20200228IRP Appendices.pdf

2020 Electric Integrated
Resource Plan Appendices
Table of Contents
Appendix A – 2020 IRP Technical Advisory Committee Presentations (Page 1)
Technical Advisory Committee Meeting 1 Presentations (Page 2)
Technical Advisory Committee Meeting 1 Minutes (Page 85)
Technical Advisory Committee Meeting 2 (Page 93)
Technical Advisory Committee Meeting 2 Minutes (Page 200)
Technical Advisory Committee Meeting 3 (Page 209)
Technical Advisory Committee Meeting 3 Minutes (Page 365)
Technical Advisory Committee Meeting 4 (Page 373)
Technical Advisory Committee Meeting 4 Minutes (Page 515)
Technical Advisory Committee Meeting 5 (Page 524)
Technical Advisory Committee Meeting 5 Minutes (Page 625)
Technical Advisory Committee Meeting 6 (Page 633)
Technical Advisory Committee Meeting 6 Minutes (Page 733)

Appendix B – 2020 Electric IRP Work Plan (Page 748)

Appendix C – Confidential Historical Generation Operation Data (Page 756)

Appendix D – AEG Conservation Potential Assessment (Page 757)

Appendix E – Conservation Potential Assessment Measurement Assumptions
(Page 933)

Appendix F – Resource Adequacy in the Pacific Northwest by E3 (Page 934)

Appendix G – New Resource Table for Transmission (Page 1044)

Appendix H – New Resource Cost Assumptions (Page 1046)

Appendix I – Black and Veatch Renewable Resource and Storage Study (Page
1047)

Appendix J – Confidential Report of Portfolio #14 (Page 1054)
2020 Electric Integrated
Resource Plan
Appendix A – 2020 Technical
Advisory Committee
Presentations and Meeting
Minutes
Page 1 Avista Corp. 2020 Electric IRP Appendices

2019 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda Wednesday, July 25, 2018 Conference Room 130
Topic Time Staff
Introductions 9:00 Lyons TAC Expectations and Process Overview 9:05 Lyons 2017 IRP Acknowledgements & Policies 9:30 Gall Break 10:15

Demand and Economic Forecast 10:30 Forsyth

Lunch 12:00 2017 Action Plan Updates 1:00 Gall 2019 IRP Draft Work Plan 1:30 Lyons Break 2:15

Hydro One Merger Agreements 2:30 Gall

Adjourn 3:00
Page 2 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP
TAC Meeting Expectations
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
July 25, 2018
Page 3 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next two years
•Current and projected load & resource position
•Preferred Resource Strategy (PRS)
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Expected case
•Market and portfolio scenarios for uncertain future
events and issues
2 Page 4 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning (Cont)
•Requires significant modeling and assumptions
–Fuel prices
–Economic activity
–Policy considerations
–Resource costs
–Energy efficiency
•Action Items –areas for more research in the next IRP
•This is not an advocacy forum
•Not a forum on a particular resource, resource type or
any particular issue
•Supports rate recovery, but not a preapproval process
3 Page 5 Avista Corp. 2020 Electric IRP Appendices
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 in all or some of the process
•Open forum, but we need to stay on topic to get through the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–January 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
4 Page 6 Avista Corp. 2020 Electric IRP Appendices
Today’s Agenda
•9:00 –Introduction and TAC Expectations and Process
Overview, Lyons
•9:30 –2017 IRP Acknowledgments and Policies, Gall
•10:15 – Break
•10:30 –Demand and Economic Forecast, Forsyth
•12:00 –Lunch
•1:00 –2017 IRP Action Plan Updates, Gall
•1:30 –2019 IRP Draft Work Plan
•2:15 – Break
•2:30 –Hydro One Merger Agreements, Gall
•3:00 –Adjourn
5 Page 7 Avista Corp. 2020 Electric IRP Appendices
TAC Expectations
•Avista:
–Input about assumptions and areas to study
–Five TAC meetings with agendas that may change
based on input
–Topics covered later today in the Draft Work Plan
•TAC Members:
–What are your expectations?
–Comments or questions about the process
6 Page 8 Avista Corp. 2020 Electric IRP Appendices
2017 Electric IRP Commission Acknowledgement Update
James Gall, IRP Manager
July 25, 2018
Page 9 Avista Corp. 2020 Electric IRP Appendices
Idaho
•Idaho Commission acknowledged the 2017 IRP on February 1, 2018 in order
No. 33971 of AVU-E-17-08.
•Comments were provided by the Commission Staff, Idaho Conservation
League (ICL), and 23 members of the public.
•The Commission in this order confirms … “The appropriate place to
determine the prudence of the IRP or the Company’s decision to follow or not
follow it, and the validation of predicted performance under the IRP, will be a
general rate case or another proceeding in which the issue is noticed.”
2 Page 10 Avista Corp. 2020 Electric IRP Appendices
Specific Idaho Staff Comments (highlights)
•Scenarios should include renewing the Lancaster contract.
•Clearly state how the Company’s portfolio complies with the EPA’s Clean Power Plan.
•Concern with natural gas prices being "extremely low throughout the entire planning period”.
•Failed to provide evidence supporting its claim "that coal price risk is not a significant factor
for Colstrip operations.”
•Continue analyzing alternatives and cost mitigation strategies for Colstrip.
•Regarding Colstrip, specify significant capital investments required for plant operation and
provide a more transparent assessment of the costs and availability of fuel for the plant.
3 Page 11 Avista Corp. 2020 Electric IRP Appendices
Specific ICL Comments (highlights)
•Asks the Commission to direct Avista to include a "thorough and detailed discussion" in its 2019 IRP, of
the policies and financial plans of the utility co-owners of Colstrip Units 3 and 4, and their impact on the
cost of producing and distributing electricity from Avista's share of Units 3 and 4.
–Such discussion should include analysis of provisions in Puget Sound Energy's (PSE) 2017
settlement with the Washington Utilities and Transportation Commission that (1) changed the
depreciation schedule for Units 3 and 4 from 2045 to 2027; and (2) allocated $10 million for
transition funds to the community of Colstrip.
•Recommends Avista include analysis of Oregon State Bill 1547, directing PGE and PacifiCorp to end
distribution of coal-generated electricity in Oregon by 2030.
•Provide a more transparent accounting and explanation" of how Avista's AURORA and PRiSM models
work.
•Avista provide a more thorough analysis "of the fuel price of coal at Colstrip and a forecasted range of
price volatility over the 20-year timeframe of the 2019 IRP."
4 Page 12 Avista Corp. 2020 Electric IRP Appendices
Customer Comments in Idaho
•The Commission conducted a public telephone hearing at which 18 people
testified, most of whom were Avista customers.
•The hearing participants testified about retiring Colstrip early, switching from
coal to renewables, and other environmental concerns.
•The Commission also received 23 written comments.
•Most comments opposed investing in Colstrip, although a few supported it.
5 Page 13 Avista Corp. 2020 Electric IRP Appendices
Specific Idaho Recommendations
•We note that customers and Staff commented on alternatives regarding the
closure of Colstrip and the inclusion in the PRS of a new gas peaker plant
after the expiration of the Lancaster agreement.
•We encourage the Company to continue evaluating all options regarding
these resources, and to consider the best interests of its customers when
developing the 2019 IRP.
•The Commission appreciates the Company's collaboration with stakeholders
in developing the 2017 Electric IRP.
6 Page 14 Avista Corp. 2020 Electric IRP Appendices
Washington 2017 IRP Acknowledgement
•Washington Commission
acknowledged the 2017 IRP on May 7,
2018 in Docket No. UE-161036
•It is important that the Commission
take this opportunity to thank the
members of the public that participated
in the Company’s Advisory Committee
process, commented in the docket,
and made oral statements at the public
meeting.
•Specific Comments:
–Colstrip Units 3 & 4
–Conservation potential assessment
–Demand response & AMI
–Forecasted natural gas prices
–Distribution system upgrade planning
–Optimal planning reserve margin
–Update legacy studies
–Portfolio scenario cost comparison
–Emissions price modeling and cost
abatement supply curve
–Public Process
7 Page 15 Avista Corp. 2020 Electric IRP Appendices
Colstrip Comments and Recommendations
1. Regarding fuel source cost and risk:
a. How dependent is Colstrip on a single-source mine for its
fuel?
b. How well understood is the supply of coal from the
Colstrip mine?
i. What are the financial risks of the type of mining
used to extract the existing coal?
ii. As the need for fuel for Colstrip declines, how does
the cost per unit of coal from the Colstrip mine
increase?
iii. What are the counter-party risks of mine operation?
iv. What risks to coal supply and coal cost does the
Joint Colstrip ownership agreement impose? How will
Avista manage them?
c. How does the fuel supply risk from Colstrip compare to
that of natural gas?
2. Does Avista have an assessment of the cost related to the
counter-party risk of Riverstone ceasing operation of its share of
Colstrip Unit 3? If not, why not?
3. Does Avista have an assessment of the cost of the counter-
party risk of Riverstone being financially unable or otherwise
failing to pay its share of decommissioning and remediation costs
for Unit 3?
4. What are the economics of the high-cost scenario under a “low
gas” scenario forecast?
5. How are the economics of Colstrip Units 3 & 4 affected if
natural gas prices continue to remain relatively flat?
6. What are Avista’s best estimates of remediation and
decommissioning costs associated with Colstrip Units 3 & 4?
7. Has the Company quantified capacity replacement costs for
Colstrip Units 3 & 4 that it could use as a basis of seeking
replacement capacity as an alternative to any large capital
investments it faces at Colstrip?
8. What is the risk of the failure of a large cost component of
Colstrip Units 3 & 4 (such as: the heat exchangers, steam turbine
or drive shafts) over Avista’s expected 20-year life of the plant?
8 Page 16 Avista Corp. 2020 Electric IRP Appendices
Other Colstrip Recommendations
•Develop a list of events regarding the economic viability of Colstrip
–For each event identify the cost, probability of occurrence, and cost range
•The 2019 plan should clearly and transparently
–Identify cost data and discuss in detail the relationship between the range of these input
assumptions, portfolio modeling logic, and the output of the modeling, as well as how the
Company used such analysis to choose its PRS.
9 Page 17 Avista Corp. 2020 Electric IRP Appendices
Conservation Potential Assessment
The 2019 IRP must include the following:
1.All conservation measures excluded from the CPA, including those excluded prior to
technical potential determination.
2.The rationale for excluding any measure.
3.A description, and source, of Unit Energy Savings data for each measure included in the
CPA.
4.An explanation for any differences in economic and achievable potential savings.
•The Company should also share its proposed energy efficiency measure lists with the
Conservation Advisory Group prior to completing the CPA.
10 Page 18 Avista Corp. 2020 Electric IRP Appendices
Demand Response and Advanced Metering
Infrastructure (AMI) Project
•The 2017 IRP does not consider the adoption of AMI technology in its energy
efficiency or demand response modeling, nor does it demonstrate any
potential benefits of deploying AMI.
•The Commission notes that the IRP is also one of the Company’s
opportunities to develop a record for the future demonstration of prudent
resource acquisition.
11 Page 19 Avista Corp. 2020 Electric IRP Appendices
Forecasted Price of Natural Gas
•The Commission does not expect utilities to predict future natural gas prices
with perfect accuracy, acknowledging this exercise is a forecast.
•We expect the utility to question and investigate the facts and reasoning used
by the consultants to derive their forecasts, given that past IRPs have
included a high-side bias to natural gas prices.
•Avista must ensure its natural gas price forecast represents the most
reasonable expectation of the future.
12 Page 20 Avista Corp. 2020 Electric IRP Appendices
Distribution System Upgrade Planning
•Any analysis of a distribution system upgrade should include consideration of storage
options that capture locational benefits associated with the site in question.
•The Commission encourages Avista’s use of sub-hourly models in the core IRP development
process to identify distribution system enhancements in its next IRP.
•Avista should perform a study to determine ancillary services valuation in the market and use
that value to evaluate the cost effectiveness of storage and peaking technologies using intra-
hour modeling capabilities.
•Advises Avista to model generic commercially available storage technologies within the IRP,
including consideration of efficiency rates, capital cost, operation and maintenance, life cycle
costs, and ability to provide non-power supply benefits.
13 Page 21 Avista Corp. 2020 Electric IRP Appendices
Other Comments and Recommendations
•Optimal Planning Reserve Margin
–The Commission urges Avista to monitor winter and summer resource adequacy and
continue to analyze planning margins, using its loss of load model, and continue to work
with the Council to validate and update its requirements while examining additional tools
such as Expected Loss of load and Expected Unserved Energy.
•Update Legacy Studies
–For future IRPs, citations to legacy analysis should be accompanied by a rationale for
why the study does not need to be updated.
•Portfolio Scenario Cost Comparison
–In displaying the costs and risks of a portfolio scenario in its IRP, Avista should
prominently display a comparison chart of the present value of revenue requirement of
each portfolio scenario along with its associated risk.
14 Page 22 Avista Corp. 2020 Electric IRP Appendices
Emissions Price Modeling and Cost Abatement Supply
Curve
•In future IRPs, Avista should incorporate in its preferred resource strategy the cost of risk of
future greenhouse gas regulation in addition to known regulations.
•This cost estimate should come from a comprehensive, peer-reviewed estimate of the
monetary cost of climate change damages, produced by a reputable organization.
•We suggest using the Interagency Working Group on Social Cost of Greenhouse Gases
estimate with a three percent discount rate.
•Avista should also continue to model other higher and lower cost estimates to understand
how the resource portfolio changes based on these costs.
•The Company must also develop a supply curve of emissions abatement measures in its
next IRP.
15 Page 23 Avista Corp. 2020 Electric IRP Appendices
Public Process
•Expect the Company to provide written responses to all Advisory
Committee questions submitted to the Company in writing,
•Provide minutes for each Advisory Committee meeting.
16 Page 24 Avista Corp. 2020 Electric IRP Appendices
Washington IRP Rulemaking
•The Washington Commission opened Docket No. U-161024 on September 2016 to
consider the following topics:
–Energy storage;
–Requests for proposals;
–Avoided costs;
–Transmission and distribution planning;
–Flexible resource modeling; and
–General procedural improvements.
•Work has been ongoing for this docket and the process is expected to wrap up
before the end of this year.
17 Page 25 Avista Corp. 2020 Electric IRP Appendices
Load and Economic Forecasts
Grant D. Forsyth, Ph.D.
Chief Economist
First Technical Advisory Committee Meeting
July 25, 2018
Page 26 Avista Corp. 2020 Electric IRP Appendices
Main Topic Areas
•Service Area Economy
•Peak Load Forecast
•Long-run Forecast
2 Page 27 Avista Corp. 2020 Electric IRP Appendices
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3 Page 28 Avista Corp. 2020 Electric IRP Appendices
Distribution of Employment: Services and
Government are Dominant
Source: BEA and author’s calculations.4
Farm
1%
Private
Goods
13%
Private Services
71%
Federal, civilian
2% (10%)Military
1%(8%)
State
3%(21% Gov)
Local
9%(61% Gov)
Other
15%
WA-ID MSA Employment, 2016
Page 29 Avista Corp. 2020 Electric IRP Appendices
Non-Farm Employment Growth, 2009-2018
Source: BLS and author’s calculations.5
-6%
-4%
-2%
0%
2%
4%
6%
Ju
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-
0
9
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.
Non-Farm Employment Growth Since June 2009
Avista WA-ID MSAs U.S.
Page 30 Avista Corp. 2020 Electric IRP Appendices
Non-Farm Employment: Finally Catching Up
Source: BLS and author’s calculations.6
90
92
94
96
98
100
102
104
106
108
110
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Non-Farm Employment Level Since 2007 (Dashed Shaded Box = Recession Period)
Avista WA-ID MSAs U.S.
Page 31 Avista Corp. 2020 Electric IRP Appendices
Population Growth: Recovering with
Employment Growth
Source: BEA, U.S. Census, and author’s calculations.7
1.9%
1.4%
1.2%
0.8%
0.5%0.5%
0.8%
1.1%
1.3%
1.8%1.9%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
An
n
u
a
l

