
2 Connected Thermostat - ENERGY STAR (1.0) 6,439 23.6% 6,439 23.6%
3 Furnace 3,261 12.0% 3,261 12.0%
4 Building Shell - Whole-Home Aerosol Sealing 2,962 10.9% 2,962 10.9%
5 Insulation - Ceiling Installation 1,906 7.0% 1,906 7.0%
6 Windows - Low-e Storm Addition 791 2.9% 791 2.9%
7 ENERGY STAR Home Design 263 1.0% 263 1.0%
8 Behavioral Programs 150 0.6% 150 0.6%
9 Insulation - Wall Sheathing 117 0.4% 117 0.4%
10 Insulation - Wall Cavity Installation 57 0.2% 57 0.2%
11 Windows - High Efficiency (Class 22) 15 0.1% 15 0.1%
12 Windows - High Efficiency (Class 30) 12 0.0% 12 0.0%
13 Building Shell - Liquid-Applied Weather-Resistive Barrier 11 0.0% 11 0.0%
14 Circulation Pump - Timer 8 0.0% 8 0.0%
15 Water Heater - Pipe Insulation 5 0.0% 5 0.0%
Subtotal 27,232 100.0% 27,232 100.0%
Total Savings in Year 27,232 100.0% 27,232 100.0%
Commercial Sector
Washington Potential
Table 7-5 and Figure 7-5 summarize the energy conservation potential for the commercial sector. In 2023, TRC
achievable economic potential is 55,557 dtherms, or 0.8% of the baseline projection. By 2045, cumulative
savings are 1,273,615 dtherms, or 14.8% of the baseline.
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 55
Table 7-5 Commercial Energy Conservation Potential Summary, Washington
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (dtherms) 7,069,971 7,101,191 7,136,906 7,720,617 8,594,749
Cumulative Savings (dtherms)
Achievable Economic TRC Potential 55,557 118,321 185,945 941,943 1,273,615
Achievable Technical 78,348 164,679 257,030 1,225,667 1,642,279
Technical Potential 162,823 305,303 462,087 1,853,896 2,436,763
Energy Savings (% of Baseline)
Achievable Economic TRC Potential 0.8% 1.7% 2.6% 12.2% 14.8%
Achievable Technical 1.1% 2.3% 3.6% 15.9% 19.1%
Technical Potential 2.3% 4.3% 6.5% 24.0% 28.4%
Figure 7-5 Cumulative Commercial Potential as % of Baseline Projection, Washington

Figure 7-6 presents the cumulative forecast of energy savings by end. Space heating makes up a majority of the
potential early, but water heating and food preparation equipment upgrades provide increased savings
opportunities in the later years.
0%
5%
10%
15%
20%
25%
30%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 56

Figure 7-6 Commercial TRC Achievable Economic Potential – Cumulative Savings by End Use,
Washington

-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
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
Dth
Space Heating
Water Heating
Food Preparation
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 57
Table 7-6 identifies the top 20 commercial measures by cumulative savings in 2023 and 2035. Strategic Energy
Management is the top measure, followed by Retrocommissioning and several HVAC and space heating
measures, along with water heater controls.
Table 7-6 Commercial Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Washington
Rank Measure / Technology 2023 Cumulative
dtherms
% of
Total
2035 Cumulative
dtherms
% of
Total
1 Strategic Energy Management 6,581 11.8% 44,626 4.7%
2 Retrocommissioning 5,777 10.4% 30,609 3.2%
3 Ventilation - Demand Controlled 5,364 9.7% 32,722 3.5%
4 HVAC - Energy Recovery Ventilator 4,613 8.3% 44,592 4.7%
5 Water Heater - Circulation Pump Controls 4,137 7.4% 32,785 3.5%
6 Boiler 3,630 6.5% 89,444 9.5%
7 Water Heater - Solar System 3,524 6.3% 23,836 2.5%
8 Water Heater - Temperature Setback 3,510 6.3% 6,799 0.7%
9 Thermostat - Connected 3,161 5.7% 13,233 1.4%
10 Water Heater - Tank Blanket/Insulation 1,875 3.4% 13,377 1.4%
11 Insulation - Wall Cavity 1,804 3.2% 127,530 13.5%
12 Water Heater - Efficient Dishwasher 1,793 3.2% 10,455 1.1%
13 Gas Boiler - Thermostatic Radiator Valves 1,750 3.1% 31,775 3.4%
14 Water Heater 1,743 3.1% 55,529 5.9%
15 Insulation - Ceiling 1,192 2.1% 76,887 8.2%
16 Water Heater - Pipe Insulation 896 1.6% 7,333 0.8%
17 Gas Boiler - High Turndown Burner 763 1.4% 5,194 0.6%
18 Gas Boiler - Hot Water Reset 747 1.3% 14,411 1.5%
19 Gas Boiler - Insulate Steam
Lines/Condensate Tank 651 1.2% 6,552 0.7%
20 Advanced Kitchen Ventilation Controls 402 0.7% 8,883 0.9%
Subtotal 53,913 97.0% 676,571 71.8%
Total Savings in Year 55,557 100.0% 941,943 100.0%
Idaho Potential
Table 7-7 and Figure 7-7 summarize the energy conservation potential for the commercial sector. In 2023, UCT
achievable economic potential is 17,641 dtherms, or 0.5% of the baseline projection. By 2045, cumulative
savings are 591,777dtherms, or 13.8% of the baseline.
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 58
Table 7-7 Commercial Energy Conservation Potential Summary, Idaho
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (dtherms) 3,342,401 3,368,913 3,397,011 3,778,711 4,299,692
Cumulative Savings (dtherms)
Achievable Economic UCT Potential 17,641 38,098 60,322 431,420 591,777
Achievable Technical 38,577 81,016 126,554 658,739 885,023
Technical Potential 86,399 162,707 245,484 1,007,830 1,338,703
Energy Savings (% of Baseline)
Achievable Economic UCT Potential 0.5% 1.1% 1.8% 11.4% 13.8%
Achievable Technical 1.2% 2.4% 3.7% 17.4% 20.6%
Technical Potential 2.6% 4.8% 7.2% 26.7% 31.1%
Figure 7-7 Cumulative Commercial Potential as % of Baseline Projection, Idaho

Figure 7-8 presents forecasts of energy savings by end use as a percent of total annual savings and cumulative
savings. Space heating makes up a majority of the potential early, but food preparation equipment upgrades
provide substantial savings opportunities in the later years.
0%
5%
10%
15%
20%
25%
30%
35%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic UCT Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 59

Figure 7-8 Commercial UCT Achievable Economic Potential – Cumulative Savings by End Use, Idaho

Table 7-8 identifies the top 20 commercial measures by cumulative savings in 2023 and 2035. Water Heaters
are the top measure, followed by custom HVAC measures and insulation.
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
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
Dth
Space Heating
Water Heating
Food Preparation
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 60
Table 7-8 Commercial Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Idaho
Rank Measure / Technology 2023 Cumulative
dtherms
% of
Total
2035 Cumulative
dtherms
% of
Total
1 Water Heater - Circulation Pump Controls 2,030 11.5% 16,022 3.7%
2 Water Heater - Temperature Setback 1,703 9.7% 3,301 0.8%
3 Strategic Energy Management 1,492 8.5% 10,327 2.4%
4 HVAC - Energy Recovery Ventilator 1,426 8.1% 14,038 3.3%
5 Retrocommissioning 1,084 6.1% 5,705 1.3%
6 Water Heater - Low-Flow Showerheads 1,071 6.1% 7,967 1.8%
7 Ventilation - Demand Controlled 1,028 5.8% 6,326 1.5%
8 Water Heater - Tank Blanket/Insulation 915 5.2% 6,526 1.5%
9 Insulation - Wall Cavity 907 5.1% 94,182 21.8%
10 Water Heater 868 4.9% 27,735 6.4%
11 Gas Boiler - Thermostatic Radiator Valves 866 4.9% 16,123 3.7%
12 Insulation - Ceiling 536 3.0% 50,921 11.8%
13 Fryer 501 2.8% 30,335 7.0%
14 Water Heater - Faucet Aerators 413 2.3% 3,132 0.7%
15 Water Heater - Pipe Insulation 383 2.2% 3,120 0.7%
16 Gas Boiler - Hot Water Reset 370 2.1% 7,266 1.7%
17 Water Heater - Thermostatic Shower
Restriction Valve 314 1.8% 2,262 0.5%
18 Gas Boiler - Insulate Steam
Lines/Condensate Tank 294 1.7% 3,020 0.7%
19 Gas Boiler - High Turndown Burner 290 1.6% 2,041 0.5%
20 Water Heater - Drainwater Heat Recovery 254 1.4% 1,707 0.4%
Subtotal 16,745 94.9% 312,056 72.3%
Total Savings in Year 17,641 100.0% 431,420 100.0%
Industrial Sector
Washington Potential
Table 7-9 and Figure 7-9 summarize the energy conservation potential for the industrial sector. In 2023, TRC
achievable economic potential is 1,956 dtherms, or 0.7% of the baseline projection. By 2045, cumulative savings
reach 36,780 dtherms, or 12.3% of the baseline. Industrial potential is a lower percentage of overall baseline
compared to the residential and commercial sectors. While large, custom process optimization and controls
measures are present in potential, these are not applicable to all processes which limits potential at the
technical level. Additionally, since the largest customers were excluded from this analysis due to their status as
transport-only customers making them ineligible to participate in energy efficiency programs for the utility, the
remaining customers are smaller and tend to have lower process end-use shares, further lowering industrial
potential.
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 61
Table 7-9 Industrial Energy Conservation Potential Summary, Washington
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (dtherms) 287,959 293,150 296,345 298,131 298,267
Cumulative Savings (dtherms)
Achievable Economic TRC Potential 1,956 3,943 5,963 25,680 36,780
Achievable Technical 1,963 3,957 5,988 25,774 37,043
Technical Potential 2,637 5,195 7,784 32,209 46,291
Energy Savings (% of Baseline)
Achievable Economic TRC Potential 0.7% 1.3% 2.0% 8.6% 12.3%
Achievable Technical 0.7% 1.3% 2.0% 8.6% 12.4%
Technical Potential 0.9% 1.8% 2.6% 10.8% 15.5%
Figure 7-9 Cumulative Industrial Potential as % of Baseline Projection, Washington

Figure 7-10 presents the forecast of cumulative energy savings by end use.
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic UCT Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 62

Figure 7-10 Industrial TRC Achievable Economic Potential – Cumulative Savings by End Use, Washington

-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
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
Dth
Space Heating
Process
Miscellaneous
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 63

Table 7-10 identifies the top 20 industrial measures by cumulative 2023 and 2035 savings. Process Heat
Recovery and Process Boiler control measures have the largest potential savings.
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 64

2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 65
Table 7-10 Industrial Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Washington
Rank Measure / Technology
2023
Cumulative
dtherms
% of
Total
2035
Cumulative
dtherms
% of
Total
1 Process - Heat Recovery 1,464.9 74.9% 19,327.6 75.3%
2 Process Boiler - Stack Economizer 135.7 6.9% 1,205.7 4.7%
3 Process Boiler - Insulate Steam Lines/Condensate Tank 69.6 3.6% 810.6 3.2%
4 Process Boiler - Hot Water Reset 66.5 3.4% 1,372.5 5.3%
5 Process Boiler - Insulate Hot Water Lines 46.6 2.4% 463.7 1.8%
6 Process Boiler - Maintenance 40.7 2.1% 87.6 0.3%
7 Destratification Fans (HVLS) 29.8 1.5% 375.3 1.5%
8 Thermostat - Connected 28.9 1.5% 146.6 0.6%
9 HVAC - Energy Recovery Ventilator 10.6 0.5% 111.2 0.4%
10 Gas Boiler - Stack Economizer 9.2 0.5% 64.7 0.3%
11 Ventilation - Demand Controlled 7.4 0.4% 47.6 0.2%
12 Retrocommissioning 7.3 0.4% 42.4 0.2%
13 Gas Boiler - High Turndown Burner 6.0 0.3% 45.0 0.2%
14 Gas Boiler - Insulate Steam Lines/Condensate Tank 5.2 0.3% 57.3 0.2%
15 Gas Boiler - Hot Water Reset 5.0 0.3% 97.1 0.4%
16 Process Boiler - Steam Trap Replacement 4.3 0.2% 26.9 0.1%
17 Process Boiler - Burner Control Optimization 4.1 0.2% 637.9 2.5%
18 Gas Boiler - Insulate Hot Water Lines 3.5 0.2% 31.8 0.1%
19 Gas Boiler - Maintenance 3.0 0.2% 5.7 0.0%
20 Unit Heater 2.3 0.1% 110.7 0.4%
Subtotal 1,950.4 99.7% 25,067.8 97.6%
Total Savings in Year 1,955.9 100.0
% 25,679.6 100.0
%
Idaho Potential
Table 7-11 and Figure 7-11 summarize the energy conservation potential for the industrial sector. In 2023, UCT
achievable economic potential is 1,540 dtherms, or 0.7% of the baseline projection. By 2045, cumulative savings
reach 28,004 dtherms, or 12.6% of the baseline. Industrial potential is a lower percentage of overall baseline
compared to the residential and commercial sectors. While large, custom process optimization and controls
measures are present in potential, these are not applicable to all processes which limits potential at the
technical level. Additionally, since the largest customers were excluded from this analysis due to their status as
transport-only customers making them ineligible to participate in energy efficiency programs for the utility, the
remaining customers are smaller and tend to have lower process end-use shares, further lowering industrial
potential.
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 66
Table 7-11 Industrial Energy Conservation Potential Summary, Idaho
Scenario 2023 2024 2025 2035 2045
Baseline Forecast (dekatherms) 223,967 223,982 223,868 222,921 222,119
Cumulative Savings (dekatherms)
Achievable Economic UCT Potential 1,540 3,083 4,636 19,707 28,004
Achievable Technical 1,543 3,089 4,649 19,786 28,219
Technical Potential 1,925 3,886 5,857 24,634 35,215
Energy Savings (% of Baseline)
Achievable Economic UCT Potential 0.7% 1.4% 2.1% 8.8% 12.6%
Achievable Technical 0.7% 1.4% 2.1% 8.9% 12.7%
Technical Potential 0.9% 1.7% 2.6% 11.1% 15.9%
Figure 7-11 Cumulative Industrial Potential as % of Baseline Projection, Idaho

Figure 7-12 presents forecasts of energy savings by end use as a percent of total annual savings and cumulative
savings.
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential Achievable Technical Potential Technical Potential
2022-2045 Avista Conservation Potential Assessment | Sector-Level Energy Efficiency Potential

Applied Energy Group, Inc. | appliedenergygroup.com 67
Figure 7-12 Industrial UCT Achievable Economic Potential – Cumulative Savings by End Use, Idaho

Table 7-12 identifies the top 20 industrial measures by cumulative 2023 and 2035 savings.
Table 7-12 Industrial Top Measures in 2023 and 2035, UCT Achievable Economic Potential, Idaho
Rank Measure / Technology
2023
Cumulative
dtherms
% of
Total
2035
Cumulative
dtherms
% of
Total
1 Process - Heat Recovery 1,138.1 73.9% 14,508.6 73.6%
2 Process Boiler - Stack Economizer 105.4 6.8% 907.7 4.6%
3 Process Boiler - Insulate Steam Lines/Condensate Tank 59.4 3.9% 692.5 3.5%
4 Process Boiler - Hot Water Reset 57.4 3.7% 1,184.4 6.0%
5 Process Boiler - Insulate Hot Water Lines 39.8 2.6% 396.2 2.0%
6 Process Boiler - Maintenance 33.3 2.2% 71.7 0.4%
7 Destratification Fans (HVLS) 23.4 1.5% 285.5 1.4%
8 Thermostat - Connected 22.4 1.5% 111.9 0.6%
9 HVAC - Energy Recovery Ventilator 9.2 0.6% 96.0 0.5%
10 Gas Boiler - Stack Economizer 7.9 0.5% 55.8 0.3%
11 Ventilation - Demand Controlled 6.4 0.4% 41.1 0.2%
12 Retrocommissioning 6.3 0.4% 36.6 0.2%
13 Gas Boiler - High Turndown Burner 5.2 0.3% 38.9 0.2%
14 Gas Boiler - Insulate Steam Lines/Condensate Tank 4.5 0.3% 49.0 0.2%
15 Gas Boiler - Hot Water Reset 4.3 0.3% 83.8 0.4%
16 Process Boiler - Steam Trap Replacement 3.5 0.2% 21.7 0.1%
17 Process Boiler - Burner Control Optimization 3.2 0.2% 476.9 2.4%
18 Gas Boiler - Insulate Hot Water Lines 3.0 0.2% 27.2 0.1%
19 Gas Boiler - Maintenance 2.5 0.2% 4.7 0.0%
20 Gas Furnace - Maintenance 1.6 0.1% 2.9 0.0%
Subtotal 1,536.7 99.8% 19,093.1 96.9%
Total Savings in Year 1,540.4 100% 19,702.8 100%

-
5,000
10,000
15,000
20,000
25,000
30,000
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
Dth
Space Heating
Process
Miscellaneous

Applied Energy Group, Inc. | appliedenergygroup.com 68
8 | DEMAND RESPONSE POTENTIAL
This study is the first time AEG estimated demand response (DR) potential for natural gas in the Avista territory.
Natural gas DR is an emerging market with only a few programs offered in the US. To estimate potential, AEG
referenced current natural gas DR program data and addressed gaps utilizing information from the electric DR
study.
This study provides demand response potential and cost estimates for the 23-year planning horizon (2023-
2045) across three states in the Avista territory (Washington, Idaho, and Oregon) to inform the development of
Avista’s 2023 IRP. Through this assessment, AEG sought to develop reliable estimates of the magnitude, timing,
and costs of DR resources likely available to Avista over the planning horizon. The analysis focuses on resources
assumed achievable during the planning horizon, recognizing known market dynamics that may hinder resource
acquisition. The DR potential will be incorporated into subsequent DR planning and program development
efforts.
Study Approach
Figure 8-1 outlines the analysis approach used to develop potential and cost estimates, with each step described
in more detail in the following subsections.
Figure 8-1 Demand Response Analysis Approach

AEG estimated demand response potential across the following scenarios:
• Achievable Technical Potential or Stand Alone. Program options are treated as the only programs
running in the Avista territory and are viewed in a vacuum. Potential savings cannot be added since it does
not account for program overlap.
• Achievable Potential or Integrated. Program options are treated as if they are run simultaneously,
and a program hierarchy is applied to account for participation overlap across programs that use the same
end-use. For programs that affect the same end use, the model selects the most likely program a customer
would participate in, and eligible participants were chosen for that program first. The remaining pool of
eligible participants will then be available to participate in the secondary program. This scenario allows for
potential to be added as it removes any double counting of savings.
Market Characterization
The first step was to segment customers by service class and develop characteristics for each segment. The two
relevant characteristics for the DR potential analysis are end-use saturations of the controllable equipment
types in each market segment and coincident peak demand in the base year. The market characteristics are
consistent with the natural gas energy efficiency analysis (see Chapter 2 for more information on market
profiles).
AEG used Avista’s rate schedules as the basis for customer segmentation by state and customer class. Table 8-1
summarizes the market segmentation developed for this study.
Market
Characterization
•Segment by
Sector,
Geography and
Size
Baseline
Projection
•Use DR
Segmentation
•Account for
Interactions
Characterize DSM
Options
•DLC Measure
Options
•DR Economic
Options
•DSR Options
Potential
Estimation
•Achievable
Technical
•Realistic
Achievable
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 69
Table 8-1 Market Segmentation
Market Dimensions Segmentation Variable Description
1 State
Idaho
Oregon
Washington
2 Customer Class

Residential
Commercial
Industrial
Baseline Forecast
Once the customer segments were defined and characterized, AEG developed the baseline projection. Load and
consumption characteristics, including customer counts and peak-hour demand values, were provided by Avista
and aligned with the natural gas energy efficiency analysis.
Customer Counts
Avista provided actual customer counts by rate schedule for each state over the 2017-2021 timeframe and
forecasted customer counts over the 2022-2026 period. AEG used this data to calculate the growth rates by
customer class across the final two forecasted years and projected customer counts through 2045. The average
annual customer growth rate for all sectors is 1.3% in Washington, 1.5% in Idaho, and 0.9% in Oregon. Table
8-2, Table 8-3, and Table 8-4 show the number of customers by state and customer class for selected years.
Table 8-2 Baseline Customer Forecast by Customer Class, Washington
Customer Class 2023 2024 2025 2035 2045
Residential 162,739 164,977 167,198 190,988 218,240
Commercial 15,277 15,349 15,421 16,154 16,922
Industrial 93 93 93 93 93
Table 8-3 Baseline Customer Forecast by Customer Class, Idaho
Customer Class 2023 2024 2025 2035 2045
Residential 84,954 86,656 88,289 106,441 128,443
Commercial 9,623 9,739 9,845 10,879 12,050
Industrial 68 68 68 68 68
Table 8-4 Baseline Customer Forecast by Customer Class, Oregon
Customer Class 2023 2024 2025 2035 2045
Residential 94,779 95,803 96,875 108,034 120,487
Commercial 12,110 12,197 12,289 13,226 14,234
Industrial 26 26 26 26 26
Winter Peak Load Forecasts by State
Winter peak load forecasts were developed by state and customer class by multiplying the per customer peak-
hour demand values by class by the forecasted customer counts. Table 8-5 shows the winter system peak for
selected future years. The system peaks are expected to increase by 33% between 2023-2045.
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 70
Table 8-5 Baseline February Winter System Peak Forecast (Dth @Generation) by State
State 2023 2024 2025 2035 2045
Washington 13,399 13,553 13,721 15,474 17,454
Idaho 6,877 6,909 7,026 8,077 9,273
Oregon 6,123 6,162 6,219 6,781 7,384
Grand Total 26,399 26,624 26,966 30,331 34,111
Figure 8-2 shows the contribution to the estimated system coincident winter peak by state. In 2023, system
peak load for the winter is 26,399 dekatherms at generation. Washington contributes 51% to the winter system
peak, while Idaho and Oregon contribute 26% and 23%, respectively. Winter coincident peak load is expected
to grow by an average of 1.3% annually from 2023-2045.
Figure 8-2 Coincident Peak Load Forecast by State (Winter)

Characterize Demand Response Program Options
Next, AEG identified and described the viable DR programs for inclusion in the analysis and developed
assumptions for key program parameters, including per customer impacts, participation rates, program
eligibility, and program costs. AEG considered the characteristics and applicability of a comprehensive list of
options available that could be feasibly run in Avista’s territory. Once a list of DR options was determined, AEG
characterized each option.
Each selected option is described briefly below.
Program Descriptions
DLC Smart Thermostats - Heating
These programs use the two-way communicating ability of smart thermostats to cycle heating end uses on and
off during events. The program targets Avista’s Residential and Commercial customers with qualifying
equipment in Washington, Idaho, and Oregon. This was assumed to be a Bring Your Own Thermostat (BYOT)
program; therefore, no equipment or installation costs were estimated.
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2023 2024 2025 2035 2045
Dt
h
Washington Idaho Oregon
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 71
Third Party Contracts
Third Party Contracts are assumed to be available for large commercial and industrial customers. This program
is based on a firm curtailment strategy targeting large process and heating loads. It is also assumed that
participating customers will agree to reduce demand by a specific amount or curtail consumption to a
predefined level at the time of an event. In return, they receive a fixed incentive payment in the form of capacity
credits or reservation payments (typically expressed as $/therm-month or $/therm-year). Customers are paid
to be on call even though actual load curtailments may not occur. The amount of the capacity payment typically
varies with the load commitment level. In addition to the fixed capacity payment, participants typically receive
a payment for gas reduction during events. Because it is a firm, contractual arrangement for a specific level of
load reduction, enrolled loads represent a firm resource and can be counted toward installed capacity
requirements. Penalties may be assessed for under-performance or non-performance. Events may be called on
a day-of or day-ahead basis as conditions warrant.
This option is typically delivered by load aggregators and is most attractive for customers with high natural gas
demand and flexibility in their operations. Industry experience indicates that aggregation of customers with
smaller-sized loads is less attractive financially due to lower economies of scale. In addition, customers with
24x7 operations, continuous processes, or with obligations to continue providing service (such as schools and
hospitals) are not often good candidates for this option.
Time-of-Use Pricing
The TOU pricing rate is a standard rate structure where rates are lower during off-peak hours and higher during
peak hours during the day, incentivizing participants to shift energy use to periods of lower grid stress. For the
TOU rate, there are no events called, and the structure does not change during the year. Therefore, it is a good
default rate for customers that still offers some load-shifting potential. This rate is assumed to be available to
all service classes.
Variable Peak Pricing
The Variable Peak Pricing (VPP) rate is composed of significantly higher prices during relatively short critical
peak periods on event days to encourage customers to reduce their usage. VPP is usually offered in conjunction
with a time-of-use rate, which implies at least three time periods: critical peak, on -peak and off-peak. The
customer incentive is a more heavily discounted rate during off-peak hours throughout the year (relative a
standard TOU rate). Event days are dispatched on relatively short notice (day ahead or day of), typically for a
limited number of days during the year. Over time, event-trigger criteria become well-established so that
customers can expect events based on hot weather or other factors. Events can also be called during times of
system contingencies or emergencies. This rate has been assumed to be offered to all service classes.
Behavioral DR
Behavioral DR is structured like traditional demand response interventions, but it does not rely on enabling
technologies, nor does it offer financial incentives to participants. Participants are notified of an event and
simply asked to reduce their consumption during the event window. Generally, notification occurs the day prior
to the event and are deployed utilizing a phone call, email, or text message. The next day, customers may
receive post-event feedback that includes personalized results and encouragement. This program is assumed
to be offered to residential and commercial customers.
Program Assumptions and Characteristics
The key parameters required to estimate the potential for a DR program are participation rate, per-participant
load reduction, and eligibility or end use saturations.6 The development of these parameters is based on
research findings and a review of available information on the topic, including national program survey

6 End Use Saturations used in this study are provided in Appendix D.
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 72
databases, evaluation studies, program reports, and regulatory filings. AEG’s assumptions of these parameters
are described below.
Participation Rate Assumptions
Table 8-6 below shows the steady-state participation rate assumptions for each demand side management
(DSM) option as well as the basis for the assumptions.
Table 8-6 Steady-State Participation Rate Assumptions (% of eligible customers)
DSM Option Residential
Service
Commercial
Service
Industrial
Service Basis for Assumption
Behavioral 12% 12% - PG&E rollout with six waves (2017) - 60% of
Electric Behavioral Program Participation
DLC Smart Thermostats -
BYOT 9% 9% -
NWPC Smart Thermostat cooling assumption
- 60% of Electric Smart Thermostat Program
Participation
Time-of-Use 8% 8% 8% Industry experience - 60% of Electric TOU
Program Participation
Variable Peak Pricing 15% 15% 15% OG&E 2019 Smart Hours Study - 60% of
Electric VPP Program Participation
Third Party Contracts - 5% 13%
Industry Experience - 60% of Electric Third
Party Contracts Program Participation.
Commercial adjusted to reflect challenge of
reducing heating loads
Load Reduction AssumptionsTable 8-7 presents the per participant load reductions for each DSM option and
explains the basis for these assumptions.
Table 8-7 DSM Per Participant Impact Assumptions
DSM Option Residential
Service
Commercial
Service
Industrial
Service Basis for Assumption
Behavioral 2% 2% - PG&E rollout with six waves (2017)
DLC Smart Thermostats -
BYOT 15% 15% - SoCalGas 2019 Impact Evaluation
Time-of-Use 3% 1% 2% Electric TOU Winter Program Impacts
Variable Peak Pricing 8% 4% 3% OG&E 2019 Smart Hours Impact
Evaluation
Third Party Contracts - 8% 8%
De-rated BYOT Residential impact for
Third Party accounting for less
discretionary load
Other Cross-cutting Assumptions
In addition to the above program-specific assumptions, there are three that affect all programs:
• Discount rate. A nominal discount rate of 5.21% was used to calculate the net present value of costs over
the useful life of each DR program. All cost results are shown in nominal dollars.
• Line losses. Avista provided a line loss factor of 6.16% to convert estimated demand savings at the
customer meter level to the generator level. Results in the next section are reported at the generator level.
• Shifting and Saving. Each program varies in the way energy is shifted or saved throughout the day. For
example, customers on the DLC Smart Thermostat program are likely to pre-heat their homes prior to the
event and turn their heaters back on after the event (snapback effect). The results in this report only show
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 73
the savings during the event window and not before and after the event. However, shifting and savings
assumptions were provided to Avista for each program to inform the IRP results.
Integrated DR Potential Results
This section presents analysis results for demand savings and levelized costs for all considered DR programs. In
the interest of succinctness, AEG only presents the Integrated scenario results in this chapter. The integrated
approach represents Realistic Achievable Potential and is the most realistic scenario allowing for multiple DR
programs to be run at the same time employing a hierarchy that eliminates double counting of impacts. The
stand-alone scenario (Achievable Technical Potential) results can be found in Appendix D. All potential results
represent savings at the generator.7
Integrated Results Summary
Table 8-8, and Figure 8-3 show the total winter demand savings for selected years. These savings represent total
integrated savings from all available DR options in Avista’s Washington, Idaho, and Oregon service territories.
All programs are assumed to start in 2024 so there is zero potential across all programs in 2023. The total
potential savings are expected to increase from 0 in 2023 to 614 dekatherms by 2045. The percentage of system
peak goes from 0% in 2023 to 1.8% by 2045.
Table 8-8 Summary of Integrated Potential (Dekatherms @ Generator)
2023 2024 2025 2035 2045
Baseline Forecast 26,574 26,801 27,145 30,533 34,338
Achievable Potential - 72 176 545 614
Achievable Potential (% of baseline) 0% 0% 1% 2% 2%
Potential Forecast 26,574 26,729 26,969 29,988 33,724
Figure 8-3 Summary of Integrated Potential (Dekatherms @ Generator)

Integrated Results
Key findings from the integrated scenario include:
• The largest potential option is DLC Smart Thermostats - BYOT, contributing 403 dekatherms by 2045.
• The next largest projected savings comes from the Variable Peak Pricing Rate, contributing 120 dekatherms
by 2045.

7 Line losses were applied to all savings potential as well as demand forecasts to present the results in terms of generation as opposed to meter.
20,000
22,000
24,000
26,000
28,000
30,000
32,000
34,000
De
a
t
h
e
r
m
s
Baseline Forecast Potential Forecast
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 74
• The three remaining options contribute 92 dekatherms by 2045
Potential by DSM Option
Figure 8-4 and

Table 8-9 show the total winter demand savings from individual DR options for selected years. These savings
represent integrated savings from all available DR options in Avista’s Washington, Idaho, and Oregon service
territories. Several DR programs require Advanced Metering Infrastructure (AMI) such as rates (TOU and VPP)
and behavioral options. Currently Washington is the only state in the Avista territory with AMI8. Therefore, DLC
Smart Thermostats – BYOT and Third Party Contracts are the only two programs available to all three states.
Across Avista’s entire territory, The DLC Smart Thermostats – BYOT program is projected to save the most of all
programs at 403 dekatherms by 2045 followed by Variable Peak Pricing at 120 dekatherms by 2045.
Figure 8-4 Summary of Potential by Option – (Dekatherms @ Generator)

8 See Appendix Section A | for end use saturation details
-
100
200
300
400
500
600
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Third Party Contracts
Variable Peak Pricing
Time-of-Use
DLC Smart Thermostats
- BYOT
Behavioral
-
100
200
300
400
500
600
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Third Party Contracts
Variable Peak Pricing
Time-of-Use
DLC Smart Thermostats
- BYOT
Behavioral
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 75
Table 8-9 Summary of Potential by Option – (Dekatherms @ Generator)
2023 2024 2025 2035 2045
Behavioral - 14 22 30 33
DLC Smart Thermostats - BYOT - 31 94 357 403
Time-of-Use - 2 6 21 23
Variable Peak Pricing - 10 30 105 119
Third Party Contracts - 15 24 32 35
Potential by Class
Table 8-10, Table 8-11, and Table 8-12 show the total winter demand savings by class for Washington, Idaho,
and Oregon respectively. Washington is projected to save 407 dekatherms (2.3% of winter system peak demand)
by 2045, Idaho is projected to save 126 dekatherms (1.4% of winter system peak demand) by 2045, and Oregon
is projected to save 80 dekatherms (1.1% of winter system peak demand) by 2045.
The residential sector contributes 69% of the total load across all three states while commercial and industrial
contribute 44% and 2% respectively. This is due primarily to the low number of industrial natural gas customers
in Avista’s territory.
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 76
Table 8-10 Potential by Class – Dekatherms @Generator, Washington
2023 2024 2025 2035 2045
Baseline Forecast 13,399 13,553 13,721 15,474 17,454
Achievable Potential - 51 120 361 407
Residential - 30 76 249 284
Commercial - 20 43 110 121
Industrial - 1 1 2 2
Table 8-11 Potential by Class – Dekatherms @Generator, Idaho
2023 2024 2025 2035 2045
Baseline Forecast 6,877 6,909 7,026 8,077 9,273
Achievable Potential - 12 32 110 126
Residential - 6 19 76 91
General Service - 6 13 33 35
Large General Service - 0 1 1 1
Table 8-12 Potential by Class – Dekatherms @Generator, Oregon
2023 2024 2025 2035 2045
Baseline Forecast 6,123 6,162 6,219 6,781 7,384
Achievable Potential - 9 24 74 80
Residential - 4 12 43 48
General Service - 5 11 30 32
Large General Service - 0 0 0 0
Figure 8-5 Potential by Class –Dekatherms @Generator, Washington

-
50
100
150
200
250
300
350
400
450
500
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Industrial
Commercial
Residential
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 77
Figure 8-6 Potential by Class – Dekatherms @Generator, Idaho

Figure 8-7 Potential by Class – Dekatherms @Generator, Oregon

Levelized Costs
Table 8-13 presents the levelized costs per dekatherm of equivalent generation capacity over 2023-2032 for
Washington, Idaho, and Oregon. The ten-year NPV dekatherm potential by program is shown for reference in
the first column.
Key findings include:
• The Third Party Contracts option is expected to be the cheapest program to run per dekatherm savings at
approximately $2,568/Dth-year. Capacity-based and energy-based payments to the third-party constitutes
the major cost component for this option. All development, O&M, and administrative costs are expected
to be incurred by the representative third-party contractor.
• The Time-of-Use option has the highest levelized cost among all the DR options over ten years at
$16,815/dekatherm-year system-wide. The main contributors to the high cost compared to low savings are
marketing and recruitment and administrative costs.
-
50
100
150
200
250
300
350
400
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Industrial
Commercial
Residential
-
50
100
150
200
250
300
350
400
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Industrial
Commercial
Residential
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 78
Table 8-13 Levelized Program Costs and Potential (TOU Opt-In Winter)
Program NPV Dth Potential Levelized Costs ($/Dth)
Behavioral 168.48 $11,170.36
DLC Smart Thermostats - BYOT 1633.65 $4,924.69
Time-of-Use 94.94 $16,814.75
Variable Peak Pricing 487.42 $4,338.36
Third Party Contracts 186.21 $2,567.59

Applied Energy Group, Inc. | appliedenergygroup.com 79
DEMAND RESPONSE POTENTIAL APPENDIX
Equipment End Use Saturation
The end use saturation data is required to further segment the market and identify eligible customers for direct
control of different equipment options. Table A-1 below shows saturation estimates by state and customer class
for Washington, Idaho, and Oregon. For Washington and Idaho, AEG used the end use saturation data from the
energy efficiency study. In absence of saturation data, Oregon saturations use Washington saturations as a
proxy. For AMI, Avista provided gas AMI saturation data for Washington, but AMI has yet to be rolled out in
Idaho and Oregon.
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 80
Table A-1 End Use Saturations by Customer Class and State9
State Customer
Class End Use Saturation 2023 2024 2025 2035 2045 Source
WA Res Gas Space Heat 87% 87% 87% 89% 89% Baseline Survey
WA Res Gas Water Heat 55% 55% 55% 56% 56% Baseline Survey
WA Res Behavioral 100% 100% 100% 100% 100% Default
WA Res AMI 85% 85% 85% 85% 85% AMI data from Avista
WA Com Gas Space Heat 77% 77% 77% 77% 77% Baseline Survey
WA Com Gas Water Heat 58% 58% 58% 58% 58% Baseline Survey
WA Com Behavioral 100% 100% 100% 100% 100% Default
WA Com AMI 86% 86% 86% 86% 86% AMI data from Avista
WA Ind Gas Space Heat 84% 84% 84% 84% 84% Baseline Survey
WA Ind Gas Process Heat 100% 100% 100% 100% 100% Baseline Survey
WA Ind AMI 97% 97% 97% 97% 97% AMI data from Avista
ID Res Gas Space Heat 94% 94% 94% 94% 94% Baseline Survey
ID Res Gas Water Heat 56% 56% 56% 56% 56% Baseline Survey
ID Res Behavioral 100% 100% 100% 100% 100% Default
ID Res AMI 0% 0% 0% 0% 0% AMI data from Avista
ID Com Gas Space Heat 77% 77% 77% 77% 77% Baseline Survey
ID Com Gas Water Heat 58% 58% 58% 58% 58% Baseline Survey
ID Com Behavioral 100% 100% 100% 100% 100% Default
ID Com AMI 0% 0% 0% 0% 0% AMI data from Avista
ID Ind Gas Space Heat 84% 84% 84% 84% 84% Baseline Survey
ID Ind Gas Process Heat 100% 100% 100% 100% 100% Baseline Survey
ID Ind AMI 0% 0% 0% 0% 0% AMI data from Avista
OR Res Gas Space Heat 87% 87% 87% 89% 89% WA Proxy
OR Res Gas Water Heat 55% 55% 55% 56% 56% WA Proxy
OR Res Behavioral 100% 100% 100% 100% 100% WA Proxy
OR Res AMI 0% 0% 0% 0% 0% AMI data from Avista
OR Com Gas Space Heat 77% 77% 77% 77% 77% WA Proxy
OR Com Gas Water Heat 58% 58% 58% 58% 58% WA Proxy
OR Com Behavioral 100% 100% 100% 100% 100% Default
OR Com AMI 0% 0% 0% 0% 0% AMI data from Avista
OR Ind Gas Space Heat 84% 84% 84% 84% 84% WA Proxy
OR Ind Gas Process Heat 100% 100% 100% 100% 100% WA Proxy
OR Ind AMI 0% 0% 0% 0% 0% AMI data from Avista
Mechanism and Event Hours
Table A-2 lists the DSM options considered in the study, including the eligible sectors, the mechanism for
deployment, and the expected annual event hours.

9 Res = Residential, Com = Commercial, Ind = Industrial
2022-2045 Avista Conservation Potential Assessment | Demand Response Potential

Applied Energy Group, Inc. | appliedenergygroup.com 81
Table A-2 DSM Program Event Hours
DSM Option Eligible Sectors Annual
Seasonal Hours
Average Event
Duration (hours)
Estimated Number
of Events per Year
Behavioral Res and Com 40 6 7
Third Party Contracts C&I 30 4 8
Time-of-Use All 528 6 88
Variable Peak Pricing Rates All 80 4 20
DLC Smart Thermostats - BYOT Res and Com 36 3 12
Stand Alone Results
Figure A-1 and Table A-3 show the winter demand savings from individual DR options. These savings represent
stand-alone savings from all available DR options in Washington, Idaho, and Oregon service territories. The
Smart Thermostats and Third Party Contracts programs are projected to save the same amount as in the
integrated scenario due to the expectation that there won’t be participation overlap across other programs for
these offerings.
• Like in the integrated scenario, the largest potential option is DLC Smart Thermostats - BYOT, contributing
403 dekatherms by 2045.
• The next largest projected savings comes from the Variable Peak Pricing Rate, contributing 145 dekatherms
by 2045.
Figure A-1 Summary of Potential by Option – Stand Alone (Dekatherms @Generator)

Table A-3 Summary of Potential by Option – Stand Alone (Dekatherms @ Generator)
2023 2024 2025 2035 2045
Behavioral - 14 23 33 37
DLC Smart Thermostats - BYOT - 31 94 357 403
Time-of-Use - 2 7 25 28
Variable Peak Pricing - 11 34 128 145
Third Party Contracts - 15 24 32 35
-
100
200
300
400
500
600
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Third Party Contracts
Variable Peak Pricing
Time-of-Use
DLC Smart Thermostats
- BYOT
Behavioral

Applied Energy Group, Inc.
2300 Clayton Road, Suite 1370
Concord, CA 94520

Appendix 3.2: Oregon Firm-Customers

Energy Trust of Oregon Background
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 housing energy assistance, and
energy efficiency and renewable energy programs for residential and business customers.1

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 865
aMW of electricity and 84 million annual therms. This equates to more than 22.3 million metric
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 2011 to 2020, as shown in
OPUC utility statistic books.2

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 2021,
Energy Trust’s programs achieved savings of 408,163 therms—equivalent to about 93% of the
IRP target, as shown in

1 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 $190 million in 2021.
2 OPUC 2020 Stat book – 10 Year Summary Tables: https://www.oregon.gov/puc/forms/Forms%20and%20Reports/2020-
Oregon-Utility-Statistics-Book.pdf
Figure 1. As seen in the figure, 2021 is the first year Energy Trust savings in Avista’s Oregon
service territory are below the IRP target. While savings remained relatively consistent with
2020, Energy Trust projected growth in 2021 as an extension of increased efficiency activities
seen in 2020 as a result of pandemic related market conditions. However, supply chain and
labor difficulties experienced in 2021 slowed down the rate of growth Energy Trust was able to
achieve. Energy Trust is working with Avista to build program delivery infrastructure to
accelerate savings acquisition to meet carbon reduction requirements in context with related
least-cost planning principles.

Figure 1 – Achieved Savings by Sector vs. IRP Targets 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 in their resource mix 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
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0.5
2016 2017 2018 2019 2020 2021
MM

T
h
e
r
m
s
Com Ind Res IRP Target
Figure 2 and discussed in greater detail in the sections below.

Figure 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®3, 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

3 http://www.lumina.com/why-analytica/what-is-analytica1/
Figure 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.

Figure 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.4 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’).
• 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.

4 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.
The characterization inputs are determined through a combination of Energy Trust
primary data analysis, regional secondary sources5, 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., wall
insulation greater than or equal to R11 replacing wall insulation with an R
value of four or less). 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. 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:
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

5 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)
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 next
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.

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. Energy
Trust first updated its methodology in Avista’s 2020 IRP to reflect the maximum achievability
estimated by the Northwest Power and Conservation Council for the 2021 Power Plan, and
has done so again for the 2023 IRP. While in past power plans a universal assumption of
85% was used, these factors now typically range from 85% to 95%.6

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.

6 For details on this, see https://www.nwcouncil.org/sites/default/files/2019_0813_p5.pdf.
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
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 4 below reiterates the types of potential shown in
Figure 2, and how the steps described above and in the flow chart fit together.

Figure 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 (Base Case)
The results of Energy Trust’s forecast are shown below. Energy Trust performed two analyses
for Avista’s 2023 IRP – a base case using an expected load forecast with expected commodity
prices, transport prices and carbon prices, and a high case using a high growth load forecast
with high growth commodity prices, transport prices and carbon prices. The results presented
below reflect the base case. The results from the high scenario are presented in a separate
section at the end of this chapter.

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 1 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 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.

Table 1 - Summary of Cumulative Modeled Savings Potential - 2023–2042
Sector Technical Potential
(Million Therms)
Achievable Potential
(Million Therms)
Cost-Effective
Achievable Potential
(Million Therms)
Residential7 20.3 16.2 15.9
Commercial 6.9 5.8 5.5
Industrial 0.4 0.3 0.3
Total 27.6 22.3 21.6

Figure 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 78% and 79% of technical potential, respectively.

Figure 5 - Savings Potential by Sector and Type – Cumulative 2023–2042 (Millions of Therms)

7 Residential sector savings potential reflect the load and stock forecast from all of Avista’s residential customers in
Oregon, including low-income customers modeled separately by AEG.
Cost-Effective Achievable Savings by End-Use

Figure 6 below provides a breakdown of Avista’s 20-year cost-effective savings potential by end
use.

Figure 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, 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 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 2.
Table 2 - Emerging Technologies Included in the Model
Residential Commercial Industrial
0
1
2
3
4
5
6
7
MM

T
h
e
r
m
s
• Attic Insulation R-60
• Behavior Competitions
• Cellular Shades
• Gas Absorption Heat Pump Water
Heater
• Gas Fired Heat Pump
• Thin Triple Pane Windows
• Wall Insulation R-30
• Condensing Gas Rooftop unit
• Gas Absorption Heat Pump
Hot Water
• Gas-fired Heat Pump
• Gas RTU Advanced Tier 1
• Thin Triple Pane Windows
• VHE DOAD/HRV
• Zero Net Energy
• Advanced Wall Insulation
• Gas Fired Heat Pump
Water Heater

Energy Trust recognizes that emerging technologies are inherently uncertain and applies 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. 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.

Table 3 - Emerging Technology Risk Factor Score Card
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

Figure 7 below 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 23%, 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 forecasted decreases in cost
and increased savings from these technologies over time where applicable, some are not cost-
effective at any point over the planning horizon.

Figure 7 – Cumulative Contribution of Emerging Technologies by Potential Type

22.3%
22.2%20.2%
0
5
10
15
20
25
30
Technical Achievable Cost-Effective Achievable
MM

T
h
e
r
m
s
Conventional Emerging

Cost-Effective Override Effect
Table 4 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 4 - Cumulative Cost-Effective Potential (2023-2042) due to Cost-Effectiveness Override
(Millions of therms)
Sector
With Cost
Effectiveness
Override
Without Cost
Effectiveness
Override
Difference
Residential 15.9 15.0 (0.8)
Commercial 5.5 5.5 -
Industrial 0.3 0.3 -
Total 21.6 20.8 (0.8)

In this IRP, approximately 8% 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, gas heated new manufactured homes, clothes
washers, and commercial wall and roof insulation8.

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 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 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, without override,
identified in this assessment is approximately 19.9 million therms, which translates to
approximately $2.89/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.

8 Since the completion of Avista’s 2023 IRP the Oregon Public Utility Commission has granted measure exceptions
associated with measures which are being offered in 2023. The results presented in this chapter reflect measures
under OPUC exception as of 2022. Notable changes include residential gas insulation measures becoming cost-
effective and not under exception, and the addition of residential and multifamily windows as measures under
exception.
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 8 – Natural Gas Efficiency Supply Curve

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 5, which compares the technical, achievable, and cost
–effective achievable potential for comparison.

Table 5 - 20-Year Cumulative Savings Potential by Type (Millions of Therms)
Technical
Potential
Achievable
Potential
Cost-
Effective
Achievable
Potential
Energy Trust
Deployed Savings
Projection
Residential 20.3 16.2 15.9 9.9
Commercial 6.9 5.8 5.5 3.8
Industrial 0.4 0.3 0.3 0.3
Exogenous9 - - - 1.4

9 The final deployed savings projection includes savings calculated outside of the modeling process consisting of the
large project adder and unclaimed market savings.
0
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
M

T
h
e
r
m
s
)
Levelized cost ($/therm)
Total 27.6 22.3 21.6 15.3

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.

Figure 9 below shows the annual savings projection by sector. The savings acquisitions in the
initial years are fairly flat due to expected market conditions. After this point, expected program
savings ramp up over the forecast period, to achieve as much cost-effective potential as
possible.

Figure 9 – Annual Deployed Final Savings Potential by Sector

Finally, Figure 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 13.7% by 2042.

-
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
MM

T
h
e
r
m
s
Residential Commercial Industrial Unclaimed Market Savings Large Project Adder
Figure 10 – Annual and Cumulated Forecasted Savings as a Percentage of Avista Load Forecast

Comparison to 2020 IRP Savings Projection
Figure 11 below shows the annual deployed savings potential discussed above compared to
Avista’s previous IRP completed in 2020. In Avista’s 2020 IRP savings peaked around year
2039, whereas Energy Trust’s current forecast shows savings peaking in year 2034 reflecting
acceleration in the near-term savings acquisition and thus acquiring more retrofit potential
earlier in the forecast period. This is especially evident in the commercial and industrial sectors,
whereas residential savings grow throughout the forecast horizon.

0%
2%
4%
6%
8%
10%
12%
14%
16%
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
Pe
r
c
e
n
t

o
f

L
o
a
d

S
a
v
e
d
Annual % of Load Saved Cumulative % of Load Saved
Figure 11 – Annual Deployed Final Savings Projection Compared to 2020

Table 6 below compares the modeled potential between this study and the 2020 IRP. Savings
are up in each category of potential in the 2023 IRP compared to the 2020 IRP, however a
lower share of cost-effective potential is reflected in the final deployment. This is primarily due to
the 2023 IRP having a higher proportion of emerging technology potential. Energy Trust applies
a different ramp rate to emerging technologies than the ramp rate applied to conventional
technologies. The emerging technology ramp rate places emerging technologies at the
beginning of an adoption curve when the model demonstrates that they become market ready
and cost-effective.

Table 6 - 20-Year Cumulative Savings Potential by IRP vintage (Millions of Therms)
2023 IRP 2020 IRP Difference
Technical 27.6 24.9 2.7
Achievable 22.3 22.2 0.1
Cost-
Effective 21.6 18.0 3.6
Deployed 15.3 14.8 0.5

Table 7 details the individual changes contributing to the 3.6 MM therm difference in cost-
effective achievable potential shown above. Changes in load and stock forecast is the largest
contributor, followed by emerging technology and measures updates.

Table 7 – Difference Between 2023 and 2020 Cost-Effective Achievable Potential (Millions of
Therms)
Difference Share of
Difference
Load and Stock Forecast + 1.29 36%
-
0.2
0.4
0.6
0.8
1.0
1.2
MM

T
h
e
r
m
s
2023 IRP Total 2020 IRP Total
Emerging Technology + 0.84 23%
Measure Updates + 0.68 19%
Avoided Costs + 0.48 13%
Discount Rate + 0.34 9%
CE Override - 0.01 0%
Total + 3.63

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 the related impact on capacity investments. This new
focus has led some utilities to embark on efforts to avoid or delay distribution system
reinforcements. Therefore, Avista and Energy Trust have collaborated to develop estimates of
peak day contributions from the energy efficiency measures in the Energy Trust forecast.

Peak day coincident factors are the percentage of annual savings that occur on a peak day and
are shown in Table 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 measures 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 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 align with a winter system peak that is typical of natural gas
utilities.

Table 8 - Peak Day Coincident Factors by Load Profile

Load Profile Peak Day Factor Source
Residential Space Heating 2.00% NW Natural
Commercial Space Heating 1.77% NW Natural
Water Heating 0.33% NWPCC
Clothes Washer 0.20% NWPCC
Process Load 0.27% NWPCC

Figure 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 230,998 therms in Avista’s
Oregon service territory over the 20-year forecast, as shown in 9 below.

Figure 12 - Annual Deployed Peak Day DSM Savings Contribution by Sector9

Table 9 - Cumulative Deployed Peak Day DSM Savings Contribution by Sector (Therms)
Sector Cumulative Peak Day Savings
(Therms)
Residential 165,069
Commercial 59,108
Industrial 2,571
Exogenous9 4,249
Total 230,998
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Pe
a
k

D
a
y

T
h
e
r
m
s
Residential Commercial Industrial Exogenous

Scenario Runs
For the 2023 IRP, Energy Trust modeled two scenarios for Avista. The two scenarios were
designed to reflect differences in load growth and avoided costs. These scenarios are outlined
in the bullets below:
• Base Case: Expected load forecast with expected commodity prices, transport prices
and carbon prices.
• High Case: High growth load forecast with high growth commodity prices, transport
prices and carbon prices.
Figure 13 provides a graphical view of the annual savings potential for the two scenarios. Table
10 provides the cumulative savings potential of each scenario.

Figure 13 - Annual Deployed Savings Comparison of Scenarios

Table 10 - Cumulative 20-year Deployed Savings Potential by Scenario (Therms)
Sector Cumulative Savings (Therms)
Base Case 15,368,375
High Case 15,942,609

The high case scenario results in an increase in deployed savings potential. This occurs through
two channels. The amount of technical and achievable potential increases as a result of the
higher load growth forecast, and, separately, increases in avoided costs result in more of that
achievable potential being cost-effective. The high case results in about a 3.7% increase in the
deployed savings forecast. As in the base case, the first five years of the forecast period are set
by program budgets and expectations of market conditions, and therefore the high case
increases begin in year six of the forecast period.
-
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
MM

T
h
e
r
m
s
Base Case High Case

Applied Energy Group, Inc. | appliedenergygroup.com 1
MEMORANDUM
To: Lisa McGarity and Ryan Finesilver – Avista Corporation
From: Eli Morris, Andy Hudson, Ken Walter, Stephanie Chen, Laraeb Khan - AEG
Date: December 16, 2022
Re: Avista Oregon Low-Income Conservation Potential Assessment
Background
To support initiatives to serve low-income customers and reduce energy burden in its Oregon natural gas service
territory, Avista Corporation (Avista) engaged Applied Energy Group (AEG) to assess the energy efficiency potential
for Oregon low-income households. This analysis leverages the natural gas conservation potential assessment (CPA)
AEG was already performing for Avista’s Washington and Idaho service territories, incorporating Oregon-specific data
to ensure results are directly applicable to Avista’s Oregon low-income customers.
This memo presents a high-level summary of potential results, followed by an overview of AEG’s methodology,
identification of key data sources, customer segmentation analysis, and more detailed potential results.
Results Summary
A summary of the energy efficiency potential for Oregon low-income customers is presented in Table 1. As shown,
achievable and cost-effective energy efficiency potential represents approximately 9% of baseline sales by 2045.
AEG notes the following considerations in reviewing these results:
• The study relied on the best available data from Avista and secondary sources. Sources did not include on-site
assessments of low-income customer equipment efficiency or practices. Therefore, current conditions and
remaining opportunities were estimated using information about typical characteristics by market segment.
• Achievable economic potential was estimated from the Total Resource Cost (TRC) perspective, consistent with
standard cost-effectiveness practices for energy efficiency in Oregon.
• Energy efficiency programs serving low-income customers are often not required to be cost-effective. Achievable
technical potential provides an estimate of what could be possible if cost-effectiveness is not considered.

Applied Energy Group, Inc. | appliedenergygroup.com 2
Table 1 – Summary of Energy Efficiency Potential
2023 2024 2025 2035 2045
Baseline Projection (Dth)1 914,784 919,566 924,873 999,238 1,128,049
Cumulative Savings (Dth)

Achievable Economic Potential 3,816 7,383 12,114 60,487 99,838
Achievable Technical Potential 8,877 18,471 30,274 165,088 205,045
Technical Potential 14,319 28,147 44,987 226,689 295,472
Cumulative Savings (% of Baseline)
Achievable Economic Potential 0.4% 0.8% 1.3% 6.1% 8.9%
Achievable Technical Potential 1.0% 2.0% 3.3% 16.5% 18.2%
Technical Potential 1.6% 3.1% 4.9% 22.7% 26.2%
Methodology
AEG used a bottom-up approach to perform the potential analysis, following the steps listed:
1. Perform a customer segmentation analysis to estimate the number of Avista Oregon residential customers
in each housing type and considered low-income, and the energy consumption of each segment.
2. Perform a market characterization to describe sector-level natural gas use for residential low-income
customers for the base year, 2021. The characterization included extensive use of Avista data and other
secondary data sources from Northwest Energy Efficiency Alliance (NEEA) and the Energy Information
Administration (EIA).
3. Develop a residential baseline projection of energy consumption by segment, end use, and technology for
2023 through 2045.
4. Define and characterize energy efficiency measures to be applied to all segments and end uses.
5. Estimate technical, achievable technical, and achievable economic energy efficiency potential at the
measure level for 2023 through 2045.
Key Data Sources
AEG used Avista’s 2022 Washington and Idaho CPA as the foundation for this assessment. Key updates from the
Washington CPA assumptions to reflect the Oregon market and potential included:
• Input and market characterization data were specific to Avista’s Oregon low-income customers. The CPA model
generally formed the basis for measure cost assumptions and savings estimates.
• With the CPA measure list as the starting point, AEG worked with Avista to identify measures in active programs
serving low-income customers, avoiding measures that are inappropriate for these segments due to costs or
other concerns.
• The model reflects baseline conditions in alignment with Oregon’s state building codes.
Where data gaps existed in Avista’s data, AEG relied on national and regional data sources for assumptions in the
potential model. Table 2 summarizes key data sources used and how they informed the study.

1 1 Dth = 1 dekatherm, or 10 therms

Applied Energy Group, Inc. | appliedenergygroup.com 3
Table 2 – Key Data Source Summary
Data Source Used for
Avista Data
Development of customer counts and energy use for each segment type,
comparison baseline forecast, customer counts forecast, presence of
equipment, end use load distribution, economics inputs, scenario development
US Census American Community Survey
(ACS) Household characteristics in block groups
Northwest Power and Conservation
Council’s 2021 Power Plan Technical achievable ramp rate library and study methodology
NEEA’s Residential Building Stock
Assessment II (RBSA), Single-Family
Homes Report 2016-2017
Benchmark equipment saturations, normalized end use and equipment
intensity (therms per household)
US Energy Information Administration
(EIA) 2015 Residential Energy
Consumption Survey (RECS)
Estimated equipment use per unit, end use distribution of natural gas use by
segment type, benchmarking equipment presence (saturation)
EIA’s 2020 Annual Energy Outlook Reference baseline purchase assumptions, equipment lifetimes and costs
Customer Segmentation Analysis
To estimate the number of Avista customers in Oregon to include in the low-income assessment, AEG mapped
address data back to corresponding geographic "block groups" in the ACS census data. Each block groups was then
processed to analyze average household size and income, producing a distribution of households into income buckets
for places where Avista customers reside. The low-income threshold corresponds with 200% of the Federal Poverty
Level. The maps in Figure 1 shows the distribution of different income groups through Avista’s Oregon service
territory.

Applied Energy Group, Inc. | appliedenergygroup.com 4
Figure 1 – Income Group Map

Once the percentage of customers in each housing type and income group was known, AEG used RBSA data to
investigate differences in energy consumption for each grouping, enabling a comparison of natural gas usage per
household across categories. Combining the geographic/demographic analysis with RBSA data on usage differences
by income level, AEG was able to produce an expanded residential profile with data-driven variation by income group.
Table 3 shows the customer energy consumption by income level in the base year, 2021. While AEG fully
characterized the residential customer populations, only low-income customers are included in the potential
analysis.
Table 3 – Customer Counts and Energy Consumption by Dwelling Type and Income Level, 2021
Segment Households Natural Gas Consumption
(Dth)
Intensity
(Dth/household)
Single Family - Regular Income 58,913 3,770,739 64,006
Single Family - Low Income 12,289 662,559 53,917
Multi-Family - Regular Income 7,707 183,230 23,774
Multi-Family - Low Income 4,428 88,679 20,026
Mobile Home - Regular Income 7,066 253,416 35,864
Mobile Home - Low Income 2,197 113,191 51,514
Total 92,600 5,071,813 54,771

Applied Energy Group, Inc. | appliedenergygroup.com 5
Potential Results
Figure 2 presents the annual potential savings relative to the baseline projection. Based on the ramp rates used, a
majority of the identified potential is assumed to be acquired over 10 years.
Figure 2 – Cumulative Energy Efficiency Potential as % of Baseline Projection

Figure 3 presents the percentage of achievable economic potential in 2045 by market segment and end use. Single
family dwellings account for 77% of low-income achievable economic potential. Space heating accounts for 67% of
low-income achievable economic potential.
Figure 3 - Achievable Economic Potential, 2045

0%
5%
10%
15%
20%
25%
30%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential Achievable Technical Potential Technical Potential
Single
Family
77%
Multi-
Family
17%
Mobile Home
6%
Potential by Market Segment
Space
Heating
67%
Secondary
Heating
0%
Water
Heating
33%
Appliances
0%Miscellaneous
0%
Potential by End Use

Applied Energy Group, Inc. | appliedenergygroup.com 6
Figure 4 presents a forecast of cumulative achievable economic potential by end use. Space heating accounts for
the majority of potential but declines slightly in the mid-2020s due to a future furnace standard.
Figure 4 – Cumulative TRC Achievable Economic Potential by End Use

Table 4 identifies the top measures by cumulative 2023 and 2035 achievable economic potential. Furnaces,
connected smart thermostats, and insulation are the top measures.
Table 4 – Top Measures in 2023 and 2035, Achievable Economic Potential
Rank Measure / Technology
2023
Cumulative
Dth
% of
Total
2035
Cumulative
Dth
% of
Total
1 Gas Furnace - Maintenance 1,813 47.5% 5,115 8.5%
2 Connected Thermostat - ENERGY STAR (1.0) 860 22.5% 18,027 29.8%
3 Furnace 694 18.2% 8,829 14.6%
4 Insulation - Ceiling Installation 326 8.5% 6,915 11.4%
5 Insulation - Wall Sheathing 51 1.3% 1,118 1.8%
6 ENERGY STAR Home Design 26 0.7% 5,090 8.4%
7 Behavioral Programs 21 0.5% 764 1.3%
8 Insulation - Wall Cavity Installation 11 0.3% 238 0.4%
9 Circulation Pump - Timer 5 0.1% 1,208 2.0%
10 Water Heater - Pipe Insulation 3 0.1% 365 0.6%
11 ENERGY STAR Doors - Storm and Thermal 2 0.1% 581 1.0%
12 Windows - Low-e Storm Addition 2 0.1% 1,315 2.2%
13 Windows - High Efficiency (Class 22) 1 0.0% 395 0.7%
14 Windows - High Efficiency (Class 30) 1 0.0% 285 0.5%
Subtotal 3,815 100.0% 50,245 83.1%
Total Savings in Year 3,816 100.0% 60,487 100.0%

-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
110,000
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
Dt
h
Space Heating
Secondary
Heating
Water Heating
Appliances
Miscellaneous

Applied Energy Group, Inc. | appliedenergygroup.com 1
MEMORANDUM
To: Ryan Finesilver and Tom Pardee – Avista Corporation
From: Eli Morris, Andy Hudson, Ken Walter, Fuong Nguyen - AEG
Date: December 16, 2022
Re: Avista Washington and Oregon Natural Gas Transportation Customer Conservation Potential Assessment
Background
Avista Corporation (Avista) engaged Applied Energy Group (AEG) to assess the conservation potential at Washington
and Oregon natural gas transportation customer1 facilities to inform the extent to which energy efficiency savings at
these facilities could help Avista comply with new regulations. In Washington and Oregon, Avista’s transportation
customers are currently exempt from funding energy efficiency programs and thus are not eligible to participate in
natural gas energy efficiency programs administered by Avista and the Energy Trust of Oregon in Washington and
Oregon, respectively.
In Washington, the Washington Utilities and Transportation Commission continues to consider whether pursuing all
cost-effective conservation, as required by Initiative 937, requires utilities to fund energy efficiency programs for
natural gas transportation customers. In Oregon, Executive Order 20-04, passed in March 2020, limits statewide
greenhouse gas emissions from large stationary sources, transportation fuel, and other liquid and gaseous fuels by
new goals established by the Oregon Department of Environmental Quality (DEQ). The Climate Protection Program
(CPP) formalizes emission reduction requirements for Oregon’s natural gas utilities, including the responsibility for
on-site emissions of natural gas transportation customers.
The remainder of this memo presents high-level study results, followed by an overview of AEG’s methodology,
identification of key data sources, potential results, and considerations and recommendations as Avista considers
new program options to reach these customers.
Results Summary
Table 1 and Table 2 summarize the energy efficiency potential at transportation customer sites in Washington and
Oregon, respectively. AEG notes the following considerations in reviewing these results:
• The potential represents expected levels of savings using average assumptions across customers and equipment.
However, a small number of customers represent a majority of transportation customer consumption (the top
21% of the largest Washington transportation customers make up roughly 76% of Avista Washington
transportation load). Therefore, actual energy efficiency impacts may vary widely depending on whether these
large customers choose to participate in potential programs and customer-specific characteristics. As such, these
results should be viewed as planning assumptions that are likely to differ in practice.
• The study relied on the best available data from Avista and secondary sources, which did not include on-site
assessments of transportation customer equipment efficiency or practices. Therefore, current conditions and

1 Transportation customers are non-residential natural gas consumers, typically large industrial users, who purchase natural gas from an alternate supplier
but use Avista’s distribution system to deliver the fuel to their sites.