G
r
o
w
t
h
Population Growth in Avista WA-ID MSAs
Proxy for
Customer
Growth
Page 32 Avista Corp. 2020 Electric IRP Appendices
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8 Page 33 Avista Corp. 2020 Electric IRP Appendices
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial
loads.
•Based on monthly peak MW loads since 2004. The peak is pulled from hourly
load data for each day for each month.
•Explanatory variables include HDD-CDD and monthly and day-of-week dummy
variables. The level of real U.S. GDP is the primary economic driver in the
model—the higher GDP, the higher peak loads. The historical impacts of DSM
programs are “trended” into the forecast.
•The coefficients of the model are used to generate a distribution of peak loads
by month based on historical max/min temperatures, holding GDP constant.
An expected peak load can then be calculated for the current year (e.g., 2016).
Model confirms Avista is a winter peaking utility for the forecast period;
however, the summer peak is growing at a faster than the winter peak.
•The model is also used to calculate the long-run growth rate of peak loads for
summer and winter using a forecast of GDP growth under the “ceteris paribus”
assumption for weather and other factors.
9 Page 34 Avista Corp. 2020 Electric IRP Appendices
GDP Growth Assumptions: 2015 IRP vs. 2017 IRP
10
2.6%
2.2%
2.0%
1.8%1.8%2.0%
2.3%
2.1%
2.1%2.1%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
2018 2019 2020 2021 2022 2023
An
n
u
a
l

G
r
o
w
t
h
2019 IRP GDP Growth 2017 IRP GDP Growth
Source: Various and author’s calculations.Page 35 Avista Corp. 2020 Electric IRP Appendices
Current Peak Load Forecasts for Winter and
Summer, 2018-2043
11
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
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
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2018-42
Winter 0.34%
Summer 0.36%
Page 36 Avista Corp. 2020 Electric IRP Appendices
Current and Past Peak Load Forecasts for
Winter Peak, 2011-2043
12
1,500
1,750
2,000
2,250
2,500
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
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
Me
g
a
w
a
t
t
s
Winter Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP
Page 37 Avista Corp. 2020 Electric IRP Appendices
Current and Past Peak Load Forecasts for
Summer Peak, 2011-2043
13
1,250
1,500
1,750
2,000
2,250
2,500
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
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
Me
g
a
w
a
t
t
s
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP
Page 38 Avista Corp. 2020 Electric IRP Appendices
Long-Term Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
14 Page 39 Avista Corp. 2020 Electric IRP Appendices
Basic Forecast Approach
2019
Time
2024 20452025
1)Monthly econometric model by
schedule for each class.2)Customer and UPC forecasts.
3)20-year moving average for “normal
weather.”4)Economic drivers: GDP, industrial
production, employment growth, population, price, and ARIMA error
correction.
5)Native load (energy) forecast derived from retail load forecast.
1)Boot strap off medium term forecast.
2)Apply long-run load growth relationships to develop simulation model for high/low
scenarios.
3)Include different scenarios for renewable
penetration with controls for price elasticity and
EV/PHEVs.
Medium Term Long Term
15 Page 40 Avista Corp. 2020 Electric IRP Appendices
The Long-Term Residential Relationship, 2020-
2040
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as
population growth, commercial
growth will follow residential,
and slow decline in industrial.
Assumed to be a function of
multiple factors including
renewable penetration, gas
penetration, and
EVs/PHEVs.
16 Page 41 Avista Corp. 2020 Electric IRP Appendices
0.40%
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
1.30%
20
1
9
20
2
0
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
Annual Residential Customer Growth Rates
2019 IRP Residential Customer Growth 2015 IRP Residential Customer Growth
2017 IRP Residential Customer Growth
Residential Customer Growth, 2019-2045
Medium Term Long Term
Average annual growth rate from
2019-2045 = 0.7%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
17 Page 42 Avista Corp. 2020 Electric IRP Appendices
18
Residential Solar Penetration, 2008-2017
0.00%
0.02%
0.04%
0.06%
0.08%
0.10%
0.12%
0.14%
0.16%
310,000 315,000 320,000 325,000 330,000 335,000 340,000
Sh
a
r
e

o
f

R
e
s
i
d
e
n
t
i
a
l

S
o
l
a
r

C
u
s
t
o
m
e
r
s

t
o

T
o
t
a
l

R
e
s
i
d
e
n
t
i
a
l

Cu
s
t
o
m
e
r
s
Customers
Customer Penetration vs. Customers Since 2008
2008
2014
2015
2016
2017
Page 43 Avista Corp. 2020 Electric IRP Appendices
Residential Solar Penetration, 2019-2045
19
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
20
1
9
20
2
0
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
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental PV Customers
2017 IRP Base-Line Residential Solar Customers 2019 IRP Base-Line Residential Solar Customers
By 2045, penetration will be near 1.5% of
residential customers and average size of
installed systems will be 10,000+ watts.
Current penetration is 0.14% and typical
size is 7,800 watts.
Penetration was near 0.5% of
residential customers and average size
of installed systems was 6,000 watts.
Page 44 Avista Corp. 2020 Electric IRP Appendices
Residential EVs/PHEVs, 2019-2045
20
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
20
1
9
20
2
0
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
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2017 IRP Projected EV/PHEV 2019 IRP Projected EV/PHEV
Current ≈ 700
Forecast By 2045 Prob.
Low 20,000 50%
Middle 70,000 30%
High 120,000 20%
Weighted Average 63,000
Page 45 Avista Corp. 2020 Electric IRP Appendices
Residential EVs/PHEVs by Household Income
21 Source: EIA, Today in Energy, May 2018. Regional data from U.S. Census
Spokane +
Kootenai
12%Spokane +
Kootenai
7%
Page 46 Avista Corp. 2020 Electric IRP Appendices
EV/PHEV Gasoline CO2 Savings Avista
Service Territory
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
20
1
9
20
2
0
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
Estimated EV/PHEV Gasoline CO2 Reduction in Metric Tons
22
Estimated with DOE data. Assumes 5.18
metric tons of C02 per gasoline vehicle.
Savings = Number of EV/PHEV x 5.18
Page 47 Avista Corp. 2020 Electric IRP Appendices
Native Load Forecast, 2019-2045
950
1,000
1,050
1,100
1,150
1,200
1,250
20
1
9
20
2
0
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Native Load Forecast, Average Megawatts
2019 IRP Base-Line Native Load 2015 IRP Base-Line Native Load 2017 IRP Base-Line Native Load
Medium Term Long Term
23 Page 48 Avista Corp. 2020 Electric IRP Appendices
Native Load Growth Forecast, 2019-2045
-0.1%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
20
1
9
20
2
0
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
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2019 IRP Base-Line Native Load Growth 2017 IRP Base-Line Native Load Growth
EV/PHEV “Bend”
24
IRP Avg. Annual
Growth
2019 IRP 0.40%
2017 IRP 0.51%
Page 49 Avista Corp. 2020 Electric IRP Appendices
Residential UPC Growth: 2019-2045
25
-2.50%
-2.00%
-1.50%
-1.00%
-0.50%
0.00%
0.50%
1.00%
20
1
9
20
2
0
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
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth
2019 IRP Residential Base-Line UPC Growth
Page 50 Avista Corp. 2020 Electric IRP Appendices
Long-Term Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
26 Page 51 Avista Corp. 2020 Electric IRP Appendices
Monthly Conservation as a Share of Total
Actual Retail Load: Navigant Estimates
27
Ratio = 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑦𝑦𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑌𝑌
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
Ja
n
-
9
9
Ju
l
-
9
9
Ja
n
-
0
0
Ju
l
-
0
0
Ja
n
-
0
1
Ju
l
-
0
1
Ja
n
-
0
2
Ju
l
-
0
2
Ja
n
-
0
3
Ju
l
-
0
3
Ja
n
-
0
4
Ju
l
-
0
4
Ja
n
-
0
5
Ju
l
-
0
5
Ja
n
-
0
6
Ju
l
-
0
6
Ja
n
-
0
7
Ju
l
-
0
7
Ja
n
-
0
8
Ju
l
-
0
8
Ja
n
-
0
9
Ju
l
-
0
9
Ja
n
-
1
0
Ju
l
-
1
0
Ja
n
-
1
1
Ju
l
-
1
1
Ja
n
-
1
2
Ju
l
-
1
2
Ja
n
-
1
3
Ju
l
-
1
3
Ja
n
-
1
4
Ju
l
-
1
4
Ja
n
-
1
5
Ju
l
-
1
5
Ja
n
-
1
6
Ju
l
-
1
6
Ja
n
-
1
7
Ju
l
-
1
7
Ra
t
i
o

o
f

C
o
n
s
e
r
v
a
t
i
o
n

t
o

K
W
H

L
o
a
d

Energy Crisis
ARRA
Increased
Conservation
Activity
Page 52 Avista Corp. 2020 Electric IRP Appendices
Median Monthly Conservation as a Share of
Total Actual Retail Load: Navigant Estimates
28
Median Ratio Month t = Median𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸, excluding 2001
0.776%
0.670%
0.757%
0.685%0.707%
0.757%
0.815%
0.696%
0.639%
0.722%0.717%0.739%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Me
d
i
a
n