Applied Energy Group, Inc. | appliedenergygroup.com 2
remaining opportunities were estimated using information about typical characteristics by market segment (i.e.,
business or industry type).
• Achievable economic potential was estimated from the Total Resource Cost (TRC) perspective, consistent with
standard cost-effectiveness practices for energy efficiency in Washington and Oregon.
• In Washington, programs are anticipated to roll out halfway through 2024; therefore, there is zero achievable
technical and achievable economic potential savings potential in 2023. In Oregon, programs are anticipated to
roll out halfway through 2023.
Table 1 – Summary Potential Results – Reference Case, Washington
2023 2024 2025 2035 2045
Baseline Projection (Dth) 7,948,528 7,926,395 7,906,170 7,784,947 7,734,852
Cumulative Savings (Dth)
Achievable Economic Potential 0 35,247 97,553 821,836 1,234,253
Achievable Technical Potential 0 42,283 115,124 970,876 1,437,154
Technical Potential 37,603 121,842 239,931 1,417,264 2,031,971
Cumulative Savings (% of Baseline)
Achievable Economic Potential 0.0% 0.4% 1.2% 10.6% 16.0%
Achievable Technical Potential 0.0% 0.5% 1.5% 12.5% 18.6%
Technical Potential 0.5% 1.5% 3.0% 18.2% 26.3%
Table 2 – Summary Potential Results – Reference Case, Oregon
2023 2024 2025 2035 2045
Baseline Projection (Dth) 4,681,846 4,677,171 4,672,870 4,646,028 4,633,981
Cumulative Savings (Dth)
Achievable Economic Potential 18,128 51,503 86,078 459,802 665,887
Achievable Technical Potential 19,119 53,850 89,939 475,228 684,470
Technical Potential 31,066 79,749 129,326 615,631 874,975
Cumulative Savings (% of Baseline)
Achievable Economic Potential 0.4% 1.1% 1.8% 9.9% 14.4%
Achievable Technical Potential 0.4% 1.2% 1.9% 10.2% 14.8%
Technical Potential 0.7% 1.7% 2.8% 13.3% 18.9%
Methodology
AEG used a bottom-up approach to perform the potential analysis, following the steps listed:
Perform a customer segmentation analysis to estimate the number of Avista Washington and Oregon
transportation customers in each market segment and the energy consumption of each segment.
Perform a market characterization to describe sector-level natural gas use for transportation customers for
the base year, 2021. The characterization included extensive use of Avista data and other secondary data
sources from the US Energy Information Administration (EIA).
Develop a baseline projection of energy consumption by segment, end use, and technology for 2023
through 2045.
Define and characterize energy efficiency measures to be applied to all segments and end uses.
Estimate technical, achievable technical, and achievable economic potential for 2023 through 2045.

Applied Energy Group, Inc. | appliedenergygroup.com 3
Key Data Sources
AEG used Avista’s 2022 Washington Natural Gas Conservation Potential Assessment (CPA) as the foundation for this
assessment. The Washington CPA assessed natural gas energy efficiency potential for Avista’s residential, commercial,
and industrial sales customers, but excluded transportation customers. Key updates AEG made to Washington CPA
assumptions to reflect Washington and Oregon transportation customers, loads, and potential included:
• Input and market characterization data for this analysis were specific to Avista’s Washington and Oregon
transportation customers, including baseline sales, forecasts, and industry designations. The Washington CPA
generally formed the basis for the measure cost assumptions and savings percentage estimates.
• AEG benchmarked the distribution of end use loads with data from the EIA’s Commercial Building and
Manufacturing Energy Consumption Surveys and discussed notable differences with Avista to ensure that they
accurately reflected known aspects of those customers. For example, if a particular manufacturing sector
showed a greater proportion of space heating load than expected compared to MECS data, Avista could confirm
that their Oregon transportation customers was dominated by a facility with significant conditioned space and
whose product line did not require as much natural gas use.
• The assessment leveraged the Washington CPA measure list.
Where data gaps existed in Avista data, AEG relied on national and regional data sources for assumptions in the
potential model. Table 3 summarizes key data sources used for the analysis and how each informed the study.
Table 3 – Key Data Source Summary
Data Source Used for
Avista Utility Data
Load segmentation by industry/building type, presence of equipment, end
use load distribution, comparison baseline forecast, economics inputs,
scenario development
Northwest Power and Conservation Council’s
2021 Power Plan Technical Achievable ramp rate library and study methodology
NEEA’s 2019 and 2014 Commercial Building
Stock Assessment (CBSA)
Benchmark equipment saturations, normalized end use and equipment
intensity (therms per sq.ft)
EIA 2014 Manufacturing Energy Consumption
Survey (MECS) and 2012 Commercial Building
Energy Consumption Survey (CBECS)
Estimated equipment use per unit, end use distribution of natural gas use
by business/industry type, benchmarking equipment presence (saturation)
EIA’s 2022 Annual Energy Outlook Reference baseline purchase assumptions, equipment lifetimes and costs
Potential Results
AEG developed achievable economic potential based on assumptions regarding the rate at which potential could be
acquired. The achievable economic potential started with standard ramp rate assumptions from the Northwest
Power and Conservation Council’s (Council’s) 2021 Power Plan, mapped to natural gas measures,2 and accounting for
the assumed timing of Avista’s program offerings. In Washington, programs are anticipated to roll out halfway
through 2024; therefore, there is zero potential savings in 2023 and fewer savings potential in 2024 before ramping
up in future years. In Oregon, programs are anticipated to roll out halfway through 2023; therefore, reduced savings
potential is identified in the first year before ramping up in future years.
Figure 1 presents the annual potential savings relative to the baseline projection. Based on the ramp rates used, a
majority of the identified potential is assumed to be acquired over the first 10 years of the study period.

2 The Council’s 2021 Power Plan only covers electric measures. To adapt these ramp rates for this natural gas assessment, AEG mapped gas measures to
the same or similar electric measure, consistent with the methodology from the Washington Natural Gas CPA.

Applied Energy Group, Inc. | appliedenergygroup.com 4
Figure 1 – Reference Case Cumulative Potential, Washington

Figure 2 – Reference Case Cumulative Potential, Oregon

Commercial Potential Results
Figure 3 and Figure 4 present the percentage of achievable economic potential 2045 by market segment and end
use, respectively. The majority of Avista’s commercial transportation customers are college (52% in Oregon and 61%
in Washington). Space heating accounts for the largest share of end use potential in both states, representing 60%
and 76% of cumulative commercial achievable economic potential in Oregon and Washington, respectively.
0%
5%
10%
15%
20%
25%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic Achievable Technical Technical Potential
0%
5%
10%
15%
20%
25%
2023 2024 2025 2035 2045
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic Achievable Technical Technical Potential

Applied Energy Group, Inc. | appliedenergygroup.com 5
Figure 3 – Commercial Achievable Economic Potential by Market Segment, 2045

Figure 4 – Commercial Achievable Economic Potential by End Use, 2045

Cumulative commercial achievable economic potential is provided in Figure 5 for Oregon and Figure 6 for
Washington.
Space
Heating
76%
Water
Heating
20%
Food …
Miscellaneous
0%
Washington
Space
Heating
60%
Water
Heating
31%
Food Preparation
9%
Miscellaneous
0%
Oregon
College
61%
Health
26%
Miscellaneous
13%
Washington
College
52%
Health
44%
Miscellaneous
4%
Oregon

Applied Energy Group, Inc. | appliedenergygroup.com 6
Figure 5 - Cumulative Achievable Economic Commercial Potential by End Use, Oregon

Figure 6 - Cumulative Achievable Economic Commercial Potential by End Use, Washington

Industrial Potential Results
Figure 7 presents the cumulative industrial potential in 2045 by end use. Industrial process end use accounts for 92%
of Oregon’s identified industrial achievable economic potential process and 91% of Washington’s identified industrial
achievable economic potential.
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
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
Dt
h
Space Heating
Water Heating
Food Preparation
Miscellaneous
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
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
Dt
h
Space Heating
Water Heating
Food Preparation
Miscellaneous

Applied Energy Group, Inc. | appliedenergygroup.com 7
Figure 7 – Industrial Achievable Economic Potential by End Use, 2045

Cumulative industrial achievable economic potential is provided in Figure 8 for Oregon and Figure 9 for Washington.
Figure 8 – Cumulative Achievable Economic Industrial Potential by End Use, Oregon

-
100,000
200,000
300,000
400,000
500,000
600,000
Dt
h
Space Heating
Process
Miscellaneous
Space
Heating
8%
Process
92%
Miscellaneous
0%
Oregon
Space Heating
9%
Process
91%
Miscellaneous
0%
Washington

Applied Energy Group, Inc. | appliedenergygroup.com 8
Figure 9 – Cumulative Achievable Economic Industrial Potential by End Use, Washington

Considerations and Recommendations
This assessment was a first step in identifying and realizing natural gas energy efficiency (and associated greenhouse
gas emissions reductions) within Avista’s transportation customer base. While program design is outside the scope
of this assessment, AEG notes the following items for Avista as it determines the best way to achieve these savings:
• Many of the inputs into the analysis are averages across market segments based on the best available data
sources and may not reflect the available potential at any individual site. To address this, AEG recommends that
Avista consider sponsoring audits of specific transportation customer sites to better understand current
equipment and practices to refine estimates of available potential for these customers.
• Because a small number of customers account for a large amount of transportation customer consumption,
whether these customers choose to participate in future programs will significantly affect the amount of savings
that Avista is able to achieve. This uncertainty could increase or decrease acquisition levels relative to the
potential identified in this assessment. As Avista considers new program designs for transportation customers,
AEG recommends targeted outreach to the largest customers to understand their likelihood of participating
in future programs, including to what extent and on what timeline.
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
Dt
h
Space Heating
Process
Miscellaneous
APPENDIX – CHAPTER 3
APPENDIX 3.2: ENVIRONMENTAL EXTERNALITIES OVERVIEW
(OREGON JURISDICTION ONLY)
The methodology for determining avoided costs from reduced incremental natural gas usage considers
commodity and variable transportation costs only. These avoided cost streams do not include environmental
externality costs related to the gathering, transmission, distribution or end-use of natural gas.
Per traditional economic theory and industry practice, an environmental externality factor is typically added
to the avoided cost when there is an opportunity to displace traditional supply-side resources with an
alternative resource with no adverse environmental impact.
REGULATORY GUIDANCE
The Oregon Public Utility Commission (OPUC) issued Order 93-965 (UM-424) to address how utilities
should consider the impact of environmental externalities in planning for future energy resources. The
Order required analysis on the potential natural gas cost impacts from emitting carbon dioxide (CO2) and
nitric-oxide (NOx).
The OPUC’s Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning)
established the following guideline for the treatment of environmental costs used by energy utilities that
evaluate demand-side and supply-side energy choices:
UM 1056, Guideline 8 - Environmental Costs
“Utilities should include, in their base-case analyses, the regulatory compliance costs they expect
for carbon dioxide (CO2), nitrogen oxides (NOx), sulfur oxides (SO2), and mercury (Hg) emissions.
Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93-695, from $0
- $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of reasonably
possible cost adders for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury (Hg), if
applicable.
In June 2008, the OPUC issued Order 08-338 (UM1302) which revised UM1056, Guideline 8. The revised
guideline requires the utility should construct a base case portfolio to reflect what it considers to be the
most likely regulatory compliance future for the various emissions. Additionally the guideline requires the
utility to develop several compliance scenarios ranging from the present CO2 regulatory level to the upper
reaches of credible proposals and each scenario should include a time profile of CO2 costs. The utility is
also required to include a “trigger point” analysis in which the utility must determine at what level of carbon
costs its selection of portfolio resources would be significantly different.
ANALYSIS
Unlike electric utilities, environmental cost issues rarely impact a natural gas utility's supply-side resource
options. This is because the only supply-side energy resource is natural gas. The utility cannot choose
between say "dirty" coal-fired generation and "clean" wind energy sources. The supply-side implication of
environmental externalities generally relates to combustion of fuel to move or compress natural gas.
Avista’s direct gas distribution system infrastructure relies solely on the upstream line pressure of the
interstate pipeline transportation network to distribute natural gas to its customers and thus does not directly
combust fuels that result in any CO2, NOx, SO2, or Hg emissions.
APPENDIX – CHAPTER 3

Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems), however, do
produce CO2 emissions via compressors used to pressurize and move natural gas. Accessing CO2 emissions
data on these upstream activities to perform detailed meaningful analysis is challenging. In the 2009 Natural
Gas IRP there was significant momentum regarding GHG legislation and the movement towards the
creation of carbon cap and trade markets or tax structure. Additionally, the pricing level of the framework
has been greatly reduced. Whichever structure ultimately gets implemented, Avista believes the cost pass
through mechanisms for upstream gas system infrastructure will not make a difference in supply-side
resource selection although the amount of cost pass through could differ widely.
Table 3.2.1 summarizes a range of environmental cost adders we believe capture several compliance futures
including our expected scenario. The CO2 cost adders reflect outlooks we obtained from one of our
consultants, and following discussion and feedback from the TAC, have been incorporated into our
Expected Case, Average Case, Low Growth & High Prices, Electrification - Carbon Reduction, and High
Growth & Low Prices portfolios.
The guidelines also call for a trigger point analysis that reflects a “turning point” at which an alternate
resource portfolio would be selected at different carbon cost adders levels. Because natural gas is the only
supply resource applicable to LDC’s any alternate resource portfolio selection would be a result of delivery
methods of natural gas to customers. Conceptually, there could be differing levels of cost adders applicable
to pipeline transported supply versus in service territory LNG storage gas. From a practical standpoint
however, the differences in these relative cost adders would be very minor and would not change supply-
side resource selection regardless of various carbon cost adder levels. We do acknowledge there is influence
to the avoided costs which would impact the cost effectiveness of demand-side measures in the DSM
business planning process.
CONSERVATION COST ADVANTAGE
For this IRP, we also incorporated a 10 percent environmental externality factor into our assessment of the
cost-effectiveness of existing demand-side management programs. Our assessment of prospective demand-
side management opportunities is based on an avoided cost stream that includes this 10 percent factor.
Environmental externalities were evaluated in the IRP by adding the cost per therm equivalent of the
externality cost values to supply-side resources as described in OPUC Order No. 93-965. Avista found that
the environmental cost adders had no impact on the company’s supply-side choices, although they did
impact the level of demand-side measures that could be cost-effective to acquire.
REGULATORY FILING
Avista will file revised cost-effectiveness limits (CELs) based upon the updated avoided costs available
from this IRP process within the prescribed regulatory timetable.

APPENDIX – CHAPTER 3
TABLE 3.2.1: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS (2022$)

2025 2030 2035 2040 2045
$/short ton $ 5.51 $ 5.51 $ 5.51 $ 5.51 $ 5.51
$/lb $ 0.003 $ 0.003 $ 0.003 $ 0.003 $ 0.003
lbs/therm 0.066 0.066 0.066 0.066 0.066
NOx Adder
$/therm $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.00
$/short ton $ 290 $ 290 $ 290 $ 290 $ 290
$/lb $ 0.145 $ 0.145 $ 0.145 $ 0.145 $ 0.145
lbs/therm 0.066 0.066 0.066 0.066 0.066
NOx Adder
$/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01 $ 0.01
$/Metric Ton $ 100.68 $ 121.36 $ 143.95 $ 173.33 $ 203.99
$/lb $ 0.046 $ 0.055 $ 0.065 $ 0.079 $ 0.093
lbs/therm 11.700 11.700 11.700 11.700 11.700
CO2 Adder
$/therm $ 0.53 $ 0.64 $ 0.76 $ 0.92 $ 1.08
So
c
i
a
l

C
o
s
t

o
f

C
a
r
b
o
n
NO
x

–
An
n
u
a
l
NO
x

–
Se
a
s
o
n
a
l
CO
2
2025 2030 2035 2040 2045
$/short ton $ 5.51 $ 5.51 $ 5.51 $ 5.51 $ 5.51
$/lb $ 0.003 $ 0.003 $ 0.003 $ 0.003 $ 0.003
lbs/therm 0.066 0.066 0.066 0.066 0.066
NOx Adder
$/therm $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.00
$/short ton $ 290 $ 290 $ 290 $ 290 $ 290
$/lb $ 0.145 $ 0.145 $ 0.145 $ 0.145 $ 0.145
lbs/therm 0.066 0.066 0.066 0.066 0.066
NOx Adder
$/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01 $ 0.01
$/Metric Ton $ 120.15 $ 141.34 $ 164.98 $ 192.34 $ 224.09
$/lb $ 0.054 $ 0.064 $ 0.075 $ 0.087 $ 0.102
lbs/therm 11.700 11.700 11.700 11.700 11.700
CO2 Adder
$/therm $ 0.64 $ 0.75 $ 0.88 $ 1.02 $ 1.19
NO
x

–
Se
a
s
o
n
a
l
CO
2Co
m
m
u
n
i
t
y

C
l
i
m
a
t
e

I
n
v
e
s
t
m
e
n
t
s
NO
x

–
An
n
u
a
l

Appendix 4.1: Black & Veatch Study

MEMORANDUM

Client: Avista Corporation B&V Project 198930
Study: Hydrogen Study for Integrated Resource Planning (IRP) B&V File 41.0000
Subject: Task 1 – Renewable Gas Technology Cost and Performance Data - Draft May 18, 2018

To: Tom Pardee, James Gall Avista Corporation

From: Jonathan Cristiani, Frank Jakob, Elizabeth Waldren Black & Veatch

Introduction

Avista Corporation (Avista) is a major US energy company whose service territory includes customers in
Washington, Idaho, and Oregon. As part of their commitment to their customers as well as
requirements from each state’s public utility commission (PUC), Avista periodically performs integrated
resource planning (IRP) for their natural gas and electric power businesses. Avista is currently in the
process of preparing their 2018 natural gas IRP documentation for PUCs in Washington, Idaho, and
Oregon and will shortly begin preparing their 2019 electric power IRP documentation for PUCs in
Washington and Idaho. Avista has engaged Black & Veatch to support the development of these IRP
filing documents, specifically to assist with an increased understanding of the technical and economic
forecasts for renewable gas production as well as the production of electricity from such renewable
gaseous fuels.

As part of this memorandum, Black & Veatch has prepared a concise background for each of the
renewable gas production investigated. Technical performance attributes reported comprise facility
capacity, process efficiencies (i.e. units of output per units of input), feedstock and/or utility
consumption, and expected lifetimes. Capital costs account for direct (e.g. equipment, piping,
installation, etc.) and indirect (e.g. site preparation, engineering, permitting, contingency, etc.) costs and
were developed on an engineering, procurement, and construction (EPC) basis exclusive of Owner’s
costs, escalation, financing, and interest. Fixed operations and maintenance (O&M) costs include labor,
taxes, insurance, professional fees, etc. Variable O&M costs can consist of consumables, scheduled /
unscheduled maintenance reserves, utilities, waste disposal fees, etc. All of these performance and cost
characteristics are presented in a tabular format and projected every five years for the 2020 through
2040 timeframe. Costs that are presented in each table specify whether they are constant US dollars
(USD) or nominal (current) USD.

A subsequent memorandum concerning electricity production from renewable gases will be issued in
the near future and will be entitled “Task 2 – Electricity Production from Renewable Gas and Hydrogen.”

MEMORANDUM Page 2
B&V Project 198930
B&V File 41.0000
May 18, 2018
Renewable Gas Production Technologies and Costs

The renewable gas technologies in which Avista has interest include hydrogen and renewable natural
gas (RNG), the latter of which consists primarily of methane and meets applicable natural gas pipeline
quality standards. Renewable gases can be produced via a number of different feedstocks and
pathways, which complicates their synopsis for the purposes of an IRP report. To accommodate these
factors, Black & Veatch recommended a number of the most promising feedstocks and pathways that
show the greatest potential for commercialization and economically-viable operations from our
perspective as an EPC company. Thus, low technology readiness pathways were not considered in this
report. Accordingly, the following renewable gas production technologies were considered:
◼ Water electrolysis to hydrogen
◼ Landfill gas to RNG
◼ Dairy manure to RNG
◼ Wastewater sludge to RNG
◼ Food waste to RNG

Renewable Hydrogen
Electrolysis is the electrochemical decomposition of water into hydrogen and oxygen using electricity to
drive the reaction. The two predominant types of electrolyzer technologies are polymer electrolyte
membrane (PEM) and alkaline. In a PEM electrolyzer, water is oxidized at the anode into oxygen gas and
hydrogen ions, which are transported across a solid polymer membrane (electrolyte) to the cathode
where they combine with one another to form hydrogen gas. Conversely in an alkaline electrolyzer,
water is reduced at the cathode into hydrogen gas and hydroxide ions, which are transported through a
liquid electrolyte solution (typically potassium hydroxide) to the anode, where they combine to form
oxygen gas and water. In both cases, the overall chemical reaction is as follows:
2𝐻2𝑂(𝑙)𝐸𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑖𝑡𝑦→ 2𝐻2(𝑔)+𝑂2(𝑔) 1

When paired with renewable electricity resources, such as solar photovoltaic or wind power generation,
water electrolysis is considered a renewable, carbon-free hydrogen production technology. The US
Department of Energy (DoE) has created a number of targets and managed a host of research and
development (R&D) programs for the production of renewable hydrogen. Much of that research has
focused on renewable hydrogen as vehicle fuel; however, many of the technical objectives established
under those programs can be extended to fuel cell power generation applications as well. As part of the
DoE program, performance and cost goals were developed for two production scales: distributed and
centralized. Distributed production corresponds with lower capacities where hydrogen is generated at
or near the point of use (e.g. at a refueling station). Centralized facilities have larger capacities that take
advantage of economies of scale but also require greater transportation and delivery costs.

Black & Veatch investigated performance and cost metrics for water electrolysis to renewable hydrogen
at both distributed and centralized scales, which are displayed in Table 1 and Table 2, respectively.

1 Hydrogen Production: Electrolysis. (2015, March). US Department of Energy. Retrieved May, 2018, from
https://www.energy.gov/eere/fuelcells/hydrogen-production-electrolysis.
MEMORANDUM Page 3
B&V Project 198930
B&V File 41.0000
May 18, 2018
Table 1 Performance and Cost Table for Distributed Renewable Hydrogen Production
PARAMETER 2020 2025 2030 2035 2040
Capacity 1,500 kg/day
Capital Cost (2017 USD) $1.94M $1.79M $1.64M $1.59M $1.54M
Fixed O&M Costs (Nominal USD/year) $133K $154K $179K $209K $243K
Variable O&M Costs (Nominal USD/year) $33K $38K $43K $48K $53K
Electricity Costs (2017 USD/kWh) $0.047 $0.047 $0.047 $0.048 $0.047
Energy Use (kWh electricity / kg hydrogen) 50 49 48 47 45
Annual Availability Factor 97%
Expected Life 20 years
Water Usage 4.4 gallons/year

Table 2 Performance and Cost Table for Centralized Renewable Hydrogen Production
PARAMETER 2020 2025 2030 2035 2040
Capacity 52,300 kg/day
Capital Cost (2017 USD) $83.6M $77.5M $71.9M $70.1M $68.4M
Fixed O&M Costs (Nominal USD/year) $3.7M $4.3M $5.0M $5.9M $6.8M
Variable O&M Costs (Nominal USD/year) $600K $662K $731K $808K $891K
Electricity Costs (2017 USD/kWh) $0.047 $0.047 $0.047 $0.048 $0.047
Energy Use (kWh electricity / kg hydrogen) 50 49 48 47 45
Annual Availability Factor 97%
Expected Life 40 years
Water Usage 4.4 gallons/year

Electrolysis plant capacities, annual availabilities, and expected lifetimes were selected based on
published US DoE Fuel Cell Technologies Office (FCTO) plans and reports. 2 Capital and O&M costs, as
well as process efficiency and water usage, were estimated using US DoE independent review reports
and financial modeling by numerous US government agencies. 3, 4 Electricity costs were estimated from

2 Fuel Cell Technologies Office - Multi-Year Research Development and Demonstration Plan. (2015). US
Department of Energy.
3 Independent Review: Current State-of-the-Art Hydrogen Production Cost Estimate Using Water Electrolysis.
(2009, September). US Department of Energy / National Renewable Laboratory.
4 Techno-Economic Analysis of PEM Electrolysis for Hydrogen Production. (2014, February). Electrolytic
Hydrogen Production Workshop, Strategic Analysis Inc. / National Renewable Energy Laboratory.
MEMORANDUM Page 4
B&V Project 198930
B&V File 41.0000
May 18, 2018
the latest US Energy Information Administration (EIA) Annual Energy Outlook (AEO) report 5 for the
Pacific Northwest region as a proxy for future renewable electricity generation. Cost projections
developed by Black & Veatch were made using the following assumptions:
◼ Capital cost compound annual reduction of 1.5 percent for 2020-2030 and 0.5 percent for 2031-
2040. Reductions indicate the learning curve associated with the increased deployment of
electrolysis systems. 6
◼ Fixed O&M cost compound annual growth of 3.1 percent based on Oil & Gas Journal’s Nelson-Farrar
cost index for “Refinery Operations” as a proxy for RNG, a similar technology.
◼ Variable O&M cost compound annual growth of 2.0 percent based on consumer price index from
the US Bureau of Labor Statistics.

Renewable Natural Gas
As mentioned, RNG is derived from an assortment of different feedstocks and pathways. Chiefly, it is
produced through the anaerobic digestion (AD) of organic wastes sourced from agricultural (e.g.
manure, energy crops) and municipal/industrial (e.g. wastewater sludge, food waste) resources. AD
involves the microbiological degradation of organic matter in the absence of oxygen, which results in the
production of biogas (e.g. a saturated, gaseous mixture of methane, carbon dioxide, and other
contaminants). AD can occur in a digester or in a landfill, the latter of which creates a biogas that is
often referred to as landfill gas (LFG). Solid and liquid residues that remain after AD has completed are
referred to as digestate and can be used as a soil conditioner or filler material in certain applications,
depending on quality. The principal types of AD digester types are plug-flow, complete-mix, and
covered-lagoon. 7

Once biogas is generated, it must be conditioned and purified of contaminants before it can be utilized.
In many applications, such as power generation via a reciprocating engine, minimal biogas cleaning and
upgrading is required. However, if the desire is for pipeline-quality RNG to be made, then more
significant processing is needed. For example, contaminants such as particulates, hydrogen sulfide,
ammonia, and siloxanes require removal to meet equipment protection and air emissions mandates.
For RNG specifically, the removal of more benign diluents such as nitrogen, oxygen, and carbon dioxide
is necessary so that stringent volumetric energy content and other quality requirements can be met.
Furthermore, in some localities pipeline quality requirements cannot be met with purified methane
alone, in which cases the cleaned and conditioned biogas must be blended with propane. The major
biogas cleaning and conditioning techniques include membrane separation, water / solvent scrubbing,
solid sorbents, and pressure swing adsorption, among others. To achieve RNG purity with mixtures of all
of the aforementioned contaminants and diluents, biogas cleaning systems will frequently be designed
with combinations of some or all of the processing technologies highlighted resulting in higher capital
and operating costs.

5 Annual Energy Outlook 2018, Table: Electric Power Projections by Electricity Market Module Region, Case:
Reference Case, Region: Western Electricity Coordinating Council / Northwest Power Pool Area. (2018). US
Energy Information Administration.
6 E4tech. Study on Development of Water Electrolysis in the EU. (2014, April). Fuel Cells and Hydrogen Joint
Undertaking.
7 Livestock Anaerobic Digester Database. (2018). US Environmental Protection Agency. Retrieved May, 2018, from
https://www.epa.gov/agstar/livestock-anaerobic-digester-database.
MEMORANDUM Page 5
B&V Project 198930
B&V File 41.0000
May 18, 2018

Landfill Gas
LFG is one of the simplest feedstocks for the production of RNG since the biogas is made in a landfill.
However, given the multitude of contaminants present due to the heterogeneity of the municipal solid
waste (MSW) from which it formed, LFG also requires one of the most complex cleaning processes. As is
the case with renewable hydrogen, LFG to RNG can be appropriate for large and small applications,
corresponding to different sized landfills and loosely defined here as distributed and centralized.
Performance and cost metrics for distributed and centralized LFG to RNG operations are shown in Table
3 and Table 4, respectively.

Table 3 Performance and Cost Table for Distributed LFG to RNG Production
PARAMETER 2020 2025 2030 2035 2040
Capacity (LFG Flowrate) 1,000 scfm
Capacity (RNG Flowrate) 490 scfm
Capital Cost (2017 USD) $7.42M $7.22M $7.02M $6.86M $6.71M
Fixed O&M Costs (Nominal USD/year) $71K $81K $96K $111K $130K
Variable O&M Costs (Nominal USD/year) $609K $672K $742K $819K $904K
LFG Payments (2017 USD/mcf) $0.34 -
$4.66
$0.37 -
$5.02
$0.38 -
$5.17
$0.38 -
$5.22
$0.40 -
$5.46
Annual Availability Factor 90%
Expected Life 20 years

Table 4 Performance and Cost Table for Centralized LFG to RNG Production
PARAMETER 2020 2025 2030 2035 2040
Capacity (LFG Flowrate) 3,000 scfm
Capacity (RNG Flowrate) 1,400 scfm
Capital Cost (USD) $15.1M $14.7M $14.4M $14.0M $13.7M
Fixed O&M Costs (USD/year) $188K $219K $255K $297K $345K
Variable O&M Costs (USD/year) $1.62M $1.79M $1.98M $2.18M $2.41M
LFG Payments (USD/scf) $0.34 -
$4.66
$0.37 -
$5.02
$0.38 -
$5.17
$0.38 -
$5.22
$0.40 -
$5.46
Annual Availability Factor 90%
Expected Life 20 years

MEMORANDUM Page 6
B&V Project 198930
B&V File 41.0000
May 18, 2018
Capacities (for LFG and RNG), availability factors, and expected project lifetimes are based on Black &
Veatch experience and prior project work. LFG payments (from project developer to the landfill
operator) can vary substantially depending on the type of project (i.e. power, combined heat and power,
RNG, etc.), the public/private nature of the landfill owner/operator, and the terms and conditions of the
specific supply agreement. Black & Veatch estimates that LFG payments could be as low as $0.30 per
thousand cubic feet (/mcf) and as high as 85 percent of industrial delivered natural gas pricing, 8 which
are estimated based on EIA AEO figures. 9 Capital, fixed O&M, and variable O&M costs are also based on
prior project work and vendor quotes using the following:
◼ Capital cost compound annual reduction of 0.5 percent for 2020-2040 to indicate a modest learning
curve associated with LFG project deployments.
◼ Fixed O&M cost compound annual growth of 3.1 percent based on Oil & Gas Journal’s Nelson-Farrar
cost index for “Refinery Operations.”
◼ Variable O&M cost compound annual growth of 2.0 percent based on consumer price index from
the US Bureau of Labor Statistics.

Dairy Manure to RNG
Organic agricultural waste (manure) from dairy cows kept in large feeding lots and confined animal
feeding operations can be substantial in quantity and a challenging waste product to manage.
Depending on the required capacity, geographical region, and local climate, there are benefits and
disadvantages in selection of specific digester types. However, a discussion of this nature is beyond the
scope of this report. For applications in the northwestern US, Black & Veatch has assumed that plug-
flow type digester is used, given its prevalence in the marketplace and suitability in a variety of climates.
Although the concentration of dairy farms in the Avista service territory is potentially not as significant
as in states such as California, it is expected that the presence of the dairy industry in places like
southwest Washington could offer opportunities for dairy manure to RNG projects.

An emerging concept in dairy manure AD for energy recovery applications is referred to as “clustering,”
whereby several farms in close proximity convey biogas to a central location, after which the biogas is
upgraded to RNG and injected into a pipeline. 10 The purpose of a cluster configuration is to achieve
improved project economics and meet other project requirements such as overcoming permitting
challenges and achieving environmental compliance. Black & Veatch has assumed that a dairy manure
cluster to RNG project is feasible in the Avista service territory and that five dairies are able to be
connected in a cluster. Performance and cost figures are displayed for such a scenario in Table 5.
Table 5 Performance and Cost Table for Dairy Manure to RNG Production
PARAMETER 2020 2025 2030 2035 2040
Capacity (Dairy Size) 4,000 cows per dairy (20,000 total)

8 Landfill Methane Outreach Program: LFGcost-Web Economic Model, Version 3.2. (2017, May). US
Environmental Protection Agency.
9 Annual Energy Outlook 2018, Table: Natural Gas Delivered Prices by End-Use Sector and Census Division, Case:
Reference Case, Region: Pacific. (2018). US Energy Information Administration.
10 Economic Feasibility of Dairy Digester Clusters in California: A Case Study. (2013, June). United States
Department of Agriculture, Rural Development Agency and California Dairy Campaign.
MEMORANDUM Page 7
B&V Project 198930
B&V File 41.0000
May 18, 2018
PARAMETER 2020 2025 2030 2035 2040
Capacity (Manure) 180,000 tons/year per dairy (900,000 tons/year total)
Capacity (Biogas Flowrate) 200 scfm per dairy (1,000 scfm total)
Capacity (RNG Flowrate) 98 scfm per dairy (490 scfm total)
Capital Cost (2017 USD) $40.6M $39.6M $38.6M $37.7M 36.7M
Fixed O&M Costs (Nominal USD/year) $238K $277K $323K $376K $438K
Variable O&M Costs (Nominal USD/year) $2.05M $2.26M $2.50M $2.76M $3.05M
Annual Availability Factor 90%
Expected Life 20 years

Capacities listed include the dairy size (i.e. number of cows), the annual amount of manure digested, the
expected biogas flowrate, and the resultant RNG flowrate. These capacities, availability factors, and
expected project lifetimes are based on Black & Veatch experience and prior project work. It was
assumed that no payments are made to farm operators by the project developer; however, in some
circumstances Manure to RNG projects will include such payments. Capital, fixed O&M, and variable
O&M costs are also based on prior project work and vendor quotes using the following:
◼ Capital cost compound annual reduction of 0.5 percent for 2020-2040 to indicate a modest learning
curve associated with Manure to RNG project deployments.
◼ Fixed O&M cost compound annual growth of 3.1 percent based on Oil & Gas Journal’s Nelson-Farrar
cost index for “Refinery Operations.”
◼ Variable O&M cost compound annual growth of 2.0 percent based on consumer price index from
the US Bureau of Labor Statistics.

Wastewater Sludge to RNG
Wastewater treatment is a diverse field in which a variety of physical, chemical, and biological processes
are used to remove contaminants from household sewage, resulting in treated effluent and sludge
products. Wastewater sludge will then undergo further treatments, which often involve stabilization
through digestion. In instances where AD is used, the resultant biogas can be recovered and upgraded
to RNG, similar to the aforementioned manure AD scenario. Municipal wastewater treatment plants are
ubiquitous across the US, thus Wastewater Sludge to RNG projects offer significant promise for
widespread adoption.

Black & Veatch has significant experience with wastewater treatment, including the AD of wastewater
sludge. In many cases for these projects, it is desirable to enhance biogas production by co-digesting
municipal fats, oils, and greases (FOG) along with the sludge. Therefore, the performance and costs
depicted herein are reported with respect to a typical municipal wastewater treatment plant upgrade to
accommodate the co-digestion of FOG and the cleaning/upgrading of biogas to RNG. These parameters
are shown in Table 6.

MEMORANDUM Page 8
B&V Project 198930
B&V File 41.0000
May 18, 2018
Table 6 Performance and Cost Table for Wastewater Sludge to RNG Production
PARAMETER 2020 2025 2030 2035 2040
Capacity (Sludge) 21,000 tons/year
Capacity (FOG) 14M gal/year
Capacity (Biogas Flowrate) 650 scfm
Capacity (RNG Flowrate) 375 scfm
Capital Cost (2017 USD) $10.7M $10.4M $10.2M $9.9M $9.7M
Fixed O&M Costs (Nominal USD/year) $175K $204K $238K $277K $323K
Variable O&M Costs (Nominal USD/year) $1.10M $1.22M $1.35M $1.49M $1.64M
Annual Availability Factor 95%
Expected Life 30 years

Capacities listed include the annual amount of sludge digested, the expected biogas flowrate, and the
resultant RNG flowrate. These capacities, availability factors, and expected project lifetimes are based
on Black & Veatch experience and prior project work. O&M costs are exclusive of full operating staff for
the overall wastewater treatment operation and only reflect the staff needed to accommodate the
biogas production and upgrading to RNG portion. Capital, fixed O&M, and variable O&M costs are also
based on prior project work and vendor quotes using the following:
◼ Capital cost compound annual reduction of 0.5 percent for 2020-2040 to indicate a modest learning
curve associated with Wastewater Sludge to RNG project deployments.
◼ Fixed O&M cost compound annual growth of 3.1 percent based on Oil & Gas Journal’s Nelson-Farrar
cost index for “Refinery Operations.”
◼ Variable O&M cost compound annual growth of 2.0 percent based on consumer price index from
the US Bureau of Labor Statistics.

Food Waste to RNG
The digestion of organic waste such as food is relatively early in its deployment compared with other
substrates discussed in this memorandum. Given the potential for contaminants if food waste is
separated from a broader stream of MSW and high solids nature of food waste compared with
manure/sludge, AD system designs can be more complex and expensive. Based on prior Black & Veatch
experience, high-solids discontinuous (i.e. batch) digester designs tend to offer the proper level of
robustness while balancing those attributes with lower capital and operating costs.

For the purposes of the current study, Black & Veatch has assumed that a batch digester is used in
conjunction with a mixture of source-separated organic food waste (i.e. grocery store or restaurant
discards) and yard waste. The biogas produced is then cleaned and upgraded in a similar manner as the
other RNG technologies described herein. Depending on the prevalence of food waste separation /
landfill diversion programs in the Avista service territory; such a project may be achievable. Most
importantly with respect to a project of this nature, tipping fees are often charged by waste handlers for
MEMORANDUM Page 9
B&V Project 198930
B&V File 41.0000
May 18, 2018
the acquisition of food waste, thereby representing an additional revenue stream to project developer.
Performance and cost information for a representative Food Waste to RNG project is outlined in Table 7.

Table 7 Performance and Cost Table for Food Waste to RNG Production
PARAMETER 2020 2025 2030 2035 2040
Capacity (Food / Yard Waste) 55,000 tons/year
Capacity (Biogas Flowrate) 400 scfm
Capacity (RNG Flowrate) 230 scfm
Capital Cost (2017 USD) $23.0M $22.5M $21.9M $21.4M $20.8M
Fixed O&M Costs (Nominal USD/year) $188K $219K $255K $297K $345K
Variable O&M Costs (Nominal USD/year) $1.62M $1.79M $1.97M $2.18M $2.41M
Tipping Fee (2017 USD/ton) $20
Annual Availability Factor 90%
Expected Life 20 years

Capacities listed include the amount of annual food/yard waste processed, the expected biogas
flowrate, and the resultant RNG flowrate. These capacities, availability factors, and expected project
lifetimes are based on Black & Veatch experience and prior project work. Capital, fixed O&M, and
variable O&M costs are also based on prior project work and vendor quotes using the following:
◼ Capital cost compound annual decay of 0.5 percent for 2020-2040 to indicate a modest learning
curve associated with Food Waste to RNG project deployments.
◼ Fixed O&M cost compound annual growth of 3.1 percent based on Oil & Gas Journal’s Nelson-Farrar
cost index for “Refinery Operations.”
◼ Variable O&M cost compound annual growth of 2.0 percent based on consumer price index from
the US Bureau of Labor Statistics.

APPENDIX 4.2: AVISTA RENEWABLE RESOURCE
DEVELOPMENT AND PROCUREMENT DECISION TREE
APPENDIX 5.1: AVISTA RENEWABLE RESOURCE LEAST COST/LEAST RISK
EVALUATION CRITERIA AND CALCULATIONS

APPENDIX 4.3: AVISTA RENEWABLE RESOURCE PROJECT REVENUE
REQUIREMENT MODEL

APPENDIX 4.4: AVISTA RENEWABLE RESOURCE PROJECT RATE IMPACT ANALYSIS
Avista will analyze all RNG-related investment costs and determine the appropriate rate recovery
mechanism, which may include an impact on base rates, purchase gas adjustments or other cost recovery
tariffs. This analysis considers, but is not limited to, factors such as the jurisdictions involved, expenditure
types, cost recovery mechanisms, the spread of the investment to Avista’s customer base and other
potential impacts to ensure the appropriate treatment of the investment.

APPENDIX 5.4: AVISTA RENEWABLE RESOURCE PROJECT CARBON REDUCTION
CALCULATION

APPENDIX 5.1: WA GRC REQUIREMENTS
For its Washington service territory, Avista agreed to include in its 2023 Natural Gas IRP, a
natural gas system decarbonization plan for complying with the Climate Commitment Act (CCA)
with the following elements.

i. The Natural Gas IRP’s decarbonization plan shall include a supply curve of
decarbonization resources by price and availability, e.g. energy efficiency bundle 1 costs
X$/ton of carbon dioxide equivalent (CO2e) reduction and can reduce Y tons of CO2e,
dairy RNG costs A$/ton and can reduce B tons of CO2e.
The Avista 2023 Natural Gas IRP has included a variety of supplies to decarbonize its energy
delivered to the end user. The resources in Figures 1 to Figure 5 below show those supply side
or demand side options (energy efficiency) available to the model to meet climate goals as laid
out in the CCA. Each figure represents the cost per metric ton of carbon dioxide equivalent
combined with the estimated potential of the resource over time.
Renewable Natural Gas (RNG) was estimated based on a Black and Veatch study with the
initial year estimated through a revenue model and decreased following expectations in 2050
based on estimates and papers as discussed in Chapter 4. These values are population
weighted with a potential volume as developed by a consultant contracted by Avista.

Figure 1: Renewable Natural Gas by Type - Costs per Metric Ton of Carbon Dioxide and
Estimated Volume of Availability

$-
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
- 100,000 200,000 300,000 400,000 500,000 600,000
$
p
e
r

M
T
C
O
2
e
Metric tons of CO2e
Landfill RNG Dairy RNG Wastewater Solid Waste
The potential for hydrogen and synthetic methane was developed using the Fischer-Pry
Technology Substitution Model1 with an estimated saturation curve of 20 years. This 20-year
timeframe was chosen based on External Factor of Government Regulation as being a driving
force of this conversion. The spike at 2.5 million MTCO2e is related to the expected end date of
the Inflation Reduction Act as discussed in Chapters 3 and 5.

Figure 2: Green Hydrogen - Costs per Metric Ton of Carbon Dioxide and Estimated Volume of
Availability

1 https://www.sciencedirect.com/science/article/abs/pii/004016259500004T
$-
$100
$200
$300
$400
$500
$600
$700
$800
- 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000
$
p
e
r

M
T
C
O
2
e
MTCO2e
Green Hydrogen
Figure 3: Synthetic Methane - Costs per Metric Ton of Carbon Dioxide and Estimated Volume of
Availability

Energy Efficiency is based on the 2023 year of the study provided by AEG as discussed in
Chapter 3 and found in Appendix 3.

Figure 4: Energy Efficiency (Non-Space Heating) - Costs per Metric Ton of Carbon Dioxide and
Estimated Volume of Availability

$-
$200
$400
$600
$800
$1,000
$1,200
- 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000
$
p
e
r

M
T
C
O
2
e
MTCO2e
Synthetic Methane
$-
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
- 500 1,000 1,500 2,000
$
p
e
r

M
T
C
O
2
e
Cumulative MTCO2e
Appliances Miscellaneous
Process Water Heating
Food Preparation
Figure 5: Energy Efficiency (Space Heating) - Costs per Metric Ton of Carbon Dioxide and
Estimated Volume of Availability

ii. The decarbonization plan shall consider a comprehensive set of strategies, programs,
incentives and other measures to encourage new and existing customers to adopt fully
energy efficient appliances and equipment or other decarbonization measures, which
could include electrification.
Chapter 3 includes a summary of the demand side resources considered in the 2023 IRP,
including electrification. Chapter 6 discusses the Preferred Resource Strategy selected in the
IRP to meet the CCA requirements, and ultimately the Company’s decarbonization plan for this
IRP. Additionally, the Appendix has all Conservation Potential Assessments (CPAs) included for
a full analysis of considerations.

iii. The decarbonization plan shall include targets for the ratio of new gas customers
added relative to new electric customers added in future years.
Due to the phase out of natural gas line extensions allowances by 2025 for Avista, and building
codes set to take effect in 2023, Avista does not anticipate any new gas customers added to the
system beginning in 2025, and potentially earlier. If no new gas customers are added to the
system, the ratio would be 0 as the numerator would be 0 in the following equation.
Ratio of New Gas Customers to New Electric Customers = New Gas Customers
New Electric Customers

Because the ratio of new gas customers relative to new electric customers is already expected
to be 0, any such future target would also be 0.

$-
$50,000
$100,000
$150,000
$200,000
$250,000
$300,000
$350,000
$400,000
$450,000
- 1,000 2,000 3,000 4,000 5,000 6,000 7,000
$
p
e
r

M
T
C
O
2
e
Cumulative MTCO2e
Space Heating
Appendix - Chapter 6

APPENDIX 6.1: MONTHLY PRICE DATA BY BASIN
EXPECTED PRICE PER DEKATHERM
Appendix - Chapter 6

AECO Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.24$ 7.90$ 6.51$ 4.72$ 4.59$ 4.67$ 4.81$ 4.77$ 4.31$ 4.66$ 5.01$ 5.21$
2024 5.08$ 4.97$ 4.22$ 3.68$ 3.68$ 4.06$ 4.06$ 3.92$ 3.82$ 4.06$ 4.33$ 4.65$
2025 4.14$ 4.15$ 3.68$ 3.32$ 3.22$ 3.10$ 3.10$ 3.10$ 3.21$ 3.08$ 3.39$ 3.72$
2026 3.36$ 3.47$ 3.19$ 2.80$ 2.80$ 2.84$ 2.84$ 2.85$ 2.82$ 2.88$ 3.19$ 3.32$
2027 3.15$ 3.03$ 2.93$ 2.72$ 2.72$ 2.75$ 2.74$ 2.74$ 2.66$ 2.67$ 3.11$ 3.22$
2028 3.11$ 3.06$ 2.81$ 2.74$ 2.73$ 2.74$ 2.74$ 2.72$ 2.70$ 2.71$ 3.07$ 3.16$
2029 3.31$ 3.27$ 2.85$ 2.87$ 2.85$ 2.88$ 2.83$ 2.87$ 2.79$ 2.78$ 3.15$ 3.21$
2030 3.31$ 3.24$ 2.98$ 2.94$ 2.96$ 2.98$ 2.92$ 2.94$ 2.82$ 2.82$ 3.17$ 3.29$
2031 3.38$ 3.27$ 2.97$ 3.03$ 3.02$ 3.07$ 3.02$ 3.03$ 2.98$ 3.04$ 3.38$ 3.50$
2032 3.41$ 3.36$ 3.23$ 3.06$ 3.09$ 3.11$ 3.08$ 3.13$ 2.96$ 2.99$ 3.57$ 3.72$
2033 3.69$ 3.72$ 3.38$ 3.19$ 3.23$ 3.26$ 3.19$ 3.24$ 3.16$ 3.19$ 3.74$ 3.77$
2034 3.77$ 3.77$ 3.47$ 3.29$ 3.29$ 3.34$ 3.29$ 3.28$ 3.16$ 3.22$ 3.71$ 3.76$
2035 3.83$ 3.77$ 3.55$ 3.41$ 3.40$ 3.45$ 3.38$ 3.39$ 3.30$ 3.38$ 3.87$ 3.90$
2036 3.96$ 3.96$ 3.49$ 3.46$ 3.49$ 3.52$ 3.49$ 3.48$ 3.35$ 3.40$ 4.03$ 4.08$
2037 4.15$ 4.12$ 3.67$ 3.55$ 3.57$ 3.60$ 3.56$ 3.54$ 3.42$ 3.46$ 4.11$ 4.15$
2038 4.24$ 4.26$ 3.74$ 3.65$ 3.68$ 3.71$ 3.68$ 3.64$ 3.53$ 3.58$ 4.16$ 4.23$
2039 4.33$ 4.35$ 3.87$ 3.80$ 3.82$ 3.86$ 3.82$ 3.79$ 3.63$ 3.68$ 4.36$ 4.49$
2040 4.58$ 4.65$ 4.07$ 3.96$ 3.99$ 4.03$ 3.98$ 3.98$ 3.79$ 3.85$ 4.62$ 4.75$
2041 4.83$ 4.92$ 4.34$ 4.11$ 4.14$ 4.17$ 4.13$ 4.10$ 3.90$ 3.97$ 4.76$ 4.88$
2042 4.99$ 5.02$ 4.48$ 4.26$ 4.29$ 4.33$ 4.29$ 4.25$ 4.07$ 4.13$ 4.97$ 5.07$
2043 5.18$ 5.20$ 4.58$ 4.55$ 4.58$ 4.62$ 4.58$ 4.53$ 4.36$ 4.48$ 5.29$ 5.37$
2044 5.44$ 5.43$ 4.85$ 4.62$ 4.65$ 4.65$ 4.63$ 4.55$ 4.38$ 4.46$ 5.34$ 5.43$
2045 5.53$ 5.55$ 4.88$ 4.80$ 4.83$ 4.87$ 4.84$ 4.74$ 4.61$ 4.68$ 5.60$ 5.66$
Malin Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.96$ 8.27$ 6.82$ 4.97$ 4.76$ 4.78$ 4.95$ 5.10$ 5.02$ 5.00$ 5.26$ 5.63$
2024 5.87$ 5.56$ 4.84$ 4.05$ 4.04$ 4.10$ 4.25$ 4.44$ 4.38$ 4.40$ 4.76$ 5.25$
2025 4.87$ 4.57$ 4.20$ 3.61$ 3.57$ 3.60$ 3.70$ 3.88$ 3.86$ 3.96$ 4.25$ 4.56$
2026 4.43$ 4.02$ 3.82$ 3.36$ 3.35$ 3.34$ 3.44$ 3.56$ 3.57$ 3.63$ 3.90$ 4.23$
2027 4.08$ 3.78$ 3.61$ 3.28$ 3.23$ 3.16$ 3.31$ 3.39$ 3.45$ 3.46$ 3.87$ 4.07$
2028 3.99$ 3.66$ 3.56$ 3.28$ 3.18$ 3.18$ 3.37$ 3.43$ 3.47$ 3.50$ 3.89$ 4.10$
2029 4.32$ 3.94$ 3.57$ 3.26$ 3.22$ 3.17$ 3.30$ 3.44$ 3.57$ 3.56$ 3.94$ 4.28$
2030 4.40$ 4.03$ 3.71$ 3.52$ 3.38$ 3.30$ 3.50$ 3.59$ 3.70$ 3.70$ 4.16$ 4.53$
2031 4.65$ 4.10$ 3.82$ 3.67$ 3.60$ 3.50$ 3.58$ 3.72$ 3.76$ 3.83$ 4.29$ 5.04$
2032 5.00$ 4.10$ 3.91$ 3.68$ 3.52$ 3.44$ 3.68$ 3.84$ 3.94$ 3.97$ 4.53$ 5.16$
2033 5.14$ 4.66$ 4.05$ 3.80$ 3.82$ 3.68$ 3.70$ 3.94$ 4.02$ 4.06$ 4.64$ 5.06$
2034 5.09$ 4.65$ 4.19$ 3.94$ 3.84$ 3.76$ 3.78$ 3.99$ 4.06$ 4.14$ 4.62$ 5.12$
2035 5.23$ 4.68$ 4.27$ 4.08$ 3.93$ 3.86$ 3.87$ 4.08$ 4.21$ 4.29$ 4.76$ 5.30$
2036 5.39$ 4.89$ 4.34$ 4.10$ 4.02$ 3.89$ 3.93$ 4.16$ 4.19$ 4.31$ 4.95$ 5.37$
2037 5.47$ 5.08$ 4.48$ 4.24$ 4.11$ 4.02$ 3.99$ 4.17$ 4.31$ 4.42$ 5.07$ 5.38$
2038 5.49$ 5.13$ 4.58$ 4.27$ 4.17$ 4.11$ 4.09$ 4.20$ 4.44$ 4.51$ 5.19$ 5.33$
2039 5.46$ 5.18$ 4.70$ 4.35$ 4.33$ 4.25$ 4.22$ 4.34$ 4.62$ 4.68$ 5.41$ 5.72$
2040 5.83$ 5.39$ 4.96$ 4.59$ 4.51$ 4.43$ 4.40$ 4.51$ 4.84$ 4.91$ 5.67$ 6.01$
2041 6.12$ 5.65$ 5.10$ 4.73$ 4.63$ 4.53$ 4.50$ 4.57$ 4.87$ 5.00$ 5.74$ 6.02$
2042 6.15$ 5.66$ 5.11$ 4.86$ 4.76$ 4.66$ 4.63$ 4.67$ 4.94$ 5.14$ 5.92$ 6.11$
2043 6.24$ 5.71$ 5.25$ 5.02$ 4.98$ 4.92$ 4.89$ 4.92$ 5.14$ 5.31$ 6.19$ 6.36$
2044 6.46$ 5.98$ 5.35$ 5.14$ 5.11$ 4.99$ 4.98$ 4.96$ 5.21$ 5.37$ 6.30$ 6.44$
2045 6.56$ 6.02$ 5.51$ 5.34$ 5.35$ 5.23$ 5.21$ 5.19$ 5.44$ 5.60$ 6.60$ 6.67$
Appendix - Chapter 6

Rockies Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.80$ 8.19$ 6.79$ 4.96$ 4.75$ 4.78$ 4.95$ 5.00$ 4.96$ 4.99$ 5.26$ 5.52$
2024 5.66$ 5.36$ 4.84$ 4.04$ 4.03$ 4.09$ 4.30$ 4.34$ 4.33$ 4.40$ 4.68$ 5.15$
2025 4.72$ 4.47$ 4.15$ 3.61$ 3.57$ 3.60$ 3.80$ 3.83$ 3.86$ 3.96$ 4.24$ 4.54$
2026 4.35$ 4.02$ 3.82$ 3.36$ 3.35$ 3.34$ 3.54$ 3.56$ 3.57$ 3.63$ 3.89$ 4.16$
2027 3.98$ 3.78$ 3.60$ 3.28$ 3.23$ 3.17$ 3.41$ 3.42$ 3.45$ 3.46$ 3.82$ 4.02$
2028 3.93$ 3.66$ 3.55$ 3.28$ 3.18$ 3.20$ 3.43$ 3.44$ 3.47$ 3.50$ 3.83$ 4.04$
2029 4.26$ 3.94$ 3.57$ 3.26$ 3.22$ 3.19$ 3.41$ 3.50$ 3.57$ 3.56$ 3.89$ 4.22$
2030 4.34$ 4.03$ 3.71$ 3.52$ 3.38$ 3.30$ 3.62$ 3.65$ 3.70$ 3.70$ 4.12$ 4.46$
2031 4.58$ 4.12$ 3.82$ 3.67$ 3.60$ 3.55$ 3.76$ 3.77$ 3.76$ 3.83$ 4.23$ 4.93$
2032 4.87$ 4.16$ 3.91$ 3.68$ 3.55$ 3.50$ 3.86$ 3.91$ 3.94$ 3.97$ 4.50$ 5.09$
2033 5.06$ 4.65$ 4.05$ 3.80$ 3.86$ 3.74$ 3.95$ 4.00$ 4.04$ 4.06$ 4.62$ 5.05$
2034 5.08$ 4.72$ 4.21$ 3.94$ 3.90$ 3.83$ 4.02$ 4.05$ 4.07$ 4.14$ 4.60$ 5.11$
2035 5.22$ 4.75$ 4.33$ 4.08$ 3.99$ 3.93$ 4.12$ 4.14$ 4.21$ 4.29$ 4.74$ 5.29$
2036 5.38$ 4.95$ 4.41$ 4.10$ 4.09$ 3.96$ 4.21$ 4.25$ 4.26$ 4.31$ 4.93$ 5.36$
2037 5.49$ 5.15$ 4.54$ 4.24$ 4.18$ 4.09$ 4.31$ 4.36$ 4.38$ 4.43$ 5.05$ 5.42$
2038 5.53$ 5.27$ 4.65$ 4.33$ 4.24$ 4.21$ 4.44$ 4.47$ 4.51$ 4.56$ 5.18$ 5.39$
2039 5.52$ 5.35$ 4.77$ 4.42$ 4.40$ 4.39$ 4.61$ 4.66$ 4.69$ 4.75$ 5.40$ 5.79$
2040 5.90$ 5.64$ 5.03$ 4.64$ 4.58$ 4.57$ 4.80$ 4.87$ 4.91$ 4.99$ 5.71$ 6.09$
2041 6.19$ 5.94$ 5.18$ 4.80$ 4.70$ 4.68$ 4.92$ 4.98$ 5.01$ 5.07$ 5.81$ 6.09$
2042 6.22$ 6.00$ 5.25$ 4.93$ 4.83$ 4.82$ 5.05$ 5.11$ 5.14$ 5.21$ 5.99$ 6.26$
2043 6.39$ 6.14$ 5.43$ 5.09$ 5.05$ 5.08$ 5.24$ 5.28$ 5.32$ 5.38$ 6.26$ 6.52$
2044 6.64$ 6.40$ 5.56$ 5.21$ 5.18$ 5.23$ 5.34$ 5.36$ 5.42$ 5.49$ 6.37$ 6.66$
2045 6.79$ 6.47$ 5.73$ 5.47$ 5.42$ 5.47$ 5.60$ 5.65$ 5.67$ 5.74$ 6.67$ 6.94$
Stanfield Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.88$ 8.21$ 6.70$ 4.88$ 4.73$ 4.81$ 5.03$ 5.05$ 4.43$ 4.83$ 5.19$ 5.67$
2024 5.73$ 5.35$ 4.40$ 3.89$ 3.86$ 4.20$ 4.27$ 4.25$ 4.04$ 4.26$ 4.57$ 5.05$
2025 4.67$ 4.46$ 3.91$ 3.51$ 3.41$ 3.28$ 3.29$ 3.50$ 3.41$ 3.34$ 3.64$ 4.29$
2026 4.06$ 3.85$ 3.50$ 3.03$ 3.02$ 3.01$ 3.02$ 3.19$ 3.12$ 3.19$ 3.50$ 3.81$
2027 3.76$ 3.42$ 3.27$ 2.99$ 2.94$ 2.92$ 2.92$ 3.09$ 2.98$ 3.00$ 3.54$ 3.88$
2028 3.88$ 3.47$ 3.16$ 2.99$ 2.91$ 2.92$ 3.04$ 3.09$ 3.05$ 3.08$ 3.51$ 3.93$
2029 4.21$ 3.74$ 3.25$ 3.12$ 3.08$ 3.06$ 3.12$ 3.25$ 3.22$ 3.21$ 3.64$ 3.93$
2030 4.29$ 3.81$ 3.41$ 3.32$ 3.21$ 3.17$ 3.30$ 3.38$ 3.28$ 3.28$ 3.75$ 4.19$
2031 4.36$ 3.88$ 3.41$ 3.46$ 3.39$ 3.33$ 3.38$ 3.48$ 3.43$ 3.51$ 3.97$ 4.63$
2032 4.56$ 3.89$ 3.69$ 3.47$ 3.34$ 3.31$ 3.47$ 3.60$ 3.42$ 3.45$ 4.15$ 4.74$
2033 4.72$ 4.39$ 3.83$ 3.59$ 3.61$ 3.51$ 3.49$ 3.71$ 3.59$ 3.64$ 4.31$ 4.60$
2034 4.68$ 4.41$ 3.94$ 3.71$ 3.64$ 3.59$ 3.57$ 3.75$ 3.63$ 3.71$ 4.29$ 4.67$
2035 4.84$ 4.43$ 4.04$ 3.84$ 3.73$ 3.69$ 3.67$ 3.84$ 3.78$ 3.85$ 4.42$ 4.70$
2036 4.86$ 4.63$ 3.99$ 3.88$ 3.82$ 3.73$ 3.75$ 3.92$ 3.76$ 3.87$ 4.60$ 5.07$
2037 5.22$ 4.82$ 4.18$ 3.99$ 3.90$ 3.84$ 3.80$ 3.93$ 3.87$ 3.97$ 4.72$ 5.07$
2038 5.16$ 4.91$ 4.25$ 4.05$ 3.97$ 3.93$ 3.90$ 3.97$ 3.99$ 4.07$ 4.74$ 5.15$
2039 5.23$ 4.96$ 4.37$ 4.15$ 4.14$ 4.08$ 4.04$ 4.11$ 4.12$ 4.18$ 4.95$ 5.45$
2040 5.54$ 5.20$ 4.59$ 4.36$ 4.30$ 4.26$ 4.21$ 4.29$ 4.28$ 4.35$ 5.22$ 5.72$
2041 5.79$ 5.48$ 4.86$ 4.51$ 4.43$ 4.40$ 4.36$ 4.36$ 4.32$ 4.44$ 5.30$ 5.75$
2042 5.85$ 5.55$ 4.92$ 4.63$ 4.56$ 4.56$ 4.52$ 4.49$ 4.40$ 4.59$ 5.48$ 5.86$
2043 5.98$ 5.65$ 4.96$ 4.84$ 4.82$ 4.86$ 4.81$ 4.77$ 4.64$ 4.80$ 5.75$ 6.12$
2044 6.21$ 5.89$ 5.23$ 4.94$ 4.92$ 4.89$ 4.87$ 4.79$ 4.68$ 4.84$ 5.85$ 6.20$
2045 6.32$ 5.96$ 5.24$ 5.14$ 5.13$ 5.13$ 5.10$ 5.00$ 4.91$ 5.06$ 6.13$ 6.43$
Appendix - Chapter 6

Station 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.17$ 7.83$ 6.44$ 4.65$ 4.52$ 4.60$ 4.74$ 4.71$ 4.26$ 4.60$ 4.94$ 5.14$
2024 5.01$ 4.89$ 4.15$ 3.61$ 3.61$ 3.99$ 3.99$ 3.85$ 3.75$ 4.00$ 4.26$ 4.58$
2025 4.07$ 4.08$ 3.61$ 3.25$ 3.16$ 3.03$ 3.03$ 3.03$ 3.13$ 3.00$ 3.31$ 3.65$
2026 3.27$ 3.39$ 3.11$ 2.72$ 2.73$ 2.77$ 2.76$ 2.78$ 2.76$ 2.81$ 3.11$ 3.25$
2027 3.07$ 2.95$ 2.86$ 2.65$ 2.64$ 2.67$ 2.67$ 2.67$ 2.59$ 2.60$ 3.03$ 3.14$
2028 3.03$ 2.98$ 2.73$ 2.66$ 2.65$ 2.66$ 2.66$ 2.64$ 2.62$ 2.64$ 2.99$ 3.08$
2029 3.23$ 3.18$ 2.77$ 2.79$ 2.77$ 2.80$ 2.75$ 2.79$ 2.71$ 2.70$ 3.06$ 3.12$
2030 3.22$ 3.16$ 2.89$ 2.85$ 2.88$ 2.90$ 2.84$ 2.86$ 2.74$ 2.73$ 3.09$ 3.21$
2031 3.29$ 3.19$ 2.89$ 2.95$ 2.94$ 2.99$ 2.93$ 2.94$ 2.89$ 2.95$ 3.29$ 3.41$
2032 3.32$ 3.27$ 3.14$ 2.97$ 3.00$ 3.02$ 2.99$ 3.04$ 2.87$ 2.89$ 3.48$ 3.63$
2033 3.60$ 3.62$ 3.29$ 3.10$ 3.14$ 3.17$ 3.10$ 3.15$ 3.06$ 3.10$ 3.65$ 3.68$
2034 3.68$ 3.68$ 3.37$ 3.20$ 3.20$ 3.25$ 3.19$ 3.18$ 3.07$ 3.13$ 3.61$ 3.66$
2035 3.73$ 3.67$ 3.45$ 3.31$ 3.30$ 3.35$ 3.28$ 3.30$ 3.22$ 3.29$ 3.77$ 3.80$
2036 3.86$ 3.86$ 3.39$ 3.36$ 3.39$ 3.42$ 3.39$ 3.38$ 3.25$ 3.30$ 3.93$ 3.98$
2037 4.05$ 4.02$ 3.57$ 3.45$ 3.47$ 3.50$ 3.46$ 3.44$ 3.32$ 3.36$ 4.01$ 4.05$
2038 4.13$ 4.16$ 3.64$ 3.54$ 3.57$ 3.60$ 3.58$ 3.54$ 3.43$ 3.48$ 4.05$ 4.13$
2039 4.23$ 4.25$ 3.77$ 3.69$ 3.72$ 3.75$ 3.72$ 3.69$ 3.53$ 3.57$ 4.25$ 4.38$
2040 4.47$ 4.54$ 3.96$ 3.85$ 3.89$ 3.92$ 3.88$ 3.88$ 3.68$ 3.74$ 4.51$ 4.64$
2041 4.72$ 4.81$ 4.23$ 4.00$ 4.04$ 4.07$ 4.02$ 4.00$ 3.80$ 3.86$ 4.65$ 4.77$
2042 4.88$ 4.91$ 4.37$ 4.15$ 4.19$ 4.22$ 4.18$ 4.14$ 3.96$ 4.03$ 4.86$ 4.96$
2043 5.06$ 5.09$ 4.47$ 4.45$ 4.48$ 4.51$ 4.47$ 4.42$ 4.25$ 4.37$ 5.18$ 5.25$
2044 5.33$ 5.32$ 4.73$ 4.51$ 4.54$ 4.55$ 4.52$ 4.44$ 4.26$ 4.34$ 5.22$ 5.32$
2045 5.41$ 5.43$ 4.76$ 4.68$ 4.71$ 4.76$ 4.73$ 4.62$ 4.49$ 4.56$ 5.48$ 5.53$
Sumas Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 9.18$ 8.47$ 7.10$ 4.99$ 4.84$ 4.88$ 5.05$ 5.02$ 4.62$ 4.93$ 5.25$ 5.79$
2024 5.81$ 5.37$ 4.57$ 4.04$ 4.00$ 4.28$ 4.37$ 4.31$ 4.10$ 4.31$ 4.58$ 5.35$
2025 4.99$ 4.55$ 3.94$ 3.58$ 3.49$ 3.42$ 3.41$ 3.42$ 3.50$ 3.44$ 3.76$ 4.45$
2026 4.21$ 3.79$ 3.52$ 3.12$ 3.12$ 3.16$ 3.16$ 3.18$ 3.16$ 3.21$ 3.52$ 4.01$
2027 3.87$ 3.36$ 3.27$ 3.05$ 3.04$ 3.08$ 3.07$ 3.07$ 3.00$ 3.01$ 3.75$ 4.23$
2028 4.15$ 3.68$ 3.33$ 3.07$ 3.06$ 3.08$ 3.07$ 3.06$ 3.04$ 3.06$ 3.71$ 4.35$
2029 4.52$ 3.96$ 3.45$ 3.21$ 3.19$ 3.23$ 3.18$ 3.22$ 3.14$ 3.13$ 3.87$ 4.34$
2030 4.47$ 4.06$ 3.64$ 3.29$ 3.32$ 3.34$ 3.28$ 3.30$ 3.19$ 3.18$ 3.99$ 4.53$
2031 4.64$ 4.15$ 3.65$ 3.39$ 3.38$ 3.43$ 3.37$ 3.38$ 3.34$ 3.40$ 4.22$ 4.64$
2032 4.59$ 4.19$ 3.94$ 3.44$ 3.46$ 3.49$ 3.46$ 3.51$ 3.34$ 3.37$ 4.41$ 4.74$
2033 4.71$ 4.69$ 4.08$ 3.57$ 3.62$ 3.65$ 3.57$ 3.63$ 3.55$ 3.58$ 4.57$ 4.79$
2034 4.85$ 4.74$ 4.24$ 3.69$ 3.68$ 3.73$ 3.68$ 3.67$ 3.56$ 3.62$ 4.55$ 4.88$
2035 5.03$ 4.78$ 4.36$ 3.81$ 3.80$ 3.85$ 3.79$ 3.80$ 3.73$ 3.81$ 4.70$ 5.13$
2036 5.25$ 4.98$ 4.34$ 3.87$ 3.90$ 3.93$ 3.90$ 3.89$ 3.77$ 3.82$ 4.89$ 5.30$
2037 5.44$ 5.18$ 4.53$ 3.97$ 3.99$ 4.02$ 3.98$ 3.96$ 3.84$ 3.89$ 5.01$ 5.61$
2038 5.72$ 5.30$ 4.59$ 4.08$ 4.11$ 4.14$ 4.11$ 4.08$ 3.97$ 4.02$ 5.03$ 5.55$
2039 5.68$ 5.38$ 4.49$ 4.22$ 4.25$ 4.29$ 4.25$ 4.23$ 4.07$ 4.12$ 5.25$ 5.88$
2040 5.99$ 5.67$ 4.52$ 4.40$ 4.44$ 4.47$ 4.43$ 4.43$ 4.24$ 4.31$ 5.56$ 6.13$
2041 6.23$ 5.97$ 4.79$ 4.55$ 4.59$ 4.62$ 4.58$ 4.55$ 4.36$ 4.42$ 5.65$ 6.15$
2042 6.27$ 6.03$ 4.94$ 4.71$ 4.74$ 4.78$ 4.74$ 4.71$ 4.53$ 4.60$ 5.82$ 6.31$
2043 6.43$ 6.12$ 5.05$ 5.01$ 5.04$ 5.08$ 5.04$ 4.99$ 4.83$ 4.95$ 6.08$ 6.57$
2044 6.67$ 6.36$ 5.32$ 5.08$ 5.11$ 5.12$ 5.10$ 5.02$ 4.85$ 4.93$ 6.20$ 6.68$
2045 6.81$ 6.35$ 5.37$ 5.29$ 5.32$ 5.37$ 5.34$ 5.24$ 5.12$ 5.18$ 6.50$ 6.96$
Appendix - Chapter 6

APPENDIX 6.1: MONTHLY PRICE DATA BY BASIN
LOW PRICE PER DEKATHERM
Appendix - Chapter 6

AECO Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 7.90$ 7.52$ 6.09$ 4.28$ 4.14$ 4.20$ 4.35$ 4.31$ 3.83$ 4.19$ 4.55$ 4.76$
2024 4.58$ 4.46$ 3.72$ 3.17$ 3.14$ 3.52$ 3.58$ 3.40$ 3.32$ 3.53$ 3.79$ 4.13$
2025 3.61$ 3.62$ 3.15$ 2.81$ 2.68$ 2.57$ 2.53$ 2.53$ 2.65$ 2.55$ 2.86$ 3.17$
2026 2.80$ 2.92$ 2.60$ 2.20$ 2.23$ 2.28$ 2.26$ 2.26$ 2.22$ 2.28$ 2.57$ 2.67$
2027 2.51$ 2.38$ 2.30$ 2.07$ 2.10$ 2.13$ 2.13$ 2.14$ 2.01$ 2.03$ 2.43$ 2.53$
2028 2.41$ 2.37$ 2.11$ 2.04$ 1.98$ 2.00$ 2.01$ 1.97$ 1.95$ 1.97$ 2.34$ 2.45$
2029 2.57$ 2.54$ 2.12$ 2.13$ 2.08$ 2.09$ 2.03$ 2.07$ 2.01$ 2.02$ 2.35$ 2.41$
2030 2.53$ 2.51$ 2.23$ 2.19$ 2.22$ 2.27$ 2.20$ 2.19$ 2.04$ 2.04$ 2.34$ 2.51$
2031 2.55$ 2.41$ 2.12$ 2.15$ 2.11$ 2.12$ 2.11$ 2.10$ 2.06$ 2.08$ 2.42$ 2.52$
2032 2.42$ 2.32$ 2.25$ 2.02$ 2.06$ 2.06$ 2.01$ 2.08$ 1.96$ 1.91$ 2.51$ 2.66$
2033 2.71$ 2.68$ 2.32$ 2.16$ 2.18$ 2.18$ 2.12$ 2.16$ 2.08$ 2.11$ 2.64$ 2.63$
2034 2.57$ 2.55$ 2.25$ 2.20$ 2.20$ 2.23$ 2.17$ 2.14$ 2.04$ 2.05$ 2.57$ 2.55$
2035 2.59$ 2.57$ 2.34$ 2.26$ 2.24$ 2.24$ 2.26$ 2.27$ 2.25$ 2.36$ 2.87$ 2.83$
2036 2.79$ 2.79$ 2.31$ 2.24$ 2.28$ 2.33$ 2.23$ 2.29$ 2.12$ 2.25$ 2.90$ 2.94$
2037 3.00$ 2.97$ 2.52$ 2.41$ 2.43$ 2.52$ 2.39$ 2.39$ 2.20$ 2.27$ 2.87$ 2.92$
2038 2.99$ 3.00$ 2.46$ 2.39$ 2.43$ 2.54$ 2.54$ 2.47$ 2.43$ 2.38$ 2.95$ 3.01$
2039 3.06$ 3.01$ 2.54$ 2.50$ 2.52$ 2.60$ 2.59$ 2.53$ 2.34$ 2.37$ 3.01$ 3.10$
2040 3.16$ 3.26$ 2.72$ 2.59$ 2.67$ 2.67$ 2.63$ 2.69$ 2.44$ 2.58$ 3.25$ 3.39$
2041 3.48$ 3.52$ 2.94$ 2.81$ 2.78$ 2.86$ 2.75$ 2.72$ 2.49$ 2.49$ 3.33$ 3.42$
2042 3.57$ 3.59$ 3.10$ 2.89$ 2.96$ 2.99$ 2.80$ 2.76$ 2.56$ 2.60$ 3.41$ 3.50$
2043 3.62$ 3.65$ 2.94$ 3.00$ 3.04$ 3.00$ 3.04$ 3.05$ 2.82$ 2.92$ 3.64$ 3.65$
2044 3.69$ 3.85$ 3.21$ 2.89$ 2.92$ 2.88$ 2.85$ 2.73$ 2.60$ 2.71$ 3.45$ 3.65$
2045 3.80$ 3.78$ 3.12$ 3.07$ 3.10$ 3.13$ 3.19$ 3.15$ 2.96$ 3.01$ 3.81$ 3.80$
Malin Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.62$ 7.89$ 6.40$ 4.53$ 4.31$ 4.31$ 4.49$ 4.65$ 4.54$ 4.52$ 4.80$ 5.17$
2024 5.37$ 5.05$ 4.33$ 3.53$ 3.50$ 3.56$ 3.77$ 3.92$ 3.88$ 3.87$ 4.21$ 4.73$
2025 4.35$ 4.04$ 3.67$ 3.10$ 3.03$ 3.07$ 3.13$ 3.30$ 3.31$ 3.43$ 3.73$ 4.01$
2026 3.87$ 3.47$ 3.23$ 2.75$ 2.78$ 2.77$ 2.87$ 2.97$ 2.97$ 3.03$ 3.28$ 3.58$
2027 3.44$ 3.13$ 2.97$ 2.64$ 2.61$ 2.54$ 2.70$ 2.78$ 2.79$ 2.82$ 3.19$ 3.39$
2028 3.29$ 2.96$ 2.85$ 2.58$ 2.43$ 2.44$ 2.65$ 2.68$ 2.73$ 2.75$ 3.15$ 3.38$
2029 3.58$ 3.21$ 2.84$ 2.52$ 2.45$ 2.38$ 2.50$ 2.64$ 2.78$ 2.79$ 3.14$ 3.48$
2030 3.63$ 3.29$ 2.97$ 2.77$ 2.64$ 2.59$ 2.77$ 2.84$ 2.92$ 2.93$ 3.33$ 3.75$
2031 3.82$ 3.24$ 2.96$ 2.79$ 2.69$ 2.54$ 2.67$ 2.79$ 2.84$ 2.88$ 3.33$ 4.06$
2032 4.01$ 3.05$ 2.94$ 2.64$ 2.49$ 2.39$ 2.61$ 2.79$ 2.94$ 2.90$ 3.47$ 4.09$
2033 4.15$ 3.62$ 2.99$ 2.78$ 2.77$ 2.60$ 2.63$ 2.86$ 2.94$ 2.98$ 3.54$ 3.92$
2034 3.89$ 3.43$ 2.97$ 2.85$ 2.75$ 2.66$ 2.66$ 2.85$ 2.94$ 2.96$ 3.48$ 3.90$
2035 3.99$ 3.48$ 3.06$ 2.93$ 2.77$ 2.66$ 2.76$ 2.97$ 3.16$ 3.26$ 3.76$ 4.22$
2036 4.22$ 3.71$ 3.16$ 2.88$ 2.81$ 2.70$ 2.67$ 2.97$ 2.96$ 3.16$ 3.82$ 4.23$
2037 4.32$ 3.93$ 3.33$ 3.10$ 2.97$ 2.94$ 2.81$ 3.02$ 3.09$ 3.23$ 3.83$ 4.15$
2038 4.24$ 3.88$ 3.30$ 3.01$ 2.92$ 2.94$ 2.95$ 3.03$ 3.34$ 3.31$ 3.99$ 4.12$
2039 4.18$ 3.84$ 3.37$ 3.06$ 3.03$ 2.99$ 3.00$ 3.09$ 3.32$ 3.37$ 4.06$ 4.33$
2040 4.41$ 4.00$ 3.61$ 3.22$ 3.18$ 3.08$ 3.04$ 3.22$ 3.49$ 3.64$ 4.29$ 4.66$
2041 4.77$ 4.24$ 3.71$ 3.44$ 3.26$ 3.22$ 3.13$ 3.19$ 3.45$ 3.52$ 4.32$ 4.56$
2042 4.73$ 4.23$ 3.72$ 3.48$ 3.42$ 3.32$ 3.14$ 3.18$ 3.43$ 3.61$ 4.36$ 4.55$
2043 4.68$ 4.16$ 3.61$ 3.46$ 3.43$ 3.30$ 3.36$ 3.45$ 3.60$ 3.75$ 4.54$ 4.64$
2044 4.71$ 4.40$ 3.71$ 3.42$ 3.38$ 3.21$ 3.20$ 3.14$ 3.43$ 3.62$ 4.42$ 4.65$
2045 4.83$ 4.25$ 3.76$ 3.60$ 3.62$ 3.49$ 3.56$ 3.60$ 3.78$ 3.92$ 4.81$ 4.81$
Appendix - Chapter 6

Rockies Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.46$ 7.81$ 6.37$ 4.52$ 4.30$ 4.31$ 4.49$ 4.54$ 4.48$ 4.51$ 4.80$ 5.07$
2024 5.16$ 4.85$ 4.33$ 3.52$ 3.49$ 3.55$ 3.82$ 3.82$ 3.83$ 3.87$ 4.13$ 4.63$
2025 4.19$ 3.94$ 3.62$ 3.10$ 3.03$ 3.07$ 3.23$ 3.25$ 3.31$ 3.43$ 3.72$ 3.99$
2026 3.79$ 3.47$ 3.23$ 2.75$ 2.78$ 2.77$ 2.97$ 2.97$ 2.97$ 3.03$ 3.27$ 3.51$
2027 3.34$ 3.13$ 2.97$ 2.64$ 2.61$ 2.54$ 2.80$ 2.82$ 2.79$ 2.82$ 3.14$ 3.33$
2028 3.24$ 2.96$ 2.85$ 2.58$ 2.43$ 2.46$ 2.70$ 2.69$ 2.73$ 2.75$ 3.10$ 3.32$
2029 3.51$ 3.21$ 2.84$ 2.52$ 2.45$ 2.40$ 2.61$ 2.70$ 2.78$ 2.79$ 3.09$ 3.42$
2030 3.57$ 3.29$ 2.96$ 2.77$ 2.64$ 2.59$ 2.89$ 2.90$ 2.92$ 2.93$ 3.28$ 3.68$
2031 3.75$ 3.26$ 2.96$ 2.79$ 2.69$ 2.60$ 2.85$ 2.85$ 2.85$ 2.87$ 3.27$ 3.95$
2032 3.88$ 3.12$ 2.94$ 2.64$ 2.52$ 2.45$ 2.79$ 2.85$ 2.94$ 2.90$ 3.44$ 4.02$
2033 4.07$ 3.61$ 2.99$ 2.78$ 2.80$ 2.66$ 2.88$ 2.92$ 2.96$ 2.98$ 3.52$ 3.91$
2034 3.88$ 3.49$ 2.99$ 2.85$ 2.82$ 2.72$ 2.90$ 2.91$ 2.95$ 2.96$ 3.46$ 3.89$
2035 3.98$ 3.55$ 3.12$ 2.93$ 2.84$ 2.72$ 3.00$ 3.03$ 3.16$ 3.26$ 3.74$ 4.21$
2036 4.21$ 3.78$ 3.23$ 2.88$ 2.88$ 2.77$ 2.95$ 3.06$ 3.03$ 3.16$ 3.80$ 4.22$
2037 4.34$ 4.00$ 3.39$ 3.10$ 3.04$ 3.01$ 3.14$ 3.21$ 3.16$ 3.24$ 3.81$ 4.19$
2038 4.28$ 4.01$ 3.37$ 3.07$ 2.99$ 3.04$ 3.30$ 3.30$ 3.41$ 3.36$ 3.98$ 4.18$
2039 4.24$ 4.01$ 3.44$ 3.13$ 3.10$ 3.13$ 3.38$ 3.40$ 3.39$ 3.44$ 4.05$ 4.40$
2040 4.48$ 4.25$ 3.68$ 3.28$ 3.25$ 3.22$ 3.45$ 3.58$ 3.57$ 3.71$ 4.34$ 4.73$
2041 4.84$ 4.53$ 3.79$ 3.50$ 3.33$ 3.37$ 3.55$ 3.60$ 3.60$ 3.59$ 4.39$ 4.64$
2042 4.80$ 4.57$ 3.87$ 3.55$ 3.49$ 3.48$ 3.56$ 3.61$ 3.63$ 3.68$ 4.43$ 4.70$
2043 4.83$ 4.59$ 3.78$ 3.53$ 3.50$ 3.45$ 3.71$ 3.80$ 3.78$ 3.82$ 4.61$ 4.80$
2044 4.89$ 4.82$ 3.92$ 3.49$ 3.45$ 3.45$ 3.56$ 3.54$ 3.64$ 3.74$ 4.49$ 4.87$
2045 5.06$ 4.71$ 3.97$ 3.74$ 3.69$ 3.73$ 3.94$ 4.06$ 4.02$ 4.07$ 4.88$ 5.08$
Stanfield Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.54$ 7.83$ 6.28$ 4.44$ 4.28$ 4.34$ 4.57$ 4.59$ 3.96$ 4.36$ 4.73$ 5.22$
2024 5.23$ 4.83$ 3.89$ 3.37$ 3.32$ 3.66$ 3.79$ 3.73$ 3.54$ 3.73$ 4.03$ 4.53$
2025 4.14$ 3.92$ 3.39$ 3.00$ 2.87$ 2.74$ 2.72$ 2.93$ 2.86$ 2.81$ 3.11$ 3.73$
2026 3.49$ 3.30$ 2.91$ 2.43$ 2.44$ 2.45$ 2.45$ 2.60$ 2.52$ 2.59$ 2.88$ 3.16$
2027 3.11$ 2.77$ 2.63$ 2.34$ 2.32$ 2.30$ 2.31$ 2.48$ 2.32$ 2.36$ 2.86$ 3.19$
2028 3.18$ 2.78$ 2.45$ 2.29$ 2.16$ 2.18$ 2.32$ 2.34$ 2.30$ 2.33$ 2.78$ 3.22$
2029 3.47$ 3.01$ 2.52$ 2.38$ 2.31$ 2.27$ 2.32$ 2.45$ 2.43$ 2.44$ 2.85$ 3.13$
2030 3.51$ 3.07$ 2.67$ 2.57$ 2.47$ 2.46$ 2.57$ 2.63$ 2.50$ 2.51$ 2.91$ 3.41$
2031 3.54$ 3.02$ 2.55$ 2.58$ 2.48$ 2.37$ 2.47$ 2.55$ 2.51$ 2.56$ 3.01$ 3.65$
2032 3.57$ 2.84$ 2.72$ 2.43$ 2.31$ 2.26$ 2.39$ 2.55$ 2.42$ 2.38$ 3.09$ 3.68$
2033 3.73$ 3.35$ 2.78$ 2.56$ 2.55$ 2.43$ 2.42$ 2.63$ 2.51$ 2.56$ 3.21$ 3.45$
2034 3.47$ 3.19$ 2.73$ 2.62$ 2.55$ 2.48$ 2.46$ 2.61$ 2.51$ 2.53$ 3.15$ 3.46$
2035 3.60$ 3.23$ 2.83$ 2.70$ 2.57$ 2.48$ 2.56$ 2.73$ 2.73$ 2.83$ 3.43$ 3.63$
2036 3.69$ 3.45$ 2.81$ 2.65$ 2.61$ 2.54$ 2.49$ 2.73$ 2.54$ 2.72$ 3.48$ 3.93$
2037 4.08$ 3.67$ 3.02$ 2.86$ 2.76$ 2.77$ 2.63$ 2.78$ 2.65$ 2.78$ 3.48$ 3.84$
2038 3.91$ 3.65$ 2.97$ 2.79$ 2.72$ 2.76$ 2.76$ 2.79$ 2.89$ 2.87$ 3.53$ 3.93$
2039 3.96$ 3.62$ 3.03$ 2.86$ 2.84$ 2.82$ 2.81$ 2.85$ 2.82$ 2.87$ 3.60$ 4.06$
2040 4.13$ 3.81$ 3.25$ 3.00$ 2.98$ 2.90$ 2.86$ 3.00$ 2.93$ 3.08$ 3.84$ 4.37$
2041 4.44$ 4.07$ 3.46$ 3.21$ 3.06$ 3.09$ 2.98$ 2.98$ 2.90$ 2.96$ 3.88$ 4.29$
2042 4.43$ 4.12$ 3.54$ 3.26$ 3.23$ 3.22$ 3.03$ 2.99$ 2.89$ 3.06$ 3.92$ 4.30$
2043 4.42$ 4.10$ 3.32$ 3.28$ 3.28$ 3.24$ 3.28$ 3.29$ 3.10$ 3.25$ 4.11$ 4.40$
2044 4.46$ 4.31$ 3.59$ 3.21$ 3.19$ 3.12$ 3.09$ 2.97$ 2.90$ 3.09$ 3.97$ 4.41$
2045 4.59$ 4.19$ 3.49$ 3.41$ 3.40$ 3.39$ 3.45$ 3.41$ 3.26$ 3.39$ 4.34$ 4.58$
Appendix - Chapter 6

Station 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 7.83$ 7.45$ 6.02$ 4.21$ 4.07$ 4.13$ 4.28$ 4.25$ 3.78$ 4.13$ 4.48$ 4.69$
2024 4.51$ 4.38$ 3.64$ 3.10$ 3.07$ 3.45$ 3.51$ 3.33$ 3.25$ 3.46$ 3.71$ 4.05$
2025 3.54$ 3.55$ 3.08$ 2.74$ 2.61$ 2.50$ 2.46$ 2.46$ 2.58$ 2.47$ 2.79$ 3.09$
2026 2.71$ 2.84$ 2.52$ 2.12$ 2.16$ 2.20$ 2.19$ 2.19$ 2.16$ 2.21$ 2.49$ 2.59$
2027 2.43$ 2.30$ 2.22$ 2.00$ 2.02$ 2.05$ 2.06$ 2.06$ 1.93$ 1.95$ 2.35$ 2.45$
2028 2.33$ 2.29$ 2.03$ 1.96$ 1.90$ 1.92$ 1.93$ 1.89$ 1.88$ 1.89$ 2.26$ 2.36$
2029 2.49$ 2.46$ 2.04$ 2.05$ 2.00$ 2.01$ 1.95$ 1.99$ 1.93$ 1.93$ 2.26$ 2.32$
2030 2.45$ 2.42$ 2.15$ 2.11$ 2.14$ 2.19$ 2.11$ 2.11$ 1.95$ 1.96$ 2.26$ 2.42$
2031 2.46$ 2.33$ 2.03$ 2.07$ 2.03$ 2.03$ 2.02$ 2.01$ 1.97$ 2.00$ 2.33$ 2.43$
2032 2.33$ 2.23$ 2.16$ 1.93$ 1.97$ 1.97$ 1.92$ 1.98$ 1.87$ 1.82$ 2.42$ 2.56$
2033 2.61$ 2.59$ 2.23$ 2.07$ 2.09$ 2.09$ 2.03$ 2.07$ 1.98$ 2.02$ 2.55$ 2.53$
2034 2.47$ 2.45$ 2.16$ 2.11$ 2.11$ 2.14$ 2.08$ 2.04$ 1.95$ 1.96$ 2.47$ 2.45$
2035 2.49$ 2.47$ 2.24$ 2.17$ 2.15$ 2.14$ 2.17$ 2.18$ 2.17$ 2.26$ 2.77$ 2.73$
2036 2.69$ 2.69$ 2.21$ 2.14$ 2.18$ 2.23$ 2.13$ 2.19$ 2.02$ 2.15$ 2.80$ 2.84$
2037 2.90$ 2.87$ 2.42$ 2.31$ 2.33$ 2.42$ 2.29$ 2.29$ 2.10$ 2.17$ 2.77$ 2.82$
2038 2.88$ 2.90$ 2.36$ 2.28$ 2.32$ 2.43$ 2.44$ 2.37$ 2.33$ 2.28$ 2.85$ 2.91$
2039 2.95$ 2.91$ 2.43$ 2.40$ 2.42$ 2.50$ 2.49$ 2.43$ 2.23$ 2.27$ 2.91$ 2.99$
2040 3.05$ 3.15$ 2.61$ 2.49$ 2.56$ 2.57$ 2.52$ 2.58$ 2.33$ 2.47$ 3.14$ 3.28$
2041 3.37$ 3.41$ 2.84$ 2.71$ 2.67$ 2.75$ 2.65$ 2.62$ 2.38$ 2.38$ 3.22$ 3.31$
2042 3.46$ 3.48$ 2.99$ 2.78$ 2.85$ 2.88$ 2.69$ 2.65$ 2.46$ 2.49$ 3.30$ 3.39$
2043 3.50$ 3.54$ 2.83$ 2.89$ 2.93$ 2.89$ 2.93$ 2.94$ 2.71$ 2.81$ 3.53$ 3.53$
2044 3.58$ 3.74$ 3.10$ 2.78$ 2.81$ 2.77$ 2.74$ 2.62$ 2.48$ 2.59$ 3.34$ 3.53$
2045 3.68$ 3.67$ 3.00$ 2.95$ 2.99$ 3.01$ 3.07$ 3.03$ 2.84$ 2.89$ 3.69$ 3.68$
Sumas Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 8.84$ 8.08$ 6.69$ 4.55$ 4.39$ 4.41$ 4.59$ 4.57$ 4.14$ 4.46$ 4.79$ 5.33$
2024 5.31$ 4.86$ 4.06$ 3.52$ 3.47$ 3.74$ 3.89$ 3.79$ 3.61$ 3.77$ 4.03$ 4.83$
2025 4.47$ 4.02$ 3.41$ 3.07$ 2.95$ 2.88$ 2.84$ 2.84$ 2.95$ 2.90$ 3.23$ 3.89$
2026 3.64$ 3.24$ 2.92$ 2.52$ 2.55$ 2.60$ 2.59$ 2.59$ 2.56$ 2.61$ 2.90$ 3.36$
2027 3.23$ 2.71$ 2.63$ 2.40$ 2.42$ 2.46$ 2.46$ 2.47$ 2.34$ 2.36$ 3.07$ 3.55$
2028 3.45$ 2.99$ 2.63$ 2.38$ 2.31$ 2.34$ 2.35$ 2.31$ 2.30$ 2.31$ 2.98$ 3.63$
2029 3.78$ 3.24$ 2.72$ 2.47$ 2.42$ 2.44$ 2.38$ 2.42$ 2.35$ 2.36$ 3.07$ 3.54$
2030 3.69$ 3.32$ 2.90$ 2.55$ 2.58$ 2.63$ 2.55$ 2.55$ 2.40$ 2.41$ 3.16$ 3.75$
2031 3.82$ 3.29$ 2.79$ 2.51$ 2.47$ 2.48$ 2.47$ 2.46$ 2.42$ 2.45$ 3.26$ 3.65$
2032 3.60$ 3.15$ 2.97$ 2.40$ 2.43$ 2.44$ 2.39$ 2.46$ 2.35$ 2.30$ 3.35$ 3.67$
2033 3.72$ 3.65$ 3.02$ 2.54$ 2.56$ 2.56$ 2.51$ 2.55$ 2.47$ 2.50$ 3.47$ 3.65$
2034 3.64$ 3.52$ 3.02$ 2.60$ 2.59$ 2.62$ 2.57$ 2.53$ 2.44$ 2.45$ 3.41$ 3.66$
2035 3.79$ 3.58$ 3.15$ 2.67$ 2.65$ 2.65$ 2.67$ 2.69$ 2.68$ 2.78$ 3.70$ 4.05$
2036 4.08$ 3.81$ 3.16$ 2.65$ 2.69$ 2.74$ 2.64$ 2.71$ 2.54$ 2.67$ 3.76$ 4.16$
2037 4.29$ 4.03$ 3.38$ 2.83$ 2.85$ 2.94$ 2.81$ 2.82$ 2.62$ 2.70$ 3.77$ 4.39$
2038 4.47$ 4.05$ 3.31$ 2.81$ 2.86$ 2.97$ 2.97$ 2.90$ 2.87$ 2.82$ 3.83$ 4.33$
2039 4.40$ 4.04$ 3.16$ 2.93$ 2.95$ 3.03$ 3.02$ 2.97$ 2.77$ 2.81$ 3.90$ 4.49$
2040 4.57$ 4.28$ 3.17$ 3.04$ 3.11$ 3.12$ 3.08$ 3.14$ 2.89$ 3.03$ 4.18$ 4.78$
2041 4.88$ 4.56$ 3.40$ 3.25$ 3.22$ 3.31$ 3.20$ 3.17$ 2.94$ 2.94$ 4.23$ 4.69$
2042 4.85$ 4.60$ 3.55$ 3.34$ 3.41$ 3.44$ 3.25$ 3.21$ 3.02$ 3.07$ 4.26$ 4.75$
2043 4.87$ 4.57$ 3.40$ 3.45$ 3.50$ 3.46$ 3.51$ 3.52$ 3.29$ 3.39$ 4.44$ 4.85$
2044 4.92$ 4.78$ 3.68$ 3.35$ 3.39$ 3.34$ 3.32$ 3.20$ 3.07$ 3.18$ 4.32$ 4.89$
2045 5.08$ 4.58$ 3.62$ 3.56$ 3.60$ 3.63$ 3.69$ 3.65$ 3.46$ 3.51$ 4.71$ 5.11$
Appendix - Chapter 6

APPENDIX 6.1: MONTHLY PRICE DATA BY BASIN
HIGH PRICE PER DEKATHERM
Appendix - Chapter 6

AECO Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 9.12$ 8.81$ 7.61$ 5.95$ 5.72$ 5.71$ 5.91$ 5.82$ 5.56$ 5.95$ 6.27$ 6.47$
2024 6.52$ 6.48$ 5.69$ 5.04$ 5.01$ 5.40$ 5.48$ 5.28$ 5.32$ 5.69$ 6.00$ 6.32$
2025 5.76$ 5.75$ 5.32$ 5.03$ 5.04$ 4.80$ 4.76$ 4.76$ 4.96$ 4.90$ 5.19$ 5.53$
2026 5.11$ 5.32$ 5.09$ 4.74$ 4.68$ 4.69$ 4.60$ 4.61$ 4.68$ 4.74$ 5.12$ 5.09$
2027 4.98$ 4.87$ 4.63$ 4.39$ 4.32$ 4.38$ 4.52$ 4.37$ 4.28$ 4.41$ 4.92$ 5.10$
2028 4.84$ 5.00$ 4.86$ 4.77$ 4.68$ 4.84$ 4.69$ 4.81$ 4.83$ 4.71$ 5.01$ 5.31$
2029 5.35$ 5.27$ 4.83$ 4.93$ 4.99$ 5.07$ 4.89$ 5.00$ 4.89$ 4.87$ 5.17$ 5.16$
2030 5.17$ 5.16$ 4.96$ 5.09$ 5.07$ 5.19$ 5.15$ 5.19$ 4.90$ 4.91$ 5.43$ 5.53$
2031 5.56$ 5.47$ 5.13$ 5.19$ 5.28$ 5.11$ 5.34$ 5.30$ 5.19$ 5.21$ 5.68$ 5.76$
2032 5.83$ 5.73$ 5.68$ 5.44$ 5.62$ 5.50$ 5.51$ 5.57$ 5.42$ 5.43$ 5.89$ 6.15$
2033 6.16$ 6.35$ 5.86$ 5.81$ 5.79$ 5.71$ 5.95$ 5.90$ 5.72$ 5.99$ 6.33$ 6.48$
2034 6.51$ 6.48$ 6.35$ 6.15$ 6.16$ 6.29$ 6.01$ 5.95$ 5.75$ 5.79$ 6.31$ 6.40$
2035 6.53$ 6.53$ 6.20$ 6.05$ 6.01$ 5.99$ 5.92$ 6.04$ 6.07$ 6.09$ 6.62$ 6.61$
2036 7.17$ 6.90$ 6.51$ 6.55$ 6.43$ 6.33$ 6.40$ 6.46$ 6.44$ 6.47$ 7.01$ 7.10$
2037 7.52$ 7.32$ 6.87$ 6.75$ 6.98$ 7.05$ 7.11$ 6.95$ 6.68$ 6.77$ 7.46$ 7.19$
2038 7.36$ 7.58$ 6.99$ 6.82$ 7.08$ 7.03$ 7.34$ 7.24$ 7.38$ 7.56$ 8.03$ 7.89$
2039 7.90$ 8.00$ 7.55$ 7.28$ 7.29$ 7.66$ 7.60$ 7.39$ 7.66$ 7.27$ 7.95$ 8.35$
2040 8.11$ 8.37$ 7.68$ 7.58$ 7.87$ 7.54$ 7.50$ 7.59$ 7.22$ 7.46$ 8.08$ 8.83$
2041 8.72$ 8.98$ 8.50$ 8.39$ 8.39$ 8.13$ 8.15$ 8.24$ 8.09$ 7.83$ 8.65$ 8.71$
2042 8.86$ 9.28$ 9.04$ 8.53$ 8.66$ 8.43$ 8.06$ 8.31$ 8.03$ 7.89$ 9.00$ 8.99$
2043 9.62$ 9.44$ 8.75$ 8.98$ 8.72$ 8.70$ 8.47$ 8.26$ 8.23$ 8.42$ 9.73$ 10.25$
2044 10.30$ 10.01$ 9.00$ 8.76$ 8.85$ 8.83$ 9.00$ 8.82$ 8.62$ 8.51$ 9.12$ 9.45$
2045 9.85$ 9.82$ 9.06$ 9.04$ 8.87$ 8.87$ 8.66$ 8.56$ 8.28$ 9.27$ 10.40$ 10.09$
Malin Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 9.84$ 9.18$ 7.93$ 6.20$ 5.89$ 5.83$ 6.05$ 6.16$ 6.26$ 6.28$ 6.52$ 6.89$
2024 7.31$ 7.08$ 6.31$ 5.41$ 5.37$ 5.44$ 5.68$ 5.80$ 5.89$ 6.03$ 6.42$ 6.92$
2025 6.50$ 6.17$ 5.84$ 5.32$ 5.39$ 5.30$ 5.36$ 5.54$ 5.62$ 5.78$ 6.05$ 6.37$
2026 6.18$ 5.87$ 5.72$ 5.30$ 5.22$ 5.18$ 5.20$ 5.32$ 5.43$ 5.49$ 5.82$ 6.00$
2027 5.91$ 5.62$ 5.30$ 4.95$ 4.84$ 4.79$ 5.08$ 5.02$ 5.06$ 5.20$ 5.68$ 5.96$
2028 5.72$ 5.60$ 5.60$ 5.31$ 5.14$ 5.28$ 5.33$ 5.52$ 5.61$ 5.50$ 5.82$ 6.25$
2029 6.36$ 5.95$ 5.55$ 5.33$ 5.36$ 5.36$ 5.36$ 5.57$ 5.66$ 5.65$ 5.96$ 6.23$
2030 6.26$ 5.94$ 5.70$ 5.68$ 5.48$ 5.51$ 5.73$ 5.84$ 5.78$ 5.79$ 6.41$ 6.77$
2031 6.83$ 6.29$ 5.98$ 5.83$ 5.86$ 5.54$ 5.90$ 5.99$ 5.97$ 6.00$ 6.59$ 7.30$
2032 7.42$ 6.46$ 6.36$ 6.06$ 6.05$ 5.83$ 6.11$ 6.28$ 6.40$ 6.42$ 6.84$ 7.58$
2033 7.61$ 7.29$ 6.52$ 6.43$ 6.38$ 6.13$ 6.46$ 6.61$ 6.58$ 6.86$ 7.22$ 7.77$
2034 7.83$ 7.36$ 7.07$ 6.80$ 6.71$ 6.72$ 6.50$ 6.66$ 6.65$ 6.71$ 7.22$ 7.76$
2035 7.93$ 7.45$ 6.92$ 6.72$ 6.55$ 6.41$ 6.41$ 6.73$ 6.97$ 6.99$ 7.52$ 8.00$
2036 8.60$ 7.83$ 7.37$ 7.19$ 6.97$ 6.71$ 6.84$ 7.14$ 7.29$ 7.39$ 7.93$ 8.39$
2037 8.84$ 8.29$ 7.68$ 7.44$ 7.52$ 7.47$ 7.54$ 7.57$ 7.58$ 7.72$ 8.42$ 8.42$
2038 8.61$ 8.46$ 7.83$ 7.44$ 7.57$ 7.43$ 7.75$ 7.80$ 8.29$ 8.48$ 9.06$ 8.99$
2039 9.02$ 8.82$ 8.39$ 7.84$ 7.80$ 8.05$ 8.01$ 7.95$ 8.64$ 8.27$ 9.00$ 9.58$
2040 9.36$ 9.10$ 8.57$ 8.20$ 8.38$ 7.94$ 7.92$ 8.12$ 8.28$ 8.52$ 9.13$ 10.10$
2041 10.01$ 9.71$ 9.27$ 9.01$ 8.87$ 8.49$ 8.53$ 8.71$ 9.06$ 8.87$ 9.63$ 9.86$
2042 10.02$ 9.92$ 9.67$ 9.12$ 9.13$ 8.76$ 8.41$ 8.73$ 8.90$ 8.89$ 9.96$ 10.03$
2043 10.68$ 9.95$ 9.42$ 9.44$ 9.11$ 9.00$ 8.78$ 8.65$ 9.02$ 9.26$ 10.62$ 11.24$
2044 11.32$ 10.56$ 9.50$ 9.28$ 9.31$ 9.16$ 9.35$ 9.24$ 9.45$ 9.43$ 10.09$ 10.45$
2045 10.88$ 10.29$ 9.69$ 9.58$ 9.39$ 9.23$ 9.03$ 9.01$ 9.11$ 10.19$ 11.39$ 11.10$
Appendix - Chapter 6

Rockies Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 9.68$ 9.10$ 7.89$ 6.19$ 5.88$ 5.82$ 6.05$ 6.05$ 6.21$ 6.27$ 6.52$ 6.79$
2024 7.10$ 6.88$ 6.30$ 5.40$ 5.36$ 5.43$ 5.72$ 5.70$ 5.84$ 6.03$ 6.34$ 6.82$
2025 6.34$ 6.07$ 5.79$ 5.32$ 5.39$ 5.30$ 5.47$ 5.49$ 5.62$ 5.78$ 6.04$ 6.35$
2026 6.10$ 5.87$ 5.72$ 5.30$ 5.22$ 5.18$ 5.31$ 5.32$ 5.43$ 5.49$ 5.82$ 5.93$
2027 5.81$ 5.62$ 5.30$ 4.95$ 4.84$ 4.80$ 5.18$ 5.05$ 5.06$ 5.20$ 5.63$ 5.90$
2028 5.67$ 5.60$ 5.60$ 5.31$ 5.14$ 5.29$ 5.39$ 5.53$ 5.61$ 5.49$ 5.76$ 6.18$
2029 6.29$ 5.94$ 5.55$ 5.33$ 5.36$ 5.37$ 5.47$ 5.63$ 5.66$ 5.65$ 5.91$ 6.17$
2030 6.20$ 5.94$ 5.69$ 5.68$ 5.48$ 5.51$ 5.85$ 5.90$ 5.78$ 5.79$ 6.37$ 6.70$
2031 6.76$ 6.31$ 5.97$ 5.83$ 5.86$ 5.59$ 6.08$ 6.05$ 5.97$ 6.00$ 6.53$ 7.19$
2032 7.29$ 6.52$ 6.36$ 6.06$ 6.08$ 5.89$ 6.29$ 6.35$ 6.40$ 6.42$ 6.82$ 7.51$
2033 7.53$ 7.28$ 6.52$ 6.43$ 6.41$ 6.20$ 6.72$ 6.67$ 6.61$ 6.86$ 7.20$ 7.76$
2034 7.82$ 7.43$ 7.09$ 6.80$ 6.78$ 6.78$ 6.74$ 6.72$ 6.66$ 6.71$ 7.20$ 7.75$
2035 7.92$ 7.51$ 6.98$ 6.72$ 6.61$ 6.47$ 6.65$ 6.80$ 6.97$ 6.99$ 7.50$ 7.99$
2036 8.59$ 7.89$ 7.43$ 7.19$ 7.03$ 6.77$ 7.12$ 7.23$ 7.35$ 7.39$ 7.91$ 8.38$
2037 8.86$ 8.35$ 7.75$ 7.44$ 7.59$ 7.53$ 7.86$ 7.77$ 7.64$ 7.74$ 8.40$ 8.46$
2038 8.66$ 8.60$ 7.90$ 7.50$ 7.64$ 7.53$ 8.10$ 8.07$ 8.36$ 8.54$ 9.05$ 9.05$
2039 9.08$ 8.99$ 8.45$ 7.90$ 7.87$ 8.19$ 8.40$ 8.26$ 8.71$ 8.34$ 9.00$ 9.65$
2040 9.43$ 9.35$ 8.64$ 8.26$ 8.45$ 8.08$ 8.33$ 8.48$ 8.35$ 8.60$ 9.18$ 10.17$
2041 10.08$ 10.00$ 9.34$ 9.08$ 8.94$ 8.63$ 8.95$ 9.11$ 9.20$ 8.94$ 9.70$ 9.93$
2042 10.09$ 10.26$ 9.81$ 9.20$ 9.20$ 8.92$ 8.83$ 9.17$ 9.10$ 8.96$ 10.03$ 10.18$
2043 10.83$ 10.38$ 9.59$ 9.51$ 9.18$ 9.16$ 9.13$ 9.01$ 9.20$ 9.33$ 10.70$ 11.40$
2044 11.50$ 10.98$ 9.71$ 9.35$ 9.38$ 9.40$ 9.72$ 9.64$ 9.66$ 9.55$ 10.16$ 10.67$
2045 11.11$ 10.74$ 9.91$ 9.72$ 9.46$ 9.47$ 9.41$ 9.47$ 9.35$ 10.33$ 11.47$ 11.37$
Stanfield Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 9.76$ 9.12$ 7.80$ 6.12$ 5.86$ 5.85$ 6.13$ 6.10$ 5.68$ 6.12$ 6.45$ 6.93$
2024 7.17$ 6.86$ 5.87$ 5.24$ 5.19$ 5.54$ 5.70$ 5.61$ 5.55$ 5.89$ 6.24$ 6.72$
2025 6.29$ 6.06$ 5.55$ 5.22$ 5.23$ 4.98$ 4.95$ 5.16$ 5.17$ 5.16$ 5.44$ 6.09$
2026 5.81$ 5.70$ 5.40$ 4.97$ 4.89$ 4.86$ 4.78$ 4.95$ 4.97$ 5.05$ 5.43$ 5.58$
2027 5.59$ 5.26$ 4.96$ 4.66$ 4.55$ 4.55$ 4.69$ 4.72$ 4.60$ 4.74$ 5.35$ 5.76$
2028 5.61$ 5.41$ 5.21$ 5.02$ 4.86$ 5.01$ 5.00$ 5.18$ 5.18$ 5.07$ 5.44$ 6.08$
2029 6.25$ 5.75$ 5.23$ 5.18$ 5.22$ 5.24$ 5.18$ 5.38$ 5.31$ 5.30$ 5.67$ 5.88$
2030 6.14$ 5.72$ 5.40$ 5.48$ 5.31$ 5.37$ 5.53$ 5.63$ 5.36$ 5.37$ 6.00$ 6.43$
2031 6.55$ 6.07$ 5.56$ 5.61$ 5.65$ 5.37$ 5.70$ 5.75$ 5.64$ 5.68$ 6.27$ 6.89$
2032 6.98$ 6.25$ 6.14$ 5.84$ 5.88$ 5.70$ 5.89$ 6.04$ 5.88$ 5.89$ 6.46$ 7.17$
2033 7.19$ 7.02$ 6.31$ 6.21$ 6.17$ 5.96$ 6.25$ 6.37$ 6.16$ 6.43$ 6.89$ 7.31$
2034 7.41$ 7.12$ 6.83$ 6.57$ 6.51$ 6.55$ 6.29$ 6.42$ 6.22$ 6.28$ 6.89$ 7.31$
2035 7.53$ 7.19$ 6.69$ 6.49$ 6.34$ 6.23$ 6.21$ 6.49$ 6.54$ 6.56$ 7.18$ 7.41$
2036 8.07$ 7.57$ 7.02$ 6.96$ 6.76$ 6.55$ 6.65$ 6.90$ 6.86$ 6.94$ 7.59$ 8.09$
2037 8.59$ 8.02$ 7.38$ 7.20$ 7.31$ 7.29$ 7.35$ 7.33$ 7.14$ 7.28$ 8.07$ 8.11$
2038 8.29$ 8.23$ 7.50$ 7.22$ 7.37$ 7.25$ 7.56$ 7.57$ 7.84$ 8.04$ 8.61$ 8.80$
2039 8.80$ 8.61$ 8.05$ 7.63$ 7.60$ 7.88$ 7.83$ 7.71$ 8.14$ 7.77$ 8.54$ 9.31$
2040 9.08$ 8.91$ 8.20$ 7.98$ 8.18$ 7.77$ 7.73$ 7.90$ 7.72$ 7.96$ 8.68$ 9.80$
2041 9.68$ 9.53$ 9.02$ 8.79$ 8.68$ 8.36$ 8.38$ 8.50$ 8.51$ 8.31$ 9.19$ 9.59$
2042 9.72$ 9.81$ 9.48$ 8.90$ 8.93$ 8.66$ 8.30$ 8.55$ 8.36$ 8.35$ 9.52$ 9.78$
2043 10.42$ 9.89$ 9.13$ 9.26$ 8.96$ 8.94$ 8.71$ 8.50$ 8.52$ 8.75$ 10.19$ 11.00$
2044 11.07$ 10.47$ 9.38$ 9.08$ 9.12$ 9.07$ 9.24$ 9.07$ 8.92$ 8.89$ 9.64$ 10.21$
2045 10.64$ 10.23$ 9.42$ 9.38$ 9.17$ 9.13$ 8.91$ 8.82$ 8.58$ 9.65$ 10.93$ 10.87$
Appendix - Chapter 6

Station 2 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 9.05$ 8.74$ 7.54$ 5.88$ 5.65$ 5.64$ 5.84$ 5.76$ 5.50$ 5.89$ 6.20$ 6.40$
2024 6.45$ 6.40$ 5.61$ 4.97$ 4.94$ 5.33$ 5.41$ 5.21$ 5.26$ 5.62$ 5.92$ 6.25$
2025 5.69$ 5.68$ 5.25$ 4.96$ 4.97$ 4.73$ 4.70$ 4.69$ 4.89$ 4.82$ 5.11$ 5.45$
2026 5.02$ 5.24$ 5.01$ 4.67$ 4.60$ 4.61$ 4.52$ 4.54$ 4.61$ 4.67$ 5.04$ 5.02$
2027 4.91$ 4.79$ 4.55$ 4.31$ 4.25$ 4.30$ 4.44$ 4.29$ 4.21$ 4.34$ 4.84$ 5.02$
2028 4.76$ 4.92$ 4.78$ 4.69$ 4.60$ 4.76$ 4.61$ 4.73$ 4.76$ 4.63$ 4.92$ 5.23$
2029 5.27$ 5.19$ 4.75$ 4.85$ 4.91$ 4.99$ 4.81$ 4.92$ 4.81$ 4.79$ 5.08$ 5.07$
2030 5.08$ 5.07$ 4.88$ 5.01$ 4.98$ 5.10$ 5.07$ 5.11$ 4.82$ 4.82$ 5.34$ 5.44$
2031 5.48$ 5.38$ 5.04$ 5.10$ 5.20$ 5.03$ 5.25$ 5.22$ 5.10$ 5.12$ 5.59$ 5.67$
2032 5.74$ 5.63$ 5.59$ 5.35$ 5.53$ 5.41$ 5.42$ 5.48$ 5.33$ 5.34$ 5.80$ 6.05$
2033 6.07$ 6.26$ 5.76$ 5.72$ 5.70$ 5.62$ 5.86$ 5.81$ 5.63$ 5.89$ 6.23$ 6.39$
2034 6.42$ 6.39$ 6.26$ 6.06$ 6.07$ 6.20$ 5.91$ 5.86$ 5.66$ 5.70$ 6.21$ 6.30$
2035 6.43$ 6.43$ 6.10$ 5.96$ 5.92$ 5.89$ 5.82$ 5.95$ 5.98$ 5.99$ 6.53$ 6.51$
2036 7.07$ 6.80$ 6.41$ 6.45$ 6.33$ 6.23$ 6.30$ 6.36$ 6.35$ 6.38$ 6.91$ 7.00$
2037 7.41$ 7.22$ 6.77$ 6.65$ 6.88$ 6.95$ 7.01$ 6.85$ 6.58$ 6.67$ 7.36$ 7.09$
2038 7.26$ 7.48$ 6.88$ 6.72$ 6.97$ 6.93$ 7.24$ 7.14$ 7.28$ 7.45$ 7.92$ 7.78$
2039 7.80$ 7.89$ 7.45$ 7.18$ 7.19$ 7.55$ 7.50$ 7.29$ 7.56$ 7.16$ 7.85$ 8.24$
2040 8.00$ 8.26$ 7.57$ 7.47$ 7.76$ 7.43$ 7.40$ 7.49$ 7.11$ 7.35$ 7.97$ 8.72$
2041 8.61$ 8.87$ 8.39$ 8.28$ 8.29$ 8.02$ 8.05$ 8.13$ 7.99$ 7.73$ 8.54$ 8.60$
2042 8.75$ 9.17$ 8.93$ 8.42$ 8.56$ 8.32$ 7.95$ 8.21$ 7.92$ 7.78$ 8.89$ 8.88$
2043 9.51$ 9.33$ 8.64$ 8.87$ 8.61$ 8.59$ 8.36$ 8.15$ 8.13$ 8.31$ 9.61$ 10.13$
2044 10.19$ 9.90$ 8.89$ 8.65$ 8.74$ 8.72$ 8.89$ 8.71$ 8.51$ 8.40$ 9.01$ 9.33$
2045 9.73$ 9.70$ 8.94$ 8.93$ 8.76$ 8.76$ 8.54$ 8.45$ 8.17$ 9.15$ 10.27$ 9.97$
Sumas Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2023 10.06$ 9.37$ 8.21$ 6.22$ 5.97$ 5.93$ 6.15$ 6.08$ 5.86$ 6.22$ 6.51$ 7.05$
2024 7.25$ 6.88$ 6.03$ 5.39$ 5.34$ 5.62$ 5.79$ 5.67$ 5.61$ 5.93$ 6.24$ 7.02$
2025 6.62$ 6.15$ 5.58$ 5.29$ 5.31$ 5.11$ 5.07$ 5.08$ 5.26$ 5.26$ 5.55$ 6.25$
2026 5.96$ 5.64$ 5.41$ 5.06$ 5.00$ 5.01$ 4.92$ 4.94$ 5.01$ 5.07$ 5.45$ 5.78$
2027 5.71$ 5.20$ 4.96$ 4.71$ 4.65$ 4.71$ 4.84$ 4.70$ 4.61$ 4.75$ 5.56$ 6.12$
2028 5.88$ 5.62$ 5.38$ 5.11$ 5.02$ 5.18$ 5.03$ 5.15$ 5.18$ 5.05$ 5.65$ 6.49$
2029 6.56$ 5.97$ 5.43$ 5.27$ 5.33$ 5.41$ 5.24$ 5.35$ 5.24$ 5.21$ 5.89$ 6.29$
2030 6.33$ 5.97$ 5.63$ 5.45$ 5.42$ 5.55$ 5.51$ 5.56$ 5.27$ 5.27$ 6.24$ 6.77$
2031 6.83$ 6.34$ 5.80$ 5.54$ 5.64$ 5.47$ 5.70$ 5.66$ 5.55$ 5.57$ 6.52$ 6.90$
2032 7.02$ 6.55$ 6.40$ 5.81$ 6.00$ 5.88$ 5.89$ 5.95$ 5.81$ 5.81$ 6.72$ 7.16$
2033 7.18$ 7.32$ 6.56$ 6.19$ 6.18$ 6.10$ 6.34$ 6.29$ 6.11$ 6.38$ 7.15$ 7.50$
2034 7.59$ 7.45$ 7.12$ 6.55$ 6.56$ 6.69$ 6.40$ 6.35$ 6.15$ 6.20$ 7.15$ 7.52$
2035 7.73$ 7.54$ 7.01$ 6.46$ 6.42$ 6.40$ 6.32$ 6.45$ 6.50$ 6.51$ 7.45$ 7.83$
2036 8.46$ 7.92$ 7.37$ 6.96$ 6.84$ 6.74$ 6.81$ 6.88$ 6.86$ 6.89$ 7.87$ 8.32$
2037 8.81$ 8.38$ 7.73$ 7.17$ 7.40$ 7.47$ 7.53$ 7.37$ 7.11$ 7.20$ 8.36$ 8.66$
2038 8.85$ 8.63$ 7.83$ 7.25$ 7.51$ 7.46$ 7.77$ 7.68$ 7.82$ 7.99$ 8.90$ 9.21$
2039 9.24$ 9.03$ 8.18$ 7.71$ 7.72$ 8.09$ 8.04$ 7.83$ 8.10$ 7.71$ 8.84$ 9.74$
2040 9.52$ 9.38$ 8.13$ 8.02$ 8.31$ 7.98$ 7.95$ 8.04$ 7.67$ 7.92$ 9.02$ 10.22$
2041 10.12$ 10.03$ 8.95$ 8.83$ 8.84$ 8.57$ 8.60$ 8.69$ 8.55$ 8.29$ 9.54$ 9.98$
2042 10.14$ 10.29$ 9.50$ 8.98$ 9.11$ 8.88$ 8.52$ 8.77$ 8.49$ 8.35$ 9.86$ 10.23$
2043 10.87$ 10.35$ 9.21$ 9.43$ 9.18$ 9.16$ 8.93$ 8.72$ 8.71$ 8.90$ 10.52$ 11.45$
2044 11.53$ 10.94$ 9.47$ 9.22$ 9.31$ 9.29$ 9.47$ 9.30$ 9.09$ 8.99$ 9.99$ 10.70$
2045 11.13$ 10.62$ 9.55$ 9.53$ 9.37$ 9.37$ 9.16$ 9.06$ 8.79$ 9.77$ 11.29$ 11.40$
Appendix - Chapter 6

APPENDIX 6.2: WEIGHTED AVERAGE COST OF CAPITAL

Appendix 6.3: Potential Supply Side Resource Options ($/Dekatherm)

WA Discount Factor 6.58%
ID Discount Factor 6.56%
OR Discount Factor 6.71%
Hydrogen Dairy
Food
Waste LFG Wastewater
Synthetic
Methane
2023 38.64$ 35.22$ 48.22$ 9.20$ 15.96$ 53.72$
2024 37.22$ 36.05$ 49.35$ 9.42$ 16.33$ 51.20$
2025 35.43$ 36.84$ 50.43$ 9.62$ 16.68$ 48.35$
2026 33.54$ 37.66$ 51.54$ 9.83$ 17.04$ 45.43$
2027 31.58$ 38.49$ 52.67$ 10.05$ 17.41$ 42.42$
2028 29.54$ 39.32$ 53.80$ 10.27$ 17.78$ 39.34$
2029 27.41$ 40.18$ 54.96$ 10.49$ 18.15$ 36.16$
2030 25.20$ 41.05$ 56.15$ 10.72$ 18.54$ 32.90$
2031 22.88$ 41.94$ 57.36$ 10.95$ 18.94$ 29.52$
2032 20.44$ 42.86$ 58.60$ 11.19$ 19.34$ 26.02$
2033 20.01$ 43.79$ 59.87$ 11.43$ 19.75$ 33.20$
2034 19.54$ 44.74$ 61.17$ 11.68$ 20.17$ 31.86$
2035 19.05$ 45.72$ 62.49$ 11.93$ 20.60$ 30.48$
2036 18.52$ 46.71$ 63.84$ 12.19$ 21.05$ 29.08$
2037 17.97$ 47.73$ 65.22$ 12.45$ 21.50$ 27.64$
2038 17.37$ 48.77$ 66.64$ 12.72$ 21.96$ 26.17$
2039 16.75$ 49.83$ 68.08$ 13.00$ 22.43$ 24.67$
2040 16.09$ 50.92$ 69.56$ 13.28$ 22.91$ 23.13$
2041 15.39$ 52.03$ 71.06$ 13.57$ 23.40$ 21.55$
2042 14.65$ 53.16$ 72.60$ 13.87$ 23.90$ 19.94$
2043 13.87$ 54.32$ 74.18$ 14.17$ 24.41$ 18.28$
2044 13.05$ 55.50$ 75.79$ 14.48$ 24.94$ 16.58$
2045 12.19$ 56.71$ 77.43$ 14.79$ 25.47$ 14.84$
Appendix - Chapter 6

APPENDIX 6.4: AVERAGE CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.11 4.53 3.72 3.29 3.16 3.18 3.33 4.06 4.35 4.64 4.96 5.22
ID_Ind 5.80 4.41 3.62 3.21 3.09 3.10 3.24 3.97 4.26 4.53 4.85 5.11
ID_Res 6.19 4.57 3.76 3.32 3.19 3.21 3.36 4.09 4.39 4.68 5.01 5.27
Klamath Falls_Com 5.69 10.27 10.01 9.77 9.82 10.04 10.66 11.17 11.89 12.25 13.22 24.27
Klamath Falls_Ind 5.67 10.12 9.87 9.68 9.74 9.97 10.57 11.09 11.82 12.06 12.97 23.81
Klamath Falls_Res 5.74 10.31 10.05 9.79 9.84 10.06 10.68 11.19 11.92 12.31 13.31 24.44
LaGrande_Com 5.69 10.31 10.06 9.82 9.86 10.08 10.70 11.17 11.89 12.25 13.23 24.29
LaGrande_Ind 5.32 9.99 9.80 9.65 9.71 9.95 10.54 10.99 11.66 11.68 12.47 22.85
LaGrande_Res 5.72 10.34 10.09 9.84 9.87 10.10 10.72 11.18 11.91 12.29 13.28 24.38
Medford_Com 5.63 10.24 9.99 9.76 9.80 10.02 10.64 11.15 11.88 12.21 13.19 24.21
Medford_Ind 5.65 10.07 9.84 9.65 9.71 9.93 10.53 11.05 11.78 11.99 12.90 23.73
Medford_Res 5.73 10.30 10.05 9.79 9.84 10.06 10.68 11.19 11.92 12.29 13.29 24.39
OR_Tport 5.48 10.13 9.56 9.35 9.40 9.60 10.37 10.89 11.68 12.03 12.85 15.06
Roseburg_Com 5.65 10.26 10.00 9.76 9.80 10.02 10.64 11.15 11.88 12.21 13.18 24.21
Roseburg_Ind 5.65 10.05 9.84 9.64 9.70 9.92 10.52 11.05 11.76 11.97 12.87 23.69
Roseburg_Res 5.73 10.31 10.05 9.79 9.83 10.05 10.67 11.18 11.91 12.29 13.28 24.38
WA_Com 7.86 6.98 6.27 5.99 6.07 6.31 6.73 6.61 6.69 6.95 7.31 7.62
WA_Ind 7.98 6.73 6.06 5.81 5.88 6.11 6.51 6.39 6.46 6.68 7.03 7.32
WA_Res 7.88 6.99 6.28 6.00 6.08 6.32 6.74 6.62 6.69 6.96 7.32 7.63
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.49 5.78 6.12 6.39 6.74 7.15 7.47 7.77 8.20 8.40 8.69
ID_Ind 5.38 5.66 5.97 6.25 6.59 6.99 7.28 7.58 8.04 8.24 8.55
ID_Res 5.54 5.84 6.18 6.45 6.80 7.22 7.55 7.86 8.27 8.48 8.75
Klamath Falls_Com 25.13 24.68 24.86 24.86 23.45 21.93 20.36 18.80 17.29 15.67 14.19
Klamath Falls_Ind 24.56 23.58 23.74 23.74 22.40 20.91 19.36 17.87 16.48 14.91 13.54
Klamath Falls_Res 25.33 25.07 25.25 25.25 23.82 22.28 20.70 19.13 17.57 15.94 14.42
LaGrande_Com 25.17 24.83 25.01 25.01 23.60 22.06 20.47 18.91 17.38 15.75 14.26
LaGrande_Ind 23.40 21.51 21.65 21.66 20.42 19.04 17.56 16.18 15.01 13.53 12.35
LaGrande_Res 25.27 25.01 25.19 25.19 23.77 22.22 20.63 19.05 17.50 15.87 14.36
Medford_Com 25.07 24.62 24.80 24.80 23.39 21.86 20.28 18.72 17.22 15.60 14.13
Medford_Ind 24.51 23.64 23.80 23.81 22.46 20.95 19.36 17.86 16.48 14.89 13.55
Medford_Res 25.28 24.99 25.17 25.18 23.75 22.21 20.63 19.05 17.50 15.87 14.36
OR_Tport 24.93 15.26 25.13 25.13 23.70 22.07 20.40 18.79 17.28 15.83 14.21
Roseburg_Com 25.06 24.61 24.80 24.80 23.40 21.86 20.28 18.72 17.22 15.60 14.13
Roseburg_Ind 24.46 23.59 23.75 23.76 22.41 20.90 19.31 17.80 16.43 14.85 13.52
Roseburg_Res 25.26 24.96 25.14 25.14 23.72 22.18 20.59 19.02 17.48 15.84 14.33
WA_Com 7.05 7.22 7.55 7.82 7.82 8.14 8.53 8.89 9.34 16.32 14.64
WA_Ind 6.76 6.89 7.19 7.47 7.45 7.72 8.07 8.43 8.94 15.93 14.32
WA_Res 7.06 7.23 7.56 7.83 7.83 8.15 8.55 8.91 9.35 16.34 14.66
WA_Tport 6.30 6.40 6.66 6.94 6.92 7.16 7.49 7.87 8.44 15.49 13.97
Appendix - Chapter 6