C
o
n
s
e
r
v
a
t
i
o
n

t
o

L
o
a
d

R
a
t
i
o
Page 53 Avista Corp. 2020 Electric IRP Appendices
Comparison of Native Load Forecasts, 2019-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
20
1
9
20
2
0
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
aM
W
aMW Load Comparision with Conservation
Base-Line Native Load Base-Line Native Load with Conservation Added Back29Page 54 Avista Corp. 2020 Electric IRP Appendices
2017 IRP Action Plan Update
James Gall, IRP Manager
First Technical Advisory Committee Meeting
July 25, 2018
Page 55 Avista Corp. 2020 Electric IRP Appendices
Generation Resource Related Analysis
•Continue to review existing facilities for opportunities to upgrade capacity and efficiency.
–Avista is currently evaluating opportunities at Kettle Falls and Post Falls.
•Model specific commercially available storage technologies within the IRP; including efficiency rates,
capital cost, O&M, life cycle, and ability to provide non-power supply benefits.
–Avista will model a suite of storage options using third party data for cost and operating data. For
benefits, Avista will model both distribution and transmission level storage to quantify locational
benefits.
•Update the TAC regarding the EIM study and Avista plan of action.
–Update to be provided later this year.
•Monitor regional winter and summer resource adequacy, provide TAC with additional Avista LOLP
study analysis.
–LOLP/ELCC analysis is currently in process and will be presented at November meeting.
•Update the TAC regarding progress regarding Post Falls Hydroelectric Project redevelopment.
–Avista is evaluating multiple options at Post Falls, an update on the plan will be at the February
2019 meeting.
2 Page 56 Avista Corp. 2020 Electric IRP Appendices
Generation Resource Related Analysis
•Perform a study to determine ancillary services valuation for storage and peaking technologies using
intra hour modeling capabilities. Further, use this technology to estimate costs to integrate variable
resources.
–Avista plans on performing this study with the Avista’s ADSS model. At this time intra hour logic is
not available. If it is not available at the time of the IRP analysis, sensitivities analysis will be
performed to simulate this changes in reserve requirements.
•Monitor state and federal environmental policies effecting Avista’s generation fleet.
–Avista is continually monitoring policies that may impact the generation fleet.
3 Page 57 Avista Corp. 2020 Electric IRP Appendices
Energy Efficiency and Demand Response
•Determine whether or not to move the T&D benefits estimate to a forward looking value versus a
historical value.
–Avista is participating in the PNUCC and the NPCC investigation into a reasonable methodology to
determine T&D deferral values. Avista plans to use the preferred methodology from this effort. As of
now, the method is based on the utilization factor of expected capital spending on T&D projects.
•Determine if a study is necessary to estimate the potential and costs for a winter and a summer
residential demand response program and along with an update to the existing commercial and
industrial analysis.
–Avista has engaged AEG to conduct this study. The results will be shared at the March Meeting.
•Use the utility cost test methodology to select conservation potential for Idaho program options.
–Avista is still committed to this methodology
•Share proposed energy efficiency measure list with Advisory Groups prior to CPA completion.
–A list will be made available prior to the March meeting.
4 Page 58 Avista Corp. 2020 Electric IRP Appendices
Transmission and Distribution Planning
•Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for transmission
service to bundled retail native load.
–Avista is committed to this Action Item and actively engages in this area.
•Continue to participate in BPA transmission processes and rate proceedings to minimize costs of
integrating existing resources outside of Avista’s service area.
–Avista is committed to this Action Item and actively engages in this area.
•Continue to participate in regional and sub-regional efforts to facilitate long-term economic expansion
of the regional transmission system.
–Avista is committed to this Action Item and participates in these efforts.
•IRP and T&D planning will coordinate on evaluating opportunities for alternative technologies to solve
T&D constraints.
–Avista will model at least five locations for both transmission and distribution assets where the
system could alternatively be upgraded with a distributed energy resources (DER) rather than
traditional assets to test whether or not a coordinated DER is a lower cost to customers.
5 Page 59 Avista Corp. 2020 Electric IRP Appendices
Draft 2019 Electric IRP Work Plan
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
July 25, 2018
Page 60 Avista Corp. 2020 Electric IRP Appendices
Tentative TAC Meetings
•TAC 1 (July 25, 2018): TAC Meeting Expectations and IRP process overview,
review of 2017 IRP Commission acknowledgement letters and policy
statements, demand and economic forecast, draft 2019 Electric IRP Work
Plan, and Hydro One’s merger agreement’s impact on the 2019 IRP.
•November 2018: Modeling process overview, generation options (costs and
assumptions), resource adequacy and ELCC analysis, overview of home
heating technologies and efficiency, expected case key assumptions (regional
loads, CO2 regulation, etc…), and market and portfolio scenarios.
•February 2019:Natural gas price forecast, electric market forecast, IRP
transmission planning studies, distribution planning within the IRP, existing
resource overview –Colstrip, Lancaster and other resources, and final
resource needs assessment.
•March 2019: Ancillary services and intermittent generation analysis,
conservation and demand response potential assessment (AEG), Pullman
Smart Grid Demonstration Project review, draft Preferred Resource Strategy,
and draft market and portfolio results.
•April 2019: Review of final PRS, market scenario results, portfolio scenario
results, carbon cost abatement supply curves and 2019 Action Items.
22 Page 61 Avista Corp. 2020 Electric IRP Appendices
2019 Draft Electric IRP Timeline
Preferred Resource Strategy (PRS)Tasks Target Date
Finalize energy forecast July 2018
Identify Avista’s supply resource options September 2018
Begin Aurora market model development October 2018
Energy efficiency load shapes input into Aurora November 2018
Finalize data sets/statistics variables for risk studies November 2018
Transmission and Distribution studies due December 2018
Finalize natural gas price forecast December 2018
Communicate energy efficiency options to TAC December 2018
Finalize deterministic & stochastic expected case market studies January 2019
Due date for additional study requests January 15, 2019
Develop PRiSM model January 2019
Finalize peak load forecast February 2019
Finalize PRiSM model assumptions February 2019
Simulation of risk studies “futures” complete February 2019
Simulate market scenarios in Aurora February 2019
Evaluate resource strategies against market futures and scenarios March 2019
Present preliminary study and PRS to TAC March 2019
3 Page 62 Avista Corp. 2020 Electric IRP Appendices
2019 Draft Electric IRP Timeline
Writing Tasks Target Date
File 2019 IRP Work Plan August 31, 2018
Prepare report and appendix outline October 2018
Prepare text drafts April 2019
Prepare charts and tables April 2019
Internal drafts released at Avista May 2019
External draft released to the TAC May 31, 2019
TAC comments and edits due June 28, 2019
Final editing and printing August 2019
Final IRP submission to Commissions and distribution to TAC August 31, 2019
4 Page 63 Avista Corp. 2020 Electric IRP Appendices
2019 IRP Modeling Process
Preferred
Resource
StrategyAURORA
“Wholesale Electric Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Existing Resources
Resource Options
Transmission
Resource & Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
&RPS
Balances Generation/Storage
Options & Costs
T&D
Projects/Costs
Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
5
Demand Response
Measures/Costs
Environmental
Policy
Page 64 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP Draft Outline
•Executive Summary
•Introduction and Stakeholder Involvement
•Economic and Load Forecast
–Economic Conditions
–Avista Energy and Peak Load Forecast
–Load Forecast Scenarios
•Existing Supply Resources
–Avista Resources
–Contractual Resources and Obligations
6 Page 65 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP Draft Outline
•Energy Efficiency and Demand Response
–Conservation Potential Assessment
–Demand Response Opportunities
•Long-Term Position
–Reliability Planning and Reserve Margins
–Resource Requirements
–Reserves and Flexibility Assessment
•Policy Considerations
–Environmental Concerns
–Greenhouse Gas Issues
–State and Federal Policies
7 Page 66 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP Draft Outline
•Transmission & Distribution Planning
–Avista’s Transmission System
–Future Upgrades and Interconnections
–Transmission Construction Costs and Integration
–Transmission and Distribution Efficiencies
•Generation Resource Options
–New Resource Options
–Avista Plant Upgrades
8 Page 67 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP Draft Outline
•Market Analysis
–Marketplace
–Fuel Price Forecasts
–Market Price Forecast
–Scenario Analysis
•Preferred Resource Strategy
–Resource Selection Process
–2017 Preferred Resource Strategy
–Efficient Frontier Analysis
–Avoided Cost
9 Page 68 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP Draft Outline
•Portfolio Scenarios
–Portfolio Scenarios
–Tipping Point Analyses
•Action Plan
–2017 Action Plan Summary
–2019 Action Plan
10 Page 69 Avista Corp. 2020 Electric IRP Appendices
Hydro One Merger Agreements Related to Resource
Planning
James Gall, IRP Manager
First Technical Advisory Committee Meeting
July 25, 2018
Page 70 Avista Corp. 2020 Electric IRP Appendices
Avista’s Proposed Merger with Hydro One
•Regulatory process update:
•Announced proposed merger July 2017
•Applications for approval filed in September 2017
•Federal approvals received
•Approvals from Alaska and Montana received
•Settlement agreements reached and filed in Washington, Idaho and Oregon.
Approvals are still pending in these states.
•We continue to work through the regulatory process toward approval
More information at www.myavista.com/hydroone
2 Page 71 Avista Corp. 2020 Electric IRP Appendices
Presentation Objective
•This presentation will review agreements between Avista, Hydro One
and intervening parties related to the Electric IRP per the merger
agreements in Washington & Idaho.
•These agreements will include methodology and specific goals the next
IRP shall include if the merger is approved.
3 Page 72 Avista Corp. 2020 Electric IRP Appendices
WA #52 Renewable Portfolio Standard Requirements
Hydro One acknowledges Avista’s obligations under applicable
renewable portfolio standards, and Avista will continue to comply with
such obligations.
Avista will acquire all renewable energy resources required by law and
such other renewable energy resources as may from time to time be
deemed advisable in accordance with Avista’s integrated resource
planning (“IRP”) process and applicable regulations.
4 Page 73 Avista Corp. 2020 Electric IRP Appendices
WA #53 Renewable Energy Resources
Avista’s non-fossil fueled generation resources constitute more than 50% of its
generation portfolio, and Avista exceeds the renewable energy standards
currently applicable to the company under RCW 19.285.040(2).
Avista makes the following renewable energy commitments. Both commitments
are made only to the extent resources are reasonably commercially available
and are (1) necessary to meet load and (2) consistent with the lowest
reasonable cost resource portfolio pursuant to Avista’s established IRP and
pursuant to the Commission’s resource evaluation and acquisition rules and
policies.
5 Page 74 Avista Corp. 2020 Electric IRP Appendices
WA #53 (a) Renewable Energy Resources
Avista will commit to initiating a Request for Proposal with the intent of acquiring
additional eligible renewable energy resources as part of this process above
and beyond the current renewable energy standards in law. Avista will commit
to obtain approximately 50 aMW of expected energy from new eligible
renewable resources by 2022.
The aMW obtained under this commitment may be used to satisfy any increase
that may be caused by changes to the renewable energy standards in law after
the date an Order approving this merger has been entered.
6 Page 75 Avista Corp. 2020 Electric IRP Appendices
ID #52: Renewable Energy Resources
Avista will continue to offer renewable power programs in consultation with
stakeholders.
Communications with customers shall accurately reflect the environmental attributes
associated with power delivered to such customers. Hydro One and Avista
acknowledge that Avista retains the burden of proof to demonstrate the prudence of
any resource acquisition.
Nothing in this Commitment prohibits Avista from selling renewable energy credits that
arise from resources included in base rates applicable in Idaho. Hydro One
acknowledges Avista's obligations under applicable renewable portfolio standards, and
Avista will continue to comply with such obligations.
7 Page 76 Avista Corp. 2020 Electric IRP Appendices
RFP Schedule
•June 6, 2018 –RFP Issuance
•June 20, 2018 –Preliminary Information due (CLOSED)
•June 29, 2018 –Short list identified
•July 20, 2018 –Detailed Proposals due from short-listed bidders
(Exhibit C)
•July 23, 2018 through August 15, 2018 –Negotiations with short-
bidders
•August 29, 2018 –Final bidder(s) selected
•November 2, 2018 -Final contracting complete with successful
bidder(s)
8 Page 77 Avista Corp. 2020 Electric IRP Appendices
RFP Bid Summary
•Nearly 900 aMW from 48 bids
•Proposals included wind, solar, geothermal, fuel cells, and storage
•From Washington, Idaho, Montana, Oregon, and Nevada
•Both PPA’s and build to own transfers were received
9 Page 78 Avista Corp. 2020 Electric IRP Appendices
WA #53 (b) Renewable Energy Resources
Avista will commit to obtain at least 90 aMW of expected energy from
new eligible renewables resources to become operational approximately
within a year of the timeframe that Colstrip 3 and 4 go offline.
“Resources” is understood to include Power Purchase Agreements (“PPAs”). Nothing in either commitment prohibits
Avista from retaining or selling renewable energy credits associated with such resources that are surplus to Avista’s
needs to meet Washington Renewable Portfolio Standards targets.
Communications with customers shall accurately reflect the environmental attributes associated with power delivered to
such customers. Hydro One and Avista acknowledge that Avista retains the burden of proof to demonstrate the
prudence of any resource acquisition.
The utility should work with an independent third-party consultant, with expertise in renewable energy resources, to
ensure that the utility has up-to-date resource cost and performance assumptions, as well as the appropriate learning
curves.
10 Page 79 Avista Corp. 2020 Electric IRP Appendices
WA #54 & ID #56 Greenhouse Gas and Carbon
Initiatives
Hydro One acknowledges Avista’s Greenhouse Gas and Carbon
Initiatives contained in its current Integrated Resource Plan, and
Avista will continue to work with interested parties on such
initiatives.
11 Page 80 Avista Corp. 2020 Electric IRP Appendices
WA #57 Energy Efficiency Goals and Objectives
Hydro One acknowledges Avista’s energy efficiency goals and
objectives set forth in Avista’s 2017 Integrated Resource Plan and
other plans, and Avista will continue its ongoing collaborative efforts
to expand and enhance them.
12 Page 81 Avista Corp. 2020 Electric IRP Appendices
ID #53 Regulatory IRP Sideboards
Avista and its affiliates agree to consider in all resource planning and acquisition efforts both demand-side
and renewable energy resources that are consistent with the Idaho Commission's resource evaluation and
acquisition rules and policies.
•Avista and its affiliates agree that "Resources" to be considered in all IRPs include Power Purchase
Agreements ("PPAs").
•Avista commits to calculating a variable generation resource's contribution to capacity in terms of that
resource's contribution to resource adequacy and that resource's ability to reduce the loss of load
probability in some or all hours or days utilizing the Effective Load Carrying Capability ("ELCC")
methodology or an appropriate approximation.[WA #60]
•Avista will work with an independent third-party consultant, with expertise in renewable energy
resources, to ensure that the utility has up-to-date resource cost and performance assumptions, as well
as the appropriate learning curves, for use in the 2019 IRP process.
•Unless it conflicts with any instructions contained in the Commission's acknowledgement letter in
response to Avista's current integrated resource plan (IRP), beginning with the next IRP, Avista commits
to modeling a range of potential costs for greenhouse gas emissions, and will work with its IRP
Advisory Group to determine the appropriate values to model. [WA #55]
13 Page 82 Avista Corp. 2020 Electric IRP Appendices
WA #76 & ID #69 Colstrip Depreciation
Hydro One and Avista agree to a depreciation schedule for Colstrip
Units 3 and 4 that assumes a remaining useful life of those units
through December 31, 2027.
WA: See Attachment A to Appendix A (Master List of Commitments in Washington) to the
Settlement Stipulation, “Colstrip Commitment Summary and Description”
ID: See #69 for full description of commitment14Page 83 Avista Corp. 2020 Electric IRP Appendices
Other “IRP” Related Items
WA #58: Optional renewable power program
WA #59 & ID #54: Energy Imbalance Market (“EIM”)
WA #61: Industrial customers’ self direct conservation
WA #62 & ID #55: Transport electrification
WA #63: Professional home energy audit
WA #65 & ID #58: Low-income energy efficiency funding
WA #67: Funding for low-income participation in new renewables
WA #69: Replacement of manufactured homes
WA #70: Low-income weatherization
ID #59 & #60: Industrial load DSM assistance
ID #71: Colstrip transmission planning
15 Page 84 Avista Corp. 2020 Electric IRP Appendices
Attendees: TAC 1, July 25, 2018 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Kirsten Wilson, Washington State DES; Amy Wheeless, NW
Energy Coalition; David Nightingale, Washington UTC; Doug Howell, Sierra Club; Kathlyn Kinney, Biomethane; Grant Forsyth, Avista; Jorgen Rasmussen, Solar Acres Farm; John Barber, Rockwood Retirement Communities; Gerry Snow, PERA; Dean Kinzer, Whitman County Commission; Garret Brown, Avista; Scott Kinney, Avista; Yao Yin, IPUC; Ben Serrurier, Cyprus Creek Renewables; Terrence Browne, Avista; Jason
Thackston, Avista; Darrell Soyars, Avista; Kim Vollan, Avista; Kevin Davis, IEP; Matt Nykiel, ICL; Ryan Finesilver, Avista; Paul Kimmel, Avista; and John Osborne, MD.
Phone:
Kelly Hall, Climate Solutions; Mike Starrett, NPCC; Steve Johnson, Washington UTC;
Ian Bledsoe; Energy Consultant, NW Energy Coalition
These notes follow the progression of the meeting. They include summaries of the
questions and comments from those not presenting, the responses (in italics), as well
as significant points raised by the presenters that are not shown on the slides
TAC Expectations and Process Overview, John Lyons
Presentation covering the background behind the electric IRP, TAC member
involvement, review agenda for the day and expectations from Avista and from the TAC.
• Jorgen Rasmussen: Can we have someone come in and talk about energy
security? Yes, Avista will look into adding this as a topic.
• Amy Wheeless: Request to track all questions, requests and responses.
• Matt Nykiel: Asked about getting assumptions earlier in the process to be able to
understand them better and make comments. Yes, Avista will work on this and
many of the assumptions will be made available at the next meeting in
November 2019.
• Amy Wheeless: How do we discuss the assumptions? The TAC gets the slides
with the assumptions ahead of the meetings.
• Doug Howell: Would like to see the slides three days ahead of the meetings.
Slides will go out on Friday before the Tuesday or Wednesday meetings.
• Matt Nykiel: Concerns about slide #3 and limitations to the discussions and
questions asked. The points are in the slides to make sure we can get through
the agenda for each TAC meeting.
• Amy Wheeless: We want an open exchange of ideas. Request that participants
can provide data and Avista will consider using it. It is best if the data is
publically available.
• David Nightingale: Discussion on minutes of the TAC and how they will be made
available. Avista is still working on the logistics of this, possibly by email or even
posted on the web site.
Page 85 Avista Corp. 2020 Electric IRP Appendices
• Gerry Snow: Is there a continuing forum between meetings? Can Google Docs
be used? There isn’t an ongoing forum or discussion group, but the IRP is
available by email and phone for any questions, comments and concerns.
Information can then be passed on to the whole TAC. No, IT policy doesn’t allow
us to use Google Docs, but could explore the use of One Drive if email doesn’t
work for TAC members.
• Clint Kalich: Discuss how the Avista web site is used in conjunction with the IRP.
Showed the TAC where to find the IRP section of the web site and the
documents available there.
2017 IRP Acknowledgements & Policies, James Gall
Presentation covering the expectations and comments in the acknowledgment letters
received from the Idaho and Washington Commissions for the 2017 Electric IRP.
• Doug Howell: Passed around letter dated June 26, 2018 to the Idaho, Montana,
Oregon and Washington utility commissions concerning Westmoreland Coal
Company; handout titled “Fracked Gas The Next Big Climate Fight;” and a July
24, 2018 article from The Billings Gazette concerning the Colstrip outage.
• Doug Howell: Wants more details on the assumptions for air quality controls at
Colstrip.
• Steve Johnson: Comment about sheltering or excluding anyone involved in
negotiations for a new contract or purchase of the Lancaster facility from non-
public analysis to ensure they are arm’s length from any new transaction.
• Doug Howell: Colstrip remediation and decommissioning and how it is going to
be paid for in a way that provides intergenerational equity.
• Doug Howell: How are existing capital projects used for supporting investment in
the IRP, Colstrip capital? This is a resource decision that uses the IRP
developed avoided cost to analyze new projects.
• Steve Johnson replied that unsure if the IRP is the place to describe how much
and when money is to be recovered for Colstrip. The Company would
demonstrate prudence in a future rate proceeding, not jumping ahead in an IRP
to design a cost recovery mechanism. The IRP recognizes such costs to be
included in depreciation recovery. IRP should identify all risks for Colstrip Units 3
and 4 and potential costs in response to the acknowledgment letter from the
Washington UTC.
• Matt Nykiel: Wants the group to be kept informed on whether a decision has
been made on depreciation at Colstrip.
• Steve Johnson offered to have a more detailed meeting with the public about
rate making.
• Dave Nightingale: Anticipation of a resource becoming unavailable if
uneconomic. Identify resources that are at risk of going away.
Page 86 Avista Corp. 2020 Electric IRP Appendices
• Matt Nykiel: Will the November meeting discuss regional coal policies from
Portland General Electric and PacifiCorp in Oregon? Yes, regional coal policies
will be covered in a later meeting.
• Doug Howell: Wants to include the risk associated with the growing liabilities of
upstream natural gas leakages. Avista has not historically considered
externalities beyond those required by laws or regulations, but will take this
request into consideration.
• Doug Howell: The Sierra Club wants the inputs for Aurora so they can have a
consultant review them and run the models. This will require a discussion at
Avista to determine what data could be shared and how it could be shared.
• Matt Nykiel: Concerns with how we can discuss the inputs without having all of
the data.
• Ben Serrurier: Do the consultants provide the data that supports how they
derived their natural gas price forecasts and can that be shared with the TAC?
Yes, Avista can provide what we are allowed to. Probably cannot give specific
details, but should be able to share the main driving forces behind the gas price
forecasts.
• Yao Yin: What if there are big differences between the two consultants for the
gas price forecasts if there are conflicting or different assumptions? Avista has
blended these forecasts in the past and has not seen fundamentally different
forecasts. Any major differences would probably be due to conflicting
assumptions.
• Dave Nightingale: Will there be high, low and medium cases? Avista does an
expected case with stochastics with an average of the 500 futures as the
expected case. Ask the consultant to do a high and low forecast. Avista will
check into this with the consultants, but it may be too costly.
• James Gall: Should we include some more information here about distributed
generation and energy storage? Yes and storage will be included as a new
resource option.
• Amy Wheeless: More distributed resources and non-traditional. Yes, Avista will
include more options and will need to see how far we can take this.
• Ben Serrurier: How are you choosing the five projects for distribution upgrades?
The amounts were small enough that we asked that group for five. UTC
threshold, but we are looking at needs and what could be met by a distributed
energy resource to solve constraints in the IRP timeframe.
• Kirsten Wilson: Regarding Washington Executive Order 1801, is vehicle-to-grid
storage going to be included? Washington State University may have to follow
the rules identified in the Executive Order. Avista will try to incorporate this, but
really has no control over this type of resource. Vehicle-to-grid storage may end
up being a scenario.
Page 87 Avista Corp. 2020 Electric IRP Appendices
• Steve Johnson: Offline, examine paragraph 43 of the UTC policy on storage
framework or method. Is this practical or is there a better way of doing it?
Criticism has been leveled at this method. Avista will probably do this in PRiSM.
• Doug Howell: For carbon prices, include the implications of the upstream
emissions.
• Dave Nightingale: Regarding how to share meeting minutes, they usually get
approved at the next meeting. Avista still needs to decide on the best way to
share the meeting minutes with the TAC.
• Dave Nightingale: The second and third bullets (WUTC IRP Rulemaking about
requests for proposals and avoided costs) are being handled separately as two
rulemakings under separate dockets. On a parallel track with conservation
(under the Advisory Group) with a subgroup for distribution planning. This is still
in discussions and a new draft will be ready in the next month or so. It will be
done by the end of the year, but will be surprised if the new regulations get
applied to this IRP.
• Yao Yin: Third point, avoided cost, trying to unwind: PURPA, resource
differences, and improved rule on how to use it. Idaho has a SAR (surrogate
avoided resource) and IRP method. Larger and smaller resource methods,
maybe we should talk offline about these.
• Doug Howell: Suggest using the Washington Governor’s Deep De-carbonization
Study to get assumptions on EV, building codes, solar and others. Avista will run
a scenario with higher assumptions.
Break (back at 10:55)
Demand and Economic Forecast, Grant Forsyth
• Grant Forsyth: Employment is one of the big drivers for customer growth, 71% of
the local economy is service based.
• Clint Kalich: Does local government include schools? Yes, it is the biggest share
and includes faculty, teachers and administrators.
• Grant Forsyth: Fairchild Air Force Base is going to be accepting all of the older
KC135 tankers as the new tankers are deployed elsewhere, so there will be a
buildup at Fairchild.
• Grant Forsyth: Idaho is growing faster than Washington service territory in
employment and population. The MSA (Metropolitan Statistical Area) is a well-
defined urban area with over 50,000 people.
• Dave Nightingale: Why is non-farming used? Farming is so low for employment it
does not make a huge difference. It is much bigger for income.
• Grant Forsyth: In-migration is the key driver for customer growth
• Grant Forsyth: Population growth is a strong proxy for customer growth.
• Garrett Brown: What is the impact of the recent announcement by Amazon?
[Warehouse in Airway Heights with 1,500 expected employees] Not a large direct
impact because they will be an Inland Power Customer, but Avista will serve their
Page 88 Avista Corp. 2020 Electric IRP Appendices
natural gas needs and will benefit from in-migration with some amount of
household and ancillary business growth.
• Doug Howell: Which are excluded to run the regression [in the peak load
forecast]? Excludes Clearwater and IEP (Inland Empire Paper) and then adds
them back in.
• Kathlyn Kinney: Why is the summer peak growing faster? It is a combination of
weather changes (why we moved from 30 to 20-year weather data); increased air
conditioning load because of higher incomes and lower costs for air conditioners;
winter conservation; and fuel switching from electric to natural gas.
• Grant Forsyth: There is a less strong impact from GDP on loads than in the past.
• Dave Nightingale: Graphically look at this, do these make sense based on the
past.
• Dave Nightingale: Are these GDP numbers regional? No, they are national GDP
estimates because our region follows the national numbers closely and regional
forecasts are scarce.
• Yao Yin: Questions about GDP differences in slide 11 (Current Peak Load
Forecasts for winter and summer, 2018-2043). Yes, they are different for each
year for 5 to 6 years, then extended out for the rest of the forecast.
• James Gall: Peak demand – we are planning to serve this load over the next 20
years plus a 14% peak planning margin and operating reserves. This made us
short in 2027 in the last plan. We may make adjustments as we get more data.
• Amy Wheeless: How does 14% compare to others? 11 – 17%. Depends on what
is included. We add operating reserves putting us at 21-22%, NPPC is about
23%. Water based utilities usually have higher planning margins for running out
of water. There is a chart on this in the last two IRPs.
• Yao Yin: Is PM necessary? Yes, we were able to cover the 2009 extreme cold
event.
• Matt Nykiel: Actual vs. forecast, do you have a chart? No, but James Gall looks
at the forecast vs. the actual after every event. We are not sure if we could add
this.
Long-term load forecast section
• Doug Howell: Is the 20-year data capturing the warming shift? It varies within our
service territory based on the work done by NASA. There is more of a warming
shift in Medford than Washington. The data shows the shift has somewhat
stabilized in the 20-year period.
• Amy Wheeless: UW climate impact and SnoPUD have data on this.
• Matt Nykiel: How do you pick the forward climate model? Can we use an average
like GDP? Potentially, we can verify GDP with historic data, but climate data may
be tough to correlate because it is lumpy, not uniform.
• Steve Johnson: Currently, is Avista’s view that the risk of climate change is open
ended? Yes, to the extent we can’t quantify it.
Page 89 Avista Corp. 2020 Electric IRP Appendices
• Clint Kalich: Magnitude of temperature and could also run scenarios on other
changes with similar results. Put a statement about risk and what we are
thinking.
• Yao Yin: Why not an econometric model for the long term? We could, but would
also need a population growth forecast.
• Garrett Brown: Is it positive or negative growth? Still positive, but about half
percent long term. 5% or more solar penetration starts making a difference.
More aggressive solar growth with larger projects over 10,000 watts.
• Yao Yin: Relationship between load and solar. How much is solar taking off of
load, the net impact?
• Doug Howell: What about the Commerce predictions for electric vehicles
(Executive Order 18-01)? Have not been able to determine where they got their
goals from, maybe the Governor’s deep de-carbonization pathway. We are going
to run some scenarios on different levels of electric vehicles, solar and
electrification.
• Amy Wheeless: Are electric vehicle fleets growing faster? In the model, there is a
connection to residential and commercial loads.
• David Nightingale: Distribution of model by Washington EVs (electric vehicles)
may be shifting with new models. Income and household density are the drivers
for EVs. Density is 4 times less in Spokane, so people live far enough away to
have some range anxiety.
• Jorgen Rasmussen: Also need to consider the used EV market and the number
and location of chargers. There are fewer chargers in our service territory.
• Jorgen Rasmussen: Could also consider the consumption of refineries. How far
do we take this?
• Yao Yin: Why not include solar in the resource side? This is for customer-owned
solar.
• Gerry Snow: When will we see the “duck curve”? Partly by feeder. 5% and higher
penetration will affect us for solar. This is more on an issue with Power Supply.
The location of the solar is important.
• Doug Howell: It would be useful if we could see growth rates and efficiency in a
deep de-carbonization scenario and how this overlays with the economic
forecast. Would need to see what kind of specific data we could get for this.
• David Nightingale: Electric vehicles are not utility scale, but impact Avista’s
system. Reliable, planning level at what point for electric vehicles and solar?
Summer peaks maybe.
• Doug Howell: When are the peaks? 6 pm in the summer and 7 – 8 am / 5 – 6 pm
in the winter.
• Kathlyn Kinney: Energy storage with hydrogen could change this.
• Yao Yin: (Slide 29 Median Monthly Conservation as a Share of Total Actual
Retail Load: Navigant Estimates): Have the ratios for the Navigant coefficients stayed the same? They have increased a bit, but not very much since using the
Page 90 Avista Corp. 2020 Electric IRP Appendices
median rather than the average. The conservation estimate is from the DSM
area.
• Jorgen Rasmussen: Have there been more energy savings in the LEDs vs. the
conversions to natural gas? Yes, the LED lighting conversions are about double
the energy savings for lighting. Conversions to LED provide more savings than
fuel conversions on a per kWh basis.
• Amy Wheeless: The WUTC is wanting less fuel conversions.
• On the last slide, the blue line is the starting point for conservation selection
Lunch 12:00
2017 Action Plan Updates, James Gall
• Amy Wheeless: Are we presenting data on bullet 1, page 4. Yes, we will present.
Yes, publically.
• Doug Howell: List of BPA commitments with Governor Bullock’s (Montana)
process. Scott Kinney replied that we have done most of them and the rest are
up to BPA.
2019 IRP Draft Work Plan, John Lyons
• Dave Nightingale: Consider placing a draft IRP review place holder meeting at
the end.
• Gerry Snow: Are you considering additional storage instead of new resources?
Yes.
• Doug Howell: There is an expectation of signing a non-disclosure agreement to
be able to get the inputs used for the March and April meetings. We want to set
up a process to the data? Avista will need to meet internally and discuss this.
• Matt Nykiel: Timing of the November meeting, add time to the agenda to follow
up on assumptions.
• Amy Wheeless: Can Avista be more nimble for inputs to be shared regarding
CO2? We are going to try, but there are several moving parts with the election
and potential upcoming state legislative efforts in Washington.
• Doug Howell: How are you going to decide how to implement the social cost of
carbon and the citizen’s initiative (I-1631 carbon fee)? Avista is still determining
how to do this and waiting for the results of the November election.
• Jorgen Rasmussen: Remember the initiative (I-1631) is considered a fee instead
of a tax. Yes, it is modeled the same as a tax even though it’s a fee and the
recent state court ruling upheld I-1631 as a fee instead of a tax.
• Scott Kinney: Would like to add that there may be limits to the amount of studies
that can be run based on how many requests we receive.
Break
Hydro One Merger Agreements, James Gall
Page 91 Avista Corp. 2020 Electric IRP Appendices
• Jason Thackston: Avista is accelerating the depreciation for Colstrip as part of
the Hydro One agreement in Washington and only if the transaction is approved
in all five states and is consummated. Idaho has a separate depreciation study
case.
• Mike Starrett (phone): For the RFP short-list (for new, renewable generation), are
they below cost? Avista cannot share the specific cost information, but we are
getting current pricing data on renewable generation.
• Doug Howell: Would like to acknowledge the $4.5 million commitment to the City
of Colstrip by Hydro One.
Adjourn
Page 92 Avista Corp. 2020 Electric IRP Appendices