APPENDIX 6.4: CARBON INTENSITY CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.94 5.70 4.49 3.99 3.78 4.03 3.88 4.60 4.81 5.17 5.49 5.70
ID_Ind 6.32 5.14 4.09 3.64 3.46 3.62 3.59 4.33 4.58 4.89 5.21 5.43
ID_Res 7.11 5.85 4.60 4.09 3.87 4.14 3.98 4.68 4.89 5.27 5.58 5.79
Klamath Falls_Com 8.21 7.53 7.27 7.18 7.30 7.51 8.15 8.65 9.39 9.73 10.08 10.34
Klamath Falls_Ind 8.17 7.38 7.12 7.09 7.22 7.44 8.07 8.57 9.32 9.65 9.99 10.24
Klamath Falls_Res 8.25 7.57 7.31 7.21 7.32 7.53 8.18 8.68 9.41 9.76 10.11 10.37
LaGrande_Com 8.62 8.50 8.00 7.89 7.99 8.36 8.71 9.15 9.83 10.26 10.60 10.83
LaGrande_Ind 7.98 7.45 7.18 7.18 7.32 7.56 8.11 8.60 9.36 9.69 10.01 10.26
LaGrande_Res 8.65 8.66 8.08 7.96 8.03 8.42 8.75 9.18 9.86 10.29 10.63 10.85
Medford_Com 8.14 7.50 7.24 7.16 7.28 7.49 8.13 8.63 9.37 9.71 10.05 10.31
Medford_Ind 8.14 7.32 7.08 7.04 7.18 7.38 8.00 8.50 9.26 9.58 9.92 10.17
Medford_Res 8.24 7.56 7.30 7.20 7.32 7.53 8.17 8.67 9.40 9.75 10.09 10.35
OR_Tport 11.81 4.17 3.39 2.97 2.81 10.25 10.61 10.92 11.29 11.63 12.07 12.39
Roseburg_Com 8.16 7.52 7.25 7.17 7.28 7.49 8.13 8.63 9.37 9.71 10.06 10.32
Roseburg_Ind 8.15 7.30 7.07 7.03 7.17 7.37 7.99 8.50 9.25 9.57 9.91 10.17
Roseburg_Res 8.24 7.57 7.30 7.21 7.32 7.53 8.17 8.67 9.40 9.75 10.10 10.36
WA_Com 8.52 8.62 7.51 7.21 7.21 7.80 7.85 7.62 7.55 7.91 8.26 8.51
WA_Ind 8.79 7.80 6.84 6.56 6.59 7.01 7.23 7.04 7.02 7.29 7.64 7.90
WA_Res 8.56 8.64 7.54 7.23 7.23 7.82 7.87 7.64 7.57 7.93 8.28 8.53
WA_Tport 7.89 6.73 6.08 5.83 5.88 6.10 6.49 6.33 6.37 6.56 6.94 7.19
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.98 6.42 6.71 6.95 7.28 7.68 8.00 8.28 8.62 8.87 9.02
ID_Ind 5.72 6.10 6.41 6.68 7.01 7.41 7.75 8.05 8.42 8.67 8.88
ID_Res 6.07 6.53 6.81 7.05 7.37 7.77 8.09 8.36 8.70 8.96 9.09
Klamath Falls_Com 10.70 11.07 11.50 11.96 13.16 15.70 16.24 16.79 16.51 16.14 14.39
Klamath Falls_Ind 10.62 10.98 11.39 11.85 13.05 15.57 16.08 16.64 16.35 15.96 14.22
Klamath Falls_Res 10.73 11.10 11.54 12.00 13.21 15.75 16.28 16.83 16.56 16.20 14.45
LaGrande_Com 11.15 11.57 11.94 12.35 13.48 15.92 16.39 16.89 16.52 16.13 14.37
LaGrande_Ind 10.63 10.96 11.35 11.80 12.96 15.45 15.93 16.50 16.07 15.63 13.89
LaGrande_Res 11.18 11.60 11.96 12.38 13.50 15.94 16.41 16.91 16.54 16.16 14.40
Medford_Com 10.67 11.03 11.46 11.93 13.12 15.65 16.18 16.74 16.46 16.07 14.32
Medford_Ind 10.55 10.89 11.30 11.76 12.94 15.46 15.97 16.54 16.25 15.84 14.08
Medford_Res 10.71 11.08 11.51 11.98 13.18 15.71 16.24 16.79 16.52 16.15 14.39
OR_Tport 12.77 13.15 13.55 13.96 14.42 14.95 15.46 16.05 16.51 15.91 14.11
Roseburg_Com 10.68 11.04 11.47 11.93 13.13 15.66 16.20 16.75 16.48 16.10 14.33
Roseburg_Ind 10.54 10.88 11.29 11.75 12.93 15.45 15.97 16.54 16.24 15.83 14.07
Roseburg_Res 10.72 11.09 11.52 11.99 13.19 15.73 16.26 16.81 16.54 16.17 14.41
WA_Com 7.87 8.22 8.47 8.70 8.62 8.88 9.24 9.54 9.93 14.75 14.66
WA_Ind 7.28 7.51 7.79 8.05 7.99 8.24 8.64 9.00 9.42 14.26 14.33
WA_Res 7.89 8.24 8.49 8.72 8.64 8.90 9.26 9.56 9.95 14.77 14.68
WA_Tport 6.57 6.67 6.95 7.25 7.21 7.49 7.91 8.34 8.82 13.70 13.98
Appendix - Chapter 6

APPENDIX 6.4: ELECTRIFICATION – EXPECTED CONVERSION COST CASE AVOIDED
COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.93 5.68 4.46 3.95 3.73 3.67 3.47 4.15 4.40 4.62 5.01 5.18
ID_Ind 6.31 5.12 4.07 3.61 3.42 3.38 3.30 3.99 4.26 4.48 4.84 5.02
ID_Res 7.09 5.83 4.57 4.04 3.81 3.75 3.53 4.20 4.45 4.67 5.07 5.24
Klamath Falls_Com 7.13 10.23 9.98 9.78 9.81 9.97 10.00 10.03 10.18 11.34 11.76 12.81
Klamath Falls_Ind 6.62 10.07 9.82 9.69 9.73 9.91 9.93 9.97 10.13 11.27 11.69 12.73
Klamath Falls_Res 7.21 10.26 10.02 9.80 9.83 9.98 10.02 10.05 10.20 11.36 11.79 12.84
LaGrande_Com 8.01 11.34 10.72 10.47 10.44 10.30 10.31 10.31 10.18 11.33 11.76 12.81
LaGrande_Ind 6.42 10.13 9.86 9.76 9.81 9.92 9.94 9.97 10.03 11.14 11.55 12.59
LaGrande_Res 7.99 11.34 10.72 10.48 10.45 10.31 10.32 10.31 10.18 11.34 11.77 12.82
Medford_Com 7.07 10.21 9.96 9.76 9.79 9.95 9.99 10.02 10.17 11.32 11.74 12.79
Medford_Ind 6.60 10.01 9.78 9.64 9.69 9.87 9.90 9.94 10.08 11.21 11.63 12.68
Medford_Res 7.21 10.27 10.01 9.80 9.82 9.98 10.02 10.04 10.20 11.35 11.78 12.83
OR_Tport 11.25 10.13 9.56 9.35 9.40 9.78 10.12 10.41 10.76 11.08 11.50 12.55
Roseburg_Com 7.11 10.21 9.97 9.76 9.79 9.95 9.99 10.02 10.17 11.32 11.75 12.80
Roseburg_Ind 6.60 9.99 9.78 9.63 9.68 9.86 9.90 9.94 10.08 11.21 11.62 12.68
Roseburg_Res 7.20 10.26 10.01 9.80 9.82 9.98 10.02 10.04 10.20 11.35 11.78 12.83
WA_Com 9.21 8.11 6.98 6.62 6.59 6.74 6.77 6.61 6.63 6.80 7.23 7.43
WA_Ind 8.57 7.56 6.59 6.28 6.28 6.45 6.59 6.44 6.48 6.64 7.04 7.26
WA_Res 9.28 8.18 7.03 6.66 6.63 6.78 6.80 6.63 6.65 6.82 7.26 7.46
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.44 5.70 5.97 6.23 6.52 6.92 7.25 7.58 8.00 8.33 8.69
ID_Ind 5.29 5.54 5.81 6.08 6.35 6.73 7.07 7.39 7.84 8.15 8.53
ID_Res 5.50 5.75 6.02 6.28 6.59 6.99 7.33 7.65 8.08 8.41 8.77
Klamath Falls_Com 23.92 24.02 23.49 22.90 22.71 22.57 21.02 19.43 17.76 15.85 12.90
Klamath Falls_Ind 23.85 23.95 23.39 22.80 22.58 22.42 20.77 19.16 17.48 15.39 12.53
Klamath Falls_Res 23.95 24.05 23.52 22.93 22.75 22.61 21.10 19.52 17.86 16.00 13.00
LaGrande_Com 23.92 24.03 23.50 22.91 22.71 22.57 21.04 19.44 17.78 15.88 13.02
LaGrande_Ind 23.71 23.81 23.24 22.65 22.35 22.11 20.32 18.67 16.94 14.57 12.16
LaGrande_Res 23.93 24.04 23.51 22.92 22.72 22.58 21.06 19.47 17.82 15.94 13.05
Medford_Com 23.90 24.00 23.47 22.88 22.67 22.52 20.95 19.35 17.69 15.73 12.88
Medford_Ind 23.80 23.90 23.35 22.76 22.51 22.33 20.67 19.05 17.38 15.26 12.74
Medford_Res 23.93 24.03 23.50 22.91 22.72 22.57 21.04 19.45 17.79 15.90 12.95
OR_Tport 23.51 23.65 23.10 22.28 22.04 21.86 20.43 18.91 17.35 15.88 14.62
Roseburg_Com 23.91 24.01 23.48 22.89 22.69 22.54 20.98 19.38 17.71 15.77 12.92
Roseburg_Ind 23.80 23.90 23.35 22.76 22.51 22.32 20.67 19.06 17.39 15.30 12.82
Roseburg_Res 23.94 24.04 23.51 22.92 22.73 22.59 21.06 19.47 17.80 15.91 12.93
WA_Com 6.86 6.96 7.22 7.48 7.41 7.69 8.08 8.46 8.94 9.33 9.76
WA_Ind 6.70 6.79 7.05 7.32 7.23 7.49 7.87 8.25 8.75 9.13 9.57
WA_Res 6.89 6.99 7.24 7.50 7.45 7.73 8.12 8.49 8.97 9.37 9.80
WA_Tport 6.30 6.40 6.66 6.94 6.84 7.09 7.48 7.87 8.39 8.76 9.20
Appendix - Chapter 6

APPENDIX 6.4: ELECTRIFICATION – HIGH CONVERSION COST CASE AVOIDED COST
($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.93 5.68 4.46 3.95 3.73 3.67 3.47 4.15 4.40 4.62 5.01 5.18
ID_Ind 6.31 5.12 4.07 3.61 3.42 3.38 3.30 3.99 4.26 4.48 4.84 5.02
ID_Res 7.09 5.83 4.57 4.04 3.81 3.75 3.53 4.20 4.45 4.67 5.07 5.24
Klamath Falls_Com 9.29 10.23 9.98 9.78 9.81 9.97 10.00 10.03 10.18 11.34 11.76 12.81
Klamath Falls_Ind 8.77 10.07 9.82 9.69 9.73 9.91 9.93 9.97 10.13 11.27 11.69 12.73
Klamath Falls_Res 9.37 10.26 10.02 9.80 9.83 9.98 10.02 10.05 10.20 11.36 11.79 12.84
LaGrande_Com 10.16 11.34 10.72 10.47 10.44 10.30 10.31 10.31 10.18 11.33 11.76 12.81
LaGrande_Ind 8.57 10.13 9.86 9.76 9.81 9.92 9.94 9.97 10.03 11.14 11.55 12.59
LaGrande_Res 10.15 11.34 10.72 10.48 10.45 10.31 10.32 10.31 10.18 11.34 11.77 12.82
Medford_Com 9.23 10.21 9.96 9.76 9.79 9.95 9.99 10.02 10.17 11.32 11.74 12.79
Medford_Ind 8.75 10.01 9.78 9.64 9.69 9.87 9.90 9.94 10.08 11.21 11.63 12.68
Medford_Res 9.37 10.27 10.01 9.80 9.82 9.98 10.02 10.04 10.20 11.35 11.78 12.83
OR_Tport 11.25 10.13 9.56 9.35 9.40 9.78 10.12 10.41 10.76 11.08 11.50 12.55
Roseburg_Com 9.27 10.21 9.97 9.76 9.79 9.95 9.99 10.02 10.17 11.32 11.75 12.80
Roseburg_Ind 8.75 9.99 9.78 9.63 9.68 9.86 9.90 9.94 10.08 11.21 11.62 12.68
Roseburg_Res 9.36 10.26 10.01 9.80 9.82 9.98 10.02 10.04 10.20 11.35 11.78 12.83
WA_Com 9.21 8.11 6.98 6.62 6.59 6.74 6.77 6.61 6.63 6.80 7.23 7.43
WA_Ind 8.57 7.56 6.59 6.28 6.28 6.45 6.59 6.44 6.48 6.64 7.04 7.26
WA_Res 9.28 8.18 7.03 6.66 6.63 6.78 6.80 6.63 6.65 6.82 7.26 7.46
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.44 5.70 5.97 6.23 6.52 6.92 7.25 7.58 8.00 8.33 8.69
ID_Ind 5.29 5.54 5.81 6.08 6.35 6.73 7.07 7.39 7.84 8.15 8.53
ID_Res 5.50 5.75 6.02 6.28 6.59 6.99 7.33 7.65 8.08 8.41 8.77
Klamath Falls_Com 23.92 24.02 23.49 22.90 22.71 22.57 21.02 19.43 17.76 15.85 12.90
Klamath Falls_Ind 23.85 23.95 23.39 22.80 22.58 22.42 20.77 19.16 17.48 15.39 12.53
Klamath Falls_Res 23.95 24.05 23.52 22.93 22.75 22.61 21.10 19.52 17.86 16.00 13.00
LaGrande_Com 23.92 24.03 23.50 22.91 22.71 22.57 21.04 19.44 17.78 15.88 13.02
LaGrande_Ind 23.71 23.81 23.24 22.65 22.35 22.11 20.32 18.67 16.94 14.57 12.16
LaGrande_Res 23.93 24.04 23.51 22.92 22.72 22.58 21.06 19.47 17.82 15.94 13.05
Medford_Com 23.90 24.00 23.47 22.88 22.67 22.52 20.95 19.35 17.69 15.73 12.88
Medford_Ind 23.80 23.90 23.35 22.76 22.51 22.33 20.67 19.05 17.38 15.26 12.74
Medford_Res 23.93 24.03 23.50 22.91 22.72 22.57 21.04 19.45 17.79 15.90 12.95
OR_Tport 23.51 23.65 23.10 22.28 22.04 21.86 20.43 18.91 17.35 15.88 14.62
Roseburg_Com 23.91 24.01 23.48 22.89 22.69 22.54 20.98 19.38 17.71 15.77 12.92
Roseburg_Ind 23.80 23.90 23.35 22.76 22.51 22.32 20.67 19.06 17.39 15.30 12.82
Roseburg_Res 23.94 24.04 23.51 22.92 22.73 22.59 21.06 19.47 17.80 15.91 12.93
WA_Com 6.86 6.96 7.22 7.48 7.41 7.69 8.08 8.46 8.94 9.33 9.76
WA_Ind 6.70 6.79 7.05 7.32 7.23 7.49 7.87 8.25 8.75 9.13 9.57
WA_Res 6.89 6.99 7.24 7.50 7.45 7.73 8.12 8.49 8.97 9.37 9.80
WA_Tport 6.30 6.40 6.66 6.94 6.84 7.09 7.48 7.87 8.39 8.76 9.20
Appendix - Chapter 6

APPENDIX 6.4: ELECTRIFICATION – LOW CONVERSION COST CASE AVOIDED COST
($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.93 5.68 4.46 3.95 3.73 3.66 3.47 4.15 4.40 4.62 5.02 5.19
ID_Ind 6.31 5.13 4.07 3.61 3.42 3.38 3.29 3.99 4.25 4.48 4.84 5.02
ID_Res 7.09 5.83 4.57 4.04 3.82 3.74 3.52 4.20 4.45 4.68 5.08 5.25
Klamath Falls_Com 6.17 4.81 4.84 5.37 5.49 6.12 6.95 8.20 9.37 11.34 11.75 12.05
Klamath Falls_Ind 5.67 4.66 4.68 5.28 5.42 6.06 6.88 8.13 9.32 11.27 11.68 11.97
Klamath Falls_Res 6.26 4.85 4.88 5.39 5.52 6.14 6.97 8.22 9.39 11.36 11.78 12.07
LaGrande_Com 7.06 5.98 5.62 6.12 6.19 6.76 7.30 8.50 9.62 11.54 12.01 12.30
LaGrande_Ind 5.47 4.73 4.73 5.37 5.51 6.12 6.90 8.15 9.33 11.24 11.65 11.96
LaGrande_Res 7.05 5.98 5.62 6.12 6.19 6.76 7.31 8.51 9.63 11.54 12.02 12.31
Medford_Com 6.11 4.79 4.81 5.35 5.48 6.11 6.94 8.18 9.35 11.32 11.73 12.03
Medford_Ind 5.64 4.59 4.63 5.23 5.37 6.02 6.84 8.09 9.27 11.21 11.63 11.92
Medford_Res 6.26 4.85 4.87 5.39 5.51 6.14 6.97 8.21 9.38 11.35 11.77 12.06
OR_Tport 5.48 4.17 9.56 9.35 2.81 9.60 9.93 10.22 10.56 10.88 11.30 11.60
Roseburg_Com 6.16 4.80 4.82 5.35 5.48 6.11 6.94 8.19 9.36 11.32 11.74 12.03
Roseburg_Ind 5.65 4.58 4.63 5.22 5.37 6.01 6.84 8.09 9.26 11.21 11.62 11.92
Roseburg_Res 6.25 4.85 4.87 5.39 5.51 6.14 6.97 8.21 9.39 11.35 11.77 12.06
WA_Com 9.21 8.11 6.98 6.62 6.59 6.73 6.77 6.61 6.63 6.80 7.24 7.44
WA_Ind 8.58 7.56 6.59 6.28 6.28 6.45 6.59 6.44 6.47 6.65 7.05 7.26
WA_Res 9.29 8.18 7.03 6.66 6.63 6.77 6.80 6.63 6.65 6.83 7.27 7.46
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.44 5.70 5.97 6.23 6.56 6.97 7.31 7.61 8.01 8.34 8.71
ID_Ind 5.29 5.54 5.81 6.08 6.41 6.82 7.16 7.44 7.85 8.16 8.55
ID_Res 5.50 5.75 6.03 6.29 6.61 7.03 7.37 7.67 8.08 8.42 8.78
Klamath Falls_Com 12.40 12.78 21.11 21.22 21.13 18.93 18.55 18.03 17.61 15.86 13.79
Klamath Falls_Ind 12.34 12.71 21.02 21.14 20.93 18.70 18.30 17.69 17.14 15.35 13.16
Klamath Falls_Res 12.42 12.81 21.13 21.25 21.19 19.01 18.63 18.15 17.77 16.04 14.00
LaGrande_Com 12.63 12.83 21.15 21.27 21.18 19.00 18.62 18.12 17.71 15.95 13.93
LaGrande_Ind 12.33 12.65 20.93 21.07 20.69 18.41 18.00 17.19 16.37 14.51 12.10
LaGrande_Res 12.64 12.84 21.15 21.28 21.21 19.02 18.64 18.16 17.77 16.02 14.01
Medford_Com 12.38 12.76 21.08 21.20 21.08 18.88 18.49 17.95 17.42 15.62 12.50
Medford_Ind 12.29 12.65 20.97 21.09 20.87 18.62 18.22 17.58 16.96 15.12 12.36
Medford_Res 12.41 12.79 21.12 21.23 21.16 18.96 18.58 18.06 17.57 15.70 12.35
OR_Tport 12.17 12.53 20.74 20.89 20.91 18.46 18.08 17.60 17.32 15.82 14.21
Roseburg_Com 12.39 12.76 21.09 21.21 21.10 18.90 18.51 17.98 17.45 15.66 12.54
Roseburg_Ind 12.29 12.65 20.96 21.09 20.88 18.64 18.24 17.60 17.00 15.18 12.47
Roseburg_Res 12.41 12.80 21.12 21.24 21.16 18.97 18.58 18.09 17.58 15.80 12.53
WA_Com 6.86 6.96 7.22 7.48 7.44 7.74 8.12 8.48 8.94 9.34 9.77
WA_Ind 6.70 6.79 7.05 7.32 7.28 7.57 7.96 8.30 8.76 9.13 9.59
WA_Res 6.89 6.99 7.24 7.51 7.47 7.76 8.15 8.52 8.98 9.38 9.81
WA_Tport 6.30 6.40 6.66 6.94 6.92 7.20 7.60 7.93 8.39 8.76 9.23
Appendix - Chapter 6

APPENDIX 6.4: HIGH CUSTOMER GROWTH CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.94 5.71 4.50 4.00 3.81 4.06 3.86 4.56 4.80 5.15 5.66 5.84
ID_Ind 6.31 5.14 4.09 3.64 3.48 3.65 3.56 4.28 4.54 4.85 5.30 5.50
ID_Res 7.11 5.86 4.61 4.10 3.90 4.18 3.95 4.65 4.89 5.25 5.77 5.95
Klamath Falls_Com 7.86 10.22 9.97 9.79 9.85 10.07 10.87 11.50 12.04 12.36 13.31 14.36
Klamath Falls_Ind 7.80 10.07 9.81 9.69 9.77 9.99 10.78 11.42 11.92 12.19 13.03 14.05
Klamath Falls_Res 7.91 10.26 10.01 9.81 9.87 10.09 10.89 11.53 12.08 12.42 13.41 14.46
LaGrande_Com 8.28 11.16 10.64 10.43 10.45 10.61 11.11 11.49 12.02 12.35 13.32 14.37
LaGrande_Ind 7.75 10.14 9.93 9.79 9.90 10.08 10.73 11.33 11.78 11.99 12.79 13.80
LaGrande_Res 8.30 11.25 10.70 10.48 10.48 10.64 11.13 11.51 12.05 12.38 13.37 14.42
Medford_Com 7.80 10.19 9.94 9.77 9.83 10.05 10.85 11.48 12.01 12.32 13.25 14.29
Medford_Ind 7.79 10.01 9.78 9.65 9.73 9.93 10.73 11.37 11.85 12.10 12.93 13.96
Medford_Res 7.90 10.26 10.00 9.81 9.87 10.08 10.89 11.52 12.06 12.39 13.37 14.41
OR_Tport 5.48 10.13 9.56 9.35 9.43 9.60 10.56 11.20 11.82 12.10 12.94 13.97
Roseburg_Com 7.81 10.20 9.95 9.77 9.83 10.04 10.85 11.49 12.01 12.32 13.26 14.30
Roseburg_Ind 7.72 9.99 9.75 9.64 9.72 9.92 10.72 11.37 11.84 12.09 12.93 13.96
Roseburg_Res 7.90 10.26 10.00 9.81 9.87 10.08 10.89 11.52 12.07 12.39 13.36 14.41
WA_Com 8.32 8.42 7.30 6.98 6.98 7.55 7.51 7.36 7.35 7.72 8.33 8.54
WA_Ind 8.58 7.58 6.61 6.32 6.34 6.75 6.89 6.76 6.78 7.05 7.55 7.78
WA_Res 8.36 8.44 7.32 7.00 7.00 7.57 7.52 7.38 7.37 7.74 8.35 8.56
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 6.10 6.37 6.65 6.86 7.15 7.47 7.76 8.03 8.39 8.61 8.78
ID_Ind 5.77 6.02 6.32 6.55 6.85 7.12 7.45 7.75 8.15 8.39 8.62
ID_Res 6.21 6.48 6.75 6.96 7.25 7.60 7.88 8.14 8.49 8.70 8.86
Klamath Falls_Com 24.62 24.29 24.79 24.80 23.46 21.89 20.45 19.11 17.59 16.12 14.57
Klamath Falls_Ind 24.02 23.13 23.56 23.64 22.43 20.87 19.56 18.50 17.12 15.77 14.32
Klamath Falls_Res 24.83 24.71 25.22 25.21 23.82 22.25 20.76 19.32 17.76 16.24 14.66
LaGrande_Com 24.69 24.50 25.01 25.02 23.65 22.04 20.58 19.18 17.64 16.15 14.58
LaGrande_Ind 23.66 22.50 22.99 23.06 21.96 20.22 19.03 18.04 16.75 15.46 14.12
LaGrande_Res 24.78 24.68 25.19 25.19 23.80 22.20 20.71 19.27 17.71 16.20 14.62
Medford_Com 24.52 24.14 24.63 24.64 23.31 21.71 20.29 18.98 17.48 16.03 14.51
Medford_Ind 23.93 23.06 23.50 23.56 22.35 20.70 19.43 18.35 16.99 15.66 14.24
Medford_Res 24.74 24.55 25.06 25.05 23.67 22.08 20.61 19.20 17.66 16.17 14.61
OR_Tport 24.42 24.61 25.13 25.12 3.87 21.94 20.39 18.82 17.25 15.84 14.21
Roseburg_Com 24.54 24.19 24.68 24.70 23.37 21.76 20.34 19.02 17.52 16.06 14.52
Roseburg_Ind 23.95 23.16 23.61 23.68 22.45 20.81 19.50 18.40 17.02 15.69 14.27
Roseburg_Res 24.72 24.51 25.01 25.01 23.64 22.06 20.59 19.20 17.67 16.17 14.61
WA_Com 7.96 8.08 8.32 8.53 8.44 8.68 8.99 9.28 9.66 14.52 14.61
WA_Ind 7.22 7.31 7.58 7.82 7.75 7.90 8.28 8.62 9.08 14.01 14.23
WA_Res 7.97 8.11 8.34 8.54 8.46 8.71 9.02 9.30 9.68 14.54 14.63
WA_Tport 6.30 6.40 6.66 6.93 6.90 7.04 7.47 7.88 8.41 13.42 13.80
Appendix - Chapter 6

APPENDIX 6.4: HYBRID CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.94 5.70 4.49 3.98 3.78 4.00 3.80 4.46 4.71 5.05 5.34 5.51
ID_Ind 6.32 5.14 4.09 3.63 3.45 3.60 3.52 4.20 4.46 4.76 5.06 5.23
ID_Res 7.11 5.86 4.60 4.08 3.87 4.12 3.89 4.54 4.79 5.14 5.44 5.59
Klamath Falls_Com 8.36 10.23 10.11 9.87 9.89 10.10 10.46 10.74 11.16 12.40 12.75 13.81
Klamath Falls_Ind 7.84 10.07 9.82 9.69 9.74 9.96 10.30 10.58 10.99 12.22 12.54 13.58
Klamath Falls_Res 8.44 10.26 10.13 9.88 9.90 10.11 10.48 10.75 11.17 12.41 12.77 13.82
LaGrande_Com 9.25 11.34 11.23 10.89 10.83 11.29 10.88 11.08 11.42 12.38 12.73 13.78
LaGrande_Ind 7.64 10.12 9.86 9.76 9.81 10.02 10.28 10.49 10.88 12.07 12.37 13.41
LaGrande_Res 9.23 11.34 11.18 10.87 10.80 11.26 10.87 11.07 11.42 12.38 12.74 13.79
Medford_Com 8.30 10.21 10.12 9.88 9.95 10.18 10.53 10.82 11.31 12.49 12.86 13.96
Medford_Ind 7.82 10.01 9.78 9.64 9.69 9.91 10.25 10.54 10.92 12.16 12.47 13.52
Medford_Res 8.44 10.27 10.15 9.90 9.96 10.19 10.55 10.84 11.33 12.51 12.88 13.98
OR_Tport 11.25 10.13 9.56 9.35 9.40 9.78 10.12 10.41 10.76 12.01 12.31 13.35
Roseburg_Com 8.34 10.21 10.15 9.96 10.05 10.30 10.64 10.96 11.50 12.57 12.96 14.05
Roseburg_Ind 7.82 9.99 9.78 9.63 9.68 9.90 10.25 10.54 10.91 12.16 12.46 13.51
Roseburg_Res 8.43 10.26 10.17 9.98 10.06 10.31 10.65 10.97 11.53 12.59 12.98 14.08
WA_Com 8.31 8.41 7.38 7.01 6.98 7.53 7.46 7.26 7.26 7.60 7.93 8.10
WA_Ind 8.59 7.58 6.61 6.30 6.32 6.70 6.84 6.67 6.70 6.96 7.29 7.49
WA_Res 9.30 8.21 7.45 7.05 7.01 7.56 7.48 7.28 7.27 7.62 7.95 8.12
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.79 6.22 6.34 6.53 6.85 7.36 7.66 7.95 8.31 8.62 8.93
ID_Ind 5.52 5.89 6.07 6.26 6.57 7.04 7.36 7.67 8.07 8.36 8.72
ID_Res 5.88 6.32 6.43 6.63 6.95 7.47 7.77 8.06 8.41 8.73 9.02
Klamath Falls_Com 23.81 23.97 23.77 23.59 23.49 22.81 21.17 19.52 17.89 16.12 14.36
Klamath Falls_Ind 23.62 23.75 23.47 23.21 22.98 22.25 20.37 18.57 17.04 15.02 13.18
Klamath Falls_Res 23.82 23.98 23.79 23.63 23.54 22.86 21.25 19.61 17.98 16.24 14.48
LaGrande_Com 23.79 23.95 23.75 23.59 23.48 22.83 21.19 19.54 17.92 16.16 14.40
LaGrande_Ind 23.47 23.59 23.22 22.81 22.48 21.70 19.60 17.61 16.12 13.85 11.80
LaGrande_Res 23.80 23.96 23.76 23.60 23.49 22.84 21.22 19.58 17.95 16.20 14.45
Medford_Com 23.89 24.07 23.82 23.63 23.55 22.80 21.14 19.47 17.86 16.06 14.27
Medford_Ind 23.57 23.69 23.40 23.11 22.86 22.13 20.24 18.42 16.90 14.86 12.99
Medford_Res 23.91 24.09 23.85 23.67 23.60 22.86 21.23 19.57 17.95 16.19 14.40
OR_Tport 23.27 23.41 22.96 22.74 22.62 21.97 20.40 18.79 17.23 15.82 14.22
Roseburg_Com 23.93 24.11 23.86 23.67 23.57 22.82 21.16 19.49 17.88 16.09 14.30
Roseburg_Ind 23.56 23.69 23.40 23.11 22.86 22.14 20.27 18.46 16.94 14.93 13.08
Roseburg_Res 23.94 24.13 23.89 23.71 23.63 22.87 21.23 19.58 17.95 16.18 14.39
WA_Com 7.56 7.92 7.94 8.15 8.11 8.55 8.89 9.22 9.58 9.97 10.29
WA_Ind 6.96 7.18 7.32 7.51 7.46 7.82 8.19 8.54 8.99 9.35 9.76
WA_Res 7.58 7.94 7.96 8.17 8.13 8.58 8.91 9.24 9.60 9.99 10.31
WA_Tport 6.30 6.40 6.66 6.86 6.81 7.09 7.48 7.87 8.39 8.76 9.23
Appendix - Chapter 6

APPENDIX 6.4: INTERRUPTED SUPPLY CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.95 5.71 4.49 4.01 3.83 4.07 3.88 4.58 4.80 5.15 5.66 5.84
ID_Ind 6.32 5.15 4.09 3.66 3.50 3.65 3.58 4.30 4.54 4.85 5.31 5.50
ID_Res 7.11 5.86 4.60 4.11 3.93 4.18 3.97 4.67 4.88 5.24 5.77 5.95
Klamath Falls_Com 5.72 10.25 9.95 9.79 9.84 10.09 17.54 18.28 18.91 19.38 20.07 20.98
Klamath Falls_Ind 5.68 10.10 9.80 9.69 9.76 10.01 17.45 18.20 18.84 19.19 19.69 20.58
Klamath Falls_Res 5.76 10.29 9.99 9.82 9.86 10.11 17.57 18.30 18.93 19.44 20.20 21.12
LaGrande_Com 6.14 11.16 10.63 10.44 10.45 10.86 17.72 18.27 18.89 19.36 20.09 21.00
LaGrande_Ind 5.52 10.16 9.85 9.77 9.83 10.11 17.36 18.06 18.71 18.84 18.99 19.86
LaGrande_Res 6.17 11.32 10.71 10.50 10.49 10.91 17.74 18.28 18.90 19.40 20.16 21.08
Medford_Com 5.65 10.22 9.93 9.77 9.82 10.06 17.52 18.26 18.89 19.33 19.99 20.90
Medford_Ind 5.65 10.04 9.76 9.65 9.71 9.95 17.40 18.14 18.78 19.10 19.58 20.47
Medford_Res 5.75 10.28 9.98 9.81 9.86 10.10 17.56 18.30 18.92 19.41 20.14 21.05
OR_Tport 11.25 10.13 9.56 9.35 9.40 9.78 17.13 17.85 18.50 19.01 19.68 20.58
Roseburg_Com 5.67 10.24 9.94 9.77 9.82 10.06 17.52 18.26 18.89 19.33 20.01 20.92
Roseburg_Ind 5.65 10.02 9.76 9.64 9.70 9.94 17.39 18.13 18.77 19.09 19.58 20.48
Roseburg_Res 5.76 10.29 9.99 9.81 9.86 10.10 17.56 18.30 18.92 19.41 20.14 21.05
WA_Com 8.33 8.41 7.29 6.98 7.01 7.56 7.52 7.38 7.35 7.70 8.32 8.53
WA_Ind 8.59 7.59 6.61 6.33 6.37 6.76 6.90 6.78 6.78 7.04 7.55 7.78
WA_Res 8.37 8.43 7.31 7.00 7.03 7.58 7.54 7.40 7.36 7.72 8.34 8.54
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 6.09 6.34 6.59 6.78 7.04 7.42 7.72 8.00 8.37 8.58 8.87
ID_Ind 5.77 6.00 6.28 6.48 6.73 7.09 7.42 7.72 8.13 8.37 8.69
ID_Res 6.20 6.45 6.70 6.89 7.16 7.55 7.84 8.11 8.47 8.68 8.96
Klamath Falls_Com 24.60 24.39 24.79 24.83 23.42 21.90 20.45 19.10 17.56 16.04 14.51
Klamath Falls_Ind 24.12 23.26 23.59 23.71 22.37 20.89 19.58 18.50 17.07 15.62 14.20
Klamath Falls_Res 24.77 24.79 25.22 25.23 23.80 22.26 20.76 19.32 17.74 16.20 14.62
LaGrande_Com 24.64 24.58 25.00 25.03 23.60 22.06 20.57 19.17 17.61 16.08 14.53
LaGrande_Ind 23.25 21.39 21.63 21.89 20.62 19.19 18.13 17.46 16.20 14.87 13.66
LaGrande_Res 24.73 24.77 25.20 25.22 23.77 22.22 20.71 19.27 17.69 16.15 14.59
Medford_Com 24.51 24.24 24.63 24.67 23.25 21.72 20.28 18.97 17.45 15.94 14.44
Medford_Ind 24.01 23.18 23.51 23.62 22.25 20.74 19.42 18.35 16.93 15.49 14.12
Medford_Res 24.69 24.65 25.05 25.07 23.63 22.09 20.60 19.20 17.64 16.10 14.56
OR_Tport 24.26 24.65 25.13 25.09 23.56 21.96 20.38 18.82 17.24 15.83 14.21
Roseburg_Com 24.53 24.30 24.70 24.74 23.32 21.79 20.34 19.02 17.49 15.97 14.46
Roseburg_Ind 24.03 23.28 23.63 23.73 22.34 20.84 19.51 18.40 16.97 15.53 14.15
Roseburg_Res 24.69 24.62 25.02 25.04 23.61 22.08 20.59 19.20 17.64 16.11 14.55
WA_Com 7.94 8.03 8.25 8.44 8.35 8.62 8.94 9.24 9.64 14.11 14.38
WA_Ind 7.22 7.28 7.54 7.75 7.63 7.87 8.24 8.60 9.06 13.59 13.94
WA_Res 7.96 8.06 8.27 8.46 8.37 8.64 8.96 9.26 9.66 14.14 14.40
WA_Tport 6.30 6.40 6.66 6.91 6.80 7.06 7.47 7.88 8.40 13.02 13.44
Appendix - Chapter 6

APPENDIX 6.4: LIMITED RNG AVAILABILITY CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.94 5.70 4.49 3.99 3.79 4.03 3.91 4.56 4.78 5.09 5.23 5.43
ID_Ind 6.32 5.14 4.09 3.64 3.47 3.62 3.61 4.29 4.53 4.81 4.83 5.04
ID_Res 7.11 5.86 4.60 4.09 3.89 4.14 4.00 4.65 4.86 5.19 5.39 5.59
Klamath Falls_Com 5.71 8.79 9.18 9.70 9.84 10.48 31.76 32.05 29.32 25.85 32.73 31.44
Klamath Falls_Ind 5.67 8.64 9.02 9.60 9.76 10.41 31.66 31.96 29.26 25.77 32.48 31.19
Klamath Falls_Res 5.75 8.83 9.22 9.72 9.87 10.50 31.79 32.07 29.34 25.87 32.82 31.53
LaGrande_Com 5.31 8.78 8.94 9.40 9.55 10.34 29.16 29.52 27.03 24.07 30.62 29.51
LaGrande_Ind 5.49 8.70 9.06 9.67 9.83 10.52 31.58 31.88 29.18 25.72 32.06 30.77
LaGrande_Res 5.93 9.60 9.65 10.18 10.33 11.29 31.90 32.11 29.34 25.89 32.74 31.45
Medford_Com 5.64 8.75 9.14 9.67 9.82 10.46 31.73 32.03 29.31 25.83 32.63 31.34
Medford_Ind 5.64 8.56 8.97 9.56 9.71 10.35 31.60 31.92 29.23 25.74 32.28 31.01
Medford_Res 5.20 8.11 8.53 9.16 9.56 10.43 31.78 32.07 29.33 25.86 32.74 31.45
OR_Tport 5.48 10.13 9.56 9.35 9.40 10.02 31.18 31.49 28.83 25.43 32.35 31.10
Roseburg_Com 5.66 8.77 9.16 9.68 9.82 10.46 31.74 32.04 29.31 25.83 32.63 31.35
Roseburg_Ind 5.65 8.54 8.97 9.55 9.70 10.34 31.59 31.92 29.22 25.74 32.26 30.99
Roseburg_Res 5.74 8.82 9.21 9.72 9.86 10.50 31.78 32.07 29.33 25.86 32.76 31.47
WA_Com 8.31 8.40 7.29 6.96 6.96 7.51 7.57 7.35 7.31 7.63 7.91 8.14
WA_Ind 8.59 7.58 6.62 6.31 6.33 6.72 6.93 6.76 6.77 7.00 7.08 7.32
WA_Res 8.35 8.43 7.32 6.98 6.98 7.53 7.59 7.37 7.33 7.65 7.95 8.17
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.25 6.49
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.69 6.10 6.24 6.61 6.92 7.34 7.66 7.93 8.30 8.55 8.85
ID_Ind 5.32 5.68 5.89 6.25 6.59 7.01 7.36 7.65 8.06 8.32 8.66
ID_Res 5.84 6.27 6.38 6.75 7.05 7.48 7.78 8.05 8.41 8.65 8.94
Klamath Falls_Com 30.11 28.67 27.27 25.81 24.35 22.82 21.35 19.74 18.16 16.46 14.73
Klamath Falls_Ind 29.88 28.44 27.06 25.61 24.17 22.65 21.21 19.61 18.06 16.36 14.64
Klamath Falls_Res 30.19 28.75 27.35 25.88 24.41 22.87 21.40 19.79 18.20 16.50 14.77
LaGrande_Com 28.46 27.28 26.07 24.75 23.49 22.05 20.64 19.08 17.54 15.90 14.22
LaGrande_Ind 29.48 28.04 26.66 25.22 23.81 22.31 20.94 19.34 17.85 16.15 14.45
LaGrande_Res 30.11 28.67 27.27 25.81 24.34 22.82 21.36 19.74 18.16 16.46 14.73
Medford_Com 30.01 28.57 27.18 25.72 24.27 22.75 21.30 19.69 18.12 16.42 14.69
Medford_Ind 29.71 28.26 26.89 25.45 24.03 22.52 21.12 19.51 17.99 16.29 14.56
Medford_Res 30.12 28.68 27.28 25.82 24.35 22.82 21.36 19.74 18.16 16.46 14.73
OR_Tport 29.76 28.30 26.91 25.46 24.01 22.46 21.16 19.55 18.07 16.36 14.65
Roseburg_Com 30.02 28.58 27.19 25.74 24.28 22.76 21.31 19.70 18.13 16.42 14.69
Roseburg_Ind 29.69 28.25 26.89 25.45 24.03 22.52 21.12 19.52 18.00 16.29 14.57
Roseburg_Res 30.13 28.69 27.30 25.83 24.37 22.84 21.37 19.76 18.17 16.47 14.74
WA_Com 7.55 7.87 7.91 8.31 8.24 8.54 8.89 9.18 9.57 14.08 14.37
WA_Ind 6.77 6.99 7.15 7.52 7.49 7.79 8.18 8.53 8.99 13.54 13.91
WA_Res 7.59 7.91 7.94 8.33 8.27 8.58 8.92 9.21 9.60 14.10 14.39
WA_Tport 5.95 6.08 6.37 6.68 6.69 7.00 7.42 7.82 8.35 12.97 13.41
Appendix - Chapter 6

APPENDIX 6.4: PRS CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.94 5.70 4.49 3.99 3.79 4.02 3.88 4.53 4.74 5.08 5.38 5.60
ID_Ind 6.32 5.14 4.09 3.64 3.46 3.62 3.58 4.26 4.50 4.80 5.10 5.32
ID_Res 7.11 5.85 4.60 4.09 3.88 4.14 3.97 4.62 4.82 5.18 5.47 5.69
Klamath Falls_Com 7.87 10.22 9.97 9.78 9.82 10.05 14.09 14.69 15.34 15.79 16.68 23.80
Klamath Falls_Ind 7.83 10.07 9.82 9.69 9.74 9.98 14.00 14.61 15.28 15.63 16.37 23.42
Klamath Falls_Res 7.92 10.27 10.01 9.81 9.84 10.07 14.12 14.72 15.36 15.85 16.78 23.94
LaGrande_Com 8.27 11.13 10.65 10.43 10.43 10.82 14.31 14.68 15.32 15.78 16.69 23.83
LaGrande_Ind 7.63 10.12 9.86 9.76 9.81 10.08 13.92 14.48 15.16 15.31 15.82 22.75
LaGrande_Res 8.31 11.29 10.73 10.49 10.47 10.87 14.33 14.70 15.33 15.81 16.74 23.89
Medford_Com 7.80 10.20 9.94 9.76 9.80 10.03 14.07 14.67 15.32 15.75 16.61 23.73
Medford_Ind 7.81 10.01 9.78 9.64 9.70 9.93 13.94 14.56 15.22 15.54 16.27 23.33
Medford_Res 7.90 10.26 10.00 9.80 9.83 10.07 14.11 14.71 15.35 15.82 16.74 23.87
OR_Tport 5.48 10.13 9.56 9.35 9.40 9.60 13.71 14.34 15.01 15.48 16.28 23.36
Roseburg_Com 7.83 10.21 9.96 9.76 9.80 10.03 14.07 14.67 15.32 15.75 16.62 23.75
Roseburg_Ind 7.81 9.99 9.78 9.64 9.69 9.92 13.94 14.55 15.21 15.54 16.27 23.34
Roseburg_Res 7.91 10.26 10.01 9.80 9.84 10.07 14.11 14.71 15.36 15.82 16.73 23.87
WA_Com 8.31 8.40 7.29 6.96 6.95 7.50 7.53 7.32 7.27 7.62 7.95 8.20
WA_Ind 8.59 7.58 6.61 6.31 6.33 6.72 6.90 6.74 6.73 6.99 7.32 7.58
WA_Res 8.35 8.43 7.31 6.98 6.96 7.52 7.55 7.33 7.28 7.64 7.97 8.22
WA_Tport 5.53 6.51 5.85 5.58 5.62 5.81 6.18 6.04 6.08 6.26 6.62 6.86
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.86 6.28 6.40 6.73 6.99 7.39 7.69 7.97 8.33 8.57 8.86
ID_Ind 5.59 5.95 6.13 6.44 6.68 7.07 7.40 7.70 8.10 8.36 8.68
ID_Res 5.95 6.38 6.50 6.83 7.10 7.51 7.81 8.07 8.42 8.67 8.94
Klamath Falls_Com 24.69 24.35 24.67 24.83 23.41 21.89 20.48 19.10 17.60 16.04 14.52
Klamath Falls_Ind 24.18 23.24 23.48 23.71 22.36 20.89 19.64 18.49 17.11 15.61 14.21
Klamath Falls_Res 24.88 24.76 25.10 25.23 23.79 22.26 20.78 19.32 17.77 16.19 14.63
LaGrande_Com 24.74 24.55 24.88 25.03 23.59 22.05 20.59 19.17 17.65 16.08 14.54
LaGrande_Ind 23.26 21.38 21.53 21.88 20.61 19.19 18.24 17.46 16.26 14.86 13.67
LaGrande_Res 24.84 24.74 25.08 25.22 23.76 22.22 20.73 19.27 17.73 16.15 14.59
Medford_Com 24.60 24.21 24.51 24.67 23.24 21.72 20.32 18.97 17.49 15.94 14.44
Medford_Ind 24.08 23.16 23.40 23.62 22.24 20.73 19.48 18.34 16.98 15.49 14.13
Medford_Res 24.79 24.61 24.94 25.07 23.62 22.09 20.62 19.20 17.67 16.10 14.56
OR_Tport 24.42 24.65 25.01 25.09 23.56 21.96 20.38 18.82 17.33 15.83 14.21
Roseburg_Com 24.62 24.27 24.58 24.74 23.32 21.78 20.37 19.02 17.53 15.97 14.46
Roseburg_Ind 24.10 23.26 23.52 23.73 22.34 20.83 19.56 18.40 17.02 15.53 14.16
Roseburg_Res 24.78 24.58 24.90 25.04 23.61 22.07 20.62 19.20 17.68 16.10 14.56
WA_Com 7.63 7.96 8.00 8.37 8.28 8.58 8.91 9.20 9.59 14.09 14.37
WA_Ind 7.02 7.24 7.39 7.70 7.59 7.85 8.22 8.57 9.03 13.57 13.93
WA_Res 7.64 7.98 8.02 8.39 8.30 8.60 8.94 9.22 9.61 14.11 14.39
WA_Tport 6.30 6.40 6.66 6.91 6.80 7.06 7.47 7.88 8.40 13.01 13.44
Appendix - Chapter 6

APPENDIX 6.4: PRS – ALLOWANCE PRICE CEILING CASE AVOIDED COST
($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.81 5.51 4.36 3.87 3.69 3.87 3.77 4.42 4.64 4.92 5.28 5.48
ID_Ind 6.24 5.02 4.01 3.57 3.41 3.53 3.52 4.20 4.44 4.71 5.04 5.25
ID_Res 6.96 5.64 4.45 3.96 3.78 3.97 3.85 4.50 4.71 5.00 5.36 5.56
Klamath Falls_Com 5.71 10.22 9.97 9.78 9.83 10.07 10.87 11.52 12.05 12.54 13.43 14.48
Klamath Falls_Ind 5.67 10.07 9.82 9.69 9.75 10.00 10.78 11.44 11.99 12.40 13.15 14.17
Klamath Falls_Res 5.75 10.27 10.01 9.81 9.85 10.10 10.90 11.54 12.08 12.60 13.53 14.58
LaGrande_Com 6.04 11.04 10.58 10.36 10.38 10.75 11.09 11.51 12.03 12.53 13.44 14.49
LaGrande_Ind 5.44 10.11 9.85 9.75 9.81 10.08 10.69 11.31 11.86 12.11 12.64 13.63
LaGrande_Res 6.08 11.18 10.65 10.42 10.41 10.79 11.12 11.52 12.05 12.55 13.49 14.54
Medford_Com 5.64 10.20 9.95 9.76 9.81 10.05 10.85 11.49 12.03 12.50 13.37 14.41
Medford_Ind 5.65 10.01 9.78 9.64 9.70 9.94 10.71 11.38 11.93 12.31 13.06 14.08
Medford_Res 5.74 10.26 10.00 9.80 9.85 10.09 10.89 11.53 12.07 12.57 13.49 14.53
OR_Tport 5.48 10.13 9.56 9.35 9.40 9.60 10.52 11.20 11.76 12.25 13.06 14.09
Roseburg_Com 5.66 10.21 9.96 9.76 9.81 10.05 10.85 11.50 12.03 12.51 13.38 14.43
Roseburg_Ind 5.65 9.99 9.78 9.64 9.70 9.93 10.70 11.37 11.92 12.30 13.06 14.08
Roseburg_Res 5.74 10.26 10.01 9.80 9.85 10.09 10.89 11.53 12.07 12.57 13.49 14.53
WA_Com 10.42 10.54 9.70 9.58 9.80 10.47 10.75 11.21 11.75 12.46 13.28 13.95
WA_Ind 10.67 9.81 9.10 9.02 9.25 9.80 10.21 10.71 11.29 11.96 12.74 13.42
WA_Res 10.46 10.56 9.72 9.60 9.81 10.48 10.77 11.22 11.76 12.48 13.29 13.97
WA_Tport 5.53 8.88 8.44 8.37 8.60 8.99 9.55 10.08 10.70 11.34 12.10 12.78
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 5.77 6.13 6.31 6.59 6.86 7.21 7.41 7.42 7.88 8.23 8.63
ID_Ind 5.55 5.87 6.09 6.37 6.63 6.99 7.21 7.28 7.75 8.08 8.49
ID_Res 5.85 6.22 6.39 6.67 6.95 7.31 7.49 7.49 7.94 8.31 8.70
Klamath Falls_Com 24.84 24.49 24.81 24.90 23.43 21.95 20.56 19.12 17.63 16.07 14.55
Klamath Falls_Ind 24.45 23.37 23.61 23.84 22.40 21.00 19.80 18.50 17.16 15.66 14.27
Klamath Falls_Res 24.98 24.90 25.24 25.29 23.80 22.29 20.84 19.34 17.80 16.22 14.65
LaGrande_Com 24.87 24.69 25.02 25.10 23.62 22.12 20.67 19.17 17.66 16.09 14.55
LaGrande_Ind 23.74 21.49 21.66 22.12 20.70 19.41 18.52 17.43 16.31 14.93 13.78
LaGrande_Res 24.94 24.88 25.22 25.27 23.78 22.27 20.80 19.27 17.74 16.16 14.60
Medford_Com 24.76 24.35 24.65 24.76 23.27 21.80 20.42 18.97 17.51 15.97 14.48
Medford_Ind 24.34 23.29 23.53 23.76 22.29 20.87 19.66 18.32 17.00 15.52 14.18
Medford_Res 24.91 24.76 25.08 25.14 23.64 22.14 20.70 19.21 17.70 16.13 14.58
OR_Tport 24.42 24.77 25.15 25.15 17.89 22.02 20.43 18.87 17.37 15.86 14.61
Roseburg_Com 24.78 24.41 24.72 24.82 23.34 21.86 20.47 19.02 17.54 15.99 14.49
Roseburg_Ind 24.36 23.39 23.65 23.86 22.39 20.97 19.73 18.38 17.04 15.56 14.21
Roseburg_Res 24.91 24.73 25.04 25.11 23.62 22.12 20.69 19.21 17.70 16.13 14.58
WA_Com 14.75 15.71 16.46 17.39 18.37 19.48 20.47 19.89 18.24 16.54 14.81
WA_Ind 14.23 15.11 15.93 16.86 17.82 18.94 19.99 19.78 18.14 16.44 14.71
WA_Res 14.77 15.73 16.48 17.41 18.39 19.50 20.49 19.90 18.25 16.55 14.81
WA_Tport 13.56 14.37 15.26 16.18 17.14 18.30 19.47 19.74 18.09 16.39 14.67
Appendix - Chapter 6

APPENDIX 6.4: PRS – HIGH PRICES CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 8.06 7.20 6.21 5.84 5.58 6.04 5.89 6.63 6.98 7.52 8.02 8.31
ID_Ind 7.45 6.64 5.83 5.50 5.25 5.66 5.62 6.39 6.74 7.26 7.75 8.06
ID_Res 8.22 7.36 6.32 5.94 5.68 6.15 5.97 6.71 7.05 7.61 8.11 8.39
Klamath Falls_Com 8.05 8.95 9.56 10.08 10.64 11.13 11.80 12.66 13.31 13.86 14.71 15.79
Klamath Falls_Ind 7.99 8.78 9.42 9.99 10.54 11.07 11.74 12.62 13.23 13.73 14.40 15.45
Klamath Falls_Res 8.11 9.00 9.60 10.11 10.67 11.15 11.82 12.68 13.33 13.91 14.82 15.91
LaGrande_Com 8.44 9.87 10.23 10.44 10.95 11.12 11.80 12.65 13.30 13.85 14.72 15.82
LaGrande_Ind 7.79 8.80 9.44 9.98 10.45 10.98 11.66 12.53 13.09 13.48 13.83 14.90
LaGrande_Res 8.49 10.04 10.32 10.48 10.99 11.14 11.81 12.66 13.31 13.87 14.78 15.87
Medford_Com 7.98 8.91 9.53 10.06 10.61 11.11 11.79 12.65 13.28 13.82 14.64 15.72
Medford_Ind 7.94 8.68 9.36 9.94 10.47 11.01 11.70 12.58 13.17 13.65 14.30 15.38
Medford_Res 8.09 8.98 9.59 10.10 10.66 11.14 11.81 12.67 13.32 13.88 14.77 15.85
OR_Tport 6.60 5.64 5.11 4.81 11.13 11.60 11.99 12.32 12.97 13.50 14.31 15.39
Roseburg_Com 8.00 8.92 9.54 10.06 10.61 11.11 11.79 12.65 13.29 13.82 14.65 15.74
Roseburg_Ind 7.94 8.65 9.36 9.93 10.46 11.00 11.70 12.58 13.16 13.64 14.29 15.40
Roseburg_Res 8.09 8.99 9.59 10.10 10.66 11.14 11.82 12.68 13.33 13.88 14.77 15.85
WA_Com 9.51 9.94 9.00 8.79 8.77 9.50 9.49 9.39 9.50 10.03 10.58 10.86
WA_Ind 9.72 9.08 8.34 8.18 8.11 8.76 8.94 8.85 8.98 9.44 9.98 10.31
WA_Res 9.55 9.96 9.02 8.81 8.79 9.52 9.51 9.40 9.52 10.05 10.60 10.88
WA_Tport 6.66 7.99 7.56 7.42 7.35 7.81 8.23 8.14 8.29 8.68 9.22 9.59
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 8.56 9.33 9.72 10.20 10.62 11.01 11.69 12.02 12.61 12.88 13.16
ID_Ind 8.29 9.01 9.48 9.95 10.35 10.71 11.44 11.79 12.36 12.65 12.96
ID_Res 8.65 9.44 9.80 10.28 10.71 11.14 11.79 12.12 12.73 12.97 13.27
Klamath Falls_Com 24.83 24.43 24.42 24.61 23.40 21.93 20.56 19.19 17.58 16.10 14.43
Klamath Falls_Ind 24.41 23.42 23.26 23.55 22.35 20.91 19.71 18.55 17.07 15.67 14.04
Klamath Falls_Res 24.98 24.80 24.84 25.00 23.78 22.29 20.86 19.41 17.76 16.25 14.57
LaGrande_Com 24.86 24.60 24.64 24.79 23.58 22.08 20.68 19.27 17.61 16.15 14.45
LaGrande_Ind 23.64 21.74 21.36 21.73 20.58 19.21 18.31 17.53 16.17 14.94 13.36
LaGrande_Res 24.93 24.77 24.83 24.97 23.75 22.25 20.81 19.37 17.70 16.22 14.52
Medford_Com 24.74 24.29 24.27 24.45 23.23 21.75 20.40 19.05 17.45 16.00 14.33
Medford_Ind 24.29 23.33 23.19 23.42 22.21 20.76 19.57 18.41 16.91 15.58 13.93
Medford_Res 24.91 24.66 24.68 24.84 23.61 22.12 20.71 19.29 17.65 16.16 14.48
OR_Tport 6.14 6.57 6.96 7.24 23.57 21.98 20.45 18.90 17.39 15.56 14.07
Roseburg_Com 24.76 24.34 24.34 24.50 23.30 21.82 20.45 19.10 17.49 16.04 14.36
Roseburg_Ind 24.30 23.40 23.31 23.51 22.31 20.86 19.66 18.48 16.95 15.62 13.96
Roseburg_Res 24.90 24.64 24.65 24.82 23.60 22.10 20.69 19.28 17.66 16.16 14.48
WA_Com 10.31 11.00 11.28 11.77 11.87 12.18 12.83 13.20 13.91 14.44 14.47
WA_Ind 9.72 10.29 10.73 11.21 11.25 11.48 12.26 12.65 13.27 13.89 13.98
WA_Res 10.33 11.03 11.30 11.79 11.88 12.21 12.85 13.22 13.93 14.46 14.50
WA_Tport 8.97 9.41 9.96 10.43 10.47 10.69 11.50 11.96 12.63 13.29 13.47
Appendix - Chapter 6

APPENDIX 6.4: PRS – LOW PRICES CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 6.52 5.19 3.95 3.41 3.15 3.30 3.10 3.73 3.81 4.05 4.32 4.43
ID_Ind 5.88 4.62 3.55 3.05 2.82 2.89 2.80 3.47 3.56 3.75 4.02 4.15
ID_Res 6.69 5.34 4.06 3.51 3.24 3.42 3.20 3.82 3.89 4.14 4.41 4.52
Klamath Falls_Com 7.43 9.73 9.47 9.24 9.91 10.54 11.35 11.89 12.57 12.76 13.63 14.59
Klamath Falls_Ind 7.39 9.58 9.32 9.14 9.83 10.45 11.25 11.81 12.49 12.60 13.35 14.29
Klamath Falls_Res 7.47 9.77 9.51 9.26 9.93 10.56 11.37 11.91 12.60 12.81 13.72 14.69
LaGrande_Com 7.83 10.65 10.17 9.89 10.52 11.29 11.58 11.89 12.56 12.74 13.63 14.60
LaGrande_Ind 7.18 9.63 9.36 9.20 9.90 10.55 11.15 11.70 12.34 12.32 12.87 13.76
LaGrande_Res 7.87 10.81 10.24 9.96 10.56 11.34 11.61 11.90 12.57 12.77 13.68 14.65
Medford_Com 7.36 9.70 9.45 9.22 9.89 10.52 11.32 11.87 12.55 12.72 13.57 14.52
Medford_Ind 7.37 9.51 9.28 9.09 9.79 10.40 11.19 11.77 12.44 12.52 13.26 14.20
Medford_Res 7.46 9.76 9.50 9.26 9.93 10.55 11.36 11.91 12.59 12.79 13.68 14.64
OR_Tport 10.81 9.61 9.02 8.80 9.48 10.26 11.02 11.61 12.33 12.49 13.26 14.24
Roseburg_Com 7.38 9.72 9.46 9.22 9.89 10.52 11.33 11.88 12.56 12.72 13.58 14.54
Roseburg_Ind 7.37 9.50 9.28 9.08 9.78 10.39 11.18 11.77 12.43 12.51 13.26 14.21
Roseburg_Res 7.46 9.77 9.51 9.26 9.93 10.55 11.37 11.91 12.59 12.79 13.68 14.64
WA_Com 7.87 7.89 6.75 6.38 6.31 6.79 6.76 6.51 6.34 6.60 6.90 7.03
WA_Ind 8.15 7.06 6.07 5.72 5.69 5.99 6.13 5.94 5.80 5.95 6.25 6.41
WA_Res 7.91 7.92 6.78 6.40 6.33 6.81 6.78 6.53 6.36 6.62 6.91 7.05
WA_Tport 5.10 5.99 5.31 4.99 4.97 5.09 5.41 5.28 5.17 5.22 5.55 5.70
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 4.73 5.11 5.24 5.54 5.69 6.04 6.32 6.52 6.75 6.82 7.11
ID_Ind 4.45 4.77 4.97 5.25 5.38 5.70 6.01 6.25 6.51 6.60 6.93
ID_Res 4.82 5.23 5.34 5.63 5.81 6.17 6.43 6.63 6.84 6.92 7.19
Klamath Falls_Com 24.61 24.33 24.69 24.86 23.41 21.90 20.48 19.14 17.60 15.97 14.54
Klamath Falls_Ind 24.12 23.22 23.50 23.76 22.37 20.89 19.65 18.53 17.12 15.52 14.26
Klamath Falls_Res 24.79 24.74 25.12 25.25 23.79 22.26 20.78 19.36 17.77 16.13 14.65
LaGrande_Com 24.66 24.53 24.90 25.06 23.59 22.05 20.60 19.22 17.65 16.01 14.56
LaGrande_Ind 23.21 21.36 21.55 21.98 20.62 19.19 18.24 17.51 16.28 14.74 13.77
LaGrande_Res 24.75 24.72 25.10 25.24 23.76 22.22 20.74 19.31 17.73 16.08 14.61
Medford_Com 24.52 24.19 24.54 24.71 23.25 21.72 20.33 19.01 17.49 15.86 14.48
Medford_Ind 24.01 23.14 23.42 23.68 22.25 20.73 19.49 18.39 16.99 15.39 14.18
Medford_Res 24.71 24.59 24.96 25.10 23.62 22.09 20.63 19.24 17.67 16.03 14.58
OR_Tport 24.37 24.63 25.06 25.19 23.59 21.99 20.43 18.93 17.35 15.69 14.24
Roseburg_Com 24.54 24.25 24.60 24.77 23.32 21.78 20.38 19.06 17.53 15.90 14.49
Roseburg_Ind 24.02 23.24 23.55 23.80 22.35 20.83 19.58 18.45 17.03 15.42 14.22
Roseburg_Res 24.70 24.56 24.92 25.07 23.60 22.07 20.63 19.24 17.68 16.04 14.58
WA_Com 6.50 6.82 6.85 7.18 7.00 7.24 7.55 7.77 8.02 14.12 14.35
WA_Ind 5.89 6.06 6.22 6.51 6.29 6.48 6.84 7.12 7.44 13.59 13.91
WA_Res 6.52 6.84 6.87 7.19 7.02 7.27 7.58 7.79 8.04 14.14 14.37
WA_Tport 5.17 5.22 5.49 5.73 5.49 5.68 6.07 6.42 6.82 13.05 13.44
Appendix - Chapter 6

APPENDIX 6.4: SOCIAL COST OF CARBON CASE AVOIDED COST ($/DEKATHERM)

2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
ID_Com 11.85 10.77 9.83 9.55 9.59 9.99 10.06 10.33 10.62 11.00 11.44 11.73
ID_Ind 11.26 10.27 9.47 9.24 9.31 9.64 9.82 10.11 10.42 10.78 11.20 11.51
ID_Res 12.01 10.91 9.93 9.64 9.68 10.09 10.14 10.41 10.69 11.08 11.52 11.81
Klamath Falls_Com 10.72 9.88 9.29 9.09 9.24 12.37 12.94 13.43 14.15 17.57 18.65 19.23
Klamath Falls_Ind 10.67 9.73 9.14 9.00 9.16 12.30 12.86 13.35 13.83 16.83 18.01 18.59
Klamath Falls_Res 10.76 9.93 9.33 9.12 9.26 12.39 12.96 13.45 14.26 17.83 18.88 19.46
LaGrande_Com 10.90 10.22 9.63 9.40 9.52 12.36 12.93 13.42 14.15 17.66 18.73 19.31
LaGrande_Ind 10.38 9.62 9.05 8.94 9.09 12.18 12.74 13.23 13.23 15.52 16.89 17.50
LaGrande_Res 10.95 10.30 9.69 9.45 9.55 12.38 12.95 13.43 14.21 17.80 18.85 19.42
Medford_Com 10.65 9.85 9.26 9.07 9.22 12.35 12.92 13.41 14.08 17.47 18.56 19.13
Medford_Ind 10.64 9.66 9.10 8.95 9.11 12.24 12.81 13.30 13.74 16.75 17.93 18.51
Medford_Res 10.75 9.92 9.32 9.11 9.26 12.38 12.95 13.45 14.21 17.74 18.80 19.37
OR_Tport 10.74 9.30 8.74 8.52 8.57 8.77 9.11 9.40 9.73 10.04 18.44 18.98
Roseburg_Com 10.67 9.87 9.27 9.07 9.22 12.35 12.92 13.41 14.10 17.50 18.58 19.16
Roseburg_Ind 10.64 9.64 9.09 8.94 9.10 12.23 12.80 13.30 13.73 16.78 17.96 18.54
Roseburg_Res 10.76 9.92 9.33 9.11 9.26 12.39 12.95 13.45 14.21 17.73 18.78 19.36
WA_Com 13.27 13.45 12.60 12.49 12.73 13.41 13.65 13.71 13.91 14.42 15.06 15.53
WA_Ind 13.52 12.69 11.98 11.90 12.16 12.73 13.13 13.22 13.46 13.92 14.52 15.02
WA_Res 13.31 13.47 12.62 12.50 12.74 13.43 13.67 13.73 13.92 14.43 15.07 15.55
WA_Tport 10.45 11.64 11.19 11.13 11.38 11.79 12.38 12.48 12.75 13.16 13.76 14.24
2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
ID_Com 12.10 12.57 12.89 13.31 13.73 14.24 14.68 15.00 15.31 15.78 14.77
ID_Ind 11.88 12.31 12.67 13.10 13.54 14.05 14.50 14.82 15.17 15.63 14.72
ID_Res 12.17 12.65 12.96 13.39 13.81 14.31 14.74 15.08 15.37 15.86 14.79
Klamath Falls_Com 23.86 24.11 23.68 23.66 23.32 21.85 20.32 18.74 17.23 15.58 14.17
Klamath Falls_Ind 23.25 23.44 22.53 22.50 22.19 20.78 19.33 17.78 16.36 14.77 13.50
Klamath Falls_Res 24.09 24.35 24.10 24.07 23.73 22.24 20.68 19.09 17.54 15.87 14.41
LaGrande_Com 23.94 24.20 23.88 23.86 23.53 22.05 20.50 18.91 17.34 15.68 14.26
LaGrande_Ind 22.17 22.28 20.63 20.63 20.36 19.04 17.74 16.21 14.93 13.42 12.40
LaGrande_Res 24.05 24.31 24.07 24.05 23.71 22.22 20.65 19.05 17.49 15.81 14.37
Medford_Com 23.76 24.00 23.52 23.50 23.16 21.69 20.16 18.57 17.06 15.42 14.05
Medford_Ind 23.15 23.33 22.43 22.40 22.08 20.66 19.20 17.63 16.20 14.59 13.40
Medford_Res 23.99 24.25 23.94 23.91 23.56 22.07 20.52 18.92 17.38 15.72 14.29
OR_Tport 23.56 11.48 11.89 12.30 12.76 13.29 13.77 19.31 17.64 15.87 14.68
Roseburg_Com 23.79 24.03 23.59 23.56 23.23 21.75 20.22 18.64 17.11 15.47 14.08
Roseburg_Ind 23.17 23.36 22.55 22.52 22.21 20.79 19.32 17.74 16.30 14.68 13.49
Roseburg_Res 23.98 24.24 23.91 23.88 23.53 22.04 20.50 18.91 17.37 15.71 14.27
WA_Com 15.22 15.75 16.19 16.81 17.04 17.61 18.26 18.81 18.24 16.54 14.81
WA_Ind 14.72 15.18 15.68 16.30 16.56 17.15 17.82 18.38 18.14 16.43 14.73
WA_Res 15.24 15.77 16.20 16.83 17.06 17.63 18.28 18.83 18.25 16.55 14.82
WA_Tport 13.93 14.33 14.90 15.49 15.78 16.40 17.10 17.74 18.10 16.40 14.69
Appendix - Chapter 6

APPENDIX 6.5: AVERAGE CASE WINTER AVOIDED COST ($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 7.71 5.01 4.30 3.57 3.33 3.31 3.43 3.95 4.36 4.70 5.08 5.37
ID_Ind 7.71 5.01 4.30 3.56 3.33 3.31 3.43 3.94 4.36 4.70 5.08 5.36
ID_Res 7.71 5.01 4.30 3.57 3.33 3.31 3.43 3.95 4.36 4.71 5.08 5.37
Klamath Falls_Com 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
Klamath Falls_Ind 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
Klamath Falls_Res 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
LaGrande_Com 7.84 8.51 10.40 9.98 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
LaGrande_Ind 7.84 8.51 10.40 9.98 9.89 10.04 10.53 11.07 11.70 12.26 13.17 20.33
LaGrande_Res 7.84 8.51 10.40 9.98 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
Medford_Com 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
Medford_Ind 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.17 20.33
Medford_Res 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
OR_Tport 7.48 8.40 10.20 9.64 9.55 9.70 10.19 10.79 11.43 12.01 12.81 14.44
Roseburg_Com 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
Roseburg_Ind 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.17 20.33
Roseburg_Res 7.84 8.51 10.40 9.97 9.89 10.04 10.53 11.07 11.70 12.26 13.18 20.33
WA_Com 9.86 7.26 6.68 6.10 6.05 6.24 6.60 6.71 6.65 6.87 7.25 7.57
WA_Ind 9.86 7.25 6.68 6.09 6.04 6.23 6.59 6.70 6.64 6.86 7.24 7.56
WA_Res 9.86 7.26 6.68 6.10 6.05 6.24 6.60 6.71 6.65 6.87 7.25 7.57
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 5.63 5.87 6.31 6.57 6.85 7.30 7.76 8.03 8.34 8.71 8.87 9.10
ID_Ind 5.63 5.87 6.30 6.57 6.85 7.30 7.76 8.03 8.34 8.71 8.87 9.10
ID_Res 5.63 5.87 6.31 6.57 6.85 7.30 7.76 8.03 8.34 8.71 8.87 9.10
Klamath Falls_Com 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Klamath Falls_Ind 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Klamath Falls_Res 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
LaGrande_Com 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
LaGrande_Ind 25.40 25.78 25.98 26.04 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
LaGrande_Res 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Medford_Com 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Medford_Ind 25.40 25.78 25.98 26.04 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Medford_Res 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
OR_Tport 21.18 19.34 21.47 25.41 24.52 23.05 21.54 19.92 18.30 16.95 15.36 14.84
Roseburg_Com 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Roseburg_Ind 25.40 25.78 25.98 26.04 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
Roseburg_Res 25.40 25.78 25.98 26.05 25.14 23.63 22.08 20.46 18.81 17.19 15.54 14.84
WA_Com 7.35 7.17 7.53 7.79 7.85 8.08 8.52 8.84 9.21 13.67 15.41 14.84
WA_Ind 7.34 7.16 7.52 7.78 7.84 8.07 8.51 8.84 9.21 13.67 15.40 14.84
WA_Res 7.35 7.17 7.53 7.79 7.85 8.08 8.52 8.84 9.21 13.67 15.41 14.84
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 13.17 15.03 14.64
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: CARBON INTENSITY CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.57 6.53 5.35 4.53 4.21 4.39 4.15 4.66 5.01 5.40 5.79 5.98
ID_Ind 9.33 6.35 5.20 4.40 4.08 4.25 4.05 4.56 4.93 5.32 5.70 5.89
ID_Res 9.65 6.58 5.39 4.58 4.25 4.44 4.19 4.69 5.04 5.43 5.82 6.00
Klamath Falls_Com 10.35 7.87 7.64 7.31 7.33 7.51 8.00 8.57 9.20 9.71 10.14 10.39
Klamath Falls_Ind 10.35 7.86 7.64 7.31 7.33 7.50 8.00 8.57 9.20 9.70 10.13 10.38
Klamath Falls_Res 10.35 7.87 7.64 7.31 7.33 7.51 8.00 8.57 9.20 9.71 10.14 10.39
LaGrande_Com 12.20 9.39 8.70 8.31 8.28 8.67 8.76 9.25 9.78 10.39 10.85 11.04
LaGrande_Ind 11.38 8.76 8.22 7.86 7.85 8.19 8.42 8.95 9.53 10.14 10.57 10.77
LaGrande_Res 12.22 9.40 8.72 8.32 8.29 8.68 8.77 9.26 9.78 10.40 10.86 11.04
Medford_Com 10.35 7.86 7.64 7.31 7.33 7.51 8.00 8.57 9.20 9.70 10.14 10.39
Medford_Ind 10.35 7.86 7.64 7.30 7.33 7.50 7.99 8.57 9.20 9.69 10.12 10.38
Medford_Res 10.35 7.87 7.64 7.31 7.33 7.51 8.00 8.57 9.20 9.71 10.14 10.39
OR_Tport 13.81 7.36 4.12 3.35 3.05 7.46 10.66 10.95 11.25 11.67 12.17 12.53
Roseburg_Com 10.35 7.87 7.64 7.31 7.33 7.51 8.00 8.57 9.20 9.71 10.14 10.39
Roseburg_Ind 10.35 7.86 7.64 7.30 7.32 7.50 7.99 8.56 9.19 9.69 10.12 10.38
Roseburg_Res 10.35 7.87 7.64 7.31 7.33 7.51 8.00 8.57 9.21 9.71 10.14 10.39
WA_Com 11.97 9.07 8.03 7.38 7.25 7.67 7.69 7.75 7.58 7.83 8.23 8.45
WA_Ind 11.75 8.86 7.86 7.21 7.09 7.49 7.54 7.61 7.46 7.71 8.09 8.32
WA_Res 12.00 9.08 8.04 7.39 7.26 7.68 7.69 7.76 7.59 7.83 8.24 8.45
WA_Tport 9.83 7.29 6.73 6.12 6.02 6.18 6.51 6.54 6.46 6.64 7.04 7.33
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 6.23 6.64 7.09 7.30 7.55 7.90 8.33 8.56 8.80 9.15 9.26 9.43
ID_Ind 6.15 6.55 6.98 7.21 7.46 7.84 8.27 8.51 8.77 9.14 9.26 9.43
ID_Res 6.26 6.67 7.12 7.34 7.58 7.92 8.35 8.58 8.82 9.16 9.26 9.43
Klamath Falls_Com 10.69 11.05 11.54 11.98 12.85 14.94 16.31 16.84 16.87 16.60 15.35 14.84
Klamath Falls_Ind 10.69 11.04 11.53 11.97 12.85 14.93 16.31 16.84 16.87 16.60 15.35 14.84
Klamath Falls_Res 10.70 11.05 11.54 11.98 12.85 14.94 16.31 16.84 16.87 16.60 15.35 14.84
LaGrande_Com 11.30 11.70 12.16 12.53 13.30 15.20 16.52 16.97 16.89 16.59 15.35 14.84
LaGrande_Ind 11.05 11.42 11.87 12.26 13.09 15.09 16.41 16.91 16.87 16.59 15.35 14.84
LaGrande_Res 11.31 11.71 12.17 12.54 13.31 15.21 16.52 16.97 16.89 16.59 15.35 14.84
Medford_Com 10.69 11.05 11.53 11.97 12.85 14.94 16.31 16.84 16.87 16.60 15.35 14.84
Medford_Ind 10.69 11.04 11.53 11.97 12.85 14.93 16.30 16.84 16.86 16.59 15.35 14.84
Medford_Res 10.70 11.05 11.54 11.98 12.85 14.94 16.31 16.84 16.87 16.60 15.35 14.84
OR_Tport 12.82 13.22 13.69 14.08 14.48 15.04 15.64 16.17 16.68 16.67 15.32 14.82
Roseburg_Com 10.69 11.05 11.53 11.97 12.85 14.94 16.31 16.84 16.87 16.60 15.35 14.84
Roseburg_Ind 10.68 11.03 11.52 11.97 12.84 14.93 16.30 16.84 16.86 16.59 15.35 14.84
Roseburg_Res 10.70 11.05 11.54 11.98 12.85 14.94 16.31 16.84 16.87 16.60 15.35 14.84
WA_Com 8.18 8.12 8.68 8.88 8.87 8.81 9.33 9.58 9.87 12.91 14.77 14.84
WA_Ind 8.05 7.99 8.34 8.56 8.58 8.71 9.11 9.42 9.74 12.88 14.76 14.84
WA_Res 8.18 8.13 8.69 8.89 8.88 8.81 9.33 9.58 9.87 12.91 14.77 14.84
WA_Tport 6.99 6.82 7.11 7.39 7.45 7.66 8.10 8.49 8.94 12.23 14.31 14.64
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: ELECTRIFICATION – EXPECTED CONVERSION COST CASE WINTER
AVOIDED COST ($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.54 6.50 5.32 4.49 4.15 3.96 3.67 4.10 4.45 4.70 5.17 5.40
ID_Ind 9.30 6.32 5.19 4.35 4.03 3.86 3.61 4.04 4.40 4.66 5.11 5.34
ID_Res 9.61 6.55 5.37 4.53 4.19 3.99 3.69 4.12 4.47 4.71 5.19 5.42
Klamath Falls_Com 8.80 8.87 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Klamath Falls_Ind 8.80 8.87 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Klamath Falls_Res 8.80 8.87 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
LaGrande_Com 10.62 10.29 11.34 10.88 10.73 10.41 10.48 10.44 10.16 10.97 11.76 12.56
LaGrande_Ind 9.81 9.70 10.89 10.46 10.34 10.22 10.30 10.28 10.16 10.97 11.75 12.55
LaGrande_Res 10.64 10.31 11.35 10.89 10.74 10.42 10.49 10.45 10.16 10.97 11.76 12.56
Medford_Com 8.80 8.87 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Medford_Ind 8.80 8.86 10.34 9.95 9.88 10.02 10.11 10.12 10.16 10.97 11.75 12.56
Medford_Res 8.80 8.87 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
OR_Tport 13.25 10.71 10.20 9.64 9.55 9.75 10.13 10.40 10.68 11.07 11.56 12.34
Roseburg_Com 8.80 8.87 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Roseburg_Ind 8.80 8.86 10.34 9.95 9.88 10.02 10.11 10.12 10.16 10.97 11.75 12.55
Roseburg_Res 8.80 8.87 10.35 9.96 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
WA_Com 11.73 8.77 7.73 7.04 6.89 6.90 6.85 6.86 6.75 6.87 7.34 7.60
WA_Ind 11.51 8.62 7.61 6.92 6.77 6.81 6.79 6.81 6.70 6.83 7.29 7.55
WA_Res 11.76 8.80 7.75 7.06 6.90 6.91 6.86 6.87 6.75 6.87 7.35 7.61
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 5.56 5.79 6.13 6.37 6.63 7.04 7.46 7.76 8.10 8.55 8.82 9.10
ID_Ind 5.51 5.74 6.08 6.33 6.59 7.00 7.43 7.73 8.08 8.53 8.80 9.10
ID_Res 5.58 5.80 6.14 6.39 6.64 7.05 7.47 7.77 8.11 8.55 8.82 9.10
Klamath Falls_Com 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.24
Klamath Falls_Ind 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.33 11.12
Klamath Falls_Res 19.60 24.12 23.90 23.30 22.94 22.84 21.97 20.41 18.78 17.12 15.33 11.28
LaGrande_Com 19.59 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.89
LaGrande_Ind 19.59 24.12 23.89 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.77
LaGrande_Res 19.59 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.89
Medford_Com 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.33 11.16
Medford_Ind 19.59 24.12 23.89 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.88
Medford_Res 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.21
OR_Tport 19.27 23.75 23.55 22.91 22.44 22.35 21.51 20.00 18.42 17.03 15.52 14.84
Roseburg_Com 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.16
Roseburg_Ind 19.59 24.12 23.89 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.82
Roseburg_Res 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.21
WA_Com 7.28 7.08 7.35 7.59 7.63 7.82 8.22 8.57 8.97 9.48 9.81 10.12
WA_Ind 7.23 7.04 7.31 7.55 7.59 7.78 8.19 8.54 8.95 9.46 9.80 10.12
WA_Res 7.29 7.09 7.36 7.59 7.64 7.82 8.23 8.58 8.98 9.48 9.82 10.12
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 9.13 9.49 9.88
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: ELECTRIFICATION – HIGH CONVERSION COST CASE WINTER
AVOIDED COST ($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.54 6.50 5.32 4.49 4.15 3.96 3.67 4.10 4.45 4.70 5.17 5.40
ID_Ind 9.30 6.32 5.19 4.35 4.03 3.86 3.61 4.04 4.40 4.66 5.11 5.34
ID_Res 9.61 6.55 5.37 4.53 4.19 3.99 3.69 4.12 4.47 4.71 5.19 5.42
Klamath Falls_Com 10.96 9.73 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Klamath Falls_Ind 10.96 9.73 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Klamath Falls_Res 10.96 9.73 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
LaGrande_Com 12.78 11.16 11.34 10.88 10.73 10.41 10.48 10.44 10.16 10.97 11.76 12.56
LaGrande_Ind 11.97 10.57 10.89 10.46 10.34 10.22 10.30 10.28 10.16 10.97 11.75 12.55
LaGrande_Res 12.80 11.17 11.35 10.89 10.74 10.42 10.49 10.45 10.16 10.97 11.76 12.56
Medford_Com 10.96 9.73 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Medford_Ind 10.96 9.73 10.34 9.95 9.88 10.02 10.11 10.12 10.16 10.97 11.75 12.56
Medford_Res 10.96 9.73 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
OR_Tport 13.25 10.71 10.20 9.64 9.55 9.75 10.13 10.40 10.68 11.07 11.56 12.34
Roseburg_Com 10.96 9.73 10.35 9.95 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
Roseburg_Ind 10.96 9.73 10.34 9.95 9.88 10.02 10.11 10.12 10.16 10.97 11.75 12.55
Roseburg_Res 10.96 9.73 10.35 9.96 9.88 10.02 10.12 10.12 10.16 10.98 11.76 12.56
WA_Com 11.73 8.77 7.73 7.04 6.89 6.90 6.85 6.86 6.75 6.87 7.34 7.60
WA_Ind 11.51 8.62 7.61 6.92 6.77 6.81 6.79 6.81 6.70 6.83 7.29 7.55
WA_Res 11.76 8.80 7.75 7.06 6.90 6.91 6.86 6.87 6.75 6.87 7.35 7.61
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 5.56 5.79 6.13 6.37 6.63 7.04 7.46 7.76 8.10 8.55 8.82 9.10
ID_Ind 5.51 5.74 6.08 6.33 6.59 7.00 7.43 7.73 8.08 8.53 8.80 9.10
ID_Res 5.58 5.80 6.14 6.39 6.64 7.05 7.47 7.77 8.11 8.55 8.82 9.10
Klamath Falls_Com 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.24
Klamath Falls_Ind 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.33 11.12
Klamath Falls_Res 19.60 24.12 23.90 23.30 22.94 22.84 21.97 20.41 18.78 17.12 15.33 11.28
LaGrande_Com 19.59 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.89
LaGrande_Ind 19.59 24.12 23.89 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.77
LaGrande_Res 19.59 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.89
Medford_Com 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.33 11.16
Medford_Ind 19.59 24.12 23.89 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.88
Medford_Res 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.21
OR_Tport 19.27 23.75 23.55 22.91 22.44 22.35 21.51 20.00 18.42 17.03 15.52 14.84
Roseburg_Com 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.16
Roseburg_Ind 19.59 24.12 23.89 23.30 22.94 22.83 21.97 20.41 18.78 17.11 15.32 10.82
Roseburg_Res 19.60 24.12 23.90 23.30 22.94 22.83 21.97 20.41 18.78 17.12 15.33 11.21
WA_Com 7.28 7.08 7.35 7.59 7.63 7.82 8.22 8.57 8.97 9.48 9.81 10.12
WA_Ind 7.23 7.04 7.31 7.55 7.59 7.78 8.19 8.54 8.95 9.46 9.80 10.12
WA_Res 7.29 7.09 7.36 7.59 7.64 7.82 8.23 8.58 8.98 9.48 9.82 10.12
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 9.13 9.49 9.88
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: ELECTRIFICATION – LOW CONVERSION COST CASE WINTER
AVOIDED COST ($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.55 6.51 5.33 4.49 4.15 3.96 3.67 4.09 4.45 4.70 5.18 5.41
ID_Ind 9.30 6.33 5.19 4.36 4.02 3.86 3.60 4.03 4.40 4.66 5.11 5.35
ID_Res 9.62 6.56 5.37 4.54 4.19 4.00 3.69 4.11 4.47 4.71 5.20 5.43
Klamath Falls_Com 7.84 5.22 5.09 5.26 5.52 5.99 6.75 7.81 8.95 10.66 11.76 12.10
Klamath Falls_Ind 7.84 5.22 5.09 5.26 5.52 5.99 6.74 7.80 8.95 10.65 11.76 12.10
Klamath Falls_Res 7.84 5.22 5.09 5.26 5.52 5.99 6.75 7.81 8.95 10.66 11.76 12.10
LaGrande_Com 9.68 6.73 6.14 6.25 6.45 6.79 7.17 8.17 9.25 10.86 12.06 12.38
LaGrande_Ind 8.86 6.11 5.66 5.80 6.03 6.43 6.95 7.98 9.09 10.76 11.90 12.23
LaGrande_Res 9.70 6.74 6.15 6.26 6.46 6.79 7.17 8.17 9.25 10.86 12.07 12.39
Medford_Com 7.84 5.22 5.09 5.26 5.52 5.99 6.74 7.80 8.95 10.66 11.76 12.10
Medford_Ind 7.84 5.22 5.09 5.25 5.52 5.98 6.74 7.80 8.94 10.65 11.75 12.10
Medford_Res 7.84 5.22 5.09 5.26 5.52 5.99 6.74 7.80 8.95 10.66 11.76 12.10
OR_Tport 7.48 4.83 7.82 9.64 5.60 7.07 9.99 10.26 10.54 10.93 11.41 11.74
Roseburg_Com 7.84 5.22 5.09 5.26 5.52 5.99 6.74 7.80 8.95 10.66 11.76 12.10
Roseburg_Ind 7.84 5.22 5.09 5.25 5.52 5.98 6.74 7.80 8.94 10.65 11.75 12.10
Roseburg_Res 7.84 5.22 5.09 5.26 5.52 5.99 6.75 7.81 8.95 10.66 11.76 12.10
WA_Com 11.74 8.78 7.74 7.05 6.88 6.90 6.84 6.86 6.75 6.87 7.35 7.62
WA_Ind 11.52 8.62 7.61 6.93 6.77 6.81 6.78 6.81 6.70 6.83 7.29 7.56
WA_Res 11.77 8.81 7.76 7.07 6.90 6.92 6.85 6.87 6.75 6.88 7.36 7.62
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 5.57 5.78 6.13 6.37 6.63 7.04 7.46 7.76 8.11 8.55 8.83 9.10
ID_Ind 5.51 5.74 6.08 6.33 6.59 7.00 7.43 7.73 8.08 8.54 8.81 9.10
ID_Res 5.59 5.80 6.14 6.39 6.65 7.05 7.48 7.77 8.11 8.56 8.84 9.10
Klamath Falls_Com 12.37 12.74 17.95 21.35 21.37 20.11 19.05 18.63 18.26 17.16 15.40 14.24
Klamath Falls_Ind 12.37 12.73 17.95 21.34 21.37 20.11 19.05 18.63 18.26 17.16 15.40 14.21
Klamath Falls_Res 12.37 12.74 17.95 21.35 21.37 20.11 19.05 18.63 18.26 17.16 15.40 14.25
LaGrande_Com 12.63 12.74 17.95 21.35 21.37 20.10 19.05 18.63 18.26 17.16 15.40 14.19
LaGrande_Ind 12.49 12.73 17.95 21.34 21.36 20.10 19.05 18.62 18.26 17.16 15.40 14.13
LaGrande_Res 12.63 12.74 17.95 21.35 21.37 20.10 19.05 18.63 18.26 17.16 15.40 14.19
Medford_Com 12.37 12.74 17.95 21.35 21.37 20.11 19.05 18.63 18.26 17.05 15.25 10.26
Medford_Ind 12.36 12.73 17.95 21.34 21.36 20.10 19.05 18.62 18.26 17.04 15.23 9.94
Medford_Res 12.37 12.74 17.95 21.35 21.37 20.11 19.05 18.63 18.26 17.05 15.25 10.32
OR_Tport 12.06 12.55 17.69 21.05 21.09 19.77 18.62 18.19 17.85 16.98 15.35 14.84
Roseburg_Com 12.37 12.74 17.95 21.35 21.37 20.11 19.05 18.63 18.26 17.05 15.25 10.26
Roseburg_Ind 12.36 12.73 17.95 21.34 21.36 20.10 19.05 18.62 18.26 17.03 15.23 9.87
Roseburg_Res 12.37 12.74 17.95 21.35 21.37 20.11 19.05 18.63 18.26 17.05 15.25 10.32
WA_Com 7.29 7.08 7.35 7.59 7.63 7.82 8.23 8.57 8.98 9.49 9.83 10.12
WA_Ind 7.24 7.04 7.31 7.55 7.60 7.78 8.20 8.55 8.95 9.47 9.81 10.12
WA_Res 7.30 7.09 7.36 7.60 7.64 7.82 8.23 8.58 8.98 9.49 9.83 10.12
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 9.13 9.49 9.88
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: HIGH CUSTOMER GROWTH CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.58 6.54 5.36 4.55 4.24 4.43 4.19 4.61 5.00 5.40 6.14 6.29
ID_Ind 9.33 6.36 5.22 4.41 4.11 4.29 4.08 4.51 4.92 5.31 5.99 6.15
ID_Res 9.65 6.60 5.41 4.59 4.28 4.48 4.22 4.64 5.03 5.43 6.19 6.34
Klamath Falls_Com 10.01 9.35 10.35 9.96 9.91 10.06 10.67 11.36 11.95 12.39 13.29 14.32
Klamath Falls_Ind 10.01 9.35 10.35 9.96 9.90 10.06 10.67 11.35 11.95 12.39 13.28 14.31
Klamath Falls_Res 10.01 9.35 10.35 9.96 9.91 10.06 10.68 11.36 11.95 12.39 13.29 14.32
LaGrande_Com 11.88 10.78 11.33 10.88 10.76 10.78 11.03 11.35 11.94 12.38 13.28 14.31
LaGrande_Ind 11.04 10.19 10.89 10.46 10.36 10.46 10.85 11.35 11.94 12.38 13.28 14.30
LaGrande_Res 11.90 10.80 11.35 10.89 10.77 10.79 11.04 11.35 11.94 12.38 13.28 14.31
Medford_Com 10.01 9.35 10.35 9.96 9.91 10.06 10.67 11.35 11.95 12.39 13.29 14.31
Medford_Ind 10.01 9.35 10.34 9.95 9.90 10.06 10.67 11.35 11.94 12.38 13.28 14.31
Medford_Res 10.01 9.35 10.35 9.96 9.91 10.06 10.67 11.36 11.95 12.39 13.29 14.32
OR_Tport 7.48 8.40 10.20 9.64 9.57 9.72 10.31 11.05 11.63 12.11 12.90 13.82
Roseburg_Com 10.01 9.35 10.35 9.96 9.91 10.06 10.67 11.36 11.95 12.39 13.29 14.31
Roseburg_Ind 10.01 9.35 10.34 9.95 9.90 10.06 10.67 11.35 11.94 12.38 13.28 14.31
Roseburg_Res 10.01 9.35 10.35 9.96 9.91 10.06 10.68 11.36 11.95 12.39 13.29 14.32
WA_Com 11.77 8.87 7.82 7.15 7.03 7.43 7.41 7.43 7.36 7.62 8.74 8.89
WA_Ind 11.55 8.66 7.65 6.98 6.86 7.25 7.27 7.29 7.23 7.50 8.19 8.38
WA_Res 11.80 8.88 7.83 7.16 7.03 7.44 7.42 7.44 7.36 7.63 8.75 8.90
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 6.52 6.64 7.09 7.25 7.48 7.78 8.22 8.40 8.65 8.90 9.05 9.20
ID_Ind 6.39 6.54 6.98 7.15 7.38 7.72 8.15 8.34 8.60 8.89 9.05 9.20
ID_Res 6.57 6.67 7.13 7.29 7.51 7.80 8.24 8.42 8.66 8.90 9.05 9.20
Klamath Falls_Com 21.08 25.39 25.89 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Klamath Falls_Ind 21.07 25.39 25.88 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Klamath Falls_Res 21.08 25.39 25.89 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
LaGrande_Com 21.07 25.38 25.88 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
LaGrande_Ind 21.06 25.38 25.88 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
LaGrande_Res 21.07 25.38 25.88 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Medford_Com 21.07 25.39 25.89 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Medford_Ind 21.07 25.38 25.88 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Medford_Res 21.08 25.39 25.89 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
OR_Tport 20.44 24.75 25.22 25.41 12.64 15.13 21.54 19.93 18.31 16.95 15.35 14.84
Roseburg_Com 21.07 25.39 25.89 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Roseburg_Ind 21.06 25.38 25.88 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Roseburg_Res 21.08 25.39 25.89 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
WA_Com 8.61 7.99 8.59 8.73 8.71 8.60 9.16 9.36 9.65 12.64 14.66 14.80
WA_Ind 8.14 7.86 8.22 8.39 8.40 8.51 8.92 9.17 9.49 12.61 14.64 14.79
WA_Res 8.62 7.99 8.60 8.74 8.72 8.61 9.16 9.37 9.65 12.64 14.66 14.80
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 11.91 14.08 14.45
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: HYBRID CASE WINTER AVOIDED COST ($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.58 6.53 5.35 4.53 4.21 4.39 4.11 4.52 4.85 5.27 5.64 5.83
ID_Ind 9.33 6.35 5.21 4.39 4.08 4.24 4.00 4.43 4.77 5.18 5.54 5.74
ID_Res 9.65 6.59 5.40 4.57 4.25 4.43 4.14 4.55 4.88 5.30 5.67 5.86
Klamath Falls_Com 10.02 9.36 10.35 9.96 9.88 10.04 10.36 10.65 10.92 11.94 12.66 13.44
Klamath Falls_Ind 10.02 9.36 10.35 9.95 9.88 10.04 10.36 10.64 10.91 11.93 12.65 13.43
Klamath Falls_Res 10.02 9.36 10.35 9.96 9.88 10.04 10.36 10.65 10.92 11.95 12.66 13.44
LaGrande_Com 11.89 10.79 11.40 10.94 10.79 11.13 10.75 10.98 11.19 11.93 12.65 13.43
LaGrande_Ind 11.06 10.20 10.89 10.46 10.34 10.64 10.54 10.79 11.04 11.92 12.64 13.42
LaGrande_Res 11.91 10.80 11.40 10.95 10.80 11.14 10.75 10.98 11.20 11.93 12.65 13.43
Medford_Com 10.02 9.36 10.35 9.96 9.88 10.04 10.36 10.65 10.92 11.95 12.65 13.44
Medford_Ind 10.02 9.35 10.34 9.95 9.88 10.04 10.35 10.64 10.91 11.93 12.64 13.42
Medford_Res 10.02 9.36 10.35 9.96 9.88 10.04 10.36 10.65 10.92 11.95 12.65 13.44
OR_Tport 13.25 10.71 10.20 9.64 9.55 9.75 10.13 10.40 10.68 11.63 12.41 13.15
Roseburg_Com 10.02 9.36 10.35 9.97 9.90 10.06 10.38 10.67 10.94 11.98 12.67 13.46
Roseburg_Ind 10.02 9.35 10.34 9.95 9.88 10.04 10.35 10.64 10.91 11.92 12.64 13.42
Roseburg_Res 10.02 9.36 10.35 9.97 9.90 10.06 10.38 10.67 10.94 11.98 12.67 13.46
WA_Com 11.77 8.86 7.81 7.13 7.00 7.39 7.34 7.35 7.20 7.50 7.88 8.10
WA_Ind 11.55 8.65 7.64 6.96 6.83 7.21 7.19 7.21 7.07 7.37 7.73 7.96
WA_Res 11.80 8.84 7.82 7.14 7.01 7.40 7.35 7.36 7.21 7.50 7.88 8.10
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 6.03 6.46 6.62 6.84 7.09 7.64 8.05 8.29 8.58 8.90 9.19 9.27
ID_Ind 5.94 6.36 6.54 6.76 7.02 7.56 7.97 8.22 8.52 8.86 9.16 9.27
ID_Res 6.06 6.50 6.64 6.86 7.11 7.66 8.08 8.32 8.60 8.91 9.20 9.27
Klamath Falls_Com 19.85 23.93 23.92 23.75 23.61 23.27 22.05 20.44 18.80 17.15 15.41 14.84
Klamath Falls_Ind 19.83 23.91 23.91 23.74 23.59 23.25 22.04 20.43 18.79 17.15 15.40 14.84
Klamath Falls_Res 19.85 23.93 23.92 23.75 23.61 23.27 22.05 20.44 18.80 17.15 15.41 14.84
LaGrande_Com 19.84 23.92 23.91 23.74 23.60 23.26 22.05 20.44 18.80 17.16 15.41 14.84
LaGrande_Ind 19.82 23.90 23.90 23.73 23.59 23.24 22.04 20.43 18.79 17.15 15.40 14.84
LaGrande_Res 19.84 23.92 23.91 23.74 23.60 23.26 22.05 20.44 18.80 17.16 15.41 14.84
Medford_Com 19.86 23.92 23.92 23.74 23.60 23.27 22.04 20.43 18.79 17.15 15.40 14.74
Medford_Ind 19.83 23.90 23.90 23.73 23.59 23.24 22.04 20.43 18.79 17.15 15.40 14.61
Medford_Res 19.86 23.92 23.92 23.75 23.60 23.27 22.04 20.43 18.79 17.15 15.40 14.74
OR_Tport 19.45 23.51 23.45 23.16 23.02 22.65 21.53 19.92 18.30 16.95 15.36 14.84
Roseburg_Com 19.87 23.93 23.93 23.76 23.61 23.27 22.04 20.43 18.79 17.15 15.40 14.74
Roseburg_Ind 19.82 23.90 23.90 23.73 23.59 23.24 22.04 20.43 18.79 17.15 15.40 14.61
Roseburg_Res 19.87 23.93 23.93 23.76 23.61 23.27 22.04 20.43 18.79 17.15 15.40 14.74
WA_Com 7.81 7.83 7.90 8.12 8.15 8.48 9.03 9.30 9.63 9.86 10.30 10.29
WA_Ind 7.68 7.68 7.77 7.99 8.03 8.36 8.75 9.05 9.40 9.80 10.16 10.29
WA_Res 7.82 7.83 7.90 8.12 8.15 8.49 9.04 9.30 9.64 9.87 10.30 10.29
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 9.13 9.49 9.88
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: INTERRUPTED SUPPLY CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.57 6.55 5.35 4.57 4.25 4.46 4.19 4.62 5.03 5.37 6.14 6.31
ID_Ind 9.33 6.37 5.21 4.43 4.12 4.32 4.08 4.52 4.95 5.29 5.99 6.17
ID_Res 9.65 6.61 5.40 4.61 4.29 4.51 4.22 4.65 5.06 5.40 6.19 6.36
Klamath Falls_Com 7.84 8.51 10.34 9.96 9.90 10.07 14.69 18.08 18.75 19.34 20.21 21.09
Klamath Falls_Ind 7.84 8.51 10.34 9.95 9.90 10.07 14.69 18.08 18.75 19.33 20.20 21.09
Klamath Falls_Res 7.84 8.51 10.34 9.96 9.90 10.07 14.69 18.09 18.75 19.34 20.21 21.10
LaGrande_Com 9.71 9.93 11.33 10.88 10.75 11.10 14.95 18.08 18.74 19.33 20.20 21.09
LaGrande_Ind 8.87 9.34 10.89 10.46 10.36 10.67 14.81 18.08 18.74 19.33 20.20 21.09
LaGrande_Res 9.73 9.95 11.34 10.89 10.76 11.12 14.96 18.08 18.74 19.33 20.20 21.09
Medford_Com 7.84 8.51 10.34 9.96 9.90 10.07 14.69 18.08 18.75 19.34 20.20 21.09
Medford_Ind 7.84 8.50 10.34 9.95 9.90 10.06 14.68 18.08 18.74 19.33 20.20 21.09
Medford_Res 7.84 8.51 10.34 9.96 9.90 10.07 14.69 18.08 18.75 19.34 20.21 21.09
OR_Tport 13.25 10.71 10.20 9.64 9.55 9.75 14.33 17.67 18.31 18.93 19.71 20.49
Roseburg_Com 7.84 8.51 10.34 9.96 9.90 10.07 14.69 18.08 18.75 19.34 20.21 21.09
Roseburg_Ind 7.84 8.50 10.34 9.95 9.90 10.06 14.68 18.08 18.74 19.33 20.20 21.09
Roseburg_Res 7.84 8.51 10.34 9.96 9.90 10.07 14.69 18.09 18.75 19.34 20.21 21.10
WA_Com 11.76 8.88 7.81 7.17 7.04 7.47 7.42 7.45 7.39 7.59 8.74 8.92
WA_Ind 11.54 8.67 7.64 7.00 6.87 7.28 7.27 7.31 7.25 7.47 8.19 8.40
WA_Res 11.80 8.90 7.82 7.18 7.05 7.48 7.43 7.45 7.39 7.60 8.75 8.93
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 6.50 6.63 7.04 7.18 7.42 7.72 8.16 8.35 8.64 8.87 9.12 9.32
ID_Ind 6.37 6.53 6.92 7.08 7.32 7.66 8.08 8.29 8.59 8.86 9.11 9.32
ID_Res 6.55 6.66 7.08 7.22 7.45 7.75 8.18 8.37 8.66 8.88 9.12 9.32
Klamath Falls_Com 23.66 25.39 25.93 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Klamath Falls_Ind 23.66 25.39 25.92 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Klamath Falls_Res 23.66 25.39 25.93 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
LaGrande_Com 23.66 25.38 25.92 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
LaGrande_Ind 23.65 25.38 25.92 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
LaGrande_Res 23.66 25.39 25.92 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Medford_Com 23.66 25.39 25.93 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Medford_Ind 23.65 25.39 25.92 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Medford_Res 23.66 25.39 25.93 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
OR_Tport 22.99 24.71 25.23 25.41 24.52 23.05 21.54 19.93 18.31 16.95 15.35 14.84
Roseburg_Com 23.66 25.39 25.93 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Roseburg_Ind 23.65 25.38 25.92 26.06 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
Roseburg_Res 23.66 25.39 25.93 26.07 25.14 23.63 22.08 20.47 18.82 17.23 15.54 14.84
WA_Com 8.60 7.99 8.54 8.66 8.66 8.55 9.10 9.31 9.65 12.37 14.37 14.55
WA_Ind 8.12 7.85 8.17 8.32 8.34 8.45 8.86 9.11 9.48 12.34 14.34 14.55
WA_Res 8.61 7.99 8.55 8.67 8.66 8.56 9.11 9.32 9.65 12.38 14.37 14.55
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 11.68 13.71 14.09
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: LIMITED RNG AVAILABILITY CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.58 6.53 5.35 4.54 4.21 4.41 4.19 4.67 4.97 5.35 5.70 5.91
ID_Ind 9.33 6.35 5.21 4.41 4.09 4.27 4.08 4.57 4.89 5.27 5.61 5.82
ID_Res 9.66 6.59 5.40 4.59 4.25 4.46 4.22 4.70 5.00 5.38 5.73 5.93
Klamath Falls_Com 7.84 7.61 9.29 9.60 9.85 10.33 23.41 32.09 30.50 27.37 30.22 32.33
Klamath Falls_Ind 7.84 7.61 9.29 9.59 9.85 10.33 23.41 32.09 30.50 27.37 30.22 32.33
Klamath Falls_Res 7.84 7.61 9.29 9.60 9.85 10.33 23.41 32.09 30.51 27.37 30.22 32.33
LaGrande_Com 9.71 9.10 10.30 10.53 10.73 11.37 23.53 32.13 30.52 27.37 30.22 32.33
LaGrande_Ind 8.88 8.49 9.84 10.10 10.33 10.94 23.48 32.12 30.51 27.37 30.22 32.33
LaGrande_Res 9.74 9.11 10.31 10.54 10.74 11.38 23.53 32.13 30.52 27.37 30.22 32.33
Medford_Com 7.84 7.61 9.29 9.60 9.85 10.33 23.41 32.09 30.50 27.37 30.22 32.33
Medford_Ind 7.84 7.61 9.28 9.59 9.84 10.32 23.41 32.09 30.50 27.37 30.22 32.33
Medford_Res 7.84 7.61 9.29 9.60 9.85 10.33 23.41 32.09 30.50 27.37 30.22 32.33
OR_Tport 7.48 8.40 10.20 9.64 9.55 9.95 22.85 31.48 29.96 26.91 30.04 32.21
Roseburg_Com 7.84 7.62 9.29 9.60 9.85 10.33 23.41 32.09 30.50 27.37 30.22 32.33
Roseburg_Ind 7.84 7.61 9.28 9.59 9.84 10.32 23.40 32.09 30.50 27.37 30.22 32.33
Roseburg_Res 7.84 7.62 9.29 9.60 9.85 10.33 23.41 32.09 30.51 27.37 30.22 32.33
WA_Com 11.77 8.86 7.81 7.14 7.00 7.41 7.42 7.50 7.33 7.57 7.93 8.16
WA_Ind 11.55 8.65 7.64 6.98 6.84 7.23 7.27 7.36 7.20 7.45 7.80 8.04
WA_Res 11.81 8.88 7.82 7.15 7.01 7.42 7.42 7.50 7.33 7.58 7.94 8.17
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 6.14 6.53 6.67 7.08 7.32 7.63 8.09 8.29 8.56 8.85 9.09 9.32
ID_Ind 6.06 6.43 6.59 6.98 7.23 7.56 8.02 8.24 8.52 8.83 9.08 9.32
ID_Res 6.17 6.56 6.69 7.11 7.35 7.65 8.12 8.32 8.57 8.86 9.09 9.32
Klamath Falls_Com 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Klamath Falls_Ind 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Klamath Falls_Res 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
LaGrande_Com 30.96 29.54 28.15 26.69 25.21 23.68 22.18 20.58 18.94 17.26 15.54 14.84
LaGrande_Ind 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
LaGrande_Res 30.96 29.54 28.15 26.69 25.21 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Medford_Com 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Medford_Ind 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Medford_Res 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
OR_Tport 30.82 29.40 28.02 26.55 25.04 23.52 22.06 20.45 18.94 17.26 15.54 14.84
Roseburg_Com 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Roseburg_Ind 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
Roseburg_Res 30.96 29.54 28.15 26.68 25.20 23.68 22.18 20.58 18.94 17.26 15.54 14.84
WA_Com 7.92 7.88 7.94 8.55 8.55 8.46 9.03 9.26 9.56 12.36 14.34 14.55
WA_Ind 7.79 7.75 7.83 8.21 8.25 8.36 8.80 9.07 9.40 12.32 14.30 14.55
WA_Res 7.92 7.89 7.94 8.56 8.56 8.46 9.04 9.27 9.56 12.36 14.34 14.55
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 11.67 13.71 14.09
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: PRS CASE WINTER AVOIDED COST ($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.58 6.53 5.35 4.54 4.21 4.40 4.14 4.62 4.94 5.32 5.70 5.88
ID_Ind 9.33 6.35 5.21 4.41 4.09 4.25 4.03 4.53 4.85 5.23 5.60 5.79
ID_Res 9.65 6.59 5.40 4.58 4.25 4.44 4.18 4.65 4.96 5.34 5.73 5.91
Klamath Falls_Com 10.01 9.35 10.35 9.96 9.88 10.05 12.58 14.58 15.17 15.75 16.69 21.40
Klamath Falls_Ind 10.01 9.35 10.35 9.95 9.88 10.04 12.58 14.58 15.17 15.75 16.69 21.39
Klamath Falls_Res 10.01 9.35 10.35 9.96 9.88 10.05 12.58 14.58 15.17 15.75 16.69 21.40
LaGrande_Com 11.88 10.78 11.33 10.88 10.73 11.08 12.89 14.57 15.16 15.74 16.68 21.39
LaGrande_Ind 11.04 10.19 10.89 10.46 10.34 10.64 12.73 14.57 15.16 15.74 16.68 21.38
LaGrande_Res 11.90 10.79 11.35 10.89 10.74 11.09 12.90 14.57 15.16 15.74 16.68 21.39
Medford_Com 10.01 9.35 10.35 9.95 9.88 10.05 12.58 14.58 15.17 15.75 16.69 21.39
Medford_Ind 10.01 9.35 10.34 9.95 9.88 10.04 12.58 14.57 15.16 15.74 16.68 21.39
Medford_Res 10.01 9.35 10.35 9.96 9.88 10.05 12.58 14.58 15.17 15.75 16.69 21.40
OR_Tport 7.48 8.40 10.20 9.64 9.55 9.70 12.20 14.19 14.80 15.41 16.26 20.80
Roseburg_Com 10.01 9.35 10.35 9.96 9.88 10.05 12.58 14.58 15.17 15.75 16.69 21.39
Roseburg_Ind 10.01 9.35 10.34 9.95 9.88 10.04 12.57 14.57 15.16 15.74 16.68 21.38
Roseburg_Res 10.01 9.35 10.35 9.96 9.88 10.05 12.58 14.58 15.17 15.75 16.69 21.40
WA_Com 11.77 8.86 7.81 7.14 7.00 7.39 7.37 7.45 7.29 7.53 7.92 8.14
WA_Ind 11.55 8.65 7.63 6.97 6.84 7.21 7.23 7.31 7.16 7.41 7.79 8.01
WA_Res 11.80 8.87 7.82 7.15 7.01 7.40 7.38 7.46 7.29 7.54 7.93 8.15
WA_Tport 7.48 6.21 6.50 5.87 5.76 5.90 6.21 6.24 6.16 6.35 6.73 7.01
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 6.14 6.53 6.72 7.12 7.34 7.65 8.12 8.31 8.57 8.87 9.09 9.32
ID_Ind 6.05 6.44 6.65 7.02 7.25 7.58 8.05 8.25 8.53 8.85 9.08 9.32
ID_Res 6.16 6.56 6.74 7.15 7.37 7.67 8.14 8.33 8.59 8.87 9.09 9.32
Klamath Falls_Com 24.87 25.41 25.82 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Klamath Falls_Ind 24.86 25.41 25.81 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Klamath Falls_Res 24.87 25.41 25.82 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
LaGrande_Com 24.86 25.40 25.81 26.01 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
LaGrande_Ind 24.85 25.40 25.81 26.01 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
LaGrande_Res 24.86 25.40 25.81 26.01 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Medford_Com 24.86 25.41 25.81 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Medford_Ind 24.86 25.40 25.81 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Medford_Res 24.87 25.41 25.82 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
OR_Tport 24.20 24.78 25.16 25.37 24.52 23.05 21.54 19.93 18.36 16.98 15.35 14.84
Roseburg_Com 24.86 25.41 25.82 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Roseburg_Ind 24.86 25.40 25.81 26.01 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
Roseburg_Res 24.87 25.41 25.82 26.02 25.14 23.63 22.08 20.46 18.84 17.23 15.54 14.84
WA_Com 7.91 7.89 7.99 8.59 8.57 8.47 9.05 9.27 9.57 12.36 14.34 14.55
WA_Ind 7.79 7.75 7.88 8.25 8.27 8.38 8.83 9.08 9.41 12.33 14.30 14.55
WA_Res 7.92 7.89 8.00 8.60 8.58 8.48 9.06 9.27 9.57 12.37 14.34 14.55
WA_Tport 6.70 6.55 6.83 7.09 7.15 7.36 7.79 8.16 8.59 11.67 13.71 14.09
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: PRS – ALLOWANCE PRICE CEILING CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.27 6.28 5.17 4.37 4.06 4.19 4.01 4.46 4.80 5.11 5.55 5.73
ID_Ind 9.06 6.13 5.05 4.26 3.96 4.08 3.93 4.39 4.74 5.06 5.48 5.67
ID_Res 9.33 6.32 5.20 4.40 4.10 4.23 4.04 4.49 4.82 5.13 5.58 5.75
Klamath Falls_Com 7.84 8.48 10.35 9.96 9.90 10.05 10.66 11.40 11.93 12.48 13.42 14.44
Klamath Falls_Ind 7.84 8.48 10.35 9.96 9.90 10.05 10.66 11.39 11.93 12.48 13.42 14.43
Klamath Falls_Res 7.84 8.48 10.35 9.96 9.90 10.05 10.66 11.40 11.93 12.48 13.42 14.44
LaGrande_Com 9.40 9.75 11.22 10.77 10.65 10.95 10.97 11.39 11.92 12.47 13.41 14.43
LaGrande_Ind 8.70 9.23 10.83 10.40 10.30 10.57 10.81 11.39 11.92 12.47 13.41 14.42
LaGrande_Res 9.41 9.76 11.23 10.78 10.66 10.96 10.98 11.39 11.92 12.47 13.41 14.43
Medford_Com 7.84 8.48 10.35 9.96 9.90 10.05 10.66 11.40 11.93 12.48 13.42 14.43
Medford_Ind 7.84 8.48 10.34 9.95 9.90 10.05 10.65 11.39 11.92 12.47 13.41 14.43
Medford_Res 7.84 8.48 10.35 9.96 9.90 10.05 10.66 11.40 11.93 12.48 13.42 14.44
OR_Tport 7.48 8.40 10.20 9.64 9.55 9.70 10.28 11.03 11.60 12.18 13.03 13.95
Roseburg_Com 7.84 8.48 10.35 9.96 9.90 10.05 10.66 11.40 11.93 12.48 13.42 14.44
Roseburg_Ind 7.84 8.48 10.34 9.95 9.90 10.05 10.65 11.39 11.92 12.47 13.41 14.43
Roseburg_Res 7.84 8.49 10.35 9.96 9.90 10.05 10.66 11.40 11.93 12.48 13.42 14.44
WA_Com 13.63 10.88 10.11 9.67 9.74 10.28 10.53 11.06 11.53 12.21 13.09 13.73
WA_Ind 13.44 10.71 9.97 9.53 9.61 10.14 10.41 10.95 11.43 12.13 12.99 13.63
WA_Res 13.66 10.89 10.12 9.67 9.75 10.29 10.54 11.06 11.54 12.22 13.10 13.73
WA_Tport 7.48 7.63 9.00 8.58 8.67 9.01 9.51 10.01 10.56 11.24 12.05 12.76
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 5.99 6.34 6.59 6.89 7.10 7.42 7.77 7.68 7.93 8.42 8.72 9.10
ID_Ind 5.93 6.28 6.55 6.84 7.05 7.40 7.76 7.68 7.93 8.42 8.72 9.10
ID_Res 6.01 6.36 6.60 6.91 7.11 7.43 7.77 7.68 7.93 8.42 8.72 9.10
Klamath Falls_Com 21.12 25.52 25.98 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Klamath Falls_Ind 21.12 25.52 25.97 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Klamath Falls_Res 21.12 25.52 25.98 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
LaGrande_Com 21.11 25.51 25.97 26.08 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
LaGrande_Ind 21.11 25.51 25.97 26.08 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
LaGrande_Res 21.11 25.51 25.97 26.08 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Medford_Com 21.12 25.52 25.97 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Medford_Ind 21.11 25.51 25.97 26.08 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Medford_Res 21.12 25.52 25.98 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
OR_Tport 20.49 24.85 25.29 25.44 21.09 20.76 21.56 20.02 18.46 17.06 15.52 14.84
Roseburg_Com 21.12 25.52 25.97 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Roseburg_Ind 21.11 25.51 25.97 26.08 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
Roseburg_Res 21.12 25.52 25.98 26.09 25.14 23.63 22.09 20.49 18.85 17.24 15.54 14.84
WA_Com 14.48 15.37 16.20 17.25 18.10 19.08 20.25 20.17 18.94 17.26 15.54 14.84
WA_Ind 14.38 15.28 16.12 17.05 17.95 19.03 20.19 20.17 18.94 17.26 15.54 14.84
WA_Res 14.49 15.38 16.20 17.25 18.11 19.08 20.25 20.17 18.94 17.26 15.54 14.84
WA_Tport 13.43 14.24 15.17 16.07 17.03 18.20 19.46 19.96 18.94 17.26 15.54 14.84
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: PRS – HIGH PRICES CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 10.52 7.89 6.99 6.36 6.01 6.36 6.20 6.57 7.08 7.68 8.18 8.67
ID_Ind 10.28 7.71 6.85 6.23 5.89 6.22 6.10 6.48 7.00 7.60 8.09 8.59
ID_Res 10.60 7.94 7.03 6.40 6.05 6.40 6.23 6.60 7.11 7.70 8.21 8.70
Klamath Falls_Com 9.97 8.65 9.58 10.00 10.52 11.03 11.66 12.31 13.15 13.79 14.67 15.83
Klamath Falls_Ind 9.97 8.65 9.58 10.00 10.52 11.02 11.66 12.30 13.15 13.79 14.66 15.83
Klamath Falls_Res 9.97 8.65 9.58 10.00 10.52 11.03 11.66 12.31 13.15 13.79 14.67 15.84
LaGrande_Com 11.80 10.12 10.58 10.50 10.97 11.02 11.66 12.30 13.14 13.78 14.66 15.83
LaGrande_Ind 10.98 9.51 10.13 10.24 10.74 11.02 11.65 12.30 13.14 13.78 14.66 15.82
LaGrande_Res 11.82 10.14 10.59 10.50 10.98 11.02 11.66 12.30 13.14 13.78 14.66 15.83
Medford_Com 9.97 8.65 9.58 10.00 10.52 11.03 11.66 12.31 13.15 13.79 14.67 15.83
Medford_Ind 9.97 8.65 9.58 10.00 10.52 11.02 11.65 12.30 13.14 13.78 14.66 15.83
Medford_Res 9.97 8.65 9.58 10.00 10.52 11.03 11.66 12.31 13.15 13.79 14.67 15.83
OR_Tport 8.44 6.21 5.76 5.17 8.82 11.59 12.02 12.21 12.79 13.43 14.22 15.27
Roseburg_Com 9.97 8.65 9.58 10.00 10.52 11.03 11.66 12.31 13.15 13.79 14.67 15.83
Roseburg_Ind 9.97 8.65 9.58 9.99 10.51 11.02 11.65 12.30 13.14 13.78 14.66 15.82
Roseburg_Res 9.97 8.65 9.58 10.00 10.52 11.03 11.66 12.31 13.15 13.79 14.67 15.84
WA_Com 12.71 10.22 9.44 8.96 8.79 9.35 9.43 9.39 9.42 9.89 10.41 10.92
WA_Ind 12.49 10.01 9.27 8.80 8.64 9.18 9.29 9.26 9.31 9.78 10.28 10.80
WA_Res 12.74 10.23 9.45 8.97 8.80 9.36 9.43 9.40 9.43 9.89 10.42 10.93
WA_Tport 8.44 7.60 8.14 7.69 7.57 7.78 8.23 8.18 8.37 8.70 9.20 9.73
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 8.75 9.45 9.92 10.35 10.92 11.23 11.96 12.33 12.69 13.40 13.20 13.88
ID_Ind 8.67 9.36 9.86 10.26 10.85 11.18 11.90 12.28 12.65 13.39 13.20 13.88
ID_Res 8.77 9.47 9.94 10.38 10.95 11.25 11.98 12.34 12.70 13.40 13.21 13.88
Klamath Falls_Com 21.63 25.44 25.61 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Klamath Falls_Ind 21.62 25.44 25.60 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Klamath Falls_Res 21.63 25.44 25.61 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
LaGrande_Com 21.61 25.43 25.60 25.63 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
LaGrande_Ind 21.61 25.43 25.60 25.63 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
LaGrande_Res 21.62 25.43 25.60 25.63 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Medford_Com 21.62 25.44 25.60 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Medford_Ind 21.62 25.44 25.60 25.63 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Medford_Res 21.63 25.44 25.61 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
OR_Tport 10.01 6.66 7.06 7.21 17.45 23.08 21.65 20.03 18.46 17.06 15.08 14.84
Roseburg_Com 21.62 25.44 25.61 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Roseburg_Ind 21.61 25.43 25.60 25.63 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
Roseburg_Res 21.63 25.44 25.61 25.64 25.17 23.65 22.13 20.56 18.84 17.26 15.54 14.84
WA_Com 10.51 10.79 11.19 11.79 12.11 12.05 12.86 13.24 13.65 14.49 14.33 14.83
WA_Ind 10.40 10.67 11.09 11.49 11.86 11.97 12.68 13.11 13.53 14.47 14.30 14.83
WA_Res 10.52 10.80 11.19 11.80 12.12 12.05 12.86 13.25 13.66 14.49 14.33 14.83
WA_Tport 9.37 9.48 9.98 10.31 10.83 11.03 11.72 12.24 12.75 13.87 13.71 14.50
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: PRS – LOW PRICES CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 9.21 6.05 4.82 3.99 3.59 3.72 3.40 3.85 4.06 4.32 4.65 4.73
ID_Ind 8.96 5.87 4.68 3.85 3.46 3.57 3.29 3.75 3.98 4.22 4.55 4.63
ID_Res 9.28 6.11 4.87 4.03 3.64 3.77 3.43 3.88 4.09 4.34 4.69 4.76
Klamath Falls_Com 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.81 12.42 12.79 13.62 14.53
Klamath Falls_Ind 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.80 12.42 12.79 13.62 14.52
Klamath Falls_Res 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.81 12.42 12.80 13.63 14.53
LaGrande_Com 11.51 10.32 10.85 10.37 10.56 11.41 11.49 11.80 12.41 12.78 13.61 14.52
LaGrande_Ind 10.67 9.73 10.40 9.94 10.17 10.98 11.31 11.80 12.41 12.78 13.61 14.51
LaGrande_Res 11.53 10.34 10.86 10.38 10.57 11.42 11.49 11.80 12.41 12.78 13.61 14.52
Medford_Com 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.81 12.42 12.79 13.62 14.52
Medford_Ind 9.63 8.88 9.85 9.42 9.70 10.38 11.13 11.80 12.41 12.79 13.61 14.52
Medford_Res 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.81 12.42 12.80 13.62 14.53
OR_Tport 12.87 10.23 9.67 9.11 9.37 10.07 10.89 11.47 12.12 12.54 13.26 14.06
Roseburg_Com 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.81 12.42 12.79 13.62 14.52
Roseburg_Ind 9.63 8.88 9.85 9.42 9.70 10.38 11.13 11.80 12.41 12.78 13.61 14.51
Roseburg_Res 9.63 8.88 9.85 9.43 9.71 10.39 11.14 11.81 12.42 12.80 13.62 14.53
WA_Com 11.40 8.38 7.28 6.59 6.38 6.72 6.63 6.68 6.42 6.53 6.88 6.99
WA_Ind 11.17 8.17 7.11 6.42 6.21 6.54 6.48 6.54 6.28 6.41 6.74 6.85
WA_Res 11.43 8.40 7.29 6.60 6.39 6.73 6.63 6.69 6.42 6.54 6.89 7.00
WA_Tport 7.10 5.73 5.97 5.32 5.12 5.21 5.48 5.47 5.33 5.36 5.69 5.83
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 4.96 5.42 5.58 5.92 6.10 6.31 6.78 6.92 7.03 7.18 7.32 7.52
ID_Ind 4.87 5.32 5.50 5.81 6.00 6.24 6.71 6.86 6.98 7.16 7.31 7.52
ID_Res 4.99 5.46 5.60 5.96 6.13 6.34 6.81 6.95 7.05 7.18 7.32 7.52
Klamath Falls_Com 21.07 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Klamath Falls_Ind 21.06 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Klamath Falls_Res 21.07 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
LaGrande_Com 21.06 25.39 25.84 25.99 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
LaGrande_Ind 21.05 25.39 25.84 25.99 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
LaGrande_Res 21.06 25.39 25.84 25.99 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Medford_Com 21.06 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Medford_Ind 21.06 25.39 25.84 25.99 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Medford_Res 21.07 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
OR_Tport 20.45 24.79 25.22 25.37 24.55 23.05 21.59 20.02 18.37 16.91 15.25 14.84
Roseburg_Com 21.06 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Roseburg_Ind 21.05 25.39 25.84 25.99 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
Roseburg_Res 21.07 25.40 25.85 26.00 25.14 23.62 22.08 20.49 18.82 17.21 15.54 14.84
WA_Com 6.74 6.78 6.86 7.41 7.35 7.15 7.74 7.91 8.06 11.74 14.31 14.48
WA_Ind 6.61 6.64 6.74 7.05 7.02 7.04 7.48 7.69 7.87 11.71 14.28 14.48
WA_Res 6.75 6.79 6.86 7.42 7.36 7.15 7.75 7.91 8.06 11.74 14.31 14.48
WA_Tport 5.50 5.44 5.68 5.84 5.88 5.99 6.42 6.74 7.01 11.07 13.67 14.01
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
Appendix - Chapter 6

APPENDIX 6. 5: SOCIAL COST OF CARBON CASE WINTER AVOIDED COST
($/DEKATHERM)

2022 -
2023
2023 -
2024
2024 -
2025
2025 -
2026
2026 -
2027
2027 -
2028
2028 -
2029
2029 -
2030
2030 -
2031
2031 -
2032
2032 -
2033
2033 -
2034
ID_Com 14.36 11.47 10.57 9.95 9.89 10.26 10.26 10.51 10.73 11.15 11.68 11.94
ID_Ind 14.14 11.32 10.44 9.84 9.79 10.15 10.18 10.44 10.67 11.10 11.61 11.88
ID_Res 14.43 11.52 10.60 9.99 9.93 10.30 10.29 10.53 10.75 11.17 11.70 11.96
Klamath Falls_Com 12.87 10.29 9.81 9.28 9.25 11.22 12.84 13.33 14.07 16.81 19.02 19.72
Klamath Falls_Ind 12.87 10.29 9.81 9.27 9.25 11.22 12.84 13.33 14.06 16.81 19.02 19.72
Klamath Falls_Res 12.87 10.29 9.81 9.28 9.25 11.22 12.85 13.33 14.07 16.81 19.02 19.72
LaGrande_Com 13.76 10.79 10.31 9.74 9.68 11.22 12.84 13.33 14.06 16.80 19.01 19.72
LaGrande_Ind 13.32 10.55 10.06 9.50 9.46 11.22 12.84 13.33 14.06 16.80 19.01 19.71
LaGrande_Res 13.77 10.80 10.32 9.74 9.68 11.22 12.84 13.33 14.06 16.80 19.01 19.72
Medford_Com 12.87 10.29 9.81 9.27 9.25 11.22 12.84 13.33 14.06 16.81 19.02 19.72
Medford_Ind 12.87 10.29 9.81 9.27 9.25 11.22 12.84 13.33 14.06 16.80 19.01 19.72
Medford_Res 12.87 10.29 9.81 9.28 9.25 11.22 12.84 13.33 14.07 16.81 19.02 19.72
OR_Tport 12.74 10.01 9.38 8.81 8.73 8.88 9.17 9.44 9.71 10.09 15.36 19.03
Roseburg_Com 12.87 10.29 9.81 9.28 9.25 11.22 12.84 13.33 14.07 16.81 19.02 19.72
Roseburg_Ind 12.87 10.29 9.81 9.27 9.25 11.22 12.84 13.33 14.06 16.80 19.01 19.72
Roseburg_Res 12.87 10.29 9.81 9.28 9.25 11.23 12.85 13.33 14.07 16.81 19.02 19.72
WA_Com 16.54 13.79 13.01 12.54 12.66 13.25 13.47 13.70 13.81 14.25 14.93 15.38
WA_Ind 16.35 13.61 12.86 12.40 12.53 13.10 13.36 13.60 13.72 14.18 14.83 15.29
WA_Res 16.58 13.80 13.02 12.55 12.67 13.25 13.48 13.71 13.82 14.25 14.94 15.39
WA_Tport 12.40 11.26 11.76 11.34 11.44 11.80 12.33 12.58 12.74 13.15 13.77 14.29
2034 -
2035
2035 -
2036
2036 -
2037
2037 -
2038
2038 -
2039
2039 -
2040
2040 -
2041
2041 -
2042
2042 -
2043
2043 -
2044
2044 -
2045
2045 -
2046
ID_Com 12.28 12.73 13.08 13.53 13.88 14.34 14.87 15.18 15.42 15.94 15.38 14.84
ID_Ind 12.22 12.66 13.04 13.48 13.84 14.31 14.84 15.17 15.42 15.94 15.38 14.84
ID_Res 12.30 12.75 13.10 13.55 13.90 14.35 14.87 15.18 15.42 15.94 15.38 14.84
Klamath Falls_Com 22.70 24.73 24.93 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Klamath Falls_Ind 22.70 24.73 24.92 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Klamath Falls_Res 22.70 24.73 24.93 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
LaGrande_Com 22.69 24.72 24.92 24.91 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
LaGrande_Ind 22.69 24.72 24.92 24.91 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
LaGrande_Res 22.69 24.72 24.92 24.91 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Medford_Com 22.70 24.73 24.93 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Medford_Ind 22.69 24.72 24.92 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Medford_Res 22.70 24.73 24.93 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
OR_Tport 21.93 16.53 12.02 12.42 12.82 13.39 13.96 17.50 18.76 17.14 15.52 14.84
Roseburg_Com 22.70 24.73 24.93 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Roseburg_Ind 22.69 24.72 24.92 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
Roseburg_Res 22.70 24.73 24.93 24.92 24.69 23.64 22.08 20.47 18.86 17.18 15.54 14.84
WA_Com 15.40 15.59 16.04 16.78 17.07 17.40 18.14 18.65 18.55 17.26 15.54 14.84
WA_Ind 15.31 15.50 15.97 16.58 16.92 17.36 18.06 18.62 18.54 17.26 15.54 14.84
WA_Res 15.41 15.59 16.04 16.78 17.08 17.40 18.14 18.65 18.55 17.26 15.54 14.84
WA_Tport 14.24 14.37 14.94 15.51 15.89 16.43 17.17 17.86 18.28 17.26 15.54 14.84
*2022-2023 avoided cost values include only January, February, and March months.
*2045-2046 avoided cost values include only November and December months.
APPENDIX 8.1: DISTRIBUTION SYSTEM MODELING

OVERVIEW
The primary goal of distribution system planning is to design for present needs and to plan for future
expansion in order to serve demand growth. This allows Avista to satisfy current demand-serving
requirements, while taking steps toward meeting future needs. Distribution system planning identifies
potential problems and areas of the distribution system that require reinforcement. By knowing when and
where pressure problems may occur, the necessary reinforcements can be incorporated into normal
maintenance. Thus, more costly reactive and emergency solutions can be avoided.