2019 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Tuesday, November 27, 2018 Conference Room 130
Topic Time Staff
Introductions and TAC 1 Recap 9:30 Lyons

Modeling Process Overview 9:40 Gall Generation Resource Options 10:10 Gall Break 11:00
Home Heating Technologies Overview 11:15 Lienhard

Lunch 12:00

Resource Adequacy and Effective Load 1:00 Gall
Carrying Capability
Electric IRP Key Assumptions 1:45 Gall/Lyons Break 2:30 2019 IRP Futures and Scenarios 2:45 Gall/Lyons

Adjourn 3:30
Page 93 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
November 27, 2018
Page 94 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next two years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2 Page 95 Avista Corp. 2020 Electric IRP Appendices
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 in all or some of the process
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–January 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3 Page 96 Avista Corp. 2020 Electric IRP Appendices
TAC #1 Recap –July 25, 2018
•Introduction
•TAC Expectations and Process Overview
•2017 IRP Acknowledgments and Policies
•Avista’s Demand and Economic Forecast
•2017 Action Plan Updates
•2019 IRP Draft Work Plan
•Hydro One Merger Agreements
•Meeting minutes are available on the IRP web site at
https://www.myavista.com/about-us/our-
company/integrated-resource-planning
4 Page 97 Avista Corp. 2020 Electric IRP Appendices
Today’s Agenda
•9:30 –Introductions and TAC 1 Recap, Lyons
•9:40 –Modeling Process Overview, Gall
•10:15 –Generation Resource Options, Gall
•11:00 – Break
•11:15 –Home Heating Technologies Overview, Lienhard
•12:00 –Lunch
•1:00 –Resource Adequacy and Effective Load Carrying
Capability, Gall
•1:45 –Key Assumptions, Gall and Lyons
•2:30 – Break
•2:45 –Futures and Scenarios, Gall and Lyons
•3:30 –Adjourn
5 Page 98 Avista Corp. 2020 Electric IRP Appendices
TAC 3 Topics
•TAC 3 on Wednesday, February 6, 2019
•Natural Gas Price Forecast
•Electric Market Forecast
•IRP Transmission Planning Studies
•Distribution Planning within the IRP
•Existing Resource Overview (Colstrip,
Lancaster, and other resources)
•Final Resource Needs Assessment
6 Page 99 Avista Corp. 2020 Electric IRP Appendices
2019 IRP Modeling Process Overview
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
November 27, 2018
Page 100 Avista Corp. 2020 Electric IRP Appendices
IRP Modeling Process
•The purpose of this discussion is to help you
understand the steps and process associated
with the analysis of the IRP.
•This presentation outlines the steps to develop
the plan along with a high level discussion of
how the tools and methods are used.
Page 101 Avista Corp. 2020 Electric IRP Appendices
2019 IRP Modeling Process
Resource
StrategyAURORA
“Wholesale Electric Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Existing Resources
Resource Options
Transmission
Resource & Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,Capacity,&RPS BalancesResource Adequacy Generation/Storage
Options & Costs
T&D
Projects/Costs
Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
3
Demand Response
Measures/Costs
Environmental
Policy
Page 102 Avista Corp. 2020 Electric IRP Appendices
•3rd party software-EPIS, Inc./Energy Exemplar
•Electric market fundamentals-production cost model
•Simulates generation dispatch to meet load and allows
for system constraints
Electric Market Modeling
4
Outputs:
–Market prices
–Energy mix
–Transmission usage
–Emissions
–Power plant margins,
generation levels, fuel costs
–Avista’s variable power supply
costs
Inputs:
–Regional loads*
–Fuel prices*
–Fuel availability*
–Resources (availability*)
–New resources costs
–Transmission
*Stochastic input
Page 103 Avista Corp. 2020 Electric IRP Appendices
Aurora Modeling Changes from 2017 IRP
•Use Epis/Energy Exemplar latest database vs.
Avista’s proprietary database
•Updates to the Epis database will include:
•Avista specific characteristics (load/generation/fuel)
•Fuel prices
•Regional hydro conditions (80-year record)
•Adjustments to allow market prices to go negative
•Load shape changes (electric vehicles/rooftop solar)
•Known regional resource retirements
•Split Northwest area between WA, OR, and ID (TBD)
Page 104 Avista Corp. 2020 Electric IRP Appendices
Aurora Load Area Topology
Potential split by
state due to
environmental
policies
6 Page 105 Avista Corp. 2020 Electric IRP Appendices
Stochastic vs. Deterministic Analysis
•Deterministic analysis forecasts for a specific set of
inputs.
–Easy to understand
–Works great for sensitivity analysis of specific changes
•Stochastic analysis forecasts for a range of inputs.
–Range (or distribution) of results
–Works great to understand risks of the inputs with variation
Deterministic
Stochastic7Page 106 Avista Corp. 2020 Electric IRP Appendices
PRiSM-Preferred Resource Strategy
Model
Internally developed using Excel based linear/mixed
integer program model (What’s Best & Gurobi)
Selects new resources to meet Avista’s capacity, energy,
and renewable energy requirements
Outputs:
–Power supply costs (variable and fixed)
–Power supply costs variation
–New resource selection (generation/conservation)
–Emissions
–Capital requirements
8 Page 107 Avista Corp. 2020 Electric IRP Appendices
PRiSM
Find optimal resource strategy to meet resource deficits over
planning horizon
New for the plan: Split Avista’s resources and loads
–City of Spokane
–Idaho
–Washington
Model selects its resources to reduce cost, risk, or both.
Objective Function:
–Minimize: Total Power Supply Cost on NPV basis (2020-2058)
–Focus on first 20 years of the forecast
–Subject to:
•Risk level•Capacity need +/-deviation•Energy need +/-deviation
•Renewable portfolio standards•Resource limitations, sizes, and timing
9 Page 108 Avista Corp. 2020 Electric IRP Appendices
Efficient Frontier Concept
•Does not find the optimal portfolio, only the optimal
portfolio for a given level of risk.
•Used in investment finance for portfolio management.
Return
Ri
s
k
Equities
Bonds
Government Debt
Stock vs. Bond Example
Efficient Frontier
10 Page 109 Avista Corp. 2020 Electric IRP Appendices
Efficient Frontier
Demonstrates the trade off of cost and risk
Avoided Cost Calculation
Ri
s
k
Least Cost Portfolio
Least Risk Portfolio
Find least cost
portfolio at a given
level of risk
Short-Term Market
Market + Capacity + RPS = Avoided Cost
Capacity Need
+ Risk
Cost
11 Page 110 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP
Generation Resource Options
James Gall,
Second Technical Advisory Committee Meeting
November 27, 2018
Page 111 Avista Corp. 2020 Electric IRP Appendices
Overview & Considerations
•The assumptions discussed are “today’s” estimates and will likely have
periodic revisions.
•Resource costs vary depending on location, equipment, fuel prices, and
ownership; while IRPs use point estimates, actual costs will be different.
•Avista retained Black & Veatch to review the renewable and storage
resource assumptions as part of the Hydro One merger agreement.
•Certain resources will be modeled as purchase power agreements (PPA)
while others will be modeled as Avista “owned”. These assumptions do not
mean they are the only means of resource acquisition.
•No transmission or interconnection costs are included at this time.
•Natural gas prices used “today” will be revised with the “final” assumption in
January 2019.
•An Excel file will be distributed with all resources, assumptions and cost
calculations for TAC members to review and provide feedback.
2 Page 112 Avista Corp. 2020 Electric IRP Appendices
Proposed Natural Gas Resource Options
Peakers
•Simple Cycle Combustion Turbine (CT)
–Aero and frame units
–Smaller units 44 MW to 80 MW
–Larger units up to 245 MW
•Hybrid CT
–92 MW
•Reciprocating Engines
–9 MW to 18 MW units with up to
10 engines
Baseload
•Both modern and advanced Combined
Cycle CT (CCCT) will be evaluated
–Smaller options 158 MW to 308
MW (3x2, 1x1)
–Larger options 324 MW to 480
MW (1x1)
•Large 2x1 technology not modeled
Natural gas turbines are modeled using a 30-year life with Avista ownership
3 Page 113 Avista Corp. 2020 Electric IRP Appendices
Renewable Resource Options
All Purchase Power Agreement (PPA) Options
Wind
•On-system wind (101 MW)
•Off-system wind (101 MW)
•Montana wind (101 MW)
•Off shore wind (100 MW)
–Share of a larger project
Solar
•Fixed PV array (5 MW AC)
•On-System Single Axis
Tracking Array (100 MW AC)
•Off-system Single Axis
Tracking Array (100 MW AC)
located in southern PNW
•On-System Single Axis
Tracking Array (100 MW AC)
with 25 MW 4 hour lithium-ion
storage resource
4 Page 114 Avista Corp. 2020 Electric IRP Appendices
Other “Clean” Resource Options
•Geothermal (20 MW)
–Off-system PPA
•Biomass (100 MW)
–i.e. Kettle Falls 3
•Nuclear (100 MW)
–Off-system PPA share of a larger facility
5 Page 115 Avista Corp. 2020 Electric IRP Appendices
Storage Technologies
Lithium-Ion
•Assumes: 88% round trip efficiency (RTE),
10-year operating life
•Assumes Avista ownership
•5 MW Distribution Level
–4 hours (20 MWh)
–8 hours (40 MWh)
•25 MW Transmission Level
–4 hours (100 MWh)
–8 hours (200 MWh)
–16 hours (400 MWh)
–40 hours (1,000 MWh)
Other Storage Options
•Assumes 20 to 30-year life and Avista ownership
•25 MW Vanadium Flow (70% RTE)
–4 hours (100 MWh)
•25 MW Zinc Bromide Flow (67% RTE)
–4 hours (100 MWh)
•25 MW Hydrogen Fuel Cell (varies)
–4 hours (100 MWh)
–16 hours (200 MWh)
–40 hours (1,000 MWh)
•25 MW Liquid Air (65% RTE)
•Liquid Air (retrofit natural gas CT)
–12.7 MW (59 MWh)
–78 MW (700 MWh)
•100 MW Pumped Hydro
–Share of larger project
–16 hours of storage
–PPA assumption
Updates to storage
costs are likely as
additional information
becomes available
6 Page 116 Avista Corp. 2020 Electric IRP Appendices
Resource Upgrades
•Northeast [natural gas peaker]
–7.5 MW using water injection
•Rathdrum CT [natural gas peaker]
–5 MW by 2055 uprates
–24 MW add supplemental compression
–17 MW (summer), 0 MW (winter) Inlet Evaporation
•Kettle Falls [biomass]
–12 MW by repowering with larger turbine during replacement
•Post Falls Redevelopment [hydroelectric]
–8 MW, 4.5 aMW with larger modern units
•Long Lake 2nd Powerhouse [hydroelectric]
–68 MW, 12 aMW with additional powerhouse located at the current “cutoff” dam
•Monroe Street/Upper Falls [hydroelectric]
–80 MW, 27 aMW with additional powerhouse located in Huntington Park
•Cabinet Gorge [hydroelectric]
–110 MW, 18 aMW using the “bypass” tunnels to capture runoff spill
7 Page 117 Avista Corp. 2020 Electric IRP Appendices
Natural Gas Fixed & Variable Costs
Green: Reciprocating Engines
Blue: SCCT
Red: CCCT
8 Page 118 Avista Corp. 2020 Electric IRP Appendices
PPA Resource Cost Analysis
2040
2030
2020
9 Prices include utility loading such as variability integration and revenue taxesPage 119 Avista Corp. 2020 Electric IRP Appendices
Storage Costs
Capacity based cost analysis
10
$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600
Distribution Scale 4hr Lithium-Ion
Distribution Scale 8hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
40hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Hydrogen Fuel Cell with 4 hrs storage w/ Electrolysis
Hydrogen Fuel Cell with 16 hrs Storage w/ Electrolysis
Hydrogen Fuel Cell with 40 Hrs Storage w/ Electrolysis
Liquid Air
Liquid Air (Retrofit CT)
Liquid Air (Retrofit- KFCT)
Pumped Hydro (16 hr/ 100 MW share)
$ per kW-Year
2040
2030
2020
Analysis still being performed
Page 120 Avista Corp. 2020 Electric IRP Appendices
Storage Costs
Energy based cost analysis
11
$0 $50 $100 $150 $200 $250 $300
Distribution Scale 4hr Lithium-Ion
Distribution Scale 8hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
40hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Hydrogen Fuel Cell with 4 hrs storage w/ Electrolysis
Hydrogen Fuel Cell with 16 hrs Storage w/ Electrolysis
Hydrogen Fuel Cell with 40 Hrs Storage w/ Electrolysis
Liquid Air
Liquid Air (Retrofit CT)
Liquid Air (Retrofit- KFCT)
Pumped Hydro (16 hr/ 100 MW share)
$ per kWh- Yr
2040
2030
2020
Analysis still being performed
Page 121 Avista Corp. 2020 Electric IRP Appendices
Facility Upgrade Cost Analysis
Green: Biomass
Blue: Hydro
Red: Natural Gas
12 Page 122 Avista Corp. 2020 Electric IRP Appendices
Other Power Purchase Options
•Market Power Purchases
–Firm purchases
–Real-time
•Mid-Columbia Hydro
–Renegotiate slice contracts from Mid-C PUDs
•Acquire existing resources from IPPs
•Renegotiate Lancaster PPA
•BPA
–Block surplus contract: up to 7-year term at BPA “cost”
–NR Energy Sales: $78.94 MWh
–After 2028, other potential options when current Regional Dialog
contracts expire
13 Page 123 Avista Corp. 2020 Electric IRP Appendices
Review Excel Sheet
14 Page 124 Avista Corp. 2020 Electric IRP Appendices
Home Heating Technologies Overview
Tom Lienhard, Chief Energy Efficiency Engineer
Second Technical Advisory Committee Meeting
November 27, 2018
Page 125 Avista Corp. 2020 Electric IRP Appendices
Home Heating Systems
•Delivery method
–Radiation
–Convection
–Forced Convection
•Number of controlled heating segments
•Fuel used for heating the fluid
–Electricity
–Natural Gas
–Other
•Efficiency of fuel delivery
•Heating load of the residence
2 Page 126 Avista Corp. 2020 Electric IRP Appendices
Home Heating Systems in US
Household Heating Systems: Although several different types of fuels are available
to heat our homes, nearly half of use natural gas. | Source: Buildings Energy Data
Book 2011 3 Page 127 Avista Corp. 2020 Electric IRP Appendices
Delivery Method
•Radiation –heated by radiant energy. Radiant
floor heating can use 40% of the energy of
convective heating systems.
•Baseboard or fluid registers on the outer
portions of the home cause natural convection.
•Furnaces and fans in heaters create forced
convection.
4 Page 128 Avista Corp. 2020 Electric IRP Appendices
Zoning
•Increasing number of controlled zones decreases
amount of heat needed. When two or more areas
can be kept at different temperatures based on need
or occupancy, savings may occur.
•Home furnaces controlled by single thermostat
cannot benefit from zoning. Attempts to zone a
forced air system often reduce heating efficiency
and have a greater impact on air source heat
pumps.
5 Page 129 Avista Corp. 2020 Electric IRP Appendices
Zoning
6 Page 130 Avista Corp. 2020 Electric IRP Appendices
Fuel Used to Heat the Transfer Fluid
•Radiant surfaces can be fueled by any source.
–Electric use electric resistance coils.
–Transfer liquids can be heated by electricity, natural
gas or any other fuel.
•Forced and natural convection systems can be
fueled by natural gas, electric elements, heat pump,
wood, or any other fuel.
•Low carbon future could use dual fuel sources.
7 Page 131 Avista Corp. 2020 Electric IRP Appendices
Fuel Delivery Efficiency
•Natural gas limited to 98% efficiency when exhausting
combustion product outside. Natural gas heat pumps
with a coefficient of performance (COP) around 1.5
under development.
•Electricity has a low threshold of 100% efficient with
resistive electric, although an air source heat pump
backed by resistance can operate below 100% during
defrost and low temperatures. Electric heat pumps can
approach an annual COP of 4, depending on outside
temperature, soil type and heat pump type.
8 Page 132 Avista Corp. 2020 Electric IRP Appendices
Fuel Delivery Efficiency– cont.
•Ground source heat pump
–Highest performing units
–Utilize stored energy of the sun in the earth to transfer heat
•Highest performing air source heat pumps are
ductless units
–Perfectly coupled between interior and exterior units.
–CO2 heat pumps being tested in the US do not have the
exterior temperature issues that other air source heat
pumps have with efficiency degradation due to cold
weather (NW CO2 Pilots)
9 Page 133 Avista Corp. 2020 Electric IRP Appendices
Fuel Delivery Efficiency – cont.
•Lowest efficiency fuel is wood
–An average of 50% of the heat makes it into the
space.
–If the damper is left open on a chimney flue, the
house will evacuate the heat inside after the fire goes
out through the stack affect.
–One of the best home audit measures is to plug the
flue of unused fireplaces to reduce lost heat.
10 Page 134 Avista Corp. 2020 Electric IRP Appendices
First Cost of Technologies
•Ground source heat pumps add $10,000 to
$20,000 to a home budget if feasible.
•In-floor radiant systems add $10,000 to $15,000
to normal forced air system in new construction.
•Full home multi-head zoned ductless units can
be $10,000 to $30,000 above baseline natural
gas systems.
11 Page 135 Avista Corp. 2020 Electric IRP Appendices
First Costs
12
Ground Source Heat Pump
Page 136 Avista Corp. 2020 Electric IRP Appendices
Home Heating Needed
•Size:smaller is better
•Insulation:more is better
•Location and installation of ductwork:inside is better
•Infiltration: none is better, need Energy Recovery
Ventilator
•Number of people: more is better
•Humidity:some is better than none
13 Page 137 Avista Corp. 2020 Electric IRP Appendices
Home Heat Loss
14 Page 138 Avista Corp. 2020 Electric IRP Appendices
Climate Zones
15
https://basc.pnnl.gov/images/iecc-climate-zone-map
RTF identifies
zones 4, 5 & 6
zones 1, 2 & 3
Page 139 Avista Corp. 2020 Electric IRP Appendices
Home Heat Loss Calculation
•Most loss from conduction through envelope and
infiltration/exfiltration through cracks.
•EL = UA(Tin-Tout)
–U is thermal conductivity,
–A is the surface area of the home, and
–Tin is temperature inside and Tout temperature outside
•1,000 ft2 home with 8 foot ceilings has an area of 3,760
ft2. If the average R value is 25, it has a U factor of .04
BTU/hr*ft2*F.
16 Page 140 Avista Corp. 2020 Electric IRP Appendices
•If average outdoor temperature during the heating
season is 42°and the set point is 72°, then the hourly
heat loss is 4,512 BTU/hour
–.04*3,760*30 = 4,512 BTUs or 3,248,640 BTU’s per month. That
is 951 kWh with electric resistance heat, about 560 kWh with an
air source heat pump, and about 33 therms.
•At Avista’s current rates, losses would be $95 for
resistance heat, $56 for a heat pump, and $30 for natural
gas.
•This is for a very small home with very good insulation in
Northwest climate zone 4 ignoring heat gain from
humans or solar.
17
Cost of Heat Loss –Example
Page 141 Avista Corp. 2020 Electric IRP Appendices
Heating Degree Days (HDD)
•Difference between 65°and outside temperature
measured in days.
•6,800 HDD: Spokane average of a 38°difference
between 65°and outside over 6 month heating season.
•4,700 HDD: Seattle average of a 29°difference between
65°and outside over 6 month heating season.
•Heat pumps operate in their wheelhouse in Seattle and
below optimum in Spokane.
18 Page 142 Avista Corp. 2020 Electric IRP Appendices
Fuel Cost
•Natural Gas heat is 1/3 the cost per BTU compared
to electricity.
–The average electric home costs more to operate than a
natural gas home in climate zones 2 and 3 at Avista’s
current gas and electric prices.
•Avista’s electric peak often occurs at the coldest
point in December, so electric homes highest
consumption coincides with our highest load.
–This includes net zero homes which don’t produce during
our winter peak.
19 Page 143 Avista Corp. 2020 Electric IRP Appendices
Questions
20 Page 144 Avista Corp. 2020 Electric IRP Appendices
Resource Adequacy and Effective Load
Carrying Capability
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
November 27, 2018
Page 145 Avista Corp. 2020 Electric IRP Appendices
Why Does Resource Adequacy Matter?
Helps determine how much new capacity our customers
need.
Informs “us” how much capacity we rely on from our
neighbors.
Provides insight on how certain resource help provide
reliable capacity.
2
We discovered this type of analysis requires a lot of process time,
specific locational assumptions for renewable resources, and is an
“art” rather than a specific science.
Page 146 Avista Corp. 2020 Electric IRP Appendices
Loss of Load Probability (LOLP)
LOLP is the current regional measurement for resource adequacy.
Measures probability of a resource adequacy deficiency over a one
year time period.
No regulatory body enforces a particular resource adequacy
standard or metric.
This is a great measure of probability of reliability, but…according to
the NPCC…
−“No measure of magnitude
−No measure of duration
−No measure of frequency within the year
−Two scenarios with same LOLP can have vastly different curtailment magnitude
and duration”
3 Page 147 Avista Corp. 2020 Electric IRP Appendices
Reliability Metrics Options
What we are modeling for?
Events not serving all load and reserve requirements due to
insufficient resources/market availability
Metrics
LOLP: Loss of Load Probability
−Number of draws with an event (probability of a draw with an event)
LOLH: Loss of Load Hours
−Hours with events / iterations (time in hours)
LOLE: Loss of Load Events
−Days with events / iterations (time in days)
EUE: Expected Unserved Energy
−Average MWh not served during an event (Magnitude)
ELCC: Effective Load Carrying Capability
−Percentage of resource capacity equal to CTs4Page 148 Avista Corp. 2020 Electric IRP Appendices
Model Assumptions & Challenges
The Model
Built in Excel with What’s Best optimizer
1,000 simulations
Randomizes:
−Forced outages
−80 years of hydro data
−128 years of weather data (load &
generation)
Challenges:
−Time: three days to run per study, to
date over 70 studies since April have
been completed.
−Randomization: may not get same
results with same assumptions.
−This is becoming more of an “art” then
a “science”
The Key Assumptions
2030 load and resources
Average peak load: 1,778 MW (Winter),
1,636 MW (Summer)
Average hourly load: 1,081 MW
Major resource changes from today: No
Lancaster, less Mid-C, no WNP-3 contract
Off-peak market purchases limited to 1,000
MW
On-peak market purchase limited to 400
MW
When daily temps > 84 and < 4 degrees
Fahrenheit, market purchases are limited
250 MW
5 Page 149 Avista Corp. 2020 Electric IRP Appendices
Without resource additions, what is our
reliability metrics in 2030?
LOLP: 27.9%
LOLH: 18.29
LOLE: 1.41
EUE: 3,430 MWh
6 Page 150 Avista Corp. 2020 Electric IRP Appendices
How much capacity is required to be at
5% LOLP?
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
1 2 3 4 5 6 7 8 9 10 11 12
Lo
s
s

o
f

L
o
a
d

P
r
o
b
a
b
i
l
i
t
y
Month
LOLP: 4.9%
LOLH: 1.85
LOLE: 0.16
EUE: 318.7 MWh
Add 245 MW (winter) / 182 MW
(summer) two unit CT
245 MW new gen / 1,778 MW
average peak load = 13.8%
planning margin
7 Page 151 Avista Corp. 2020 Electric IRP Appendices
LOLP at Different Levels of Capacity
Additions
y = 2E-05x2 -0.0079x + 1.0335R² = 0.9821
0%
1%
2%
3%
4%
5%
6%
7%
215 220 225 230 235 240 245 250
LO
L
P
Capacity Additions (Winter-MW)
8 Page 152 Avista Corp. 2020 Electric IRP Appendices
Does Wind Improve Reliability?
Wind can improve reliability, but not equal to a CT
Location diversification improves capacity credit!
Studies to date include two studies:
−Case 1: NW Wind
−Case 2: Montana Wind
9 Page 153 Avista Corp. 2020 Electric IRP Appendices
Case 1: NW Wind
1st study: exclude Palouse Wind
2nd study: decrease CTs by 25 MW and add more wind until 5%
LOLP is achieved
Concerns:
How will other NW projects with less correlation to Palouse change this
result?
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Palouse Wind excluded 5.5%1.86 0.17 307
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
+ 300 MW wind 5.5%1.80 0.15 296
+ 400 MW wind 5.5%1.72 0.14 256
+ 500 MW wind 5.4%1.70 0.14 280
Reference case -15 MW CT 5.5%1.93 0.17 319
1)5% LOLP never achieved
2)other metrics improve with more wind
3)Suggest ELCC for NW wind:
15/300= 5%
10 Page 154 Avista Corp. 2020 Electric IRP Appendices
Case 2: Montana Wind
Reduce CTs by 25 MW, add wind until 5% LOLP is maintained
Concerns:
Low temperature cut outs, wind turbines must curtail when temperatures are
below -30 Celsius (-22 F)
All Montana wind regimes may not be the same
Earlier analysis showed 30% capacity contribution with alternate data
Avista needs to perform more studies including larger reduction in capacity deficit
positions
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
+ 60 MW MT wind 4.9%1.49 0.13 249
+ 70 MW MT wind 4.9%1.39 0.12 203
+ 100 MW MT wind 4.1%1.18 0.10 205
ELCC for MT Wind: 25/60= 42%
11 Page 155 Avista Corp. 2020 Electric IRP Appendices
Does Solar Improve Reliability?
Solar studies are performed similar to wind, but use an
earlier version of the model
CT reductions:
−76 MW Winter
−56 MW Summer
Never get to 5% LOLP!
Summer LOLP reduces to zero in high cases
Conducted a new reference case with 20 MW less CT
winter capacity to arrive at a 5.8% LOLP
ELCC is 2.2% (20 / 900)
Case LOLP LOLH LOLE EUE
Reference 5.0%1.75 0.15 254
Reference –76 MW CTs 9.4%3.73 0.30 689
300 MW 7.8%2.71 0.22 440
600 MW 7.6%2.29 0.21 353
900 MW 5.8%2.14 0.18 350
Reference –20 MW CT 5.8%1.75 0.17 327
12 Page 156 Avista Corp. 2020 Electric IRP Appendices
Does Demand Response (DR) Improve
Reliability?
Demand response temporarily reduces load for a period of time
Studied three scenarios compared to “CT” reference case
25 MW, 4 hour reduction up to 10 times per year
25 MW, 8 hour reduction up to 10 times per year
25 MW, 16 hour reduction up to 10 times per year
Proposed ELCC:
4 hour: 8% (2 MW / 25 MW)
8 hour: 60% (15 MW / 25 MW)
16 hour: 64% (16 MW / 25 MW)
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
4 hour duration 6.1%1.99 0.18 338
8 hour duration 5.7%1.87 0.16 316
16 hour duration 5.6%1.67 0.15 282
Reference case -15 MW CT 5.5%1.93 0.17 319
13 Page 157 Avista Corp. 2020 Electric IRP Appendices
Does Storage Improve Reliability?
Storage moves energy, but doesn’t create energy!
Storage can lose 10% to 50% of the energy it stores
Study assumes 90% round trip efficiency (i.e. Lithium-
ion technology)
Storage requires the ability to add additional energy
to the system from another source to add significant
capacity value
Higher storage penetration may lead to less capacity
contribution
14 Page 158 Avista Corp. 2020 Electric IRP Appendices
Storage Results
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
25 MW, 4 hour storage 5.8%2.13 0.19 352
25 MW, 16 hour storage 5.7%2.04 0.17 315
25 MW, 40 hour storage 5.6%1.92 0.17 387
25 MW, 4 hour storage,w/ 50 MW solar 5.6%1.96 0.18 330
50 MW, 4 hour storage,w/ 50 MW Solar 5.3%1.95 0.17 302
50 MW, 4 hour storage,w/ 100 MW Solar 5.2%2.23 0.19 379
Avista proposes to use the following capacity credits for low capacity additions
4 hour: 56% (14 MW / 25 MW)
16 hour: 52% (13 MW / 25 MW)
40 hour: 48% (12 MW / 25 MW)
A third party analysis estimates 10% capacity credit results without new energy
resources. With new energy resources its between 12% and 60%
15 Page 159 Avista Corp. 2020 Electric IRP Appendices
Resource Combination Analysis
What if we remove new “CTs” and planned our system
with non-traditional resources
Case LOLP LOLH LOLE EUE
No new resources 27.9%18.3 1.41 3,430
Reference case (add 245 MW CT)4.9%1.85 0.16 319
Add: 200 MW MT wind, 155 MW NW wind, 50 MW
DR, 125 MW 6 hour storage, and 250 MW solar
6.3%2.43 0.20 429
Add: 200 MW MT wind, 245 MW NW wind, 50 MW
DR, 150 MW 6 hour storage, and 350 MW solar
4.8%2.40 0.17 487
Exclude Colstrip from portfolio & no new resources 75.8%106.8 8.43 21,265
Add: 400 MW MT wind, 400 MW NW wind, 100 MW
DR,200 MW 6 hour storage, and 500 MW solar
13.2%5.46 0.45 1,174
16 Page 160 Avista Corp. 2020 Electric IRP Appendices
Third Party ELCC Analysis
Slides not included at this time for distribution or webcast
Page 161 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP Key Assumptions
James Gall, IRP Manager
John Lyons, Senior Resource Policy Analyst
Second Technical Advisory Committee Meeting
November 27, 2018
Page 162 Avista Corp. 2020 Electric IRP Appendices
Existing Forms of Carbon Regulation
•Indirect: Renewable resource additions, higher RPS
•Carbon tax: British Columbia
•Direct regulation: Affordable Clean Energy Rule
•Cap and trade: AB 32 in California
•State mandates: Oregon SB 1547 and emissions
performance standards
2 Page 163 Avista Corp. 2020 Electric IRP Appendices
Renewables
•Renewables drive emissions lower, but may be indirect to the
location of the renewable generation’s location
•RPS standards in each state (large utility goals shown below)
–WA: 15% by 2020 (100% clean proposals)
–OR: 50% goal by 2040
–CA: 45% by 2023, 50% by 2026, 60% goal by end of 2030, and 100% by 2045 (SB 100)
–NV: 25% by 2025 (50% by 2030, needs another yes vote in 2020)
–AZ: 15% by 2025 (50% by 2035 failed in Nov. election)
–NM: 20% by 2020
–CO: 30% by 2020 (Higher proposals expected)
–MT: 15%
•Consumer Driven Renewables
–Rooftop solar
–Large commercial direct investment
–Green tariffs (jurisdictional and organizational)
3 Page 164 Avista Corp. 2020 Electric IRP Appendices
Direct Regulation
Washington SB 6001-Emissions performance standard limits “baseload”
generation to 930 lbs of CO2 per MWh for new resources or contracts five
years or longer
Affordable Clean Energy Rule (ACE) –August 2018 replacement proposal
for the Clean Power Plan
1.Defines the “best system of emission reduction” (BSER) for existing plants as
on-site, heat-rate efficiency improvements;
2.Provides “candidate technologies” for states to establish standards of
performance for their plans;
3.Updates the New Source Review (NSR) permitting program to encourage
efficiency improvements at existing plants; and
4.Aligns regulations under CAA section 111(d) to give states time and flexibility to
develop their own plans.
4 Page 165 Avista Corp. 2020 Electric IRP Appendices
Carbon Regulation and Taxes
•AB 32 in California
–1990 levels by 2020 and 80% below 1990 levels by 2050
–Typically modeled as a “price” adder due to economy-wide trading
system, using minimum price
•Oregon
–Coal to Clean: coal can no longer serve Oregon loads after 2030/2035
–Cap and trade program expectations in next legislative session
•Washington 100% Clean Proposals
•Affordable Clean Energy Rule
•Canadian Carbon Taxes
–British Columbia: $30/metric ton (Can$)
–Alberta: $30/metric ton (Can$)
5 Page 166 Avista Corp. 2020 Electric IRP Appendices
Aurora Inputs
•Regional loads
•Fuel prices
•Hydro levels
•Wind variation
•Environmental constraints
•Resource availability
•Transmission
6 Page 167 Avista Corp. 2020 Electric IRP Appendices
Regional Loads
•Forecast load growth for all Western Interconnect regions
•Consider both peak and energy growth
•Use latest load forecast from Epis
•Stochastic modeling simulates load changes due to weather
and considers regional correlation of weather patterns
•Economically driven load changes are difficult to quantify and
are usually picked up as IRPs are published
•Peak load is increasingly more difficult to quantify as “Demand
Response” programs may cause data integrity issues
•Energy demand forecasts need to be net of conservation,
electric vehicle forecasts, and behind the meter generation
7 Page 168 Avista Corp. 2020 Electric IRP Appendices
California/Baja
Northwest
Desert SW
Rocky Mtns
Canada
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
220,000
20
2
0
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
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3
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20
3
9
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Peak Forecast
Energy & Peak Forecast
Energy AAGR Change
Canada 1.32%
Rocky Mtns.0.53%
Desert SW 1.84%
California 0.40%
Northwest 0.42%
Total 0.83%
Peak AAGR Change
Canada 1.44%
Rocky Mtns.0.52%
Desert SW 1.89%
California -0.06%
Northwest 0.44%
Total 0.72%8
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
220,000
20
2
0
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
Av
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s
Energy Forecast
Page 169 Avista Corp. 2020 Electric IRP Appendices
Electric Vehicles (EV)
•Current load shapes have low EV penetration, but by 2030, load
shapes will differ due to EV and behind the meter solar
•EV percentage of new vehicle sales forecast by 2030
•After 2030, EV growth equals traditional vehicle growth (half of
population growth)
9 http://evadoption.com/ev-market-share/ev-market-share-state/
0%
5%
10%
15%
20%
25%
30%
AZ CA CO ID MT NM NV OR UT WA WY
Pe
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S
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EV Sales Forecast
Page 170 Avista Corp. 2020 Electric IRP Appendices
EV Load Shaping
A combined hourly load shape for EV’s will be combined
using Avista EV load data from its Pilot Project
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
kW
Hour of the Day
EV Daily Load Shapes
10 Page 171 Avista Corp. 2020 Electric IRP Appendices
Rooftop Solar
•Rooftop solar impacts future load growth and changes its
hourly profile
•Future rooftop solar growth depends on policy choices
•Assumes 20-30% growth, before leveling off to 3% long
run growth in 2020s
11
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Western Interconnect Consumer Solar
Page 172 Avista Corp. 2020 Electric IRP Appendices
Natural Gas Prices
•Natural gas prices among the most difficult inputs to quantify
•A combination of forward prices and consultant studies will be
used for this IRP. This work should be complete by December
2018 (i.e. deterministic forecast)
•500 different prices using an auto regressive technique will be
modeled, the mean value of the 500 simulations will be equal
to the deterministic forecast
•A controversial input for these prices is the amount of
variance within the 500 simulations
•Historically prices were highly volatile, recent history is more
stable
•Final variance estimates consider current market volatility and
implied variance from options contracts
12 Page 173 Avista Corp. 2020 Electric IRP Appendices
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
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6
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1
7
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8
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20
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20
2
1
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2
2
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2
3
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2
4
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2
5
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2
6
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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