COMPUTER MODELING
When designing new main extensions, computer modeling can help determine the optimum size facilities
for present and future needs. Undersized facilities are costly to replace, and oversized facilities incur
unnecessary expenses to Avista and its customers.

THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last decade to become a highly technical and useful
means of analyzing the operation of a distribution system. Using a pipeline fluid flow formula, a specified
parameter of each pipe element can be simultaneously solved. Through years of research, pipeline
equations have been refined to the point where solutions obtained closely represent actual system
behavior.

Avista conducts network load studies using GL Noble Denton’s Synergi® 4.8.0 software. This computer-
based modeling tool runs on a Windows operating system and allows users to analyze and interpret
solutions graphically.

CREATING A MODEL
To properly study the distribution system, all natural gas main information is entered (length, pipe
roughness and size) into the model. "Main" refers to all pipelines supplying services.
Nodes are placed at all pipe intersections, beginnings and ends of mains, changes in pipe
diameter/material, and to identify all large customers. A model element connects two nodes together.
Therefore, a "to node" and a "from node" will represent an element between those two nodes. Almost all
of the elements in a model are pipes.

Regulators are treated like adjustable valves in which the downstream pressure is set to a known value.
Although specific regulator types can be entered for realistic behavior, the expected flow passing through
the actual regulator is determined and the modeled regulator is forced to accommodate such flows.

FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the relationships between flow, pressure drop, diameter and
pipe length. For all models, the Fundamental Flow equation (FM) is used due to its demonstrated
reliability.
Efficiency factors are used to account for the equivalent resistance of valves, fittings and angle changes
within the distribution system. Starting with a 95 percent factor, the efficiency can be changed to fine tune
the model to match field results.
Pipe roughness, along with flow conditions, creates a friction factor for all pipes within a system. Thus,
each pipe may have a unique friction factor, minimizing computational errors associated with generalized
friction values.

LOAD DATA
All studies are considered steady state; all natural gas entering the distribution system must equal the
natural gas exiting the distribution system at any given time.

Customer loads are obtained from Avista’s customer billing system and converted to an algebraic format
so loads can be generated for various conditions. Customer Management Module (CMM), an add-on
application for Synergi, processes customer usage history and generates a base load (non-temperature
dependent) and heat load (varying with temperature) for each customer.

In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable loads
are interrupted. Therefore, the models will be conducted with only core loads.

DETERMINING NATURAL GAS CUSTOMERS’ MAXIMUM HOURLY USAGE
DETERMINING DESIGN PEAK HOURLY LOAD
The design peak hourly load for a customer is estimated by adding the hourly base load and the hourly
heat load for a design temperature. This estimate reflects highest system hourly demands, as shown in
Table 1:

This method differs from the approach that is used for IRP peak day load planning. The primary reason
for this difference is due to the importance of responding to hourly peaking in the distribution system,
while IRP resource planning focuses on peak day requirements to the city gate.

APPLYING LOADS
Having estimated the peak loads for all customers in a particular service area, the model can be loaded.
The first step is to assign each load to the respective node or element.

GENERATING LOADS
Temperature-based and non-temperature-based loads are established for each node or element, thus loads
can be varied based on any temperature (HDD). Such a tool is necessary to evaluate the difference in flow
and pressure due to different weather conditions.

GEOGRAPHIC INFORMATION SYSTEM (GIS)
Several years ago Avista converted the natural gas facility maps to GIS. While the GIS can provide a
variety of map products, the true power lies in the analytical capabilities. A GIS consists of three
components: spatial operations, data association and map representation.

A GIS allows analysts to conduct spatial operations (relating a feature or facility to another
geographically). A spatial operation is possible if a facility displayed on a map maintains a relationship to
other facilities. Spatial relationships allow analysts to perform a multitude of queries, including:
Identify electric customers adjacent to natural gas mains who are not currently using natural gas
Display the number of customers assigned to particular pipes in Emergency Operating Procedure zones
(geographical areas defined to aid in the safe isolation in the event of an emergency)
Classify high-pressure pipeline proximity criteria

The second component of the GIS is data association. This allows analysts to model relationships
between facilities displayed on a map to tabular information in a database. Databases store facility
information, such as pipe size, pipe material, pressure rating, or related information (e.g., customer
databases, equipment databases and work management systems). Data association allows interactive
queries within a map-like environment.

Finally, the GIS provides a means to create maps of existing facilities in different scales, projections and
displays. In addition, the results of a comparative or spatial analysis can be presented pictorially. This
allows users to present complex analyses rapidly and in an easy-to-understand method.

BUILDING SYNERGI® MODELS FROM A GIS
The GIS can provide additional benefits through the ease of creation and maintenance of load studies.
Avista can create load studies from the GIS based on tabular data (attributes) installed during the mapping
process.

MAINTENANCE USING A GIS
The GIS helps maintain the existing distribution facility by allowing a design to be initiated on a GIS.
Currently, design jobs for the company’s natural gas system are managed through Avista’s Maximo tool.
Once jobs are completed, the as-built information is automatically updated on GIS, eliminating the need
to convert physical maps to a GIS at a later date. Because the facility is updated, load studies can remain
current by refreshing the analysis.

DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy, a present case model has to be developed that reflects what the
system was doing when downstream pressures and flows are known. To establish the present case,
pressure recording instruments located throughout the distribution system are used.

These field instruments record pressure and temperature throughout the winter season. Various locations
recording simultaneously are used to validate the model. Customer loads on Synergi® are generated to
correspond with actual temperatures recorded on the instruments. An accurate model’s downstream
pressures will match the corresponding field instrument’s pressures. Efficiency factors are adjusted to
further refine the model's pressures and better match the actual conditions.

Since telemetry at the gate stations record hourly flow, temperature and pressure, these values are used to
validate the model. All loads are representative of the average daily temperature and are defined as hourly
flows. If the load generating method is truly accurate, all natural gas entering the actual system (physical)
equals total natural gas demand solved by the simulated system (model).

DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day. The
efficiency factors established in the present case are used throughout subsequent models.

ANALYZING RESULTS
After a model has been balanced, several features within the Synergi® model are used to interpret results.
Color plots are generated to depict flow direction, pressure, and pipe diameter with specific break points.
Reinforcements can be identified by visual inspection. When user edits are completed and the model is re-
balanced, pressure changes can be visually displayed, helping identify optimum reinforcements.

PLANNING CRITERIA
In most instances, models resulting in node pressures below 15 psig indicate a likelihood of distribution
low pressure, and therefore necessitate reinforcements. For most Avista distribution systems, a minimum
of 15 psig will ensure deliverability as natural gas exits the distribution mains and travels through service
pipelines to a customer’s meter. Some Avista distribution areas operate at lower pressures and are
assigned a minimum pressure of 5 psig for model results. Given a lower operating pressure, service
pipelines in such areas are sized accordingly to maintain reliability.

DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At that
point, the total amount of natural gas entering the system equals the maximum capacity before new
construction is necessary. The difference between natural gas entering the system in this scenario and a
peak day model is the maximum additional capacity that can be added to the system.

Since the approximate natural gas usage for the average customer is known, it can be determined how
many new customers can be added to the distribution system before necessitating system reinforcements.
The above models and procedures are utilized with new construction proposals or pipe reinforcements to
determine the potential increase in capacity.

FIVE-YEAR FORECASTING
The intent of the load study forecasting is to predict the system’s behavior and reinforcements necessary
within the next five years. Various Avista personnel provide information to determine where and why
certain areas may experience growth.
By combining information from Avista’s demand forecast, IRP planning efforts, regional growth plans
and area developments, proposals for pipeline reinforcements and expansions are evaluated with
Synergi®.

Appendix 8.2

Oregon Public Utility Commission Order No. 16-109 (the Order) included the following
language:

Finally, as part of the IRP-vetting process and subsequent rate proceedings, we expect
that Avista conduct and present comprehensive analyses of its system upgrades. Such
analyses should provide: (1) a comprehensive cost-benefit analysis of whether and when
the investment should be built; (2) evaluation of a range of alternative build dates and
the impact on reliability and customer rates; (3) credible evidence on the likelihood of
disruptions based on historical experience; (4) evidence on the range of possible
reliability incidents; (5) evidence about projected loads and customers in the area; and
(6) adequate consideration of alternatives, including the use of interruptibility or
increased demand-side measures to improve reliability and system resiliency.

In order to address this portion of the Order, Avista has prepared this appendix, which
includes documentation addressing the six points above for each of the natural gas
distribution system enhancements included in the 2021 Natural Gas Integrated Resource
Plan (IRP) for Avista’s Oregon service territory. Each of these three enhancement projects
represents a significant, discrete project which is out of the ordinary course of business (that
is to say, different from ongoing capital investment to address Federal or State regulatory
requirements, relocation of pipe or facilities as requested by others, failed pipe or facilities,
etc., all of which occur routinely over time and which are discussed below).

The routine, ongoing capital investments can be loosely classified in the following categories
(which are not mutually exclusive):

• Safety – Ongoing safety related capital investment includes the repair or replacement
of obsolete or failed pipe and facilities. This category includes, but is not necessarily
limited to, investment to address deteriorated or isolated steel pipe, cathodic
protection, and the replacement of pipeline which has been built over, as well as the
remedy of shallow pipe or the repair or replacement of leaking pipe.
• System Maintenance – Ongoing capital investment related to system maintenance
includes replacement of facilities or pipe that has reached the end of their useful
lives, as well as other general investment required to maintain Avista’s ability to
reliably serve customers.
• Relocation Requested by Others – Ongoing capital investment related to relocation
requested by others falls primarily into two categories, relocation requested by other
parties which is required under the terms of our franchise agreements (such as

relocations required to accommodate road or highway construction or relocation),
or relocation requested by customers or others (in which case the customer would
be responsible for the cost of the immediate request, but in which case Avista may
perform additional work, such as the replacement of a steel service with
polyethylene to reduce future maintenance or cathodic protection requirements on
that pipe).
• Mandated System Investment – Ongoing capital investment in this category is driven
by Federal or State regulatory requirements, such as investment that results from
TIMP/DIMP programs, among other programs.
Avista’s Aldyl-A replacement program has been addressed in substantial detail in Oregon
Public Utility Commission Docket UG-246, Avista/500-501.

1
Technical Advisory Committee (TAC) # 1
February 16, 2022
Natural Gas Integrated
Resource Plan
2
Agenda
Item Time
Meeting Guidelines and reminders 9:00am –9:10am
2023 IRP Topics and Timeline 9:10am –9:30am
2021 IRP Review 9:30am –9:45am
Weather Planning Standard 9:45am –10:00am
Break 10:00am –10:10am
RNG Supply Overview 10:10am –11:00am
Climate Protection Plan (CPP) Overview 11:00am –12:00pm
3
Meeting Guidelines
•IRP team is working remotely and is available for questions and comments
•Stakeholder feedback form
•Responses shared with TAC at meetings, by email and in Appendix
•Would a form and/or section on the web site be helpful?
•IRP data posted to web site –updated descriptions and navigation are in development
•Virtual IRP meetings on Microsoft Teams until able to hold large meetings again
•TAC presentations posted on IRP page
•This meeting is being recorded and an automated transcript made
44
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Raise hand or use the chat box for questions or comments
•Respect the pause
•Please try not to speak over the presenter or a speaker
•Please state your name before commenting for the note taker
•This is a public advisory meeting –presentations and comments will be
documented and recorded
5
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•An IRP is submitted every 2 years in Idaho, Oregon and Washington
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
•Supply side resource choices
•Conservation / demand response
•Customer growth
•Market and portfolio scenarios for uncertain future events and issues
6
Technical Advisory Committee
•The public process piece of the IRP –input on what to study, how to study,
and review of assumptions and results
•Wide range of participants involved in all or parts of the process
•Please ask questions
•Always soliciting new TAC members
•Open forum while balancing need to get through topics
•Welcome requests for new studies or different modeling assumptions.
•Available by email or phone for questions or comments between meetings
7
2023 IRP TAC Meeting Topics
•Weather forecast
•Peak Weather
•2021 IRP Action Items
•Climate Protection Plan (CPP)
•Renewable Natural Gas (RNG)
8
2023 IRP TAC Meeting Topics
•Natural gas market overview
•Natural gas price forecast
•Transportation contracts
•Current supply side resources
•Future supply side resource options
•Climate Commitment Act (CCA)
•Electrification
9
2023 IRP TAC Meeting Topics
•Clean energy survey study
•Conservation potential assessment
•AEG (ID and WA)
-Performing a low income and transportation customer study for Oregon
•ETO (OR)
•Demand Response (AEG)
•Plexos model overview
•Distribution system planning
10
2023 IRP TAC Meeting Topics
•Preferred Resource Strategy
•Portfolio scenario analysis
•Risk assessment and stochastics
•Carbon Pricing
•Social cost of carbon (OR and WA)
•Action Items for next IRP
•Other items of interest
11
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•April 2022
TAC #3
•June 2022
TAC #4
•August
2022
TAC #5
•October
2022
Draft IRP
to TAC
•January 2023
TAC #6 (if
necessary)
•February
2023
File IRP
•April 2023
12
Avista 2021 IRP Review
13
Avista
ID 92,000
OR 105,000
WA 175,000
Total 372,000
1414
LDC -Total System Average Daily Load
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
Nov-20 Dec-20 Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21
Dt
h

/

D
a
y
Average Load Max Load Min Load Peak Day
15
Existing Resources vs. Peak Day Demand
Expected Case –Washington/Idaho (DRAFT)
16
Existing Resources vs. Peak Day Demand
Expected Case –Medford/Roseburg (DRAFT)
17
Existing Resources vs. Peak Day Demand
Expected Case –Klamath Falls (DRAFT)
18
Existing Resources vs. Peak Day Demand
Expected Case –La Grande (DRAFT)
19
Carbon Reduction scenario
•Carbon reduction goals to meet 2035 targets of 45% below 1990 emissions
•Any actual availability of physical RNG resources and rate impact by year can be further
studied in future Integrated Resource Plans
•Actual projects will be considered on an ad-hoc basis to determine which costs and
environmental attributes may make different RNG types a least cost solution
•Exact 1990 emissions are not known and are estimated based on prior 10k’s
•Many of the rules from EO 20-04 will be coming out after this IRP is submitted
•Allowances are not considered
20
Major Changes since last IRP
•CCA (WA)
•CPP (OR)
•Clean Energy Costs
•Risk of Customer growth
21
2021 IRP Action Items
Action Item Commission
Recommendation 1: In the next IRP, use at least five years of historic data for modeling use per customer OPUC
Recommendation 2: Include a No Growth scenario in the next IRP OPUC
Recommendation 3: In future IRPs, provide a comparison between the current CPA and the last CPA, including a narrative explanation of
major changes in the potential OPUC
Recommendation 4: Discuss demand response as a demand side resource option at a TAC meeting before filing the next IRP OPUC
Recommendation 5: Discuss long-term transport procurement strategies at a TAC meeting before the next IRP OPUC
Host a workshop within two months of the publishing of DEQ’s Clean Power Plan Rules, to discuss challenges and opportunities to
incentivize near-term actions to reduce GHGs to meet Clean Power Plan targets, including consideration of SB 98 and SB 844 programs.OPUC
Recommendation 7: Provide a workshop in the next IRP development process to discuss the possibility of using the social cost of carbon
to help inform carbon risks in its portfolios OPUC
Recommendation 8: Include a non-zero carbon risk value for its Idaho customers OPUC
Recommendation 9: Prior to the next IRP, conduct market research to reflect the willingness of Oregon customers to pay for various
carbon reduction strategies. Present results at a TAC meeting OPUC
Recommendation 10: Work with stakeholders and Staff to identify information that should be included in an RNG project pipeline update
and provide an update on the Company’s RNG project pipeline as part of the next IRP Update, including, but not limited to consumer risks
and costs assessment associated with buy vs build RNG options OPUC
22
2021 Action Items cont.
Action Item Commission
Recommendation 11: In the next IRP, provide an analysis of the capabilities of Avista’s system to accommodate
hydrogen, where upgrades would be required to accommodate hydrogen, and estimated costs of those upgrades OPUC
Recommendation 12: In the next IRP, describe the assumptions for changes to renewable technologies and their
impact on future levelized costs in the text of the next IRP OPUC
Recommendation 13: Work with TAC to develop a scenario with a future large scale supply interruptions, like the
October 2018 Enbridge incident OPUC
Recommendation 14: In the next IRP, Avista should continue to keep the Commission apprised of the Sutherlin and
Klamath Falls city gate projects. The Company should also provide a list of areas or projects where the Company is
monitoring for capacity or pressure issues.OPUC
Further model carbon reduction in Oregon and Washington All
Investigate new resource plan modeling software and integrate Avista’s system into software to run in parallel with
Sendout All
Model all requirements as directed in Executive Order 20-04 All
Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm savings of the amount identified and
approved by the Energy Trust Board All
Explore the feasibility of using projected future weather conditions in its design day methodology All
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 All
23
Weather Planning
24
Weather Trend
Heating Degree Day (HDD) begins at 65°F
Anything less than this beginning value would be 1 HDD for each degree of Fahrenheit reduction (e.g.65-64=1 HDD)
3,000
3,500
4,000
4,500
5,000
5,500
6,000
6,500
7,000
7,500
Idaho -Washington
10y 20y 30y
HD
D HD
D
3,000
3,200
3,400
3,600
3,800
4,000
4,200
4,400
4,600
4,800
5,000
Medford
10y 20y 30y
25
4,000
4,500
5,000
5,500
6,000
6,500
7,000
7,500
Klamath Falls
10y 20y 30y
4,000
4,500
5,000
5,500
6,000
6,500
La Grande
10y 20y 30y
Weather Trend cont.
HD
D
HD
D
HD
D
2,500
3,000
3,500
4,000
4,500
5,000
Roseburg
10y 20y 30y
26
20-Year Average Daily Weather
3,000
3,500
4,000
4,500
5,000
5,500
6,000
6,500
7,000
7,500
20 year avg
Klamath Falls La Grande Medford Roseburg Spokane
#
o
f

H
D
D
’
s
27
Idaho -Washington
0%
5%
10%
15%
20%
25%
30%
-5.0-4.5-4.0-3.5-3.0-2.5-2.0-1.5-1.0-0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Fr
e
q
u
e
n
c
y
Z-statistic
Spokane Dec-Jan-Feb Temperature Anomaly Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Peak Day -11°F
-30
-20
-10
0
10
20
30
40
19
4
9
19
5
1
19
5
3
19
5
5
19
5
7
19
5
9
19
6
1
19
6
3
19
6
5
19
6
7
19
6
9
19
7
1
19
7
3
19
7
5
19
7
7
19
7
9
19
8
1
19
8
3
19
8
5
19
8
7
19
8
9
19
9
1
19
9
3
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
ID -WA
1% Probability Coldest each year Coldest on Record Coldest in 20
°F
28
Medford
-10
-5
0
5
10
15
20
25
30
35
40
19
4
9
19
5
1
19
5
3
19
5
5
19
5
7
19
5
9
19
6
1
19
6
3
19
6
5
19
6
7
19
6
9
19
7
1
19
7
3
19
7
5
19
7
7
19
7
9
19
8
1
19
8
3
19
8
5
19
8
7
19
8
9
19
9
1
19
9
3
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
Medford
1% probability Coldest each year Coldest on Record Coldest in 20
0%
5%
10%
15%
20%
25%
-5.0-4.5-4.0-3.5-3.0-2.5-2.0-1.5-1.0-0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Fr
e
q
u
e
n
c
y
Z-statistic
Medford Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Medford Peak Day 16°F
°F
29
Klamath Falls
-20
-15
-10
-5
0
5
10
15
20
25
30
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
20
2
1
Klamath Falls
1% probability Coldest each year Coldest on Record Coldest in 20
0%
5%
10%
15%
20%
25%
-5
.
0
-4
.
5
-4
.
0
-3
.
5
-3
.
0
-2
.
5
-2
.
0
-1
.
5
-1
.
0
-0
.
5
0.
0
0.
5
1.
0
1.
5
2.
0
2.
5
3.
0
3.
5
4.
0
4.
5
5.
0
Fr
e
q
u
e
n
c
y
Z-statistic
Klamath Falls Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/2021 Period
Peak Day -7°F
°F
30
Roseburg
-10
0
10
20
30
40
50
60
70
19
4
9
19
5
1
19
5
3
19
5
5
19
5
7
19
5
9
19
6
1
19
6
3
19
6
5
19
6
7
19
6
9
19
7
1
19
7
3
19
7
5
19
7
7
19
7
9
19
8
1
19
8
3
19
8
5
19
8
7
19
8
9
19
9
1
19
9
3
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
Roseburg
1% probability Coldest each year Coldest on Record Coldest in 20
0%
5%
10%
15%
20%
25%
30%
-5
.
0
-4
.
5
-4
.
0
-3
.
5
-3
.
0
-2
.
5
-2
.
0
-1
.
5
-1
.
0
-0
.
5
0.
0
0.
5
1.
0
1.
5
2.
0
2.
5
3.
0
3.
5
4.
0
4.
5
5.
0
Fr
e
q
u
e
n
c
y
Z-statistic
Roseburg Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Peak Day 19°F
°F
31
La Grande
-20
-15
-10
-5
0
5
10
15
20
25
19
4
9
19
5
1
19
5
3
19
5
5
19
5
7
19
5
9
19
6
1
19
6
3
19
6
5
19
6
7
19
6
9
19
7
1
19
7
3
19
7
5
19
7
7
19
7
9
19
8
1
19
8
3
19
8
5
19
8
7
19
8
9
19
9
1
19
9
3
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
La Grande
1% probability Coldest each year Coldest on Record Coldest in 20
0%
5%
10%
15%
20%
25%
30%
-5
.
0
-4
.
5
-4
.
0
-3
.
5
-3
.
0
-2
.
5
-2
.
0
-1
.
5
-1
.
0
-0
.
5
0.
0
0.
5
1.
0
1.
5
2.
0
2.
5
3.
0
3.
5
4.
0
4.
5
5.
0
Fr
e
q
u
e
n
c
y
Z-statistic
La Grande Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Peak Day -7°F
°F
32
Weather Summary
•Average daily weather by planning region for the past 20
years
•A peak event by planning region based on the past 30 years
of the coldest average day, each year, combined with a 1%
probability of a weather occurrence
•We are currently evaluating options for using projected
weather in our forecasting
3333
Renewable Natural Gas (RNG)
Michael Whitby, RNG Manager
343434
Advancing RNG at Avista
Avista has been actively pursuing RNG. This section covers the following
items:
▪RNG: A Climate Change Solution
▪RNG Procurement
▪RNG Pathways & Technologies
▪Build vs Buy
▪RNG Project Development (Lessons learned)
▪RNG Procurement & Potential Project Pipeline
▪Voluntary RNG Customer Programs
▪Decarbonization Pathways Analysis
▪Steps to Decarbonization
▪Decarbonization Pathways & CC&R Potential
▪Industry Reports
▪Policy
353535
RNG: A Climate Change Solution
RNG is a drop-in fuel that has many benefits over alternative solutions
▪RNG “Decarbonizes” the gas stream
▪RNG is not a fossil fuel and does not add carbon emissions to the atmosphere
▪RNG is seamless to our customers and does not require changes to appliances or equipment
▪RNG is interchangeable with conventional gas and does not require utilities to make any changes to the existing
infrastructure
▪RNG leverages an efficient energy delivery system. From production to customer = 91% efficient
▪RNG is a here and now solution, however further advancements & supportive policy to expand low carbon fuel
pathways through innovation
▪RNG supports and enhances the resiliency and reliability of our energy system and is more affordable than electrification
scenarios
▪RNG leverages the existing infrastructure’s energy storage capabilities that alternative electrification solutions cannot
compete with.
▪In the right applications, direct use of natural gas is best use
▪Natural gas generation provides critical capacity as renewables expand until utility-scale storage is cost effective and
reliable
▪RNG promotes customer fuel choice over choice elimination
363636
RNG Procurement
Exploring the Procurement Options
To make informed decisions on RNG procurement, Avista set out to understand
the known and emerging procurement pathways available for RNG. This has
included undertaking a process to research and seek out potential projects,
as well as identify technologies and explore innovations that can help to achieve
meaningful decarbonization.
Pathways & Technologies
Conventional RNG
Unconventional RNG
Innovative RNG
Primary Approaches
Build
vs.
Buy
373737
RNG Pathways & Technologies
As Avista seeks to identify pathways to decarbonize our gas supply we have been evaluating
exploring a range of technologies
Technology Attributes/Comments
Conventional RNG Amine scrub, membrane separation, H2o wash, pressure swing absorption
Pyro Catalytic Hydrogenation (PCH)Woody waste to synthetic RNG
Thermal gasification Plasma Enhanced Melter -Municipal waste to synthetic RNG
Mobile RNG Solution Small scale remote RNG production & transport without a pipeline
Proprietary biocatalyzed methanation Unconventional RNG that boosts RNG volumes
Carbon Capture & Recycle (CC&R)Carbon Reduction
Carbon capture & recycle (CC&R) w/
proprietary biosynthesized methanation
Carbon Reduction & Synthetic RNG
Solar to hydrogen Green hydrogen in support of CC&R & proprietary methanation
383838
Build vs. Buy
RNG Development Projects (Build)
Avista has been pursuing several RNG projects with a variety of feedstock types to
build a pipeline of potential RNG projects. The following list represents the projects
pathways in the order in which they have been pursued:
•Conventional
•Unconventional (proprietary biocatalyzed methanation)
•Innovative Carbon Capture & Recycle (CC&R) solutions
Building RNG projects is complex and comes with a host of challenges.
•RNG projects can be delivered at a lower cost since they do not include the profit margins
associated with the California market, however competition for, and influence on the biogas
cost still exists.
•Having pursued RNG projects and having purchased RNG, Avista recognizes the value of
developing projects on a utility cost of service model, which on a like to like basis is
the best value for our customers.
393939
Build vs. Buy
Purchasing RNG (Buy)
•This pathway is widely available with a lot of variations with respect to volumes, costs, and
sell back/cost sharing options, however the pricing is influenced by the California
transportation sector (Federal RIN & CA LCFS markets).
•Avista has procured an RNG supply for Avista’s first ever Voluntary Customer RNG
Program in the State of Washington.
404040
RNG Project Development Challenges
Lessons learned from pursuing RNG projects directly with feedstock owners:
▪Competition
▪The California transportation market dominates the supply
▪Federal RIN & California LCFS markets influence commercial terms
▪Reaching commercial terms is challenging
▪The utility cost of service model is a foreign concept
▪Every RNG project is unique
▪Economies of scale
▪New RNG Projects can take 2-3 years to develop
▪Limited feedstock supply
▪Partnering strategy
▪Picking partners
414141
RNG Procurement & Potential Project Pipeline
#Project Pathway Type In Service Avista
Territory (Y/N)
Partnering
Considered
Estimated Supply
(Dth/YR) (Avista only)
Est. Online Date
1 Conventional RNG Yes Yes ~ 200K -350K 2024
2 Unconventional RNG Yes Yes ~ 150K -250K TBD
3 Unconventional RNG Yes Yes ~ 70K -120K 2024-25
4 Conventional RNG Yes Yes ~ 30K -50K TBD
5 Conventional RNG Yes Yes ~ 20K -30K TBD
6 Innovative CC&R RNG Yes Yes ~ 50K -80K 2024-25
7 Thermal Gasification Yes Yes ~ 70K -200K TBD
8 Conventional RNG Yes Yes ~ 60K -140K TBD
9 Pyro Catalytic Hydrogenation Yes Yes ~ 70K -150K TBD
10 Purchased RNG Yes No ~ 5K -10.8K 2022
Avista has been pursuing RNG projects with a host of feedstock owners
for the past few years. The table below captures these efforts by type & volume
424242
Voluntary RNG Customer Programs
Q1 2022 -Avista’s first ever Voluntary Customer RNG program launched
in Washington
▪This voluntary RNG subscription is much like Avista’s My Clean Energy program,
in which customers can elect to purchase pre-defined ‘blocks’ therms of energy generated from
renewable sources.
▪The M-RETS system has been selected to track RNG environmental attributes.
▪1 Renewable Thermal Certificate (RTC) = 1 Dekatherm (Dth) of RNG
▪Transparent electronic certificate tracking
Market related challenges & opportunities:
▪Customers lack understanding of RNG since it is a new product
▪Customers like the environmental aspects of RNG
▪Customers like to choose their level of participation to manage costs predictably
Q2 2022 -Avista will seek approval for a voluntary RNG tariff
in Oregon & Idaho
434343
Decarbonization Pathways Analysis
Avista engaged Guidehouse to evaluate and compare various pathways.
The takeaway is that a mix of pathways will be needed to reach decarbonization
goals and mandated targets
444444
Steps to Decarbonization –A mix of pathways
The Guidehouse analysis shows the logical decarbonization progression from
energy efficiency to the deployment of low carbon fuels
454545
Decarbonization Pathways & CC&R Potential
The Guidehouse analysis shows a range of pathways and how Low Carbon
fuels including CC&R can help to achieve carbon reduction goals
464646
RNG Pathways Analysis
The Guidehouse analysis included a comparison of Electrification to Low
Carbon Fuel pathways as a part of Avista’s resource mix.
474747
Avista’s experience in pursuing
RNG comports with the findings
found within AGA’s latest report.
Industry Reports
484848
Policy
RNG leverages existing infrastructure and customer equipment. A mix of
solutions including conventional & innovative low carbon fuels will be needed
to reach decarbonization goals and targets.
494949
Questions?
50
Climate Protection Plan (CPP)
Overview
51
CPP Purpose and Scope
•Signed into Law on March 10,2020 by Governor Kate Brown viaExecutiveOrder20-04
•The purposes of the Climate Protection Program are to:
•reduce greenhouse gas emissions that cause climate change from sources inOregon
•achieve co-benefits from reduced emissions of other air contaminants,and
•enhance public welfare for Oregon communities,particularly environmental justicecommunitiesdisproportionatelyburdenedbytheeffectsofclimatechangeandaircontamination.
•Local distribution companies, known as natural gas utilities
•covered emissions do not include emissions from biomass derived fuels.
•Does not include emissions from landfills, electric power plants, and natural gas compressor stations on and owned by interstate pipelines.
OAR 340-271-0010
52
Program Coverage
•Local distribution companies
•Covered emissions do not include emissions from biomass derived fuels.
•Covered emissions described as anthropogenic greenhouse gas emissions from combustion of natural gas, excluding natural gas used at large electricity generating facilities.
•Covered stationary sources include: Stationary sources for covered emissions described as anthropogenic greenhouse gas emissions from industrial processes and fuel combustion not otherwise regulated from a covered fuel supplier and that meet or exceed 25,000 MT CO2e.
•Does not include emissions from landfills, electric power plants, and natural gas compressor stations on and owned by interstate pipelines.
•Does not include emissions from biomass-derived fuels
•New stationary sources with the potential to emit covered emissions at or above 25,000 MT CO2e.
53
Compliance
A compliance period is three years. This
first compliance period begins with 2022
and includes calendar years 2023 and
2024.
Demonstration of compliance is only
required after a three-year compliance
period.
54
Avista Emissions Target
OAR 340-271-9000 –Table 4
MT
C
O
2
e
DEQ will distribute compliance instruments to covered fuel suppliers by March 31
of each year as follows: Covered fuel suppliers that are natural gas utilities will
receive an annual distribution of compliance instruments described in Table 4.
41%
26%
1%
32%
Residential Commercial Industrial Transport
55
Community Climate Investment (CCI)
(2) A CCI entity may use CCI funds only for:
(a)Implementing eligible projects in Oregon, which are actions that reduce anthropogenic greenhouse gas
emissions that would otherwise occur in Oregon.
•Eligible projects include actions that reduce emissions in Oregon resulting from:
(A) Transportation of people, freight, or both;
(B) An existing or new residential use or structure;
(C) An existing or new industrial process or structure; and
(D) An existing or new commercial use or structure.
56
CCI Costs
$-
$20
$40
$60
$80
$100
$120
$140
$160
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
20
4
6
20
4
7
20
4
8
20
4
9
20
5
0
CCI
57
UM-2178
Scope: The purpose of this Fact Finding will be to analyze the potential natural gas utility bill impacts that may result from limiting GHG emissions of regulated natural gas utilities under the DEQ's Climate Protection Program and to identify appropriate regulatory tools to mitigate potential customer impacts. The ultimate goal of the Fact Finding will be to inform future policy decisions and other key analyses to be considered in 2022, once the CPP is in place.
•Presentations and modeling was provided to the OPUC and other stakeholders to understand the LDC’s ability to meet EO 20-04
•Avista intends to build the findings and additional supply side resources into the 2023 IRP as a way of showing a more detailed path and analysis to compliance
State of Oregon: Public Utility Commission of Oregon
58
Avista Compliance to CPP
Challenges to CPP Opportunities of CPP
More entities looking for same resources clean up grid
As a smaller LDC additional costs are spread across fewer customers a specific directive to decarbonize with goals
Cost Equity, Avista's customers are generally less wealthy as compared to
other Oregon counties LDCs play an active role in Oregon’s clean energy future
Increased demand for limited new resources drives higher prices Utilize SB 98 to help projects online
Clean Fuel Supply Ramp up to match cap in near term Increased Energy Efficiency Potential
Higher Costs Gas continues to hold economic fuel choice to decarbonize the electric
grid
Responsibility for transport customers emissions
Technology Maturation
Cost Recovery
Reliability of Electric System with additional load
Rate pressure will lead to the utilization of different heating fuels
Limited ability to link to other state’s clean energy programs
Infrastructure Cost recovery –Electrification will result in costs being
spread across a smaller customer base
Host a workshop within two months of the publishing of DEQ’s Clean Power Plan Rules, to discuss challenges and opportunities to incentivize near-term
actions to reduce GHGs to meet Clean Power Plan targets, including consideration of SB 98 and SB 844 programs.
59
Oregon Territory
Median Household Income
Source: SNL maps
60
Questions?
61
Scenarios -Draft
•Preferred Resource Case –Our expected case based on assumptions and costs with a least risk and least cost resource selection
•Avista company goal -Carbon Neutral by 2045 –Intended to move the 2050 state/federal goals up to the company goal of 2045
•Electrification Push –A low case to show the risk involved with energy delivered through the natural gas infrastructure moving to the electric system
•High Customer Case –A high case to measure risk of additional customer and meeting our emissions and energy obligations
•Limited RNG Availability –A scenario to show costs and supply options if RNG availability is smaller than expected
•High Prices -Interrupted Supply –A scenario to show the impacts and risks associated with large scale supply impacts and the ability for Avista to provide the needed energy to our customers
•Other?
62
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•April 2022
TAC #3
•June 2022
TAC #4
•August
2022
TAC #5
•October
2022
Draft IRP
to TAC
•January 2023
TAC #6 (if
necessary)
•February
2023
File IRP
•April 2023
Technical Advisory Committee (TAC) # 2
May 3, 2022
Natural Gas Integrated
Resource Plan
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Raise hand or use the chat box for questions or comments
•Respect the pause
•Please try not to speak over the presenter or a speaker
•Please state your name before commenting for the note taker
•This is a public advisory meeting –presentations and comments will be
documented and recorded
2
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•May 2022
TAC #3
•June 2022
TAC #4
•August
2022
TAC #5
•October
2022
Draft IRP
to TAC
•January 2023
TAC #6 (if
necessary)
•February 2023
File IRP
•April 2023
Major Milestone Date Topics
TAC 1 Wednesday, February 16, 2022 RNG Discussion, Compliance To EO 20-04, Policy, Peak Day
Weather Planning Standard
TAC 2 Tuesday, May 3, 2022
Use Per Customer, Planned Scenarios, Customer Forecast, Current
Supply Side Resources, Plexos Model Overview, Baseline Demand
Projections
TAC 3 Wednesday, June 22, 2022 Customer Survey Results,CCA Overview, Distribution
TAC 4 Tuesday, August 23, 2022 Future Supply Side Resource Options, CPA, Demand Response
TAC 5 Tuesday, October 25, 2022 Final Results / Stochastics, Scenario Results
Draft Feedback Due Wednesday, February 1, 2023
File Friday, March 31, 2023
3
Agenda
Item Time
2023 Timeline / Agenda Overview 9:00am –9:10am
Customer Forecast 9:10am –9:40am
Use per Customer 9:40am –10:10am
Break 10:10am –10:20am
Current Supply Side Resources 10:20am –11:00am
Plexos Model Overview 11:00am –11:30am
Proposed Scenarios 11:30am –12:00pm
4
Grant D. Forsyth, Ph.D.
[e-mail]
Chief Economist
2023 IRP Long-Run Customer
Forecast: Natural Gas
Firm Customers (Meters) by State and Class, 2021
WA
47%
ID
25%
OR
28%
Firm Customers by State
Residential
90%
Commercial
10%
Industrial
0.1%
Firm Customers by Class
6
150
170
190
210
230
250
270
290
310
0
5
10
15
20
25
30
35
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
WA
-ID

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR Firm Industrial WA-ID Firm Industrial
291 31
26
164: Meters
Reclassified to
Commercial.
7
System Firm Industrial Customers, 1997-2021
Customer Forecast Models
•Forecast models are structured around each schedule, in each class, by jurisdiction. In the
case of OR, this is done individually for each of Avista’s service islands.
•Time series transfer function models (models with regressions drivers and ARIMA error terms).
•Simple time series smoothing models (for schedules with little customer variation).
•Same models used for the bi-annual revenue model forecast pushed out to 2045. The
forecasts for this IRP were generated from the “Spring 2022” forecast completed in March 2022.
•Customer forecasts are sent to Gas Supply for inclusion in the PLEXOS model.
•Example of transfer function model: WA sch. 101 residential customers…
8
Transfer Function Model Example
𝐶𝑡,𝑦,𝑊𝐴101.𝑟=𝛼0 +𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝑆𝑒𝑝2018=1 +𝜔𝑂𝐿𝐷𝑂𝑐𝑡2015=1
+𝜔𝑂𝐿𝐷𝐹𝑒𝑏2016=1 +𝜔𝑂𝐿𝐷𝑀𝑎𝑟2018=1 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣2018=1 +𝜔𝑂𝐿𝐷𝑆𝑒𝑝2020=1
+𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦12,1,0 0,0,0 12
Monthly
Customer
(Meter
Count)
Monthly
Interpolated
Population for
Spokane MSA
Seasonal
Dummies
Outlier
Dummy
(Interventions)Error
Correction
Component
Structural Change
Dummy for a Step-
up in Customers
(Interventions for
steps up or down).
9
Getting to Population as a Driver,
2022-2026 & 2027-2045
Average GDP Growth
Forecasts:
•WSJ, FOMC,
Bloomberg, etc.
•Average forecasts
out 5 full calendar
years.
Non-farm Employment
Growth Model:
•Model links year y, y-1, and
y-2 GDP growth to year y
regional employment
growth.
•Forecast out 5 full calendar
years.
•Averaged with IHS
employment growth
forecasts.
Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year y
county population growth.
•Forecast out 5 full calendar years for
Spokane, WA; Kootenai, ID; and
Jackson+Josephine, OR.
•Averaged with IHS growth forecasts.
•Growth rates used to generate
population forecasts for use in
regression models—important driver
for main residential and commercial
schedules.
EMPGDP
2022-2026 For Spokane, WA; Kootenai, ID,
and Jackson+Josephine, OR
OR Douglas, Klamath, and Union counties: IHS population growth forecasts for
2027-2045
Kootenai and Jackson: IHS population growth forecasts for 2027-2045
Spokane: IHS population growth forecasts for 2027-2045
Monthly Interpolation assumes: PN =
P0erN
10
WA-ID Region Firm Customers
(2023-2045)
220,000
240,000
260,000
280,000
300,000
320,000
340,000
360,000
380,000
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
WA-ID Base-line 2021 WA-ID Base-line 2023
+17,394IRPAvg.Annual
Growth 2023-2045
2023 1.2%
2021 1.1%
11
OR Region Firm Customers
(2023-2045)
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
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
OR Base-line 2021 OR Base-line 2023
IRP Avg.Annual
Growth 2023-2045
2023 0.9%
2021 0.7%
+5,121
12
Medford, OR Region Firm Customers
(2023-2045)
55,000
60,000
65,000
70,000
75,000
80,000
85,000
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
Medford Base-line 2021 Medford Base-line 2023
IRP Avg.Annual
Growth 2023-2045
2023 1.1%
2021 0.8%
+4,613
13
Roseburg, OR Region Firm Customers
(2023-2045)
15,000
15,500
16,000
16,500
17,000
17,500
18,000
18,500
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
Roseburg Base-line 2021 Roseburg Base-line 2023
+459
IRP Avg.Annual
Growth 2023-2045
2023 0.4%
2021 0.4%
14
Klamath, OR Region Firm Customers
(2023-2045)
15,000
16,000
17,000
18,000
19,000
20,000
21,000
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
Klamath Base-line 2021 Klamath Base-line 2023
IRP Avg.Annual
Growth 2023-2045
2023 0.6%
2021 0.6%
≈ -45
15
La Grande, OR Region Firm Customers
(2023-2045)
7,400
7,600
7,800
8,000
8,200
8,400
8,600
8,800
9,000
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
La Grande Base-line 2021 La Grande Base-line 2023
IRP Avg.Annual
Growth 2023-2045
2023 0.5%
2021 0.5%
+94
16
System Firm Customers
(2021-2045)
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
480,000
500,000
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
WA-ID-OR Base 2021 WA-ID-OR Base 2023
IRP Avg.Annual
Growth 2023-2045
2023 1.1%
2021 1.0%
+22,516
17
WA-ID Region Firm Customer Range
(2023-2045)
220,000
240,000
260,000
280,000
300,000
320,000
340,000
360,000
380,000
400,000
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
WAIDFIRMCUS Base WAIDFIRMCUS High WAIDFIRMCUS Low
Variable Base
Growth
High
Growth
Low
Growth
WA-ID
Customers 1.2%1.5%0.8%
WA Population 0.6%0.8%0.2%
ID Population 1.7%2.1%1.0%
WA-ID
Population 0.9%1.2%0.4%
18
OR Region Firm Customer Range
(2023-2045)
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
140,000
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
ORFIRMCUS Base ORFIRMCUS High ORFIRMCUS Low
Variable Base
Growth
High
Growth
Low
Growth
Customers 0.9%1.1%0.6%
Population 0.4%0.6%0.2%
19
System Firm Customer Range
(2023-2045)
300,000
350,000
400,000
450,000
500,000
550,000
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
Variable Base
Growth
High
Growth
Low
Growth
Customers 1.1%1.4%0.7%
Population 0.7%0.9%0.3%
20
Summary of Growth Rates
System Base-Case High Low
Residential 1.2%1.5%0.8%
Commercial 0.5%0.8%0.1%
Industrial 0.0%2.1%-16.9%
Total 1.1%1.4%0.7%
WA Base-Case High Low
Residential 1.1%1.3%0.8%
Commercial 0.4%0.7%0.1%
Industrial 0.0%1.8%-22.6%
Total 1.1%1.3%0.7%
ID Base-Case High Low
Residential 1.6%2.0%0.9%
Commercial 0.5%1.0%-0.1%
Industrial 0.0%1.3%-100.0%
Total 1.5%1.9%0.8%
OR Base-Case High Low
Residential 0.9%1.1%0.6%
Commercial 0.6%0.8%0.3%
Industrial 0.0%4.4%-9.8%
Total 0.9%1.1%0.6%
-100% reflects
zero customers
by 2045
21
Use per Customer
23
(CDD)
(HDD)
Temp
(℉)
Degree
Days
100 =35
90 =25
80 =15
70 =5
65 =0
60 =5
50 =15
40 =25
30 =35
20 =45
10 =55
0 =65
-10 =75
-20 =85
Temperature & Degree Days
Cooling
Degree Days
Heating
Degree Days
Base Coefficients
2 Year 3 Year 5Year 2 Year 3 Year 5Year 2 Year 3 Year 5Year
Washington 0.04606 0.04656 0.04692 0.34753 0.36691 0.37156 3.38736 3.30828 3.27823
Idaho 0.05007 0.04931 0.04813 0.35555 0.37307 0.37783 4.44256 4.85642 5.05549
Klamath Falls 0.03769 0.03793 0.03612 0.23591 0.24248 0.23301 4.65297 4.37893 4.15214
La Grande 0.05968 0.06263 0.06556 0.28766 0.32194 0.34687 42.01296 47.95618 49.61649
Medford 0.05927 0.05567 0.05291 0.43019 0.41408 0.39437 4.73881 4.52838 4.25709
Roseburg 0.06747 0.06151 0.05156 0.47685 0.44512 0.38135 5.65826 5.60567 4.07662
Residential Commercial Industrial
24
Heat Coefficients
2 Year 3 Year 5Year 2 Year 3 Year 5Year 2 Year 3 Year 5Year
Washington 0.00629 0.00631 0.00633 0.03554 0.03714 0.03687 0.20622 0.18381 0.16876
Idaho 0.00666 0.00663 0.00649 0.02769 0.02806 0.02842 0.23788 0.23223 0.22321
Klamath Falls 0.00514 0.00526 0.00513 0.01921 0.01995 0.01946 0.18185 0.17935 0.14478
La Grande 0.00542 0.00551 0.00600 0.02254 0.02395 0.02688 0.51825 0.88173 1.58695
Medford 0.00869 0.00789 0.00723 0.03860 0.03446 0.03030 0.22523 0.16844 0.12185
Roseburg 0.00855 0.00847 0.00717 0.03672 0.03783 0.03086 0.06607 0.05201 0.03476
Residential Commercial Industrial
*Values reflect 12-month average heat coefficient
25
Residential (2012-2021)
26
Commercial (2012-2021)
27
Industrial (2012-2021)
28
Use Per Customer
29
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
20122013 20142015 201620172018 20192020 2021
DT
h

p
e
r

C
u
s
t
o
m
e
r

p
e
r

Y
e
a
r
Klamath Falls Medford Roseburg
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
DT
h

p
e
r

C
u
s
t
o
m
e
r

p
e
r

Y
e
a
r
Idaho La Grande Washington
Residential Use per Customer
(Idaho and Washington)
30
0
1000
2000
3000
4000
5000
6000
7000
8000
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
#
o
f

H
D
D
'
s
Us
e

p
e
r

C
u
s
t
o
m
e
r

(
D
T
h
)
Idaho HDD's Use per Res Customer
0
1000
2000
3000
4000
5000
6000
7000
8000
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
#
o
f

H
D
D
'
s
Us
e

p
e
r

C
u
s
t
o
m
e
r

(
D
T
h
)
Washington HDD's Use per Res Customer (DTh)
Idaho Washington
Residential Use per Customer
(Oregon)
31
0
1000
2000
3000
4000
5000
6000
7000
8000
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
#
o
f

H
D
D
'
s
Us
e

p
e
r

C
u
s
t
o
m
e
r

(
D
T
h
)
Klamath Falls HDD's Use per Customer (DTh)
0
1000
2000
3000
4000
5000
6000
7000
8000
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
#
o
f

H
D
D
'
s
Us
e

p
e
r

C
u
s
t
o
m
e
r

(
D
T
h
)
Medford HDD's Use per Res Customer (DTh)
0
1000
2000
3000
4000
5000
6000
7000
8000
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
#
o
f

H
D
D
'
s
Us
e

p
e
r

C
u
s
t
o
m
e
r

(
D
T
h
)
Roseburg HDD's Use per Res Customer (DTh)
0
1000
2000
3000
4000
5000
6000
7000
8000
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
#
o
f

H
D
D
'
s
Us
e

p
e
r

C
u
s
t
o
m
e
r

(
D
T
h
)
La Grande HDD's Use per Res Customer (DTh)
Residential Use per Customer per HDD
32
0.000
0.002
0.004
0.006
0.008
0.010
0.012
0.014
0.016
0.018
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Us
e

p
e
r

C
u
s
t
o
m
e
r

p
e
r

H
D
D

(
D
T
h
)
Idaho Klamath Falls La Grande Medford Roseburg Washington
33
1.Expected customer count forecast by each of the 6 areas
2.Use per customer coefficients: 5-, 3-, or 2-year average use per
HDD per customer
3.Current weather planning standard
Developing a Reference Case
Customer
count
forecast
Use per
customer
coefficients
Weather
Reference
Case
Demand
33
Demand Modeling Equation –a closer look
The base and weather sensitive usage (degree-day usage)
factors are developed outside the model and capture a
variety of demand usage assumptions.
# of customers x Daily weather sensitive usage / customer
# of customers x Daily base usage / customer
Plus
34
Idaho
Optional footer for data sources, etc.35
Oregon
Optional footer for data sources, etc.36
Washington
Optional footer for data sources, etc.37
Justin Dorr
Manager of Natural Gas Resources
Supply Side Resources
39
•The Integrated Resource Plan (IRP) brings together the various components necessary to ensure proper resource planning for reliable service to utility customers.
•One of the key components for natural gas service is interstate pipeline transportation.Low prices, firm supply and storage resources
are meaningless to a utility customer without the ability to transport the gas
reliably during cold weather events.
•Acquiring firm interstate pipeline transportation provides the most reliable delivery of supply.
Interstate Pipeline Resources
39
40
Pipeline Overview
40
41
Pipeline Contracting
Simply stated: The right to move (transport) a
specified amount of gas from Point A to Point B
A B
41
42
•Firm transport
•Point A to Point B
•Kingsgate to Malin
•Alternate firm
•Point C to Point D
•Kingsgate to Stanfield
•Seasonal firm
•Point A to Point B but only in winter
•Interruptible
•Maybe it flows, maybe it doesn’t
Contract Types
42
43
•Mileage Rate (GTN)
•Distance between receipt and delivery determines price
•Plus variable charges
•Postage Stamp (NWP)
•1 mile from receipt to deliver same price as 1000 miles
•Plus variable charges
Pipeline Rate Design
43
Avista's Transportation Contract Portfolio
Avista holds firm transportation capacity on 6 interstate pipelines:
Pipeline Expirations Base Capacity
Dth
Williams NWP 2025 –2042
(2035)
285,000
Westcoast
(Enbridge)
2026 10,000
TransCanada -
NGTL
2024-2046 208,000
TransCanada -
Foothills
2024-2046 204,000
TransCanada -
GTN
2023-2028 210,000
164,000
TransCanada-
Tuscarora
2023 200
44
1)Pipe reservations and modeling are only for LDC customers
2)Pipe reservations and model explicitly DO NOT CONSIDER electric side of business.
45
4646
47
48
49
•Peaking resource
•Improves reliability
•Enables capture of price spreads between time periods
•Enables efficient counter cyclical utilization of transportation (i.e. summer
injections)
•May require transportation to service territory
•In-service territory storage offers most flexibility
Storage –A Valuable Asset
49
Washington and Idaho
Owned Jackson Prairie
•7.7 Bcf of Capacity with approximately 346,000 Dth/d of deliverability
Oregon
Owned Jackson Prairie
•823,000 Dth of Capacity with approximately 52,000 Dth/d of deliverability
Leased Jackson Prairie
•95,565 Dth of Capacity with approximately 2,654 Dth/d of deliverability
Avista's Storage Resources
50
51
The Facility
•Jackson Prairie is a series of
deep, underground reservoirs –
basically thick, porous sandstone
deposits. •The sand layers lie approximately
1,000 to 3,000 feet below the
ground surface. •Large compressors and pipelines
are employed to both inject and
withdraw natural gas at 54 wells
spread across the 3,200 acre
facility.
Jackson Prairie Energy Comparisons
52
Plexos
New Optimization Model
•Prior model, SENDOUT, had not been updated by the vendor
since 2013
•Increasing complexity in planning for new rules, emissions
constraints and fuel types was not easily handled within
SENDOUT
54
55
Model Diagram
56
57
58
59
60
61
Plexos Model Visual –Pipeline Network
62
Plexos Model Visual –Emissions Constraint
63
Proposed Scenarios
Emission Reduction Paths
AGA Net-Zero Emissions Opportunities for Gas Utilities65
Proposed Scenarios
Preferred
Resource Case
Avista company goal
Carbon Neutral by 2045 Electrification Push
High Customer
Case
Limited RNG
Availability High Prices
Interrupted
Supply
Customer Growth Expected Customer Growth
No New Customers after 2023 in
Oregon and Washington
High Customer
growth Expected Customer Growth
Use Per Customer Expected UPC
Expected Price Blend of 2 fundamental consultants, 1 fwd price
Hydrogen (Green and Synthetic
Methane)20% blend by volume 6% by energy
RNG -Dairy, Waste Water
Treatment, Landfill, Food
Waste, Carbon Capture and
Recycle (CC&R)
125% of Population
Weighted national
supply curve from
ICF
150% of Population
Weighted national supply
curve from ICF
125%of Population Weighted national supply curve from
ICF
Low Resource
Potential from
ICF
125% of Population Weighted
national supply curve from ICF
OR -Community Climate
Investments Cost, limits and restrictions defined in CPP rule
WA -Allowances and Offsets TBD -Currently in Draft
Energy Efficiency ETO CPA in Oregon and AEG CPA in Idaho and Washington
Weather 20 year rolling Average
Peak Weather 99% Probability based on prior 30 year annual peak, by planning area
Environmental Program CCA (WA), CPP (OR)
Demand Response Expected
Climate Protection Plan -OR Per Rules
Climate Commitment Act -WA Per Rules
66
Scenarios -Draft
•Preferred Resource Case –Our expected case based on assumptions and costs with a least risk and least cost resource selection
•Avista company goal -Carbon Neutral by 2045 –Intended to move the 2050 state/federal goals up to the company goal of 2045
•Electrification Push –A low demand case to show the risk involved with energy delivered through the natural gas infrastructure moving to the electric system
•High Customer Case –A high case to measure risk of additional customer and meeting our emissions and energy obligations
•Limited RNG Availability –A scenario to show costs and supply options if RNG availability is smaller than expected
•High Prices -Interrupted Supply –A scenario to show the impacts and risks associated with large scale supply impacts and the ability for Avista to provide the needed energy to our customers
•Other?
67
Questions?
68
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•May 2022
TAC #3
•June 2022
TAC #4
•August 2022
TAC #5
•October
2022
Draft IRP
to TAC
•January
2023
TAC #6 (if
necessary)
•February 2023
File IRP
•April 2023
Major Milestone Date Topics
TAC 1 Wednesday, February 16, 2022 RNG Discussion, Compliance To EO 20-04, Policy, Peak Day
Weather Planning Standard
TAC 2 Tuesday, May 3, 2022
Use Per Customer, Planned Scenarios, Customer Forecast, Current
Supply Side Resources, Plexos Model Overview, Baseline Demand
Projections
TAC 3 Wednesday, June 22, 2022 Customer Survey Results,CCA Overview, Distribution
TAC 4 Tuesday, August 23, 2022 Future Supply Side Resource Options, CPA, Demand Response
TAC 5 Tuesday, October 25, 2022 Final Results / Stochastics, Scenario Results
Draft Feedback Due Wednesday, February 1, 2023
File Friday, March 31, 2023
69
2
•
•
Market
Characterization
•Baseline studies
•Utility data
•Secondary data
Identify Demand-
Side Resources
•EE equipment
•EE measures
•Emerging tech.
Baseline
Projection
•Utility forecasts
•Standards and
building codes
Potential
Estimation
•Technical
•Achievable Tech.
•Economic Achiev.
-
20
40
60
80
100
120
140
160
180
Therms
Mi
l
l
i
o
n
s
Residential Natural Gas Projection by End
Use
Space
Heating
71%
Secondary
Heating…
Water
Heating
20%
Appliances
2%
Miscellaneous
1%
Residential 2019 Gas Use by End Use
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
2021 2022 2023 2025 2030 2040
thousand
therms
Cumulative Natural Gas Savings
7
Sector Accounts 2021 Dth Segmentation
Residential 237,935 16,973,954 Single Family, Multi-Family, Manufactured Home,
and by Income Group within housing type
Commercial 24,454 9,814,874 Office, Retail, Restaurant, Grocery, College,
School, Hospital, Lodging, Warehouse, Other
Industrial 194 496,972 Mix of industries from customer data will inform
presence of end uses and measure applicability
Total 262,584 27,285,801
Residential
62%
Commercial
36%
Industrial
2%
Natural Gas Use by Sector 2021
•
Single Family Profile
End Use Technology Saturation
UEC
(therms)
Intensity
(therms/HH)
Usage
(Dth)
Space Heating Furnace 85%646 548 8,648,686
Boiler 2%432 10 160,215
Secondary Heating Fireplace 5%110 6 88,017
Water Heating Water Heater (<= 55 Gal)55%145 80 1,258,802
Water Heater (> 55 Gal)0%52 0 162
Appliances Clothes Dryer 28%22 6 97,826
Stove/Oven 59%28 17 260,523
Miscellaneous Pool Heater 1%106 1 15,120
Miscellaneous 100%1 1 14,482
0
100
200
300
400
500
600
700
800
900
1000
WA Residential Intensity (therms/HH)
Space Heating
Secondary Heating
Water Heating
Appliances
Miscellaneous
Single Family
64%Multi-Family
4%
Mobile Home
3%
LI -Single
Family
22%
LI -Multi-
Family
5%
LI -Mobile
Home
2%
Washington Residential Natural Gas Use
Technical
Achievable
Technical
UCT and TRC
Economic
Achievable
•
•
•
0
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
35,000,000
40,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
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
In
c
r
e
m
e
n
t
a
l