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6
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9
20
4
0
$
p
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D
t
h
Consultant 1 Consultant 2 2013 IRP2015 IRP 2017 IRP 2019 IRPActualsForwards (10/22/2018)
Henry Hub Natural Gas Prices *
* Based on methodology described above, to be updated
Levelized price is $4.57/dth (2020-39)
13 Page 174 Avista Corp. 2020 Electric IRP Appendices
Coal Prices
•Decreased demand for US based coal with lower natural
gas prices and state and federal regulations, but
potential exports may stabilize the industry
•Western US coal plants typically have long-term
contracts and many are mine mouth
•Rail coal projects incur diesel price risk
•Prices will be based on review of coal plant publically
available prices and EIA mine mouth and rail forecasts,
currently the price escalator is ~2.5%
•Colstrip Fuel Prices will be discussed at the February
TAC meeting with final fuel forecasts
14 Page 175 Avista Corp. 2020 Electric IRP Appendices
Hydro
•80 years of hydro conditions are used for the Northwest
states, British Columbia and California provided by BPA
–Hydro levels change monthly
–Aurora dispatches the monthly hydro based on whether its run-
of-river or storage
•For stochastic studies the hydro levels will be randomly
drawn from the 80-year record
•Columbia River Treaty could change regional hydro
patterns, but until there is a new treaty, no changes will
be included
15 Page 176 Avista Corp. 2020 Electric IRP Appendices
Northwest State Hydro Volatility
Mean: 15,587 aMW
16 Page 177 Avista Corp. 2020 Electric IRP Appendices
Wind
•Modeling technique
−Autoregressive technique to simulate output in similar to reported data
available from BPA, CAISO, and other publically available data sources-
also considers correlation between regions
−For stochastic studies several wind curves, will be drawn from to
simulate variation in wind output each year for each of the 500 draws
•Oversupply modeling technique
−RECs and PTC’s have caused wind facilities to economically generate
in oversupply periods in the Northwest-particularly in the spring months
−Wind is modeled in Aurora as a negative marginal cost, allowing for the
model to simulate negative prices
17 Page 178 Avista Corp. 2020 Electric IRP Appendices
NW Wind Capacity Factor History
Source: https://transmission.bpa.gov/business/operations/wind/18
Ca
p
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Annual Capacity Factor
Pr
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Portion of Hours Less Than 5% Capacity Factor
Ca
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Page 179 Avista Corp. 2020 Electric IRP Appendices
Western Interconnect Coal Retirements
The price forecast simulation may find additional coal retirements in the later half of
the study period
19
Plant Units State
Summer
Capacity
(MW)
Retirement
Year Proposed
Fuel
Conversion
Apache Station 2 Arizona 175 2017 Committed Natural gas
Hardin 1 Montana 107 2018 Proposed
Naughton 3 Wyoming 330 2018 Proposed
Navajo 1 to 3 Arizona 2,250 2019 Committed
Centralia Complex 1 Washington 670 2020 Committed
Centralia Complex 2 Washington 670 2025 Committed
Cholla 4 Arizona 380 2020 Proposed Natural gas
Boardman (OR)1 Oregon 585 2021 Committed
North Valmy 1 Nevada 254 2021 Proposed
Colstrip 1 & 2 Montana 614 2022 Committed
Comanche 1 Colorado 325 2022 Proposed
Nucla 1-3, ST4 Colorado 100 2022 Proposed
San Juan Generating Station 1 & 4 New Mexico 847 2022 Proposed
TS Power Plant ST Nevada 218 2022 Proposed
Cholla 1 & 3 Arizona 387 2025 Proposed
Comanche 2 Colorado 335 2025 Proposed
Craig (CO)1 Colorado 428 2025 Committed
Intermountain ST1 & ST2 Utah 1,800 2025 Proposed Natural gas
North Valmy 2 Nevada 268 2025 Proposed
Dave Johnston 1 to 4 Wyoming 762 2027 Proposed
Jim Bridger 1 Wyoming 531 2028 Proposed
Naughton 1 & 2 Wyoming 357 2029 Proposed
Hayden 1 & 2 Colorado 446 2030 Proposed
Page 180 Avista Corp. 2020 Electric IRP Appendices
Initiative 1631
•2018 Carbon Emissions Fee Measure
–$15 per metric ton of carbon emissions fee on January 1,
2020
–Increase fee $2 per year until state emissions goals met
–Direct proceeds to various programs and projects to
improve carbon emissions
•Failed with 56.55% voting against the measure
–Avista counties 67% voting against
•Will update TAC and modeling for new legislation in the
upcoming Washington session
20 Page 181 Avista Corp. 2020 Electric IRP Appendices
City of Spokane 100% Renewable Goal
•Spokane City Council adopts aspirational goal to have
the city served with all renewable power by 2030 (August
2018)
•Committee will be formed to scope and define this
ordinance
–Net renewable or something else?
–How it will be ramped in?
–Implications and help for low income and other at risk
groups?
–Rate issues
21 Page 182 Avista Corp. 2020 Electric IRP Appendices
2019 IRP Futures and Scenarios
James Gall, IRP Manager
John Lyons, Senior Resource Policy Analyst
Second Technical Advisory Committee Meeting
November 27, 2018
Page 183 Avista Corp. 2020 Electric IRP Appendices
IRP Modeling Plan for Environmental
Policies
•No expected case due to potential policy uncertainty
•Three futures used rather than an expected case +
scenarios
•Alternative futures and scenarios can also be studied,
but will need to be minimal due to resource constraints
•Proposed Futures (500 simulations each)
1.Existing policies & trends
2.Social Cost of Carbon
3.Clean Resources
2 Page 184 Avista Corp. 2020 Electric IRP Appendices
Existing Policies & Trends
Major future assumption change is a greenhouse gas price distribution with:
•1/3 probability of no pricing
•1/3 probability of $10/metric ton (2018$) escalating at 2.5% year
−Begins in 2025
−Applies to all of Western Interconnect resources
•1/3 probability of cap and trade of 20% below 1990 levels
−20% goal by 2030
−40% goal by 2040
−Applies to all of Western Interconnect
−An implied CO2 price will be a result of each study
3 Page 185 Avista Corp. 2020 Electric IRP Appendices
Social Cost of Carbon (SCC)
•No CO2 cost penalties for dispatch, the SCC will be included
as a cost in resource and energy efficiency acquisitions
•Pricing will be a distribution of costs from the Interagency
Working Group on Social Cost of Carbon (Aug 2016)
−1/3 probability of 5.0% discount rate pricing distribution (90th
Confidence Level)
−1/3 probability of 3.0% discount rate pricing distribution (90th
Confidence Level)
−1/3 probability of 2.5% discount rate pricing distribution (90th
Confidence Level)
•SCC will be applied to the Washington portion of load service
for Avista resource portfolios
4 Page 186 Avista Corp. 2020 Electric IRP Appendices
Social Cost of Carbon Pricing
Distribution From
5
Use 90th confidence interval for each of the
three distributions for the 500 simulationsPage 187 Avista Corp. 2020 Electric IRP Appendices
Social Cost of Carbon
Confidence Interval
90th Confidence Interval Ranges
Distribution of 500 Simulations
Pr
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$ per Metric Ton (2007$)
Mean Price is ~$25/metric ton
Prices will be pulled evenly
from the three discount rate
scenarios
6 Page 188 Avista Corp. 2020 Electric IRP Appendices
Clean Resource Future
•Washington: 100% of load met by “clean” resources on a “net” basis
−80% by 2030, 90% by 2040, and 100% by 2050
−Qualifying resources can be sourced from anywhere in the Western
Interconnect
−Up to 20% of resources can be “RECs” from outside of the region or
alternative compliance
−Price cap of $5 per metric ton ($2018) beginning in 2030 and 1%
revenue requirement for portfolio modeling
•Oregon cap and trade
−20% below 1990 levels by 2030
−50% below 1990 levels by 2040
−80% below 1990 levels by 2050
7 Page 189 Avista Corp. 2020 Electric IRP Appendices
Additional Scenarios
Aurora Studies
•High natural gas prices (deterministic)
•Low natural gas prices (deterministic)
•Social Cost of Carbon (stochastic)
•High Colstrip fuel cost (deterministic)
•Colstrip shutdown (stochastic)
PRiSM Studies
•Study from each of the Aurora cases
•Colstrip closes in 2027
•Colstrip closes in 2035
•High cost to retain Colstrip (with low gas)
•Low and high load growth, alternative load cases (i.e. electrification, EV, behind the meter generation, power-to-gas, etc.)
•Lancaster continues
•High cost to retain Colstrip
•Colstrip fuel prices
•Conservation TRC vs. UCT
•Tipping point scenarios
8 Page 190 Avista Corp. 2020 Electric IRP Appendices
High and Low Natural Gas Prices
•Deterministic studies to show the impacts of
consistently lower or higher natural gas prices
than the expected price forecast
•Low case will have existing price levels and not
increase
•High case level TBD –more details forthcoming
at February 2019 TAC meeting
9 Page 191 Avista Corp. 2020 Electric IRP Appendices
Social Cost of Carbon
•Differs from the future discussed earlier by
including the price for dispatch for all plants in
the Western Interconnect
•Will include the same prices as discussed in the
SCC future
10 Page 192 Avista Corp. 2020 Electric IRP Appendices
Colstrip Basic Assumptions
•Avista’s share of fuel, O&M, and capital investment costs
•Increased common costs due to shut down of units 1 & 2 in 2022
•Selective catalytic reduction (SCR) –2027 and 2028, includes
capital costs, ammonia and fixed and variable O&M to reduce NOx
•Enhanced mercury controls
•Coal Combustion Residuals (CCR’s)
–Coal dry ash handling (2022) and long term storage
•Smart Burn combustion controls installed in 2017
•Water management
•Depreciation schedule shortened to 2027 per merger agreement
•Additional details on the specifics will be provided in TAC 4
11 Page 193 Avista Corp. 2020 Electric IRP Appendices
Colstrip Scenarios
•Retire Colstrip Units #3 and #4 in 2027 as an
alternative to SCR investment
•Retire Colstrip Units #3 and #4 in 2035 as an
alternative to SCR investment
•Colstrip fuel prices increase 30%
•High cost to retain Colstrip case (next slide)
12 Page 194 Avista Corp. 2020 Electric IRP Appendices
High Cost to Retain Colstrip Case
•This case answers questions about several higher cost issues
impacting Colstrip’s compliance cost
•This scenario uses assumptions in the three futures, except:
–EPA expands regional air quality programs and rules to the western
U.S. such as CASPR and NAAQS requiring SCR installation on Units
#3 and #4 at an earlier date (End of 2023)
–Units #1 and #2 shut down earlier than announced, increasing the
amount of shared costs cover by Units #3 and #4 (End of 2019)
–MACT PM/MATS RTR compliance problems. Dry system required to
remove particulates and reduce water use (End of 2023)
–No enhancement to existing SO2 scrubbers as no current regulation
drives reduction levels beyond current plant emissions
–Higher Colstrip fuel costs
–Low natural gas cost environment
–Specific cost details will be provided in TAC 4
13 Page 195 Avista Corp. 2020 Electric IRP Appendices
Load Growth Scenarios
•High and low load growth scenarios due to
economic changes in the service territory
•Potential load study scenarios
–High EV penetration case (120,000 EVs by 2045)
–Behind-the-meter generation (10% penetration by 2030)
–Fuel switching electric to natural gas
–Fuel switching natural gas to electric
14 Page 196 Avista Corp. 2020 Electric IRP Appendices
Lancaster Continues
•Lancaster PPA currently ends October 2026
•PPA has an option to extend the contract 5 years
at a negotiated price
•Implications of extending the PPA or purchasing
the plant beyond the current end of the PPA
15 Page 197 Avista Corp. 2020 Electric IRP Appendices
Alternative Energy Efficiency Evaluations
•All cases will model cost effectiveness of energy
efficiency using the total resource cost (TRC) in
Washington and the utility cost test (UCT) in
Idaho
•This scenario tests both methods of evaluation
16 Page 198 Avista Corp. 2020 Electric IRP Appendices
Tipping Point Analyses
•Estimates the cost reduction or operating
characteristics needed to change the resource
strategy
–Are there any assumptions that need to be tested to
find the cost tipping point?
–Past studies have included capital costs for solar and
storage
17 Page 199 Avista Corp. 2020 Electric IRP Appendices
1