S
a
v
i
n
g
s

(
D
t
h
)
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)29,414,120 29,675,685 30,496,490 32,215,067 36,547,665
Cumulative Savings (Dth)
Achievable Economic 134,786 272,271 749,007 1,786,294 3,136,102
Achievable Technical 297,165 651,909 1,927,022 4,672,773 7,427,167
Technical Potential 683,777 1,382,691 3,717,219 8,099,510 13,024,530
Energy Savings (% of Baseline)
Achievable Economic 0.5%0.9%2.5%5.5%8.6%
Achievable Technical 1.0%2.2%6.3%14.5%20.3%
Technical Potential 2.3%4.7%12.2%25.1%35.6%
Incremental Savings (Dth)
Achievable Economic 134,786 148,614 172,490 227,703 93,621
Achievable Technical 297,165 357,151 480,848 589,559 190,622
Technical Potential 693,690 723,398 846,959 934,311 439,915
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
40.0%
2023 2024 2027 2032 2042
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic
Achievable Technical
Technical Potential
0
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
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
In
c
r
e
m
e
n
t
a
l

S
a
v
i
n
g
s

(
D
t
h
)
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)18,489,822 18,688,449 19,295,674 20,539,977 23,591,578
Cumulative Savings (Dth)
Achievable Economic 69,555 132,295 356,199 815,071 1,353,411
Achievable Technical 176,790 399,302 1,252,962 3,206,725 4,911,795
Technical Potential 429,994 905,601 2,530,507 5,747,603 9,337,234
Energy Savings (% of Baseline)
Achievable Economic 0.4%0.7%1.8%4.0%5.7%
Achievable Technical 1.0%2.1%6.5%15.6%20.8%
Technical Potential 2.3%4.8%13.1%28.0%39.6%
Incremental Savings (Dth)
Achievable Economic 69,555 73,083 77,290 93,201 52,239
Achievable Technical 176,790 223,252 327,945 406,973 135,250
Technical Potential 439,907 479,545 598,656 678,285 347,207
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
40.0%
45.0%
2023 2024 2027 2032 2042
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic
Achievable Technical
Technical Potential
Rank Idaho –Achievable Economic UCT
Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Furnace 216,304 37.1%
2 Connected Thermostat -ENERGY STAR
(1.0)155,844 26.7%
3 ENERGY STAR Home Design 65,417 11.2%
4 Building Shell -Whole-Home Aerosol
Sealing 53,919 9.3%
5 Insulation -Ceiling Installation 38,952 6.7%
6 Gas Furnace -Maintenance 27,441 4.7%
7 Windows -Low-e Storm Addition 9,508 1.6%
8 Behavioral Programs 4,155 0.7%
9 Circulation Pump -Timer 2,744 0.5%
10 Insulation -Wall Sheathing 2,433 0.4%
Subtotal 576,716 99.0%
Total Savings in Year 582,595 100.0%
Ran
k
Washington –Achievable Economic
TRC Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Furnace 420,956 54.6%
2 Building Shell -Whole-Home Aerosol
Sealing 124,541 16.2%
3 Insulation -Ceiling Installation 70,670 9.2%
4 Gas Furnace -Maintenance 51,736 6.7%
5 Connected Thermostat -ENERGY STAR
(1.0)30,781 4.0%
6 Boiler 18,677 2.4%
7 ENERGY STAR Home Design 9,959 1.3%
8 Behavioral Programs 9,196 1.2%
9 Building Shell -Liquid-Applied Weather-
Resistive Barrier 8,367 1.1%
10 Windows -Low-e Storm Addition 5,914 0.8%
Subtotal 750,798 97.4%
Total Savings in Year 770,816 100.0%
Single Family
69%
Multi-Family
5%
Mobile Home
3%
LI -Single Family
17%
LI -Multi-Family
4%
LI -Mobile Home
2%
Residential Gas Consumption by Segment
Regular Income
76%
Low Income
24%
20 Year Cumulative Achievable Economic Potential by
Income Group
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
50,000
100,000
150,000
200,000
250,000
300,000
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
In
c
r
e
m
e
n
t
a
l

S
a
v
i
n
g
s

(
D
t
h
)
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)10,412,372 10,470,104 10,678,947 11,153,754 12,435,557
Cumulative Savings (Dth)
Achievable Economic 61,744 132,968 375,053 935,651 1,717,894
Achievable Technical 116,869 245,560 656,182 1,430,257 2,450,164
Technical Potential 249,222 468,009 1,163,993 2,307,056 3,606,368
Energy Savings (% of Baseline)
Achievable Economic 0.6%1.3%3.5%8.4%13.8%
Achievable Technical 1.1%2.3%6.1%12.8%19.7%
Technical Potential 2.4%4.5%10.9%20.7%29.0%
Incremental Savings (Dth)
Achievable Economic 61,744 72,005 91,557 130,956 38,704
Achievable Technical 116,869 130,350 149,230 179,030 52,649
Technical Potential 249,222 239,290 243,712 251,628 89,333
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
2023 2024 2027 2032 2042
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic
Achievable Technical
Technical Potential
Rank Idaho –Achievable Economic UCT
Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Insulation -Wall Cavity 113,825 22.1%
2 Windows -Secondary Glazing Systems 57,922 11.2%
3 Insulation -Ceiling 57,598 11.2%
4 Ducting -Repair and Sealing 53,296 10.3%
5 Water Heater 40,158 7.8%
6 Furnace 38,787 7.5%
7 Fryer 29,491 5.7%
8 Gas Boiler -Thermostatic Radiator
Valves 15,741 3.1%
9 Water Heater -Circulation Pump
Controls 15,684 3.0%
10 HVAC -Energy Recovery Ventilator 14,140 2.7%
Subtotal 436,642 84.6%
Total Savings in Year 516,012 100.0%
Rank Washington –Achievable Economic
TRC Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Insulation -Wall Cavity 146,946 12.2%
2 Boiler 138,797 11.5%
3 Ducting -Repair and Sealing 121,645 10.1%
4 Windows -Secondary Glazing Systems 111,172 9.2%
5 Insulation -Ceiling 84,303 7.0%
6 Water Heater 79,479 6.6%
7 Furnace 78,323 6.5%
8 HVAC -Energy Recovery Ventilator 58,049 4.8%
9 Strategic Energy Management 41,377 3.4%
10 Broiler 36,258 3.0%
Subtotal 896,351 74.6%
Total Savings in Year 1,201,882 100.0%
0
100,000
200,000
300,000
400,000
500,000
600,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
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
In
c
r
e
m
e
n
t
a
l

S
a
v
i
n
g
s

(
D
t
h
)
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)511,926 517,132 521,869 521,336 520,530
Cumulative Savings (Dth)
Achievable Economic 3,487 7,008 17,756 35,571 64,796
Achievable Technical 3,506 7,047 17,879 35,791 65,208
Technical Potential 4,561 9,081 22,719 44,852 80,927
Energy Savings (% of Baseline)
Achievable Economic 0.7%1.4%3.4%6.8%12.4%
Achievable Technical 0.7%1.4%3.4%6.9%12.5%
Technical Potential 0.9%1.8%4.4%8.6%15.5%
Incremental Savings (Dth)
Achievable Economic 3,487 3,526 3,643 3,546 2,679
Achievable Technical 3,506 3,549 3,673 3,557 2,723
Technical Potential 4,561 4,563 4,591 4,397 3,376
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
16.0%
18.0%
2023 2024 2027 2032 2042
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic
Achievable Technical
Technical Potential
Rank Idaho –Achievable Economic UCT
Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Process -Heat Recovery 22,382 79.8%
2 Process Boiler -Hot Water Reset 1,207 4.3%
3 Process Boiler -Stack Economizer 814 2.9%
4 Process Boiler -Insulate Steam
Lines/Condensate Tank 785 2.8%
5 Process Boiler -Burner Control
Optimization 568 2.0%
6 Process Boiler -Insulate Hot Water Lines 395 1.4%
7 Destratification Fans (HVLS)344 1.2%
8 Insulation -Wall Cavity 332 1.2%
9 Insulation -Ceiling 257 0.9%
10 Unit Heater 146 0.5%
Subtotal 27,230 97.1%
Total Savings in Year 28,042 100.0%
Rank Washington –Achievable Economic
TRC Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Process -Heat Recovery 29,905 81.4%
2 Process Boiler -Hot Water Reset 1,398 3.8%
3 Process Boiler -Stack Economizer 1,086 3.0%
4 Process Boiler -Insulate Steam
Lines/Condensate Tank 919 2.5%
5 Process Boiler -Burner Control
Optimization 760 2.1%
6 Process Boiler -Insulate Hot Water Lines 462 1.3%
7 Destratification Fans (HVLS)453 1.2%
8 Insulation -Wall Cavity 374 1.0%
9 Insulation -Ceiling 298 0.8%
10 Unit Heater 183 0.5%
Subtotal 35,838 97.5%
Total Savings in Year 36,754 100.0%
Data
Collection
Align with EE
Potential Study
•Market
Profiles
Secondary
Sources
•DR Program
Evaluation
Reports from
other Utilities
Characterize
the Market
Segmentation by
Customer Class
•Residential
•Commercial
•Industrial
Develop list of DR
Options
Program Options
•Behavioral
•DLC Water Heating
•DLC Smart Thermostats –BYOT
•Third Party Contracts
•Time-of-Use
•Variable Peak Pricing
Characterize
the Options
Develop Program
Assumptions
•Impacts
•Participation
•End Use
Saturations
•Costs
•Incentives
Estimate
Potential
Achievable Potential
•Integrated program
options without
participant overlap
•
•
•
•
•
•
•
33
𝑃𝑟𝑜𝑔𝑟𝑎𝑚𝐼𝑚𝑝𝑎𝑐𝑡𝑦𝑒𝑎𝑟,𝑝𝑟𝑜𝑔𝑟𝑎𝑚
=𝑃𝑒𝑟𝐶𝑢𝑠𝑡𝑜𝑚𝑒𝑟𝑃𝑒𝑎𝑘𝐼𝑚𝑝𝑎𝑐𝑡𝑦,𝑝∗𝐸𝑙𝑖𝑔𝑖𝑏𝑙𝑒𝑃𝑎𝑟𝑡𝑖𝑐𝑖𝑝𝑎𝑛𝑡𝑠𝑦,𝑝∗𝑃𝑎𝑟𝑡𝑖𝑐𝑖𝑝𝑎𝑡𝑖𝑜𝑛𝑅𝑎𝑡𝑒𝑦,𝑝
∗𝐸𝑞𝑢𝑖𝑝𝑚𝑒𝑛𝑡𝑆𝑎𝑡𝑢𝑟𝑎𝑡𝑖𝑜𝑛𝑅𝑎𝑡𝑒𝑦,𝑝
Washington Potential 2024 2025 2026 2032 2042
Baseline Forecast (Dth)13,643 13,812 13,982 15,025 16,946
Market Potential 39 108 238 355 403
Peak Reduction % of Baseline 0.3%0.8%1.7%2.4%2.4%
Potential Forecast 13,604 13,704 13,743 14,670 16,543
Idaho Potential 2024 2025 2026 2032 2042
Baseline Forecast (Dth)6,955 7,073 7,203 7,806 8,952
Market Potential 14 39 87 134 157
Peak Reduction % of Baseline 0.2%0.6%1.2%1.7%1.8%
Potential Forecast 6,941 7,034 7,115 7,672 8,795
WA -Winter Potential 2024 2025 2026 2032 2042
Baseline Forecast (Dth)13,643 13,812 13,982 15,025 16,946
Achievable Potential (Dth)39 108 238 355 403
Behavioral 8 15 25 31 35
DLC Water Heating 6 19 46 72 81
DLC Smart Thermostats -BYOT 12 37 86 135 154
Time-of-Use 2 6 14 20 23
Variable Peak Pricing 10 30 66 96 109
Third Party Contracts 0 1 1 1 1
ID -Winter Potential 2024 2025 2026 2032 2042
Baseline Forecast (Dth)6,955 7,073 7,203 7,806 8,952
Achievable Potential (Dth)14 39 87 134 157
Behavioral 4 8 13 16 18
DLC Water Heating 3 11 25 40 48
DLC Smart Thermostats -BYOT 7 20 48 77 90
Time-of-Use -----
•
•
•
•
•
•
•
•
•
Income Class Responses Avg.
Therms/HH
Δ from
Regular
Non-Low-Income 180 636 n/a
Low Income 55 544 -14%
Gas Customer Intensity by Income Level –RBSA II
HH Size Low Income
Threshold
1 $25,760
2 $34,840
3 $43,920
4 $53,000
5 $62,080
6 $71,160
7 $80,240
8 $89,320
Income Groups by Household Size
Segment Households % of All Homes Usage (Dth)Therms / HH
Single Family 12,289 65.0%622,559 539
Multi-Family 4,428 23.4%88,679 200
Mobile Home 2,197 11.6%113,191 515
Total 18,914 100.0%864,429 457
Single Family
77%
Multi-Family
10%
Mobile Home
13%
Gas Use by Segment
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
2021 2024 2027 2030 2033 2036 2039 2042
Consumption
(Dth)LoadMAP Reference Baseline
Achievable Economic TRC Potential
Achievable Technical Potential
Technical Potential 0
5,000
10,000
15,000
20,000
25,000
30,000
2023 2026 2029 2032 2035 2038 2041
Incremental
Savings
(Dth)
Annual Incremental Potential
Achievable Economic TRC Potential Achievable Technical Potential
Technical Potential
Summary of Energy Savings (Dth), Selected Years 2023 2024 2025 2032 2042
Baseline Forecast (Dth)914,784 919,566 924,873 970,712 1,084,508
Cumulative Savings (Dth)
Achievable Economic TRC Potential 3,816 7,383 12,114 46,713 87,816
Achievable Technical Potential 8,877 18,471 30,274 136,654 193,386
Technical Potential 14,319 28,147 44,987 186,349 280,253
Energy Savings (% of Baseline)
Achievable Economic TRC Potential 0.4%0.8%1.3%4.8%8.1%
Achievable Technical Potential 1.0%2.0%3.3%14.1%17.8%
Technical Potential 1.6%3.1%4.9%19.2%25.8%
Incremental Savings (Dth)
Achievable Economic TRC Potential 3,816 3,991 4,768 5,691 4,215
Achievable Technical Potential 8,877 10,082 12,013 16,345 4,560
Technical Potential 14,319 15,043 17,214 22,036 9,225
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
2023 2024 2025 2032 2042
%
o
f

B
a
s
e
l
i
n
e
Achievable Economic TRC Potential
Achievable Technical Potential
Technical Potential
Rank Oregon –Achievable Economic TRC
Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Water Heater -Intermittent Ignition System 20,106 22.9%
2 Connected Thermostat -ENERGY STAR (1.0)17,561 20.0%
3 Furnace 14,529 16.5%
4 ENERGY STAR Home Design 13,955 15.9%
5 Insulation -Ceiling Installation 6,757 7.7%
6 Gas Furnace -Maintenance 4,885 5.6%
7 Circulation Pump -Timer 1,625 1.9%
8 Windows -Low-e Storm Addition 1,530 1.7%
9 Clothes Washer -ENERGY STAR (8.0)1,475 1.7%
10 Water Heater -Thermostatic Shower
Restriction Valve 1,313 1.5%
Subtotal 83,737 95.4
Total Savings in Year 87,816 100.0%
Space
Heating
22%
Water
Heating
10%
Food
Preparation
2%
Process
62%
Miscellaneous
4%
Transport Gas Use by End Use (2021)
Washington
63%
Oregon
37%
Transport Gas Use by State (2021)
College
18%
Health
8%
Misc
Commercial
4%Industrial
70%
Transport Gas Use by Segment (2021)
•
•
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
50,000
100,000
150,000
200,000
250,000
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
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)12,630,414 12,603,587 12,536,256 12,461,252 12,381,843
Cumulative Savings (Dth)
Achievable Economic 107,191 218,064 559,247 1,152,647 1,948,052
Achievable Technical 124,024 252,377 647,251 1,314,951 2,159,878
Technical Potential 188,234 376,388 933,031 1,815,113 2,880,756
Energy Savings (% of Baseline)
Achievable Economic 0.8%1.7%4.5%9.2%15.7%
Achievable Technical 1.0%2.0%5.2%10.6%17.4%
Technical Potential 1.5%3.0%7.4%14.6%23.3%
Incremental Savings (Dth)
Achievable Economic 105,937 110,468 118,059 122,313 56,419
Achievable Technical 124,024 129,555 139,511 140,942 59,652
Technical Potential 188,234 190,900 194,773 185,788 90,879
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)3,876,336 3,850,572 3,786,849 3,718,685 3,652,695
Cumulative Savings (Dth)
Achievable Economic 46,984 97,364 253,184 532,339 813,871
Achievable Technical 63,623 131,295 340,370 694,783 1,028,470
Technical Potential 113,277 226,642 555,555 1,058,457 1,507,428
Energy Savings (% of Baseline)
Achievable Economic 1.2%2.5%6.7%14.3%22.3%
Achievable Technical 1.6%3.4%9.0%18.7%28.2%
Technical Potential 2.9%5.9%14.7%28.5%41.3%
Incremental Savings (Dth)
Achievable Economic 45,776 49,907 54,949 59,216 10,220
Achievable Technical 63,623 68,758 76,240 78,244 13,377
Technical Potential 113,277 115,781 117,358 109,862 34,382
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
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
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Rank Oregon –Achievable Economic TRC
Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Water Heater -Circulation Pump
Controls 16,536 11.7%
2 Boiler 13,554 9.6%
3 Insulation -Wall Cavity 11,059 7.8%
4 Ducting -Repair and Sealing 10,949 7.7%
5 Windows -Secondary Glazing Systems 9,204 6.5%
6 Water Heater -Solar System 9,040 6.4%
7 Water Heater 8,241 5.8%
8 Insulation -Ceiling 7,362 5.2%
9 Gas Boiler -Thermostatic Radiator
Valves 7,030 5.0%
10 HVAC -Energy Recovery Ventilator 6,801 4.8%
Subtotal 99,777 70.5%
Total Savings in Year 141,627 100.0%
Rank Washington –Achievable Economic
TRC Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Insulation -Wall Cavity 88,949 13.5%
2 Ducting -Repair and Sealing 75,713 11.5%
3 Windows -Secondary Glazing Systems 75,654 8.3%
4 HVAC -Energy Recovery Ventilator 54,894 7.8%
5 Insulation -Ceiling 51,005 7.5%
6 Gas Boiler -Thermostatic Radiator
Valves 49,198 6.0%
7 Water Heater 39,310 5.5%
8 Water Heater -Circulation Pump
Controls 36,069 5.2%
9 Gas Boiler -Insulate Steam
Lines/Condensate Tank 34,275 3.6%
10 Hydronic Heating Radiator
Replacement 33,280 3.5%
Subtotal 538,346 72.3%
Total Savings in Year 771,266 100.0%
Summary of Energy Savings (Dth), Selected Years 2023 2024 2027 2032 2042
Reference Baseline (Dth)8,754,078 8,753,015 8,749,407 8,742,566 8,729,148
Cumulative Savings (Dth)
Achievable Economic 60,207 120,700 306,063 620,308 1,134,181
Achievable Technical 60,401 121,082 306,881 620,168 1,131,408
Technical Potential 74,957 149,746 377,476 756,657 1,373,328
Energy Savings (% of Baseline)
Achievable Economic 0.7%1.4%3.5%7.1%13.0%
Achievable Technical 0.7%1.4%3.5%7.1%13.0%
Technical Potential 0.9%1.7%4.3%8.7%15.7%
Incremental Savings (Dth)
Achievable Economic 60,161 60,562 63,109 63,097 46,199
Achievable Technical 60,401 60,798 63,272 62,698 46,275
Technical Potential 74,957 75,119 77,414 75,926 56,497
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
10,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041
Consumption
(Dth)
LoadMAP Reference Baseline
Achievable Economic
Achievable Technical Potential
Technical Potential
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
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
Annual Incremental Potential
Achievable Economic Achievable Technical Potential Technical Potential
Rank Oregon –Achievable Economic TRC
Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Process -Heat Recovery 409,396 77.5%
2 Process Boiler -Hot Water Reset 24,562 4.6%
3 Process Boiler -Insulate Steam
Lines/Condensate Tank 16,222 3.1%
4 Process Boiler -Stack Economizer 15,124 2.9%
5 Process Boiler -Burner Control
Optimization 10,364 2.0%
6 Process Boiler -Insulate Hot Water
Lines 7,905 1.5%
7 Insulation -Wall Cavity 7,332 1.4%
8 Boiler 6,480 1.2%
9 Destratification Fans (HVLS)5,839 1.1%
10 Insulation -Ceiling 5,645 1.1%
Subtotal 508,868 96.3%
Total Savings in Year 528,593 100.0%
Rank Washington –Achievable Economic
TRC Potential
2042
Achievable
Economic
Potential
(Dth)
% of
Total
Savings
1 Process -Heat Recovery 467,011 77.2%
2 Process Boiler -Hot Water Reset 28,019 4.6%
3 Process Boiler -Insulate Steam
Lines/Condensate Tank 18,505 3.1%
4 Process Boiler -Stack Economizer 17,253 2.9%
5 Process Boiler -Burner Control
Optimization 11,822 2.0%
6 Boiler 10,861 1.8%
7 Process Boiler -Insulate Hot Water Lines 9,017 1.5%
8 Insulation -Wall Cavity 8,260 1.4%
9 Destratification Fans (HVLS)6,612 1.1%
10 Insulation -Ceiling 6,360 1.1%
Subtotal 583,720 96.4%
Total Savings in Year 605,243 100.0%
•
Includes
•To the extent possible, the same forecast drivers
used in the official load forecast, particularly
customer growth, natural gas prices, normal
weather, income growth, etc.
•Trends in appliance saturations, including
distinctions for new construction.
•Efficiency options available for each technology ,
with share of purchases reflecting codes and
standards (current and finalized future standards)
•Expected impact of appliance standards that are
“on the books”
•Expected impact of building codes, as reflected in
market profiles for new construction
•Market baselines when present in regional
planning assumptions
Excludes
•Expected impact of naturally occurring efficiency
(except market baselines)
•Exception:RTF workbooks have a market
baseline for lighting, which AEG’s models also
use.
•Impacts of current and future demand-side
management programs
•Potential future codes and standards not yet
enacted
Component TRC UCT
Avoided Energy Benefit Benefit
Non-Energy Impacts*Cost/Benefit
Incremental Cost Cost
Incentive Cost
Administrative Cost Cost Cost
10% Conservation Credit Benefit
•
•
•
•
60
0%
20%
40%
60%
80%
100%
1 4 7 10 13 16 19
Lost Opportunity Ramp Rates
LO12Med LO5Med LO3Slow
0%
2%
4%
6%
8%
10%
1 4 7 10 13 16 19
Retrofit Ramp Rates
Retro12Med Retro5Med Retro3Slow
Your Trusted Insights Partner Since 1978
Avista IRP Clean Energy Research
April 2022
Research Overview
2
Objectives
Determine willingness to pay for the implementation of clean
energy among Avista customers
Establish baseline of environmental concerns; perceived
responsibility of individuals, businesses, and Avista
specifically
Understand customer tradeoffs between bill increases
and carbon emission goals
Explore perceptions associated with Avista should they
invest in carbon-neutral or carbon-free emissions
Gauge perceptions specific to natural gas preferences
and tradeoffs
Quantify differences by state, customer type, green
perceptions, and demographic factors
Methodology
Web survey with Avista customers.
•Customers from Washington, Idaho, and Oregon
sourced randomly by email
•Survey optimized for both desktop and mobile
•Conducted in April 2022
•Final sample size of n=1,100
Proportional representation of state and service type.
Respondents screened to ensure appropriate target
•Avista customer age 18+
•Has or shares household finance and utility bill
responsibility
•Not employed by a utility company, or in media,
advertising, or market research firm
WA ID OR
52%29%20%
G GE E
25%47%29%
Report Interpretation
•All significant differences are reported at the 95% confidence level or higher. The total sample size of n=1,100 has a maximum
sampling variability of +/-3.0% at the 95% level.
•Some percentages may not add to 100% due to rounding
Analysis Approach
3
This study incorporates a conjoint exercise to force tradeoffs between various green initiatives and customer willingness to pay.
Respondents review various combinations of energy goals, timeframes for that goal, energy sources, and potential bill increases,
and select their “most preferred” from a series of options (including an option for “none” each time).
Subsequent analysis produces utility scores for each individual attribute, allowing us to calculate which combination has the
broadest appeal.
Energy Goal
Investing in renewables to achieve carbon neutrality
Providing 100% carbon-free power by only generating energy through clean energy sources
Goal Timeframe
In the next year
In the next 5 years (by 2027)
In the next 10 years (by 2032)
In the next 25 years (by 2047)
Bill Increase
2% monthly increase
5% monthly increase
10% monthly increase
20% monthly increase
50% monthly increase
100% monthly increase
Energy Source
Sourced locally
Sourced regionally
Sourced from anywhere
Key Takeaways
4
When faced with tradeoffs, price is the prevailing factor.
While the majority of customers find importance in
sourcing green or local energy, they are only willing to pay
so much. Anything beyond a 10% monthly bill increase
shows significant declines in popularity.
If bill increases to invest in carbon-free or carbon-neutral
options are kept below 10%, the specific energy goal,
timeframe, local vs. regional source are less important.
Price is Important.
Increases beyond 10% monthly still appeal to a certain
subset of customers, particularly those who place great
importance on “green,” and/or when the goal can be
achieved within the next 10 years.
Some customers see beyond price
Overall, roughly one in five do not find importance in
being “green”
When evaluating various green investment options, 17%
reject all, including more ambitious outcomes for just a 2%
increase
Three in ten say they would be likely to seek bill
assistance or consider moving to another state if bill were
to increase due to Avista investing in carbon-free or
carbon-neutral energy
Any increase to invest in “green” energy will
alienate some customers
Detailed Findings:
Green Insights
At a personal level, the concept of being environmentally friendly or “green” is important to
nearly eight in ten customers
6
8%
12%
36%
42%
4 - Very
3 - Somewhat
2 - Not very
1 - Not at all
Unsure
Q1. How important is the concept of being environmentally friendly or "green" to you personally?
78%
Personal Importance of “Green”
(n=1,100)
find the concept of
being “green”
important
Key Differences and Insights
Green importance differs by state.
Customers in Oregon and Washington are significantly more likely than
those in Idaho to find the concept of “green” to be important.
83%80%71%
Green importance differs by area.
Customers in urban areas are significantly more likely than those in rural
areas to find the concept important.
Green importance differs by gender.
Women are significantly more likely than
men to find it important.
Green importance is consistent across age and income categories.
85%73%
urban
84%
suburban
80%
rural
75%
Customers place similar importance on the “green” responsibility of themselves, businesses,
and utility companies
7
Q1. How important is the concept of being environmentally friendly or "green" to you personally?
Q3. How important is it for general companies or organizations you do business with to be environmentally friendly or "green?“
Q4. How important is it specifically for utility companies like Avista to be environmentally friendly or "green?"
8%8%8%
12%13%12%
36%36%
29%
42%40%49%
Personal Companies or
Organizations
Utility Companies Like
Avista
4 - Very
3 - Somewhat
2 - Not very
1 - Not at all
Unsure
Importance of “Green” For…
(n=1,100)
78%
find the concept of
personally being
“green” important
77%
find it important for
companies they do
business with to be
“green”
79%
find it important for
utility companies like
Avista to be “green”
Personal importance to be “green” is driven by responsibility to protect the planet; for those
believing it is not important to personally be green, cost is the main reason
8
Q2A. Why is it [very/somewhat important] to personally be environmentally friendly or "green?“
Q2B. Why is it [not very/not at all important] to personally be environmentally friendly or "green?"
Why is it Important?
(n=860)
Why is it NOT Important?
(n=224)
•To protect our planet/environment (38%)
•Good for the future/future generations (24%)
•Responsibility/right thing to do/stewardship (16%)
•To address climate change/global warming (13%)
•Cost/it’s expensive (29%)
•Not real/hoax/misinformation (25%)
•“Green” is worse for the environment, not better (20%)
•Politics/Political Agenda (17%)
“If we take care of our planet, it will in turn last for generations
to come. If we take care of it, it will always take care of us.”
“Every person has to take responsibility for the environment.
We are stewards of the Earth after all. That responsibility
cannot, and should, not be abrogated. If we don't stand up and
insist on choices that protect that for which we are responsible
then no one will and we necessarily choose a very dark
alternative for an uncertain and unjust future.”
“Because the terms ‘environmentally friendly’ and ‘green’ have
been distorted to the point where they have little relevance to
actually protecting the environment.”
“In the 60+ years I've been around, the air land and waters
have markedly improved. As the current crop of ‘renewables’
are unreliable and expensive, good ol' fossil fuels are the best
bang for bucks.”
Solar and wind are commonly associated with both renewable and clean energy
9
Q6. When you hear the words "renewable energy," what sources come to mind?
Q7. When you hear the words "clean energy," what sources come to mind?
Top Sources Associated With…
(n=1,100)
91%
89%
73%
34%
29%
28%
20%
6%
3%
<1%
2%
1%
84%
81%
67%
20%
30%
31%
31%
3%
31%
0%
2%
4%
Solar
Wind
Hydroelectric
Biofuels
Nuclear energy
Hydrogen
Natural gas
Coal
Geothermal
Wood
Another energy source
None of these
Renewable Energy Clean Energy
Both solar and wind have somewhat
higher associations with being
renewable than with being clean
Biofuels are more closely associated with being
renewable than with being clean
Natural gas and geothermal have closer associations with
being clean than with being renewable
Power from local resources as much as possible 87%
Power from renewable resources as much as
possible 84%
Prioritize low costs for customers above
renewable energy options 73%
Provide customers options to contribute towards
lowering carbon emissions 72%
Achieve carbon neutrality in energy production by
acquiring renewable power equal to energy use 67%
Achieve 100% carbon-free power by generating
energy entirely from clean resources 65%
Offer customer options (rebates, charging
stations, etc.) for electric vehicles 61%
Invest in electric vehicles and/or vehicles with
lower carbon emissions for their own fleet 60%
Generate power from as many resources as
possible 58%
3%
1%
4%
3%
5%
3%
4%
2%
6%
4%
6%
8%
13%
16%
17%
20%
22%
13%
6%
9%
15%
12%
12%
15%
15%
16%
23%
38%
27%
30%
34%
25%
27%
27%
27%
30%
49%
57%
42%
38%
42%
38%
35%
33%
28%
Unsure 1 - Not at all important 2 - Not very important 3 - Somewhat important 4 - Very Important
When considering potential utility company initiatives, customers place highest
importance on generating power from local and renewable resources
10
Q5. How important is it for utility companies like Avista to do each of the following?
Top Box
Importance
Customers place near equal importance on Avista achieving carbon neutrality and on achieving
100% carbon-free power
11
5%
16%
12%
25%
42% 4 - Very
3 - Somewhat
2 - Not very
1 - Not at all
Unsure
Q5. How important is it for utility companies like Avista to do each of the following?
Achieve carbon neutrality in energy production by acquiring renewable power equal to energy use.
Achieve 100% carbon-free power by generating energy entirely from clean resources.
67%
Importance For Avista to
Achieve Carbon Neutrality
(n=1,100)
find it important
for utility
companies like
Avista to achieve
carbon neutrality
3%
17%
15%
27%
38% 4 - Very
3 - Somewhat
2 - Not very
1 - Not at all
Unsure
65%
Importance of Avista Achieving
100% Carbon-Free Power
(n=1,100)
find it important for
utility companies
live Avista to
achieve 100%
carbon-free power
The importance of Avista achieving these goals differs by certain key audiences
12
Q5H. How important is it for utility companies like Avista to do each of the following? Achieve carbon neutrality in energy production by acquiring renewable
power equal to energy use. | Achieve 100% carbon-free power by generating energy entirely from clean resources.
Key Differences and Insights: Carbon Neutrality
Carbon neutrality importance differs by state.
Customers in Oregon are significantly more likely than those in
Idaho to say it is important for to achieve carbon neutrality.
73%67%61%
Carbon neutrality importance differs by area.
Carbon neutrality importance differs by gender.
Women are significantly more likely than
men to find it important.
75%60%
urban
72%
suburban
69%
rural
63%
Importance of carbon neutrality differs by income.
Customers in urban areas are significantly more likely than those
in rural areas to find the achievement important.
Those making $150K+ in household income
are significantly more likely than those
making less than $60K to say it is important.
<$60K $150K+
62%72%
Key Differences and Insights: 100% Carbon-Free
Carbon-free power importance differs by state.
Customers in Oregon are significantly more likely than those in
Idaho to find an achievement of 100% carbon-free to be important.
69%66%60%
Carbon-free power importance differs by area.
Customers in urban and suburban areas are significantly more
likely than those in rural areas to find the achievement important.
Importance of 100% carbon-free power differs by gender.
Women are significantly more likely than
men to find it important.
Importance is consistent across age and income
categories.
73%59%
urban
74%
suburban
67%
rural
59%
Detailed Findings:
Green Investment
Conjoint Results Summary: Overall Feature Scoring
Category Attribute Result Meaning
Energy Goal
Investing in renewables to achieve carbon neutrality 0.55 If all other factors are held consistent, providing
100% carbon-free energy vs. investing in carbon
neutrality has almost no impactProviding 100% carbon-free power by only
generating energy through clean energy sources 0.59
Goal Timeframe
In the next year 0.60 There is a drop-off in utility at the 25-year level;
however, there is little differentiation between in
the next year, five years, or ten years when all other
factors are held consistent
In the next 5 years (by 2027)0.59
In the next 10 years (by 2032)0.59
In the next 25 years (by 2047)0.52
Bill Increase
2% monthly increase 0.83 If all other factors are held consistent, the monthly
bill increase has the biggest impact; utility drops off
considerably with more than a 10% increase
It should be noted, however, that those placing high
importance on being green demonstrate a
willingness to pay beyond the 10% mark
5% monthly increase 0.78
10% monthly increase 0.69
20% monthly increase 0.53
50% monthly increase 0.36
100% monthly increase 0.25
Energy Source
Sourced locally 0.59 Though 87% find sourcing power locally to be
important, ultimately there is little differentiation
between local, regional, and anywhere, when
considering other factors along with locality
Sourced regionally 0.58
Sourced from anywhere 0.55
None 0.39
Overall, 17% of respondents said no to all options
presented, indicating no willingness to pay for green
investments
C2. Now, we will present you with a series of 12 screens, each with a set of options for an energy package that could be made available in the future for
your home. For each set, please indicate the one you would be most likely to choose. You can always select “none” if you would not select any of the
options.
(n=1,100)
Conjoint Results Summary: Feature Scores by Personal Green Importance
Category Attribute Feature Score by Green Importance
Very
(n=445)
Somewhat
(n=399)
Not
(n=331)
Energy Goal
Investing in renewables to achieve carbon neutrality 0.67 0.53 0.38
Providing 100% carbon-free power by only
generating energy through clean energy sources 0.76 0.54 0.35
Goal Timeframe
In the next year 0.79 0.54 0.33
In the next 5 years (by 2027)0.76 0.54 0.35
In the next 10 years (by 2032)0.72 0.55 0.38
In the next 25 years (by 2047)0.59 0.52 0.39
Bill Increase
2% monthly increase 0.87 0.86 0.71
5% monthly increase 0.88 0.78 0.60
10% monthly increase 0.85 0.65 0.45
20% monthly increase 0.74 0.46 0.24
50% monthly increase 0.53 0.30 0.13
100% monthly increase 0.42 0.17 0.04
Energy Source
Sourced locally 0.72 0.55 0.39
Sourced regionally 0.73 0.55 0.37
Sourced from anywhere 0.69 0.51 0.34
None 0.14 0.43 0.80
C2. Now, we will present you with a series of 12 screens, each with a set of options for an energy package that could be made available in the future for
your home. For each set, please indicate the one you would be most likely to choose. You can always select “none” if you would not select any of the
options.
Conjoint Results Summary: Feature Scores by Service Type
Category Attribute Feature Score by Service Type
Gas Only
(n=271)
Dual
(n=513)
Electric Only
(n=316)
Energy Goal
Investing in renewables to achieve carbon neutrality 0.57 0.56 0.54
Providing 100% carbon-free power by only
generating energy through clean energy sources 0.61 0.60 0.58
Goal Timeframe
In the next year 0.63 0.60 0.58
In the next 5 years (by 2027)0.62 0.59 0.57
In the next 10 years (by 2032)0.61 0.59 0.57
In the next 25 years (by 2047)0.52 0.52 0.51
Bill Increase
2% monthly increase 0.83 0.84 0.82
5% monthly increase 0.79 0.79 0.76
10% monthly increase 0.71 0.70 0.66
20% monthly increase 0.56 0.53 0.50
50% monthly increase 0.39 0.35 0.35
100% monthly increase 0.28 0.24 0.24
Energy Source
Sourced locally 0.61 0.59 0.57
Sourced regionally 0.60 0.59 0.56
Sourced from anywhere 0.57 0.55 0.53
None 0.36 0.38 0.42
C2. Now, we will present you with a series of 12 screens, each with a set of options for an energy package that could be made available in the future for
your home. For each set, please indicate the one you would be most likely to choose. You can always select “none” if you would not select any of the
options.
Conjoint Results Summary: Optimal Feature Combination
Category Attribute
Energy Goal Investing in renewables to achieve carbon neutrality
Goal Timeframe In the next year
Bill Increase 2% monthly increase
Energy Source Sourced locally
C2. Now, we will present you with a series of 12 screens, each with a set of options for an energy package that could be made available in the future for
your home. For each set, please indicate the one you would be most likely to choose. You can always select “none” if you would not select any of the
options.
(n=1,100)
Unsurprisingly, the optimal utility results from customers achieving the most for the lowest cost. While this is not a
realistic scenario, it provides a baseline for any changes made to move toward carbon-free or carbon-neutral energy in
the future. Subsequent slides show change from optimal should other factors be considered.
Conjoint Summary: Difference from Optimal Combination (Based on Goal)
18
0.0%-0.2%
Investing in renewables to achieve carbon
neutrality
Providing 100% carbon-free power by only
generating energy through clean energy
sources
Optimal Feature Combination
Energy Goal Investing in renewables to
achieve carbon neutrality
Goal Timeframe In the next year
Bill Increase 2% monthly increase
Energy Source Sourced locally
Change from Optimal Based on Goal
If all other factors are held consistent,
providing 100% carbon-free energy
vs. investing in carbon neutrality has
almost no impact
Conjoint Summary: Difference from Optimal Combination (Based on Timeframe)
19
0.0%-0.4%-0.5%
-3.2%
In the next year In the next 5 years
(by 2027)
In the next 10 years
(by 2032)
In the next 25 years
(by 2047)
Optimal Feature Combination
Energy Goal Investing in renewables to
achieve carbon neutrality
Goal Timeframe In the next year
Bill Increase 2% monthly increase
Energy Source Sourced locally
Change from Optimal Based on Timeframe
If all other factors are held consistent, a
shorter timeline has minimal impact; utility
drops off after 10 years
Conjoint Summary: Difference from Optimal Combination (Based on Bill Increase)
20
Optimal Feature Combination
Energy Goal Investing in renewables to
achieve carbon neutrality
Goal Timeframe In the next year
Bill Increase 2% monthly increase
Energy Source Sourced locally
Change from Optimal Based on Monthly Bill Increase
0%
-2%
-5%
-12%
-18%
-22%
2% monthly
increase
5% monthly
increase
10% monthly
increase
20% monthly
increase
50% monthly
increase
100% monthly
increase
If all other factors are held consistent, the
monthly bill increase has the biggest impact;
utility drops off considerably with more than a
10% increase
Conjoint Summary: Difference from Optimal Combination (Based on Source)
21
0.0%-0.2%
-1.5%
Sourced locally Sourced regionally Sourced from anywhere
Optimal Feature Combination
Energy Goal Investing in renewables to
achieve carbon neutrality
Goal Timeframe In the next year
Bill Increase 2% monthly increase
Energy Source Sourced locally
Change from Optimal Based on Source
If all other factors are held consistent, the
source of energy has almost no impact;
energy sourced locally or regionally is only
slightly more preferred
Detailed Findings:
Investment Support
Three in five customers say Avista should invest in carbon-neutral energy even if it involves a
rate increase for customers
23
C3. Should Avista invest in carbon-neutral or carbon-free energy, even if it involves a rate increase for customers?
5%
20%
11%
30%
33%
Yes, definitely
Possibly
Probably not
Definitely not
I’m not sure
Should Avista invest in carbon-neutral or
carbon-free energy, even if it involves a rate
increase for customers?
(n=1,100)
Investment sentiment differs by income.
Those with higher household incomes are
significantly more likely than those making
$60K or less to agree Avista definitely should
invest, even if it involves a rate increase.
Investment sentiment differs by area.
Customers in urban areas are significantly more likely than those in rural
areas to believe Avista should definitely invest.
Lack of investment support differs by gender.
While those supporting investment is consistent
across gender, men are significantly more likely than
women to definitely not support investment.
Support is consistent across age and state.
15%23%
urban
40%
suburban
36%
rural
29%
Key Differences and Insights
<$60K $60K+
28%42%
Supporters say the main reason Avista should invest in carbon-neutral energy is to “save the
planet,” while the main reason to not invest among detractors is “consumer cost”
24
C3A. In your opinion, what is the main reason Avista should invest in carbon-neutral or carbon-free energy, even if it involves a rate increase for customers?
C3B. In your opinion, what is the main reason or reasons Avista should not invest in carbon-neutral or carbon-free energy?
What is the main reason to invest?
(n=697)
What is the main reason to NOT invest?
(n=345)
•To save the planet (21%)
•For a cleaner environment (19%)
•For cleaner air (16%)
•To fight climate change (16%)
•Depends on cost effectiveness (16%)
•It’s the right thing to do (16%)
•Consumer costs/expensive (57%)
•Don’t believe in it/hoax/impossible (17%)
•Unnecessary/will not change anything (16%)
•Politics/political agenda (10%)
“Finite resources are finite. It doesn't matter that you save
money today but have fewer or no energy sources later.”
“Carbon neutral and carbon free energy are ridiculous ideas
that only increase the cost of energy for everyone.”
Nearly seven in ten customers would be likely to “make at home-sacrifices” if their bill
increased due to Avista’s investment in carbon-neutral energy
25
C4. If Avista did go that route, and your bill increased, how likely would you be to take each of the following actions?
2%5%5%5%7%6%5%13%
20%21%32%32%39%47%18%
14%18%
22%21%
27%21%
40%34%38%20%31%16%15%27%27%18%21%8%13%12%
Make at-home
sacrifices, such as
using less heat
Consider rooftop
solar for home
Invest in energy
efficient upgrades
such as new windows
or roof
Consider alternative
fuels at home, such
as wood or propane
Pay a little extra to
help subsidize
customers who may
be struggling
Look for bill
assistance
Consider moving to
another state
If Avista did go that route, and your bill increased, how likely would you be to take
each of the following actions?
(n=1,100)
Unsure Not at all likely Not very likely Somewhat likely Extremely likely
67%60%56%41%40%28%27%
Top Box
Just over a quarter indicate they’d seek bill assistance should rates rise due to Avista pursuing
carbon-neutral or carbon-free options; for over half, this would take a 10% increase or more
26
C4. If Avista did go that route, and your bill increased, how likely would you be to take each of the following actions? Look for bill assistance
C5. What level of bill increase would you envision driving you to seek bill assistance?
6%
39%
27%
16%
13%
Extremely likely
Somewhat likely
Not very likely
Not at all likely
Unsure
Likelihood to Seek Bill Assistance if Bill Increased
(n=1,100)
16%
11%
19%20%
16%18%
<5%
increase
5%
increase
10%
increase
20%
increase
50%
increase or
more
Not sure
Level of Bill Increase That Would Drive Seeking Assistance
(Among Those Likely to Seek Assistance; n=313)
28%
indicate likelihood
to look for bill
assistance
5% increase
or less
10% increase
or more27%55%
Roughly a third indicate they’d consider moving to another state should rates rise; however,
there is uncertainty around what threshold of increase would drive this decision
27
C4. If Avista did go that route, and your bill increased, how likely would you be to take each of the following actions? Consider moving to another state
C6. What level of bill increase would you envision driving you to consider moving to another state?
5%
47%
21%
15%
12%
Extremely likely
Somewhat likely
Not very likely
Not at all likely
Unsure
Likelihood to Move Out of State if Bill Increased
(n=1,100)
11%
7%
11%
20%
15%
36%
<5%
increase
5%
increase
10%
increase
20%
increase
50%
increase or
more
Not sure
Level of Bill Increase That Would Drive Moving Out of State
(Among Those Likely to Consider Moving; n=299)
27%
indicate likelihood
to consider moving
to another state
10% increase
or less
20% increase
or more30%35%
Over half of customers say their favorability would not be impacted if Avista does not achieve
carbon neutrality by 2027
28
C7. If Avista is not able to achieve carbon neutrality by 2027, how would this affect your favorability of the company?
12%
20%
56%
4%
9%
Favorability of the Company if Avista is not able to
Achieve Carbon Neutrality by 2027
(n=1,100)
Increase significantly
Increase somewhat
No impact
Decrease somewhat
Decrease significantly
Potential decreased favorability differs by age.
Younger participants are significantly more likely than
older participants to say their favorability of Avista would
decrease significantly if Avista is not able to achieve carbon
neutrality by 2027.
18-54 55+
15%10%
Potential decreased favorability is consistent
across state, gender, area of residence, and
income categories.
26%
14%
49%
4%
8%
Favorability of the Company if Avista is not able to Provide
100% Carbon-Free Power by 2045
(n=1,100)
Increase significantly
Increase somewhat
No impact
Decrease somewhat
Decrease significantly
Nearly half say their favorability would not change if Avista does not achieve carbon free by
2045
29
C8. If Avista is not able to provide 100% carbon-free power by 2045, how would this affect your favorability of the company?
Potential favorability differs by state.
Customers in Oregon and Washington are significantly more
likely than those in Idaho say their favorability of Avista
would decrease significantly.
29%27%21%
Potential favorability differs by area.
Customers in urban and suburban areas are significantly more
likely than those in rural areas to decrease favorability.
Potential favorability differs by household income
Those with higher household incomes
are significantly more likely than those
making $80K or less to decrease
favorability.
urban
32%
suburban
28%
rural
21%
23%33%
$80K+<$80K
Detailed Findings:
Natural Gas Insights
Nearly half of customers would not consider switching from natural gas to help reduce
carbon emissions
31
N1. How likely would you be to consider switching from natural gas to another energy source to help reduce carbon emissions?
11%
23%
24%
26%
15%
4 - Extremely
3 - Somewhat
2 - Not very
1 - Not at all likely
Unsure
Likelihood to Consider Switching From
Natural Gas to Another Energy Source
(Among Gas Customers, n=784)
42%
are likely to consider
switching from natural
gas to another energy
source
Three-quarters gas customers agree eliminating natural gas should be entirely voluntary
32
N2. How much do you agree or disagree with the following statements concerning natural gas in your home?
7%
4%
11%
12%
7%
15%
15%
6%
14%
12%
17%
36%
52%
54%
12%
11%
12%
10%
15%
15%
13%
22%
24%
30%
27%
19%
14%
14%
52%
46%
35%
33%
23%
4%
4%
Agreement Concerning Eliminating Natural Gas In Home
(Among Gas Customers; n=784)
I’m not sure Completely disagree Somewhat disagree Somewhat agree Completely agree
74%
71%
65%
60%
42%
18%
18%
Top Box
Eliminating natural gas as an option should be entirely
voluntary
I don’t like the idea as an option because it removes my
choice as a customer
Eliminating natural gas as a fuel option makes me concerned
about reliability
I would be more likely to if some or all of the conversion costs
were paid for
Eliminating natural gas as an option makes me concerned
about cooking
Eliminating natural gas as an option should be regulated by
state mandate
Eliminating natural gas as an option should be regulated by
federal mandate
Six in ten would be more likely to convert from natural gas if some or all conversion costs
were covered; of these, 59% would be willing to pay under $1000
33
N2. How much do you agree or disagree with the following statements concerning natural gas in your home?
I would be more likely to eliminate natural gas as an option in my home if some or all of the conversion costs were paid for by the electric utility and/or
government incentives
N3. If you did have to contribute some costs towards converting from natural gas in your home, how much would you consider your max level of contribution?
12%
17%
10%
27%
33%
4 - Completely Agree
3 - Somewhat Agree
2 - Somewhat Disagree
1 - Completely Disagree
Unsure
Would be More Likely to Convert if Some
or All Conversion Costs are Covered
(Among Gas Customers, n=784)
16%16%
27%
16%
3%
23%
Up to
$250
Up to
$500
Up to
$1,000
Up to
$5,000
$10,000 or
more
None are
acceptable
Maximum Personal Contribution
(Among Gas Customers More Likely to Convert If
Some/All Costs Are Covered; n=473)
Under $1000 $1,000 or
more59%19%
60%
agree they would
be more likely to
eliminate natural
gas if some/all
costs are covered
Customer Demographics
Demographics
35
Education Total WA ID OR
(n=1,100)(n=569)(n=316)(n=215)
High school or less 7%5%10%7%
Trade or Technical School 6%6%9%4%
Some college 20%20%20%21%
Graduated college 36%37%35%33%
Graduate/professional school 26%28%22%30%
Age
18-24 1%<1%2%--
25-34 5%4%9%4%
35-44 13%15%14%9%
45-54 14%14%14%12%
55-64 23%21%26%22%
65-74 25%24%24%31%
75+12%16%4%16%
Refused 6%5%7%7%
Home Type Total WA ID OR
(n=1,100)(n=569)(n=316)(n=215)
Single family dwelling 83%92%64%87%
A duplex or triplex 4%2%7%3%
In a building with 4 or more
units 6%2%16%2%
Income
Median ~$70K ~$78K ~$62K ~$66K
Household
Mean # of people 2.4 2.5 2.2 2.2
Gender
Women 46%44%47%53%
Men 46%49%45%40%
Non-binary or Other <1%1%1%--
Prefer not to say 7%7%7%8%
1
Technical Advisory Committee (TAC) # 4
September 29, 2022
Natural Gas Integrated
Resource Plan -Draft
2
Agenda
Item Time
ETO -CPA 12:30pm –1:15pm
Natural Gas Market Dynamics and Prices 1:15pm –2:00pm
break 2:00pm –2:15pm
Supply Side Resource Options 2:15pm –3:00pm
CCA Overview 3:00pm –3:15pm
Climate Change Weather 3:15pm –4:00pm
Updated Load Forecast and Scenarios 4:00pm –4:30pm
3
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•May 2022
TAC #3
•August 2022
TAC #4
•September 2022
TAC #5
•November 2022
Draft IRP to
TAC
•January 2023
TAC #6 (if
necessary)
•February
2023
File IRP
•April 2023
Energy Efficiency Resource Assessment
for AVA’s 2023 IRP (DRAFT)
September 29th, 2022
Agenda
•About Energy Trust
•Energy Trust’s Resource Assessment
Model Overview and Methodology
•IRP Savings Projection Overview
•The Deployment of Cost-Effective Achievable
Savings
•Forecast Results
5
Independent
nonprofit
Providing
access to
affordable
energy
Generating
homegrown,
renewable
power
Serving 1.8 million customers of
Portland General Electric,
Pacific Power, NW Natural,
Cascade Natural Gas and Avista
Building a
stronger Oregon
and SW
Washington
About us
6
Nearly 770,000 sites
transformed into energy
efficient, healthy, comfortable
and productive homes
and businesses
From Energy Trust’s investment of $2.2 billion in utility customer funds:
18,000 clean energy systems
generating renewable power
from the sun, wind, water,
geothermal heat and biopower
$8.9 billion in savings over time
on participant utility bills from
their
energy-efficiency and solar
investments
36.2 million tons
of carbon dioxide emissions kept
out of
our air, equal to removing 7 million
cars from our roads for a year
Clean and affordable energy since 2002
7
2022 Programs –Acquiring all C/E Efficiency
•Residential –Existing and New Homes
•Single family, moderate income, rental, manufactured homes
•Weatherization (insulation, windows, air sealing)
•Gas fireplaces, furnaces
•Water heaters
•Commercial –Existing, New, Multifamily, SEM
•Retail, offices, schools, groceries….all market segments
•HVAC, controls, water heating, windows, insulation
•Industrial & Agriculture –Non transport sites
•Manufacturing facilities, greenhouses
•HVAC, O&M, process improvements
8
Avista & Energy Trust
•Serving Avista Territory in Oregon for over 5 years,
since 2016:
•Served over 10,500 households, over 600 commercial sites
and 20 industrial sites
9
Energy Trust’s Resource
Assessment Model Overview
Resource Assessment (RA) Purpose
•Informs utility Integrated Resource
Planning (IRP)
•Provides estimates of 20-year energy
efficiency potential and the associated
load reduction
•Helps utilities to strategically plan future
investment in both demand and supply
side resources
11
RA Model Background
•20-year energy efficiency potential estimates
•“Bottom-up” modeling approach –measure level inputs are
scaled to utility level efficiency potential
•Energy Trust uses a model in Analytica that was developed
by Navigant Consulting in 2014
•The Analytica RA Model calculates Technical, Achievable and
Cost-Effective Achievable Energy Efficiency Potential.
•Final program/IRP targets are established via a deployment
protocol exogenous of the model.
•Inputs refreshed to reflect most up to date assumptions
according to IRP schedules
•A “living model” which is constantly being improved
12
Changes to Modeling Since 2020 IRP
•Lost opportunity/unconstrained potential
•Align with NWPCC achievability assumptions
•Measure updates, new measures and new
emerging technologies included in the model
13
14
Not
Technically
Feasible
Technical Potential
Calculated
within RA
Model
Market
Barriers
Achievable Potential
(Historically 85%of Technical Potential, Recently
changed to reflect updated NWPCC assumptions)
Not Cost-
Effective
Cost-Effective Achiev.
Potential
Program Design &
Market Penetration
Final Program
Savings
Potential
Developed
with
Programs &
Market
Information
Forecasted Potential Types
15
20-Year IRP EE Forecast Flow Chart
Data Collection and Measure Characterization
Utility 'Global Inputs'
Load
Forecasts
by Sector
Customer
Counts /
Building Stock
Customer
Stock
Demographics
Utility Avoided
Costs ($/Therm
Saved)
Measure Level Inputs
Measure
Savings
Incremental
Costs
Market Data
Density/Saturation
/Suitability
Baseline and
Efficient
Equipment
Technical Energy Efficiency Potential
All technically available energy efficiency potential in service territory
Achievable Energy Efficiency Potential
Technical Potential varies for different end uses due to market barriers
(use Power Council assumed %ages from 2021 Power Plan)
Cost-Effectiveness Screen
Measures are screened for cost-effectiveness using the TRC Test
Total Resource Cost Test (TRC) = Benefits / Costs
Cost-Effective Achievable Energy Efficiency Potential
Measures with TRC Ratio > 1.0 included in Cost-Effective Achievable Potential
Deployment of Cost-Effective Achievable EE Potential
Exogenous of the RA Model -Energy Trust works internally with programs and uses
NWPPC council methodologies to determine acquisition rates of CE Potential
‘Bottom-up’ modeling approach:
1.Measure inputs are characterized per unit
2.Number of units per scaling basis are estimated
•Residential: # of Homes Served
•Commercial: 1000s of Sq. Ft. Served
•Industrial: Customer Segment Load Forecasts
3.The savings and costs of each measure are scaled to
the utility level based on scaling basis inputs provided
by AVA
Simple Example (Illustrative Numbers)
Methodology Overview
16
Eff. Gas Furnace –
100 Therms Savings
•Measure Data
1 Gas Furnace per
home and 50% at baseline efficiency
•Market Data
25,000 Homes
served by utility
•Utility Data
100 x 1 x 0.50 x
25,000 = 1,250,000 savings potential
•Total Potential
RA Model inputs
17
Measure Level Inputs
Measure Definition and Application:
•Baseline/efficient equip. definition
•Applicable customer segments
•Installation type (RET/ROB/NEW)*
•Measure life
Measure Savings
Measure Cost
•Incremental cost for ROB/NEW
measures
•Full cost for retrofit measures
Market Data (for scaling)
•Density
•Baseline/efficient equipment
saturations
•Suitability
Utility ‘Global’ Inputs
Customer and Load Forecasts
•Used to scale measure level
savings to a service territory
•Residential Stocks: # of homes
•Commercial Stocks: 1000s of Sq.Ft.
•Industrial Stocks: Customer load
Avoided Costs (provided by
utilities)
Customer Stock Demographics:
•Heating fuel splits
•Water heat fuel splits
* RET = Retrofit; ROB = Replace on
Burnout; NEW = New Construction
Incremental Measure Savings Approach
Competition groups
19
En
e
r
g
y

S
a
v
i
n
g
s

(
T
h
e
r
m
s
)
En
e
r
g
y

S
a
v
i
n
g
s

(
T
h
e
r
m
s
)
TRC 1.5
(Numbers are
for illustrative
purposes
only)TRC 1.1 Inc. SavingsAll Savings
Savings potential
for competing
technologies are
incremental to one
another based on
relative TRCs
•Energy Trust utilizes the Total Resource Cost (TRC) test
to screen measures for cost effectiveness
•If TRC is > 1.0, it is cost-effective
•Measure Benefits:
•Avoided Costs (provided by AVA)
•Annual measure savings x NPV avoided costs per therm
•Quantifiable Non-Energy Benefits
•Water savings, etc.
Total Measure Costs:
•The customer cost of installing an EE measure (full cost
if retrofit, incremental over baseline if replacement)
Cost-Effectiveness Screen
19
TRC =𝑴𝒆𝒂𝒔𝒖𝒓𝒆𝑩𝒆𝒏𝒆𝒇𝒊𝒕𝒔
𝑻𝒐𝒕𝒂𝒍𝑴𝒆𝒂𝒔𝒖𝒓𝒆𝑪𝒐𝒔𝒕
Cost-Effectiveness Override in Model
Energy Trust applied this feature to measures found to be
NOT Cost-Effective in the model but are offered through
Energy Trust programs.
Reasons:
1.Blended avoided costs may produce different results than
utility specific avoided costs
2.Measures offered under an OPUC exception per UM 551
criteria.
20
Model
Outputs
23
Types of
Potential:
Technical
Achievable
Cost-Effective
Achievable
Levelized Cost
Measure Costs & Benefits
Supply Curves
IRP Savings Projections:
Methodology to Deploy Cost-Effective Achievable Potential
Why Deploy?
•The RA model results represent the
maximum savings potential in a given
year.
•Ramp rates are an estimate of how much
of that available potential will come off
AVA’s system each year.
•Energy Trust ramp rates are based on
NWPCC methods and ramp rates, but
calibrated to be specific to Energy Trust.
25
•Total RA Model cost-effective potential is different
depending on the measure type.
•Retrofit measure savings are 100% of all potential in every
year, therefore must be distributed in a curve that adds to
100% over the forecast timeframe (bell curve)
•Lost opportunity measure savings are the savings
available in that year only and deployment rates are what %
of that available potential rate can be achieved –results in an
s-curve
•Generally follows the NWPCC deployment
methodology
•100% cumulative penetration for retrofit measures over 20-
year forecast
•100% annual penetration for lost opportunity by end of 20-
year forecast (program or code achieved)
•Hard to reach measures or emerging technologies do not
ramp to 100%
Ramp Rate Overview
26
Ramp Rate Examples
27
0%
20%
40%
60%
80%
100%
120%
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21
Lo
s
t

o
p
p
o
r
t
u
n
i
t
y

%

a
d
o
p
t
i
o
n
s
Re
t
r
o
f
i
t

C
u
r
v
e

%

a
d
o
p
t
i
o
n
s
Year
Retrofit Curve Lost Opportunity Curve
28
Energy Trust calibrates the first five years of energy
efficiency acquisition ramp rates to program
performance and budget goals.
Ramp Rate Calibration
Years 1-2
•Program
forecasts –
based on
budget and
current
market
conditions
Years 3-5
•Planning and
Programs
work together
to create
forecast
Years 6-20
•Planning
forecasts long-
term
acquisition rate
to generally
align NWPCC
Application of Ramp Rates &
Relation to RA Model
Results
•Energy Trust’s calibration
process means ramp rates are
not the same as the NWPCC,
but follow similar methods.
•Ramp rates are specific to AVA.
•The application of these ramp
rates is the reason why not all of
the RA Model Cost-Effective
Achievable Potential is
forecasted to be acquired.
•The deployment process is done
exogenously of the RA Model.
29
AVA’s 2023 IRP Results
Cumulative Savings by Type and Year
31
0
5
10
15
20
25
30
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
MM

T
h
e
r
m
s
Technical Achievable Cost-effective achievable IRP Projected Savings
Annual Deployed IRP Forecasted Savings
32
-
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
MM

T
h
e
r
m
s
Residential Commercial Industrial Unclaimed Market Savings Large Project Adder
Cumulative Savings by Sector and Type
34
0
5
10
15
20
25
Residential Commercial Industrial
MM

T
h
e
r
m
s
Technical Achievable Cost-effective achievable IRP Projected Savings
Cumulative Savings by Sector and Type (Therms)
35
Residential Commercial Industrial All Sectors
Technical
Potential 20,345,233 6,942,478 345,190 27,632,901
Achievable
Potential 16,213,842 5,817,303 293,412 22,324,557
Cost-effective
Achievable Potential 15,852,804 5,458,700 293,412 21,604,916
IRP Projected Savings 9,903,449 3,782,116 283,961 13,969,526
Study years include 2023 -2042
Cumulative Cost-Effective Savings & IRP Savings
Projections by End-Use Compared
36
0
1
2
3
4
5
6
7
MM

T
h
e
r
m
s
Cost-Effective Potential Deployed IRP Savings Projection
Energy Trust applied this feature to measures found to be
NOT Cost-Effective in the model but are offered through
Energy Trust programs under OPUC Exception
Cost Effective Override Effect
38
Measures that are Overridden Override Applied?Notes
Res -Attic/Ceiling insulation TRUE OPUC Exception
Res -Floor insulation TRUE OPUC Exception
Res -Wall insulation TRUE OPUC Exception
Res –Efficient Gas Clothes Washer TRUE OPUC Exception
Res –Gas heated new manufactured homes TRUE OPUC Exception
Com –Wall insulation TRUE OPUC Exception
Com –Flat roof insulation TRUE OPUC Exception
Energy Trust applied this feature to measures found to be
NOT Cost-Effective in the model but are offered through
Energy Trust programs under OPUC Exception
Cost Effective Override Effect
39
Total Cumulative Potential Cost-Effective
Potential
Deployed IRP
Savings Projection
Savings with CE Override (MM Therms)21.60 13.97
Savings with NO CE Override (MM Therms)20.78 13.17
Variance (MM Therms)0.83 0.80
CE Overridden % of Total Potential 3.8%5.7%
•Energy Trust also provides estimates of a peak day reduction in peak day
consumption
•Peak Day factors derived from Energy Trust avoided cost calculations
Peak Day Factors and Cumulative Peak Day Savings
Estimates
40
Peak Day
Factor
CE Potential Peak
Day Therms
(cumulative)
IRP Savings Targets
Peak Day Therms
(cumulative)
Cooking 0.36%643 406
Com Heating 1.77%72,375 52,833
Domestic Hot
Water 0.33%13,711 7,569
FLAT 0.27%577 575
Res Heating 1.98%247,555 165,245
Res Clothes
Washer 0.20%--
Supply Curve by Levelized Cost (20-year Cumulative
Achievable Potential)
41
0
5
10
15
20
25
-$5.04 $0.00 $0.04 $0.12 $0.19 $0.24 $0.39 $0.43 $0.72 $0.92 $1.14 $4.29
Cu
m
u
l
a
t
i
v
e

P
o
t
e
n
t
i
a
l

(
M
M

T
h
e
r
m
s
)
Levelized cost ($/therm)
Supply Curve by TRC Ratio (20-year Cumulative Achievable
Potential)
42
0
5
10
15
20
25
INF 92.85 28.18 19.36 13.29 9.08 5.69 4.36 3.29 0.99 -
Cu
m
u
l
a
t
i
v
e

P
o
t
e
n
t
i
a
l

(
M
M

T
h
e
r
m
s
)
TRC (present value of benefits / present value of costs)
IRP Forecasts Compared to Actual Savings (Annual MM
Therms)
43
-
0.2
0.4
0.6
0.8
1.0
1.2
MM

T
h
e
r
m
s
2023 IRP Total 2020 IRP Total 2018 IRP Total Actuals
2020 and 2023 Cumulative Cost-Effective
Achievable Potential Compared (MM therms)
44
Difference Share of
Difference
Load and Stock Forecast + 1.29 36%
Emerging Technology + 0.84 23%
Measure Updates + 0.68 19%
Avoided Costs + 0.48 13%
Discount Rate + 0.34 9%
CE Override -0.01 0%
Total + 3.63
Historical Performance compared to IRP targets (Annual
MM Therms)
45
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0.5
2016 2017 2018 2019 2020 2021
MM

T
h
e
r
m
s
Com Ind Res IRP Target
Savings as a Percent of Load Forecast
46
Average Annual % of Load Saved = 0.73%
0%
2%
4%
6%
8%
10%
12%
14%
16%
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
Pe
r
c
e
n
t

o
f

L
o
a
d

S
a
v
e
d
Annual % of Load Saved Cumulative % of Load Saved
Thank you
Kyle Morrill
Sr. Project Manager, Planning
[e-mail]
48
Michael Brutocao
Tom Pardee
Natural Gas Market Dynamics
and Prices
494949
Wood Mackenzie –Legal Disclaimer
The foregoing [chart/graph/table/information] was obtained from the North
America Gas Service™, a product of Wood Mackenzie.” Any Information
disclosed pursuant to this agreement shall further include the following
disclaimer: "The data and information provided by Wood Mackenzie should
not be interpreted as advice and you should not rely on it for any purpose.
You may not copy or use this data and information except as expressly
permitted by Wood Mackenzie in writing. To the fullest extent permitted by
law, Wood Mackenzie accepts no responsibility for your use of this data and
information except as specified in a written agreement you have entered
into with Wood Mackenzie for the provision of such of such data and
information."
5050
5151
5252
5353
5454
5555
5656
5757
5858
5959
60
US Storage
61
LNG Exports
62
North American Rig Count
Source: Baker Hughes
0
500
1,000
1,500
2,000
2,500
7/
1
7
/
1
9
8
7
7/
1
7
/
1
9
8
9
7/
1
7
/
1
9
9
1
7/
1
7
/
1
9
9
3
7/
1
7
/
1
9
9
5
7/
1
7
/
1
9
9
7
7/
1
7
/
1
9
9
9
7/
1
7
/
2
0
0
1
7/
1
7
/
2
0
0
3
7/
1
7
/
2
0
0
5
7/
1
7
/
2
0
0
7
7/
1
7
/
2
0
0
9
7/
1
7
/
2
0
1
1
7/
1
7
/
2
0
1
3
7/
1
7
/
2
0
1
5
7/
1
7
/
2
0
1
7
7/
1
7
/
2
0
1
9
7/
1
7
/
2
0
2
1
#
o
f

R
i
g
s
Oil Gas
US
0
100
200
300
400
500
600
700
800
1/
7
/
2
0
0
0
1/
7
/
2
0
0
1
1/
7
/
2
0
0
2
1/
7
/
2
0
0
3
1/
7
/
2
0
0
4
1/
7
/
2
0
0
5
1/
7
/
2
0
0
6
1/
7
/
2
0
0
7
1/
7
/
2
0
0
8
1/
7
/
2
0
0
9
1/
7
/
2
0
1
0
1/
7
/
2
0
1
1
1/
7
/
2
0
1
2
1/
7
/
2
0
1
3
1/
7
/
2
0
1
4
1/
7
/
2
0
1
5
1/
7
/
2
0
1
6
1/
7
/
2
0
1
7
1/
7
/
2
0
1
8
1/
7
/
2
0
1
9
1/
7
/
2
0
2
0
1/
7
/
2
0
2
1
1/
7
/
2
0
2
2
OIL GAS
Canada
63
Forward Prices (9/23/2022)
64
Daily Prices
Average Prices 9/2012 –9/2022
Max Prices 9/2012 –9/2022
65
PLEXOS Stochastics
66
PLEXOS Stochastics Continued
Without Autocorrelation With Autocorrelation
67
Stochastics Setup
Auto Correlation calculation performed on data from 6/1/1997 –6/1/2022 (25 years)
Pl
e
x
o
s

E
x
a
m
p
l
e
Av
i
s
t
a

S
e
t
u
p
68
Input: Standard Deviation of Errors
Calculations performed on data from 6/1/2011 –6/1/2022 (11 years)
69
Stochastics: Henry Hub (500 Draws)
70
Stochastics: Henry Hub Levelized Prices (500 Draws)
-$ per Dth
71
Results: Henry Hub Stochastics (500 Draws)
72
Expected Case Price Forecasts
73
Tom Pardee
Supply Side Resource Options
74
RNG Project Development Challenges
Lessons learned from pursuing RNG projects directly with feedstock owners:
▪Competition
▪The California transportation market dominates the supply
▪Federal RIN & California LCFS markets influence commercial terms
▪Reaching commercial terms is challenging
▪The utility cost of service model is a foreign concept
▪Every RNG project is unique
▪Economies of scale
▪New RNG Projects can take 2-3 years to develop
▪Limited feedstock supply
▪Partnering strategy
▪Picking partners
75
RNG Procurement & Potential Project Pipeline
#Project Pathway Type In Service Avista
Territory (Y/N)
Partnering
Considered
Estimated Supply (Dth/YR)
(Avista only)
Est. Online Date
1 Conventional RNG Yes Yes ~ 200K -350K 2024
2 Unconventional RNG Yes Yes ~ 150K -250K TBD
3 Unconventional RNG Yes Yes ~ 70K -120K 2024-25
4 Conventional RNG Yes Yes ~ 30K -50K TBD
5 Conventional RNG Yes Yes ~ 20K -30K TBD
6 Innovative CC&R RNG Yes Yes ~ 50K -80K 2024-25
7 Thermal Gasification Yes Yes ~ 70K -200K TBD
8 Conventional RNG Yes Yes ~ 60K -140K TBD
9 Pyro Catalytic Hydrogenation Yes Yes ~ 70K -150K TBD
10 Purchased RNG Yes No ~ 5K -10.8K 2022
Avista has been pursuing RNG projects with a host of feedstock owners
for the past few years. The table below captures these efforts by type & volume
Action Item Feedback: “Engage with stakeholders early in the development process to discuss potential RNG project types and
ownership structures and ways to mitigate or balance project risks fairly.”
76
RNG Cost Estimate by type
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
$
p
e
r

Dt
h
(N
o
m
i
n
a
l

$
)
Centralized LFG to RNG Production Dairy Manure to RNG Production Wastewater Sludge to RNG Production Food Waste to RNG Production
RNG Type Levelized Price
(Dth)
Landfill $11.14
Dairy $42.65
Wastewater $19.29
Food Waste $58.36
Source: Black and Veatch estimates
7777
2018 Oregon SB 344 Report Highlights
Total Potential Annual Methane Production = 50 Bcf
Source -Anaerobic Cubic Feet of CH4 per Year
Agricultural Manure 4,639,626,825
Wastewater 1,225,228,606
Food Waste 138,571,656
Landfill 4,351,052,420
Total 10,354,479,507
Source -Gasification Cubic Feet of CH4 per Year
Forest Industry Residuals 16,998,109,000
Agricultural Industry Residuals 22,686,775,000
Total 39,684,884,000
Oregon Department of Energy, 2018 Biogas and Renewable Natural Gas Inventory SB 334 Report
7878
WA RNG Report (HB 2580)
*Released December 1, 2018
WSU Energy Program, Harnessing Renewable Natural Gas for Low-Carbon Fuel: A Roadmap for Washington State
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
Dth
Existing Projects
Near Term Projects
Medium Term Projects
79
Direct Air Capture
Source: science direct
$-
$50.00
$100.00
$150.00
$200.00
$250.00
$300.00
$350.00
$400.00
$450.00
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
$
p
e
r

M
T
C
O
2
e
IRA $ per MTCO2e
80
Green Hydrogen (H2)
•Hydrogen is the most abundant
element in the universe
•The lightest element and wants
to escape making it harder to
contain
•Highly combustible
•Tax credits from IRA assumed at
a levelized credit for the full $3
per kg incentive from green H2
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
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
$
p
e
r

k
g
$ per kg (nominal $)kg per Dth
H H
81
Synthetic Methane
•Can be used in existing pipelines with no upgrades
•Unlimited potential, based solely on capacity of transportation or
distribution pipeline
•Sourced from carbon capture and green hydrogen
•Assume Inflation Reduction Act (IRA) benefits of:
-$130 per MTCO2e for carbon capture
-$3 per kg for green hydrogen
82
Synthetic Methane Costs
Levelized Price (year 1)$35.78
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
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
$
p
e
r

D
t
h
Cost of Carbon Cost of Green H2
83
Electrification Estimates
•Look at a daily efficiency and conversion by area
•Roll up this daily efficiency into a monthly
average conversion (therms to kwh)
•Uses rates by area from electric providers
•Oregon Trail rises by 3% per year
•All other rates rise by Avista expected cost
increase and includes transmission and
distribution estimates
•Pacific Power
•Inland Power/VERA/Modern Electric
•Base rates are not included as it is assumed
customers currently have electricity from
these providers
•Maximum rate, per MMBTU, for low use
months is the cost to convert plus energy
•Conversion costs
•Levelized 20-year costs each year by end
use type
•Includes Inflation Reduction Act cost
estimates from 2023-2032 to help offset
costs
•Conversion costs grown by inflation each
year
•Estimates for equipment from Home
Innovation Research Labs –February 2021
(Denver, CO)
•Commercial estimates are double the
residential conversion costs
•LDC Capital costs for distribution pipelines
and gate stations and other equipment are
not included in electrification estimate
84
Residential Electrification –Levelized Energy Costs
$
p
e
r

Dt
h
(n
o
m
i
n
a
l

$
)
*convert from natural gas to electric with daily efficiencies by source
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
Water Heat
La Grande Res - Water Heat Klamath Falls Res - Water Heat Medford Res - Water Heat
Roseburg Res - Water Heat WA Res - Water Heat
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
Space Heat
La Grande Res - Space Heat Klamath Falls Res - Space Heat Medford Res - Space Heat
Roseburg Res - Space Heat WA Res - Space Heat
85
Commercial Electrification –Levelized Energy Costs
*convert from natural gas to electric with daily efficiencies by source
$
p
e
r

Dt
h
(n
o
m
i
n
a
l

$
)
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
Water Heat
La Grande Com - Water Heat Klamath Falls Com - Water Heat Medford Com - Water Heat
Roseburg Com - Water Heat WA Com - Water Heat
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
Space Heat
La GrandeCom - Space Heat Klamath Falls Com - Space Heat Medford Com - Space Heat
Roseburg Com - Space Heat WA Com - Space Heat
86
Electrification –Estimated Conversion Costs
Source:Home Innovation Research Labs –February 2021
Res -Water
Heat
Com -Water
Heat
Res -Space
Heat
Com -Space
Heat Res -Other
Rate 3%3%3%3%3%
Years 5 5 5 5 5
Capital Amount $2,325 $ 4,650 $ 5,891 $ 11,782 $ 596
Electric Panel Upgrade $ -$ -$ -$ -
$
-
IRA Tax incentives $ 1,163 $ -$ 2,946 $ -$ 298
Capital Amount $ 1,163 $ 4,650 $ 2,946 $ 11,782 $ 298
87
Residential Electrification Costs –Levelized
(energy + conversion costs)
$
p
e
r

Dt
h
(n
o
m
i
n
a
l

$
)
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
Water Heat
La Grande Res - Water Heat Klamath Falls Res - Water Heat Medford Res - Water Heat
Roseburg Res - Water Heat WA Res - Water Heat
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
Space Heat
La Grande Res - Space Heat Klamath Falls Res - Space Heat Medford Res - Space Heat
Roseburg Res - Space Heat WA Res - Space Heat
88
Commercial Electrification Costs –Levelized
(energy + conversion costs)
$
p
e
r

Dt
h
(n
o
m
i
n
a
l

$
)
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
Water Heat
La Grande Com - Water Heat Klamath Falls Com - Water Heat Medford Com - Water Heat
Roseburg Com - Water Heat WA Com - Water Heat
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
Space Heat
La GrandeCom - Space Heat Klamath Falls Com - Space Heat Medford Com - Space Heat
Roseburg Com - Space Heat WA Com - Space Heat
89
Supply Side Options Summary -2025
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$
p
e
r

D
t
h
90
Request For Proposal
•Avista is going out for an RFP in the next few months
•The RFP will help determine pricing and market availability to size RNG
and other fuels to help meet climate change programs in Oregon and
Washington
•Avista will inform the TAC members when RFP is released
91
Tom Pardee
CCA Overview
92
Washington State Climate Commitment Act
•SB 5126, passed in the Summer 2021
•We will create a cap-and-invest program starting Jan.1, 2023, by setting emissions allowance budgets that meet the greenhouse gas limits in RCW
70A.45.020.
•Starting on Jan. 1, 2023, the cap-and-invest program will cover industrial facilities, certain fuel suppliers, in-state electricity generators, electricity importers, and natural gas distributors with annual greenhouse gas emissions above 25,000 metric tons of carbon dioxide equivalent.
•On Jan. 1, 2027, the program adds waste-to-energy facilities.
•On Jan. 1, 2031, the program adds certain landfills and railroad companies.
93
Baseline Emissions
https://ecology.wa.gov/DOE/files/5b/5bdc1ffb-01dc-49de-b0cf-e5758aa5c1f6.pdf, page 18
94
Allowance Reduction
https://ecology.wa.gov/DOE/files/5b/5bdc1ffb-01dc-49de-b0cf-e5758aa5c1f6.pdf, page 28
95
Major Rule Components
•7% initial years decline in cap
•Cap is average deliveries for customers less than 25,000 MTCO2e from 2015-2019
•Offset projects can qualify
•8% in first timeframe, 6% in second 4-year timeframe and 6% thereafter
•Allowances given to meet the initial target
•93% first year of which 35% can be used for compliance by the LDC
-Free allowance reduce 5% each year until reaching zero.
•All allowance revenue from the auctions is to be used to offset costs for low-income residential customers.
•Allowances do not expire and may be banked
•No cost allowances may not be traded, transferred or sold
96
Emissions
(Metric Tons of Carbon Dioxide equivalent (MTCO2e)
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MT
C
O
2
e
Washington CCA
97
Offsets
•Interchangeable with allowances
and purchased if cheaper than
allowance price
•Offsets remove allowances from
the cap
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
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
20
4
6
20
4
7
20
4
8
20
4
9
20
5
0
Offsets
Offset Projects Offset Projects - Tribal Lands
98
Free Allowances
#
o
f

a
l
l
o
w
a
n
c
e
s
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
Free Allowances to reduce rates Free allowances for Avista's use
35%30%
25%
20%
15%
10%
5%
99
Allowance Price
-
20
40
60
80
100
120
140
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
No
m
i
n
a
l

D
o
l
l
a
r
s

p
e
r

M
e
t
r
i
c

T
o
n
Washington Carbon Pricing For the IRP
Ecology Estimate Join California 2025- California Low Price Floor Price than National Price Weighted Avg Price
100
CCA Summary
Climate Commitment Act
(CCA)
Washington
Start Date January 1, 2023
Avista Compliance obligation All emissions less than 25,000 MTCO2e
Compliance Periods 4 years (2023 –2026)
2050 Goal 95% below 2015-2019 avg.
First Year offset 7.00% -(2023-2030)
1.95% -(2031-2050)
Violation $10k per MTCO2e
Offset projects
All projects are below cap (remove
available allowances)
-Up to 8% for four years (3% tribal)
-After first four years 6% (2% tribal)
Program offsets Allowances
101
Climate Change Weather
Mike Hermanson
Tom Pardee
102102
Climate Change Data Sources
•Climate and Hydrology Datasets for RMJOC Long-Term Planning Studies: Second Edition
•River Management Joint Operating Committee (RMJOC)
-BPA, US Army Corps of Engineers, US Bureau of
Reclamation
•Research Team
-University of Washington, Oregon State University
•Daily Max/Min Temp available for 1950-2099 Medford Klamath Falls
La Grande
Spokane
103103
Global Climate Models
•Global Climate Models (GCMs)
•Coarse resolution ranging from 75 to 300 km grid size
•Provides projections of temperature and precipitation
•Multiple Representative Concentration Pathways (RCP 4.5, RCP 6, RCP
8.5)
•10 GCM models used in study
-CanESM2 (Canada)
-CCSM4 (US)
-CNRM-CM5 (France)
-CSIRO-Mk3-6-0 (Australia)
-GFDL-ESM2M (US)
-HadGEM2-CC (UK)
-HadGEM2-ES (UK)
-inmcm4 (Russia)
-IPSL-CM5-MR (France)
-MIROC5 (Japan)
104104
Representative Concentration Pathways
•Description by Intergovernmental Panel on Climate Change (IPCC)
•RCP2.6 –stringent mitigation scenario
•RCP4.5 & RCP6.0 –intermediate scenarios
•RCP8.5 –very high GHG emissions
•RMJOCII Study evaluated RCP4.5 and RCP8.5
•RCP4.5 and RCP6.0 similar within the IRP planning horizon
Scenario 2046-2065 2081-2100
Mean Likely range Mean Likely range
Global Mean
Surface
Temperature
Change (C°)
RCP2.6 1.0 0.4 to 1.6 1.0 0.3 to 1.7
RCP4.5 1.4 0.9 to 2.0 1.8 1.1 to 2.6
RCP6.0 1.3 0.8 to 1.8 2.2 1.4 to 3.1
RCP8.5 2.0 1.4 to 2.6 3.7 2.6 to 4.8
105105
Downscaling Techniques
•Downscale GCM data to finer
resolution necessary to model
hydrology
•Statistical methods to represent
variation within large grid size
•Two methods used (BCSD, MACA)
-Bias Corrected Spatial Disaggregation
-Multivariate Adaptive Constructed
Analog
•18 modeled data sets available for
Spokane, Medford, and La Grande
•9 modeled data sets available for
Klamath Falls
Typical GCM
Grid Size
Downscaled
Grid Size
106
Weather Summary
•Average daily weather by planning region for the prior 20 years including climate change weather data.
•Example:
-2022 data is from 2002 –2021
-2030 data is from 2010 –2029
•Median of daily values for all climate study results by area
•A peak event by planning region based on the past 30 years of the coldest average day, each year, combined with a 1% probability of a weather occurrence
•Calculation now includes future projected peak values and is trended to the 2045 value from the historic coldest on record to smooth out volatility of peak day temperatures
•Using the median values as peak day drastically reduces the temperatures for the design weather day
•Taking the 95th percentage of climate models daily results and utilizing the highest annual value to include in the peak calculation reduces this risk of unserved customers
107
Idaho –Washington
108
Idaho –Washington
0%
5%
10%
15%
20%
25%
30%
-5.0-4.5-4.0-3.5-3.0-2.5-2.0-1.5-1.0-0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Fr
e
q
u
e
n
c
y
Z-statistic
Spokane Dec-Jan-Feb Temperature Anomaly Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
-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
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
20
3
6
20
3
9
20
4
2
20
4
5
Te
m
p
e
r
a
t
u
r
e

(
d
e
g
r
e
e
s

-
F)
Min of GEG Avg.99%Coldest on Record
Median - Max Trend Line Peak
95% of
climate
study
daily values
annual max
Median
maximum value
109
Medford
110
Medford
0%
5%
10%
15%
20%
25%
-5.0-4.5-4.0-3.5-3.0-2.5-2.0-1.5-1.0-0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Fr
e
q
u
e
n
c
y
Z-statistic
Medford Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
0
5
10
15
20
25
30
35
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
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
20
3
6
20
3
9
20
4
2
20
4
5
Te
m
p
e
r
a
t
u
r
e

(
d
e
g
r
e
e
s

-
F)
Min of MED avg.99%Coldest on Record
Median - Max Trend Line Peak
111
Klamath Falls
112
Klamath Falls
0%
5%
10%
15%
20%
25%
-5
.
0
-4
.
5
-4
.
0
-3
.
5
-3
.
0
-2
.
5
-2
.
0
-1
.
5
-1
.
0
-0
.
5
0.
0
0.
5
1.
0
1.
5
2.
0
2.
5
3.
0
3.
5
4.
0
4.
5
5.
0
Fr
e
q
u
e
n
c
y
Z-statistic
Klamath Falls Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/2021 Period
-20
-15
-10
-5
0
5
10
15
20
25
30
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
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
20
3
6
20
3
9
20
4
2
20
4
5
Te
m
p
e
r
a
t
u
r
e

(
d
e
g
r
e
e
s

-
F)
Min of KF Avg.99%Coldest on Record
Median - Max Trend Line Peak
113
Roseburg
114
Roseburg
0%
5%
10%
15%
20%
25%
30%
-5
.
0
-4
.
5
-4
.
0
-3
.
5
-3
.
0
-2
.
5
-2
.
0
-1
.
5
-1
.
0
-0
.
5
0.
0
0.
5
1.
0
1.
5
2.
0
2.
5
3.
0
3.
5
4.
0
4.
5
5.
0
Fr
e
q
u
e
n
c
y
Z-statistic
Roseburg Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
0
5
10
15
20
25
30
35
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
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
20
3
6
20
3
9
20
4
2
20
4
5
Te
m
p
e
r
a
t
u
r
e

(
d
e
g
r
e
e
s

-
F)
Min of MED avg.99%Coldest on Record
Median - Max Trend Line Peak
115
La Grande
116
La Grande
0%
5%
10%
15%
20%
25%
30%
-5
.
0
-4
.
5
-4
.
0
-3
.
5
-3
.
0
-2
.
5
-2
.
0
-1
.
5
-1
.
0
-0
.
5
0.
0
0.
5
1.
0
1.
5
2.
0
2.
5
3.
0
3.
5
4.
0
4.
5
5.
0
Fr
e
q
u
e
n
c
y
Z-statistic
La Grande Dec-Jan-Feb Temperature Anomaly
Histogram
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
-20
-15
-10
-5
0
5
10
15
20
25
30
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
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
20
3
6
20
3
9
20
4
2
20
4
5
Te
m
p
e
r
a
t
u
r
e

(
d
e
g
r
e
e
s

-
F)
Min of LaG Avg.99%Coldest on Record
Median - Max Trend Line Peak
117
Planning Region Coldest on Record 2021 IRP Peak Trended Peak 2045
La Grande, Oregon -10 -11 -8.0
Klamath Falls, Oregon -7 -9 -5.1
Medford/Roseburg, Oregon 4 11 11.7
Spokane, ID/WA -17 -12 -14.6
Peak Temp Changes
(degrees Fahrenheit)
118
Michael Brutocao
Updated Load Forecast
(includes climate change weather)
119
Annual System
120
Annual Idaho –Washington
121
Annual Klamath Falls
122
Annual La Grande
123
Annual Medford
124
Annual Roseburg
125
System Peak Day (Feb 28)
126
Idaho –Washington Peak Day (Feb 28)
127
La Grande Peak Day (Feb 28)
128
System Peak Day (Dec 20)
129
Klamath Falls Peak Day (Dec 20)
130
Medford Peak Day (Dec 20)
131
Roseburg Peak Day (Dec 20)
132
Scenarios
❑Preferred Resource Case –Our expected case
based on assumptions and costs with a least risk
and least cost resource selection
❑Preferred Resource Case Low Prices –Same
as PRS, but includes low price curve for natural
gas
❑Preferred Resource Case High Prices -Same
as PRS, but includes high price curve for natural
gas
❑Electrification Expected Conversion Costs –
Expected conversion costs case to show the risk
involved with energy delivered through the natural
gas infrastructure moving to the electric system
❑Electrification Low Conversion Costs –A low
conversion cost case to show the risk involved
with energy delivered through the natural gas
infrastructure moving to the electric system
❑High Customer Case –A high case to measure
risk of additional customer and meeting our
emissions and energy obligations
❑Limited RNG Availability –A scenario to show
costs and supply options if RNG availability is
smaller than expected
❑Interrupted Supply –A scenario to show the
impacts and risks associated with large scale
supply impacts and the ability for Avista to provide
the needed energy to our customers
❑Carbon Intensity –Include carbon intensity of all
resources from Preferred Resource Case
including upstream emissions on natural gas
❑Social Cost of Carbon –A scenario to value
resources in all locations using the Social Cost of
Carbon @ 2.5% and includes upstream emissions
❑Average Case –Non climate change projected
20-year history of average daily weather and
excludes peak day
❑Hybrid Case –Natural Gas used for space heat
below 40⁰ F while transferring all other usage to
electricity.
133
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•May 2022
TAC #3
•August 2022
TAC #4
•September 2022
TAC #5
•November 2022
Draft IRP to
TAC
•January 2023
TAC #6 (if
necessary)
•February
2023
File IRP
•April 2023
1
Technical Advisory Committee (TAC) # 5
December 15, 2022
Natural Gas Integrated
Resource Plan
2
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.
3
Agenda
Item Time
Applied Energy Group –Demand Response 9:00am –9:30am
Distribution 9:30am –10:15am
Review Assumptions 10:15am –10:30am
Break 10:30am –10:40am
Preferred Resource Strategy and Scenario Results 10:40am –11:30am
WA GRC Commitments -Action Plan -Next Steps 11:30am –12:00pm
4
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•May 2022
TAC #3
•August 2022
TAC #4
•September 2022
TAC #5
•December 2022
Draft IRP to
TAC
•January 2023
TAC #6 (if
necessary)
•February
2023
File IRP
•April 2023
Applied Energy Group, Inc. | appliedenergygroup.com
Natural Gas
Demand
Response
5
Date: 12/15/2022
Prepared for: Avista Technical Advisory Committee
Program Options and Eligibility
DSM Option States Eligible Classes Eligible
Behavioral WA Res, Com
DLC Smart Thermostats -BYOT WA, ID, OR Res, Com
Time-of-Use WA Res, C&I
Variable Peak Pricing WA Res, C&I
Third Party Contracts WA, ID, OR C&I
Applied Energy Group, Inc. | appliedenergygroup.com
Assumptions
Study Assumptions
The programs in this study target the peak hour of the peak day (Dekatherms)
Winter only
Program Impact and Cost assumptions
Derived primarily from other Gas DR Programs
•Smart Thermostat Program based on SoCalGas’s Smart Therm Program
•Third Party Contracts Program based on National Grid and ConEdison Programs
Diverged where gaps in research exist
•Customized for Avista’s service territory
•Pulled remaining assumptions from Electric DR Model and scaled down where appropriate
Applied Energy Group, Inc. | appliedenergygroup.com
Advanced Metering Infrastructure (AMI) Assumptions
Some of the options require AMI
DLC Options-No AMI Metering Required
Dynamic Rates and Behavioral-require AMI for billing
Washington
Utilized current Avista AMI saturation rates by sector and held constant
Idaho and Oregon
No AMI Projected
Dynamic Rates and Behavioral Programs not estimated
Achievable Potential
9
Applied Energy Group, Inc. | appliedenergygroup.com
Overall Potential
2023 2024 2025 2035 2045
Baseline Forecast 26,574 26,801 27,145 30,533 34,338
Potential -72 176 545 614
Potential (%)0%0%1%2%2%
Potential Forecast 26,574 26,729 26,969 29,988 33,724
20,000
22,000
24,000
26,000
28,000
30,000
32,000
34,000
36,000
De
a
t
h
e
r
m
s
Baseline Forecast Potential Forecast
Applied Energy Group, Inc. | appliedenergygroup.com
Achievable Potential -Washington
11
Key Findings:
•All five options available due to AMI saturation
•Largest potential option is DLC Smart Thermostats –BYOT (52% of potential)
•Next largest is VPP (29% of potential)
Winter Potential (Dth)2023 2024 2025 2035 2045
Baseline Forecast 13,399 13,553 13,721 15,474 17,454
Achievable Potential -51 120 361 407
Behavioral -14 22 30 33
DLC Smart Thermostats -BYOT -16 49 188 212
Time-of-Use -2 6 21 23
Variable Peak Pricing -10 30 105 119
Third Party Contracts -8 13 17 19
-
50
100
150
200
250
300
350
400
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Third Party Contracts
Variable Peak Pricing
Time-of-Use
DLC Smart Thermostats -
BYOT
Behavioral
Applied Energy Group, Inc. | appliedenergygroup.com
Achievable Potential -Idaho
12
Key Findings:
•Rates and Behavioral options unavailable
•DLC Smart Thermostats –BYOT (94% of potential)
•Third Party Contracts (6% of potential)
Winter Potential (Dth)2023 2024 2025 2035 2045
Baseline Forecast 6,877 6,909 7,026 8,077 9,273
Achievable Potential -12 32 110 126
Behavioral -----
DLC Smart Thermostats -BYOT -9 26 102 118
Time-of-Use -----
Variable Peak Pricing -----
Third Party Contracts -4 6 8 8
-
50
100
150
200
250
300
350
400
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Third Party Contracts
DLC Smart Thermostats
- BYOT
Applied Energy Group, Inc. | appliedenergygroup.com
Achievable Potential -Oregon
13
Winter Potential (Dth)2023 2024 2025 2035 2045
Baseline Forecast 6,123 6,162 6,219 6,781 7,384
Achievable Potential -9 24 74 80
Behavioral -----
DLC Smart Thermostats -BYOT -6 18 67 73
Time-of-Use -----
Variable Peak Pricing -----
Third Party Contracts -3 5 7 7
-
50
100
150
200
250
300
350
400
2023 2024 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
D
t
h
)
Third Party Contracts
DLC Smart Thermostats
- BYOT
Key Findings:
•Rates and Behavioral options unavailable
•DLC Smart Thermostats –BYOT (91% of potential)
•Third Party Contracts (9% of potential)
Applied Energy Group, Inc. | appliedenergygroup.com
Program Costs by State
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
2023 2024 2025 2035 2045
In
c
r
e
m
e
n
t
a
l

S
p
e
n
d

(
M
i
l
l
i
o
n

$
)
Washington
2023 2024 2025 2035 2045
Oregon
Third Party Contracts
Variable Peak Pricing
Time-of-Use
DLC Smart Thermostats
- BYOT
Behavioral
2023 2024 2025 2035 2045
Idaho
Applied Energy Group, Inc. | appliedenergygroup.com
Gas DR Key Findings
Natural Gas DR is an emerging resource
Small number of programs in existence
Numerous questions surround applicability and reliability of Gas DR
Program Potential
Smart Thermostats –Gas Heating
•Largest savings potential –Available to all states
Variable Peak Pricing
•Largest potential among rates –WA only
Third Party Contracts
•6% of overall potential –Third largest
•Small amount of industrial gas customers
o Not a lot of discretionary load to reduce
Thank You.
Kelly Marrin, Managing Director
[e-mail]
Andy Hudson, Project Manager
[e-mail]
Eli Morris, Managing Director
[e-mail]
Tommy Williams, Associate Consultant
[e-mail]
16
17
Modeled DR Inputs –Levelized
Input into Plexos Per Dth Price
Behavioral $0
DLC Water Heating $0
DLC Smart Thermostats -BYOT $5,754
Time-of-Use $0
Variable Peak Pricing $0
Third Party Contracts $137,045
Input into Plexos Per Dth Price
Behavioral $0
DLC Water Heating $0
DLC Smart Thermostats -BYOT $5,767
Time-of-Use $0
Variable Peak Pricing $0
Third Party Contracts $136,783
OregonIdaho
Input into Plexos Per Dth Price
Behavioral $11,849
DLC Water Heating $0
DLC Smart Thermostats -BYOT $5,756
Time-of-Use $18,883
Variable Peak Pricing $4,474
Third Party Contracts $135,937
Washington
18
Natural Gas Technical Advisory Committee
December 15, 2022
Terrence Browne PE, Senior Gas Planning Engineer
Distribution System Planning
19
Mission
•Using technology to plan and design a safe, reliable, and
economical distribution system
20
Gas Distribution Planning
•Service Territory and Customer Overview
•Scope of Gas Distribution Planning
•SynerGi Load Study Tool
•Planning Criteria
•Interpreting Results
•Monitoring Our System
•Areas Currently Monitoring for Low Pressure and Proposed Solutions
•Gate Station Capacity Review
•Avista’s Capability To Accommodate Hydrogen
2121
–Population of service area 1.7 million
406,000 electric customers
372,000 natural gas customers
Service Territory and Customer Overview
•Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
47%
29%24%
2222
Winter Peaking Profile
Technical Advisory Committee (TAC) # 1
February 16, 2022
23
Our Planning Models
•8,000 miles of distribution main
•120 cities
•40 load study models
24
__
Pup Pdown
Q
L ||
D
__
5 Variables for Any Given Pipe
25
Scope of Gas Distribution Planning
Supplier Pipeline
High Pressure Main
Reg.
Distribution Main and Services
Reg.Reg.
Gate
Sta.
26
Scope of Gas Distrib. Planning cont.
Gate
Sta.
Reg.Reg.Reg.
Reg.Reg.
Gate
Sta.
Gate
Sta.
27
SynerGi (SynerGEE, Stoner) Load Study
•Simulate distribution behavior
•Identify low pressure areas
•Test reinforcements against future
growth/expansion
•Measure reliability
2828
Preparing a Load Study
•Estimating Customer Usage
•Creating a Pipeline Network
•Join Customer Loads to Pipes
•Convert to Load Study
29
Estimating Customer Usage
•Gathering Data
•Days of service
•Degree Days
•Usage
•Name, Address, Revenue Class, Rate Schedule…
30
Estimating Customer Usage cont.
•Degree Days
•Heating (HDD)
•Cooling (CDD)
•Temperature -Usage
Relationship
•Load vs. HDD’s
•Base Load (constant)
•Heat Load (variable)
•High correlation with
residential
Avg. Daily Heating Cooling
Temperature Degree Days Degree Days
('Fahrenheit)(HDD)(CDD)
85 20
80 15
75 10
70 5
65 0 0
60 5
55 10
50 15
45 20
40 25
35 30
30 35
25 40
20 45
15 50
10 55
5 60
4 61
0 65
-5 70
-10 75
-15 80
3131
Heat Base
32
Creating a Pipeline Model
•Elements
•Pipes, regulators, valves
•Attributes: Length, internal diameter, roughness
•Nodes
•Sources, usage points, pipe ends
•Attributes: Flow, pressure
3333
34
Join Customer Loads to a Model
•Residential and commercial loads are assigned to pipes
•Industrial or other large loads are assigned to nodes
•Model “firm” loads only for identifying reinforcements
35
Balancing Model
•Simulate system for any temperature
•HDD’s
•Solve for pressure at all nodes
36
Validating Model
3737
Validating Model cont.
3838
Validating Model cont.
3939
Validating Model cont.
40
•Simulate recorded condition
•Electronic Pressure Recorders
•Do calculated results match field data?
•Gate Station Telemetry
•Do calculated results match source data?
•Possible Errors
•Missing pipe
•Source pressure changed
•Industrial loads
Validating Model cont.
41
•Reliability during design HDD
•Spokane 76 HDD
•Medford 49 HDD
•Klamath Falls 72 HDD
•La Grande 72 HDD
•Roseburg 46 HDD
•Maintain minimum of 15 psig in system at all times
•5 psig in lower MAOP areas
•3 psig in Medford 6 psig systems
Planning Criteria –2022
42
•Reliability during design HDD
•Spokane 76 HDD (avg. daily temp. -11’ F)
•Medford 49 HDD (avg. daily temp. 16’ F)
•Klamath Falls 72 HDD (avg. daily temp. -7’ F)
•La Grande 72 HDD (avg. daily temp. -7’ F)
•Roseburg 46 HDD (avg. daily temp. 19’ F)
•Maintain minimum of 15 psig in system at all times
•5 psig in lower MAOP areas
•3 psig in Medford 6 psig systems
Planning Criteria –2022
*Planning Criteria from 2021 Natural Gas IRP
43
Interpreting Results
•Identify Low Pressure Areas
•Number of feeds
•Proximity to source
•Looking for Most Economical Solution
•Length (minimize)
•Construction obstacles (minimize)
•Customer growth (maximize)
44
Monitoring Our System
•Electronic Pressure Recorders
•Daily Feedback
•Real time if necessary
•Validates our Load Studies
45
ERX #015: Loon Lake, WA
12/17/2016
01/05/2017
12/29/2016
46
ERX #007: West Medford 6 psig System, OR
12/18/2016
12/26/2016
01/06/2017
47
Real-time Pressure & Flow Monitoring
48
2022-2023 Winter
49
2013-2014 Winter
50
•Jacksonville, OR
•Medford 6 psig system, OR
•Palouse, WA
•South Hill Spokane, WA
•*Notes:
•List not comprehensive
•projects are subject to change and will be reviewed on a regular basis
Areas Currently Monitoring for Low Pressure and
Proposed Solutions*
51
Gate Station Capacity Review
52
y = 0.1278x + 3.5481
R² = 0.64840
5
10
15
20
25
30
35
0 10 20 30 40 50 60 70 80 90 100
Fl
o
w

(
m
c
f
h
)
HDDCity Gate Station # X
Daily Peak Flow (mcfh)
GTN Physical Capacity
(31 mcfh)
Design Day Peak Flow
(14.0 mcfh; 82 HDD)
Contractual Amount
(21.9 mcfh, Diversity
Factor = 1.5)
Linear (Daily Peak Flow
(mcfh))
76 HDD
Gate Station Capacity Review (example)
77
53
y = 2.1146x + 65.605
R² = 0.63080
50
100
150
200
250
300
0 10 20 30 40 50 60 70 80 90 100
Fl
o
w

(
m
c
f
h
)
HDDCity Gate Station # Y
Daily Peak Flow (mcfh)
NWP Physical Capacity
(206.0 mcfh, Diversity Factor
= 1.44)
Design Day Peak Flow
(239.0 mcfh; 82 HDD)
Contractual Amount (121.8
mcfh, Diversity Factor =
1.44)
Linear (Daily Peak Flow
(mcfh))
77
76 HDD
Gate Station Capacity Review (example)
54
City Gate Stations Currently Monitoring and Proposed
Solutions*
•Sutherlin, OR: rebuild/enhance in 2024+
•Medford, OR: work with pipeline to increase capacity
•Klamath Falls –Keno, OR: completed in 2020
•Pullman, WA: work with pipeline to increase capacity
•*Notes:
•List not comprehensive
•projects are subject to change and will be reviewed on a regular basis
55
Avista’s Capability To Accommodate Hydrogen
•Requirements (physical):
•Meets existing tariff gas quality standards
•Injection in a contained system with customer equipment that is capable of accepting
a hydrogen blend
•Metering at interconnect point for volume and gas quality
•Pressure regulation at interconnect point
56
Avista’s Capability To Accommodate Hydrogen
•Other
•Interconnection application process
•Interconnection agreement
•Where, when, & costs of upgrades required:
•Each project will be different
•Dependent on:
-the proximity of the project to our distribution system
-Size/scale of project
57
Questions and Discussion
Mission
Using technology to plan and design a
safe, reliable, and economical distribution
system
58
Tom Pardee
Review of Assumptions
59
Expected Growth
•In 2022 Washington State Building Code Council passed a commercial building and residential customer building requirement starting July 1, 2023.
•Requires the use of a heat pump as the primary heat source in new buildings
•Does not require a specific fuel type
•Does not require current customers to switch equipment at any time to electricity
•New residential and commercial customers in Washington starting July 2023 will be treated as hybrid heating where natural gas use begins at temperatures lower than 40 degrees Fahrenheit
60
System Firm Customer Range
(2023-2045)
300,000
350,000
400,000
450,000
500,000
550,000
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
Variable Base
Growth
High
Growth
Low
Growth
Customers 1.1%1.4%0.7%
Population 0.7%0.9%0.3%
60
61
Weather Summary
•Average daily weather by planning region for the prior 20 years including climate change weather data.
•Example:
-2022 data is from 2002 –2021
-2030 data is from 2010 –2029
•Median of daily values for all climate study results by area
•A peak event by planning region based on the past 30 years of the coldest average day, each year, combined with a 1% probability of a weather occurrence
•Calculation now includes future projected peak values and is trended to the 2045 value from the historic coldest on record to smooth out volatility of peak day temperatures
•Using the median values as peak day drastically reduces the temperatures for the design weather day
•Taking the 95th percentage of climate models daily results and utilizing the highest annual value to include in the peak calculation reduces this risk of unserved customers
62
Planning Region Trended Peak 2045
La Grande, Oregon -8.0
Klamath Falls, Oregon -5.1
Medford/Roseburg, Oregon 11.7
Spokane, ID/WA -14.6
Peak Temp Changes
(degrees Fahrenheit)
63
Expected Natural Gas Price Forecasts
64
RNG Cost Estimate by type
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
$
p
e
r

Dt
h
(N
o
m
i
n
a
l

$
)
Centralized LFG to RNG Production Dairy Manure to RNG Production Wastewater Sludge to RNG Production Food Waste to RNG Production
RNG Type Levelized Price
(Dth)
Landfill $11.14
Dairy $42.65
Wastewater $19.29
Food Waste $58.36
Source: Black and Veatch estimates
65
Green Hydrogen (H2)
•Hydrogen is the most abundant
element in the universe
•The lightest element and wants
to escape making it harder to
contain
•Highly combustible
•Tax credits from IRA assumed at
a levelized credit for the full $3
per kg incentive from green H2
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
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
$
p
e
r

k
g
$ per kg (nominal $)kg per Dth
H H
66
Synthetic Methane Costs Levelized Price (year 1)$35.78
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
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
$
p
e
r

D
t
h
Cost of Carbon Cost of Green H2
67
Residential Electrification Costs –Levelized
(energy + conversion costs)
$
p
e
r

Dt
h
(n
o
m
i
n
a
l

$
)
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
Water Heat
La Grande Res - Water Heat Klamath Falls Res - Water Heat Medford Res - Water Heat
Roseburg Res - Water Heat WA Res - Water Heat
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
Space Heat
La Grande Res - Space Heat Klamath Falls Res - Space Heat Medford Res - Space Heat
Roseburg Res - Space Heat WA Res - Space Heat
68
Commercial Electrification Costs –Levelized
(energy + conversion costs)
$
p
e
r

Dt
h
(n
o
m
i
n
a
l

$
)
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
Water Heat
La Grande Com - Water Heat Klamath Falls Com - Water Heat Medford Com - Water Heat
Roseburg Com - Water Heat WA Com - Water Heat
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
Space Heat
La GrandeCom - Space Heat Klamath Falls Com - Space Heat Medford Com - Space Heat
Roseburg Com - Space Heat WA Com - Space Heat
69
Electrification –No Capital Costs
70
Allowance Price
-
20
40
60
80
100
120
140
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
No
m
i
n
a
l

D
o
l
l
a
r
s

p
e
r

M
e
t
r
i
c

T
o
n
Washington Carbon Pricing For the IRP
Ecology Estimate Join California 2025- California Low Price Floor Price than National Price Weighted Avg Price
71
CCI Costs
$-
$20
$40
$60
$80
$100
$120
$140
$160
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
20
4
6
20
4
7
20
4
8
20
4
9
20
5
0
CCI
72
Quick Market Update
73
Natural Gas Prices
Daily
Forwards
*prior two weeks of daily prices
74
Preferred Resource Strategy
(PRS)
75
Simulation Analysis
•Simulation analysis is performed using stochastic simulation
paired with Monte Carlo simulation to understand risk
•Stochastic simulation provides a single solution based on the
number of simulations performed
•5 future simulations
•Monte Carlo simulation is used to provide risk analysis
around the resources selected stochastically
•500 MC simulations
76
Demand by State
0
5,000
10,000
15,000
20,000
25,000
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
1,
0
0
0

M
M
B
T
U
WA_Com_Current WA_Com_New WA_Ind WA_Res_Current WA_Res_New WA_Tport
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
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
1,
0
0
0

M
M
B
T
U
Klamath Falls_Com Klamath Falls_Ind Klamath Falls_Res LaGrande_Com LaGrande_Ind
LaGrande_Res Medford_Com Medford_Ind Medford_Res OR_Tport
Roseburg_Com Roseburg_Ind Roseburg_Res
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
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
1,
0
0
0

M
M
B
T
U
ID_Com ID_Ind ID_Res
77
Idaho
0
10
20
30
40
50
60
70
80
90
100
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
En
e
r
g
y

S
a
v
i
n
g
s

1
,
0
0
0

M
M
B
T
U
DSM
ID_Com ID_Ind ID_Res
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
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
1,
0
0
0

M
M
B
T
U
ID Natural Gas
AECO (ID)Rockies (ID)Spokane (ID)Stanfield (ID)Station 2 (ID)Sumas (ID)
78
Oregon
0
20
40
60
80
100
120
140
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
EE

S
a
v
i
n
g
s

1
,
0
0
0

M
M
B
T
U
DSM
Klamath Falls_Com Klamath Falls_Ind Klamath Falls_Res LaGrande_Com LaGrande_Ind
LaGrande_Res Medford_Com Medford_Ind Medford_Res OR_Tport
Roseburg_Com Roseburg_Ind Roseburg_Res
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
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
1,
0
0
0

M
M
B
T
U
OR Natural Gas
AECO (OR)Malin (OR)Rockies (OR)Stanfield (OR)Station 2 (OR)Sumas (OR)
0
2,000
4,000
6,000
8,000
10,000
12,000
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
1,
0
0
0

M
M
B
T
U
OR Carbon Reducing Alternatives
Synthetic Methane (OR)RNG - LFG (OR - Tport)RNG - LFG (OR)RNG - Wastewater (OR)
-
20,000
40,000
60,000
80,000
100,000
120,000
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
#
o
f

C
C
I
'
s
CCI’s
79
Washington
0
50
100
150
200
250
300
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
En
e
r
g
y

S
a
v
i
n
g
s

1
,
0
0
0

M
M
B
T
U
WA_Com WA_Ind WA_Res WA_Tport
0
5,000
10,000
15,000
20,000
25,000
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
1,
0
0
0

M
M
B
T
U
WA Natural Gas
AECO (WA)Rockies (WA)Spokane (WA)Stanfield (WA)Station 2 (WA)Sumas (WA)
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
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
#
o
f

A
l
l
o
w
a
n
c
e
s
Allowances
Total Free (Used)Total Given Total Purchased
0
500
1000
1500
2000
2500
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
1,
0
0
0

M
M
B
T
U
WA Carbon Reducing Alternatives
Synthetic Methane (WA - Tport)Synthetic Methane (WA)RNG - LFG (WA)
80
PRS -System Peak Day
81
Residential PGA Impact
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
2025 2035 2045
$
p
e
r

Th
e
r
m
ID_Res Medford_Res WA_Res_Current WA_Res_New
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
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
$
p
e
r

T
h
e
r
m
ID_Res Medford_Res
WA_Res_Current WA_Res_New
82
Monte Carlo –Levelized System Cost (500 Draws)
83
Monte Carlo –System Cost Net Present Value (500 Draws)
84
Monte Carlo –Average Annual Gross System Demand
(500 Draws)
85
Monte Carlo –Gross System Demand 2023-2045
(500 Draws)
86
Scenario Results
87
Scenarios
❑Preferred Resource Case –Our expected case
based on assumptions and costs with a least risk and
least cost resource selection
❑Preferred Resource Case Low Prices –Same as
PRS, but includes low price curve for natural gas
❑Preferred Resource Case High Prices -Same as
PRS, but includes high price curve for natural gas
❑Preferred Resource Case CCA Ceiling Prices –
Same as PRS, but our expected case based on
assumptions with a yearly ceiling price for allowances
in the CCA program
❑Electrification Expected Conversion Costs –
Expected conversion costs case to show the risk
involved with energy delivered through the natural
gas infrastructure moving to the electric system
❑Electrification Low Conversion Costs –A low
conversion cost case to show the risk involved with
energy delivered through the natural gas
infrastructure moving to the electric system
❑Electrification High Conversion Costs -A high
conversion cost case to show the risk involved with
energy delivered through the natural gas
infrastructure moving to the electric system
❑High Customer Case –A high case to measure risk
of additional customer and meeting our emissions
and energy obligations
❑Limited RNG Availability –A scenario to show costs
and supply options if RNG availability is smaller than
expected
❑Interrupted Supply –A scenario to show the impacts
and risks associated with large scale supply impacts
and the ability for Avista to provide the needed energy
to our customers
❑Carbon Intensity –Include carbon intensity of all
resources from Preferred Resource Case including
upstream emissions on natural gas
❑Social Cost of Carbon –A scenario to value
resources in all locations using the Social Cost of
Carbon @ 2.5% and includes upstream emissions
❑Average Case –Non climate change projected 20-
year history of average daily weather and excludes
peak day
❑Hybrid Case –Natural Gas used for space heat
below 40⁰ F while transferring all other usage to
electricity.
88
Scenario Analysis
•Uncertainty in future outcomes
•Understanding potential future outcomes through varying
scenarios can help determine risk levels
89
System Demand by Scenario
Hi
g
h

C
u
s
t
o
m
e
r

C
a
s
e
Hi
g
h

C
u
s
t
o
m
e
r

C
a
s
e
Hi
g
h

C
u
s
t
o
m
e
r

C
a
s
e
Av
e
r
a
g
e

C
a
s
e
Av
e
r
a
g
e

C
a
s
e
Av
e
r
a
g
e

C
a
s
e
PR
S
PR
S
PR
S
PR
S

-
Al
l
o
w
a
n
c
e

P
r
i
c
e

C
e
i
l
i
n
g
PR
S

-
Al
l
o
w
a
n
c
e

P
r
i
c
e

C
e
i
l
i
n
g
PR
S

-
Al
l
o
w
a
n
c
e

P
r
i
c
e

C
e
i
l
i
n
g
Li
m
i
t
e
d

R
N
G

A
v
a
i
l
a
b
i
l
i
t
y
Li
m
i
t
e
d

R
N
G

A
v
a
i
l
a
b
i
l
i
t
y
Li
m
i
t
e
d

R
N
G

A
v
a
i
l
a
b
i
l
i
t
y
PR
S

-
Hi
g
h

P
r
i
c
e
s
PR
S

-
Hi
g
h

P
r
i
c
e
s
PR
S

-
Hi
g
h

P
r
i
c
e
s
PR
S

-
Lo
w

P
r
i
c
e
s
PR
S

-
Lo
w

P
r
i
c
e
s
PR
S

-
Lo
w

P
r
i
c
e
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Ex
p
e
c
t
e
d

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Ex
p
e
c
t
e
d

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Ex
p
e
c
t
e
d

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Hi
g
h

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Hi
g
h

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Hi
g
h

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
Ca
r
b
o
n

I
n
t
e
n
s
i
t
y
Ca
r
b
o
n

I
n
t
e
n
s
i
t
y
Ca
r
b
o
n

I
n
t
e
n
s
i
t
y
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Lo
w

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Lo
w

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-
Lo
w

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
Hy
b
r
i
d

C
a
s
e
Hy
b
r
i
d

C
a
s
e
Hy
b
r
i
d

C
a
s
e
So
c
i
a
l

C
o
s
t

o
f

C
a
r
b
o
n
So
c
i
a
l

C
o
s
t

o
f

C
a
r
b
o
n
So
c
i
a
l

C
o
s
t

o
f

C
a
r
b
o
n
In
t
e
r
r
u
p
t
e
d

S
u
p
p
l
y
In
t
e
r
r
u
p
t
e
d

S
u
p
p
l
y
In
t
e
r
r
u
p
t
e
d

S
u
p
p
l
y
-
10,000
20,000
30,000
40,000
50,000
60,000
2025 2035 2045
1,
0
0
0

M
M
B
T
U
90
RNG Supply
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
1,
0
0
0

M
M
B
T
U
PRS OR - Renewables Social Cost of Carbon ID - Renewables Social Cost of Carbon WA - Renewables
Social Cost of Carbon OR - Renewables PRS - Low Prices OR - Renewables PRS - High Prices OR - Renewables
PRS - High Prices WA - Renewables Limited RNG Availability OR - Electrification Limited RNG Availability OR - Renewables
Interrupted Supply OR - Renewables Hybrid Case OR - Renewables High Customer Case OR - Renewables
Electrification - Low Conversion Costs OR - Electrification Electrification - Low Conversion Costs OR - Renewables Electrification - Expected Conversion Costs OR - Renewables
Carbon Intensity OR - Renewables Average Case OR - Renewables
91
Synthetic Methane
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
1,
0
0
0

M
M
B
T
U
Average Case Carbon Intensity Electrification - Expected Conversion Costs
Electrification - Low Conversion Costs High Customer Case Hybrid Case
Interrupted Supply Limited RNG Availability PRS
PRS - High Prices PRS - Low Prices Social Cost of Carbon
20
k
22
k
42
k
Scenario 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Average Case ---------------30 948 1,364 1,735 2,148 2,657 3,627 4,152
Carbon Intensity --0 4 7 10 13 17 20 24 27 31 34 38 41 44 48 51 55 58 61 589 960
Electrification -Expected Conversion Costs ------------------362 575 865 1,187 1,953
Electrification -Low Conversion Costs --------------------316 1,148 1,438
High Customer Case --3 7 11 15 20 24 28 32 37 41 45 50 54 329 1,187 1,642 2,069 2,532 3,026 3,947 4,615
Hybrid Case ---------1 4 8 11 15 18 21 25 28 31 34 38 413 827
Interrupted Supply 5 9 13 17 20 24 27 30 34 37 41 44 48 51 55 155 1,095 1,506 1,914 2,341 2,817 3,737 4,325
Limited RNG Availability ---4 7 10 13 506 1,597 3,097 477 1,946 2,624 3,168 3,669 4,174 4,699 5,243 5,743 6,251 6,804 7,338 8,401
PRS ---3 7 10 13 17 20 24 27 31 34 38 41 154 1,081 1,497 1,905 2,332 2,810 3,726 4,318
PRS -High Prices ---3 6 10 13 16 20 23 27 30 34 37 41 399 1,076 1,493 1,902 2,761 3,567 3,953 4,437
PRS -Low Prices ---3 7 10 14 17 20 24 27 31 34 38 41 162 1,094 1,504 1,907 2,329 2,804 3,261 4,318
Social Cost of Carbon ---3 7 10 13 17 20 24 27 31 34 38 41 44 687 2,068 2,380 2,703 20,729 22,664 42,385
92
Oregon
Community Climate Investments
0
20,000
40,000
60,000
80,000
100,000
120,000
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
#
o
f

C
C
I
'
s
Max CCI's Available High Customer Case Average Case
PRS Limited RNG Availability PRS - High Prices
PRS - Low Prices Electrification - Expected Conversion Costs Carbon Intensity
Electrification - Low Conversion Costs Hybrid Case Social Cost of Carbon
Interrupted Supply Avg
93
Washington
Allowances and/or Offsets
If offset projects are cheaper than allowance price, an offset will be purchased
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
#
o
f

A
l
l
o
w
a
n
c
e
s
Allowances
High Customer Case Average Case PRS
PRS - Allowance Price Ceiling Limited RNG Availability PRS - High Prices
PRS - Low Prices Electrification - Expected Conversion Costs Electrification - High Conversion Costs
Carbon Intensity Electrification - Low Conversion Costs Hybrid Case
Social Cost of Carbon Interrupted Supply Avg
94
($800.00)
($700.00)
($600.00)
($500.00)
($400.00)
($300.00)
($200.00)
($100.00)
$0.00
PR
S

-

A
l
l
o
w
a
n
c
e

P
r
i
c
e

C
e
i
l
i
n
g
PR
S

-

H
i
g
h

P
r
i
c
e
s
PR
S
PR
S

-

L
o
w

P
r
i
c
e
s
Hig
h

C
u
s
t
o
m
e
r

C
a
s
e
Av
e
r
a
g
e

C
a
s
e
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-

H
i
g
h

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
El
e
c
t
r
i
f
i
c
a
t
i
o
n

-

E
x
p
e
c
t
e
d

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
Ele
c
t
r
i
f
i
c
a
t
i
o
n

-

L
o
w

C
o
n
v
e
r
s
i
o
n

C
o
s
t
s
Lim
i
t
e
d

R
N
G

A
v
a
i
l
a
b
i
l
i
t
y
Ca
r
b
o
n

I
n
t
e
n
s
i
t
y
Hy
b
r
i
d

C
a
s
e
So
c
i
a
l

C
o
s
t

o
f

C
a
r
b
o
n
In
t
e
r
r
u
p
t
e
d

S
u
p
p
l
y
Hy
b
r
i
d

E
l
e
c
t
r
i
c

C
o
s
t
s
Hy
b
r
i
d

T
o
t
a
l

C
o
s
t
s
Levelized Yearly Costs (Millions $)
2023-2042
Levelized Cost
2023 –2042
*Natural gas system cost only
Mi
l
l
i
o
n
s

o
f

$
95
December 15, 2022
Shawn Bonfield, Sr. Manager of Regulatory Policy & Strategy
WA GRC Commitments
Applicable to Natural Gas IRP
96
WA General Rate Case Natural Gas Transition Issues
Avista agrees to include in its 2023 Natural Gas IRP, a natural gas system
decarbonization plan for complying with the Climate Commitment Act.
i.The Natural Gas IRP’s decarbonization plan shall include a supply curve of
decarbonization resources by price and availability, e.g.energy efficiency bundle 1 costs
X$/ton of carbon dioxide equivalent (CO2e) reduction and can reduce Y tons of CO2e,
dairy RNG costs A$/ton and can reduce B tons of CO2e.
ii.The decarbonization plan shall consider a comprehensive set of strategies, programs,
incentives and other measures to encourage new and existing customers to adopt fully
energy efficient appliances and equipment or other decarbonization measures, which
could include electrification.
iii.The decarbonization plan shall include targets for the ratio of new gas customers added
relative to new electric customers added in future years.
97
WA General Rate Case CCA Commitments
Within 60 days of the adoption of the final Department of Ecology rules), Avista will begin consulting with its applicable advisory groups concerning its plans for complying with the CCA for electric and gas service, and the terms of any future tariff filing, including the following:
i.Reporting requirements for the consignment of no-cost allowances for the benefit of ratepayers,
ii.The accounting treatment of any proceeds from the consignment of allowances, and
iii.The investment of any proceeds from the sale of allowances during the rate plan including investments in projects that provide benefits to ratepayers including, but not limited to, weatherization, decarbonization, conservation and efficiency services, and bill assistance. (RCW 70A.65.130)
Note: Department of Ecology final rules adopted on September 29th and go into effect on October 30th with program beginning on January 1st. Avista provided initial CCA Overview provided at September 29th TAC Meeting.
98
CCA Deferred Accounting Petition
•Filed CCA deferred accounting petition on November 1st for natural gas costs
and revenues related to compliance with the CCA
•Expect to begin incurring compliance costs in Q1 2023.
•Expect to receive revenues from consigned allowances in Q3 2023.
•Proposed to file annual tariff revisions to recover deferred costs. Current
thinking is to begin recovery on November 1, 2023.
•Did not include proposal for what to do with revenues as more conversation is
needed with WUTC.
99
Regulatory Next Steps for CCA Compliance
•Expect deferred accounting petition to be processed by WUTC in January 2023.
•WUTC initiating CCA compliance discussions in Q1 2023
•Thinking through needed rate schedule changes for allocating costs and revenues attributed to CCA.
•Continuation of low-income bill discount tariff.
•Transport customers –separating those above and below 25,000 MTC02e.
•General Service –separating those on the system before and after July 25, 2021.
•Special Contracts -separating those above and below 25,000 MTC02e.
•Tariff riders for CCA costs and benefits and which rate schedules tariff riders are applicable to.
100
Key Regulatory CCA Questions
•How are low-income customers determined?
•Can low-income customers not be charged CCA compliance costs to avoid
complexity of providing them bill credits to offset costs?
•What is “reasonable distance” when considering RNG resources? (Note:
Ecology expected to release guidance on RNG reporting soon.)
•What falls into the category of “decarbonization” that revenues from no-cost
allowances can be used for?
101
2025 Natural Gas IRP
Action Items
102
Oregon Action Items
•Purchase Community Climate Investments for compliance to the Climate
Protection Plan for years 2022, 2023 and 2024 to comply with emissions levels
•ETO identified 2023 gross savings of 546 thousand therms in the IRP verses 427
thousand therms of planned savings in the 2023 ETO Budget and Action Plan.
Work with ETO to meet IRP gross savings target of 568 thousand therms in 2024
•New program offered by ETO for interruptible customers in 2023 to save 15
thousand therms.
•Engage stakeholders to explore additional new offerings for interruptible, transport
and low-income customers to work towards identified savings of 375 thousand
therms in 2024
•Acquire 8.64 million therms of RNG in 2023 and 21.80 million therms of RNG in
2024
103
Washington Action Items
•Purchase Allowances or offsets for compliance to the Climate
Commitment Act for years 2023 and 2024 to comply with
emissions levels
•Begin to offer a transport customer EE program by 2024 with
the goal of saving 35 thousand therms
•Explore methods for using Non Energy Indicators (NEI) in
future IRP analysis
104
Other Action Items
•Explore modeling alternatives like end use model to
compliment time series
105
Next Steps
106
Next Steps
•Include Monte Carlo risk analysis and send out prior to IRP
draft
•Determine electricity costs for Hybrid scenario
•Review RPF and incorporate selection in IRP
•Draft IRP January 25, 2023
•Virtual Public meeting March 8, 2023
•File final IRP March 31, 2023
107
2023 –Avista Natural Gas IRP
TAC #1
•February
2022
TAC #2
•May 2022
TAC #3
•August 2022
TAC #4
•September 2022
TAC #5
•December 2022
Draft IRP to
TAC
•January 2023
TAC #6 (if
necessary)
•February
2023
File IRP
•April 2023