Attendees: TAC 2, Tuesday, November 27, 2018 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Jennifer Snyder, Washington UTC; Amy Wheeless, NW Energy Coalition; Steve Johnson, Washington UTC; Michael Eldred, Idaho Public Utilities Commission; Matt Nykiel, Idaho Conservation League; Shelby Herber, Idaho Conservation League; Dave Van Hersett, Avista residential customer; John Barber, Rockwood Retirement Community; Brian Parker, 350.org; Jørgen Rasmussen, Solar
Acres Farm; Kirsten Wilson, DES Energy Program; Garrett Brown Avista; Clint Kalich, Avista; Barry Kathrens, 350.org; Pauline Druffel, 350 Spokane; Thomas Dempsey, Avista; Terrence Browne, Avista; Darrell Soyars, Avista; Scott Kinney, Avista; Mary Tyrie, Avista; Tom Lienhard, Avista; Tom Pardee, Avista; Kaylene Schultz, Avista; Amber Gifford, Avista; Rachelle Farnsworth, Idaho Public Utilities Commission; James
Gall, Avista; and Gerry Snow, PERA.
Phone Participants:
Doug Howell, Sierra Club; Sarah Laycock, Washington State Attorney General’s Office;
Mike Starrett, Power Council; Nancy Estep, NW Energy Coalition.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses are in italics, and
significant points raised by presenters that are not shown on the slides are also
included.

TAC Expectations and Process Overview, John Lyons
Matt Nykiel: On the topics, what is available and when, and what will not be available?
Avista is developing a matrix of the data to indicate timing and availability of data.
Doug Howell: Why are there less meetings (5 instead of 6) for this IRP? We are having
fuller agendas in five meetings rather than spreading out to six.

2019 IRP Modeling Process Overview, James Gall
Matt Nykiel: Which of these are going to be available publically? For the February TAC
meeting – market price results high level inputs, annual fuel, demand and resources
today. Existing publically available data, transmission, and the load forecast provided in
the last TAC meeting. Resource position will be next TAC meeting, Demand Side
Management and Demand Response information will be at a later meeting. High level
or detail level would be available in FERC level data.
(See separate data matrix file sent with these meeting notes)
Steve Johnson: Simple list of items, where they are found and when they will be
released.
Page 200 Avista Corp. 2020 Electric IRP Appendices
2

Doug Howell: PSE has distinct scenarios for load, gas and fuel prices. How is Avista
different in the process? We will hit this later today.
Brian Parker: Will proprietary data be included in the list? Why is it proprietary? Often
contractual and market intelligence data is proprietary, such as the natural gas price
forecast we purchase.
Doug Howell: Across the country we now have non-disclosure agreements in eight
different states. Hoping to have them soon in Louisiana with the same owners as PSE
(Puget Sound Energy). So we can have a consultant run the model, we want the data
under a nondisclosure agreement. We hope to have one with PSE too.
Doug Howell: Are known and expected resource retirements included? Includes
publically announced retirements. If plants are uneconomic when modeled, but not
announced, Aurora would shut those plants down too.
James Gall: For the OWI (Oregon, Washington and Idaho) region, which Avista has
modeled as one bubble in Aurora, we will try to split this region up by state to
accommodate state-level resource policy decisions.
Amy Wheeless: What about resource shuffling? This will be covered later.
Matt Nykiel: Do we have a guideline for what will be modeled stochastically versus
deterministically? Avista tries to run as many studies as we can stochastically, but each
study takes about a week to complete. We generally default to deterministic studies as
we run out of modeling time which is limited.
PRiSM Section
Doug Howell: What is the rationale for splitting up the region? [OWI being modeled as
separate areas instead of one area] Splitting up the region allows us to account for a
situation where a state or city wants a unique policy that differs from the rest of the
region, such as a 100% renewable energy requirement for a city.
Mike Starrett: How are we going to do this for prudence? What if the city and state are
not aligned like PGE and the City of Spokane. Would probably develop a green tariff.
Clint Kalich: This is an exercise for information. What costs might be if this type of policy
occurred. The IRP doesn’t promote tariffs, but informs the development of them.
Steve Johnson: Boutique resource portfolios for new resources from PSE. Shows cost
differentials for core and unique customers.
Matt Nykiel: How practically can we identify them?
James Gall: More of an accounting mechanism. We know generation, but need to
account for overages and surplus.
Brian Parker: What will we be able to share from the study?
Page 201 Avista Corp. 2020 Electric IRP Appendices
3

James Gall: We would be able to share what is selected by PRiSM and the least cost
results. We will talk about Spokane later.
Doug Howell: I have heartburn about long-term impacts, like coal ash having horribly
wrong cost estimates, and how to reconcile them. Also low balling cost estimates of
wind and solar. And climate cost estimates resulting in obsolete resources in the future.
Slide 10 – 11
James Gall: We are taking market risk. Others in scenario risk.
Amy Wheeless: Risks? Market load, hydro and wind variability, not other risks.
Clint Kalich: Qualitative choices.
John Lyons: Scenarios are used for fundamentally different futures with second order
change, like a future with a new low-cost efficient car battery that changes the market
for electric cars.
Amy Wheeless: BPA used an efficient frontier with how they picked DSM.
James Gall: We look at all 5,000 plus DSM measures, so conservation lowers risk, cost,
and reduces summer/winter peak.

Generation Resource Options, James Gall
Steve Johnson: So actual runs will have the transmission cost where applicable later
on.
Matt Nykiel: When will gas prices be locked in? Probably after the February meeting.
Steve Johnson: Price excursions with the British Columbia pipeline. Will discuss later
since Tom Pardee (Natural Gas IRP Manager) is not in the room.
John Barber: What is the hybrid technology? LMS 100 is a mix of frame and aero
derivative. The compressor section compresses, cools and reinjects the air. It is more
efficient than a peaker, but not as efficient as a combined-cycle plant.
Steve Johnson: Does Avista model oil backup? No, we have been able to rely on the
pipelines not being fully subscribed. Now that they are fully subscribed, we will need to
decide if we need to model oil, LNG or purchase gas as a backup.
Jennifer Snyder: Ask PSE (Puget Sound Energy) if they got any traction in offshore
wind.
Steve Johnson: Where does Avista get its updated data for expected capacity factors?
How does Avista compare unknowns? Wind vs. solar. Avista has gotten data from
renewable RFPs with wind at a 38% capacity factor, but our actual experience has been
much lower. We only pay by the megawatt-hour for actual generation under a contract.
Page 202 Avista Corp. 2020 Electric IRP Appendices
4

Wind on Avista’s system is in the high 30s and high 40s for wind projects in Montana.
Solar capacity factors are also for RFPs, as well as generation from the solar projects at
Lind and Boulder Park. There is also solar data from NOAA, which is being used by
bidders.
John Barber: Just lithium ion? Yes, in conjunction with solar and all types of battery
storage for other projects.
Steve Johnson: Ramping costs, shut off, curtailment. Yes, we can shut it off wind, but
still have to pay for it.
James Gall: Modeling on an hourly basis. Some may have PPAs with certain hours or
ramping.
Amy Wheeless: Biomass seems pretty big. Yes, we have the opportunity to do one
biomass project that big. Is nuclear included? Yes, small nuclear is being modeled.
John Barber: Doesn’t biomass operate as a baseload plant and not as a peaker. Usually
true, this project would operate more as a peaking biomass facility in the winter.
Pauline Druffel: Doesn’t biomass produce greenhouse gases? Yes, but biomass is
carbon neutral under Washington law.
Page 5 – Other Clean Resource Options
Amy Wheeless: Are hydro PPA’s going to be included? Yes, on a later slide (Slide #13)
Slide #6 - Storage Technologies
Thomas Dempsey: Liquid air is a long-term energy storage using solar and wind
generation to compress and liquefy the air. When using this system, the plant does not
have to compress air, so we would get full use of the generating resource.
Steve Johnson: What are the efficiencies? 60 – 70% round trip efficiency. Hydrolysis is
only 25% efficient.
James Gall: We are using the Lazard Study, and a new version should be available next
month, so we will use the most up-to-date costs available.
Steve Johnson: For hydro and Post Falls. PSE costs for rebuilding Snoqualmie Falls
were much higher than expected. Make sure you are modeling these hydro rebuilding
costs really carefully. The project economics didn’t work out.
Steve Johnson: Power purchase options. Design a model to capture the value of an
asset’s value of these contracts. Green value. Very important to know it would serve
load with the value of different kinds of resources. And articulate why, how, and ways
resources are driving costs meeting loads with market options.
Resource Option Spreadsheet
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5

Amy Wheeless: What is the deadline for comments on the resource spreadsheet? By
the middle to end of January.
Steve Johnson: With the 20-year timeframe, are we adding more noise than necessary?
Would retrofitting be cheaper? Avista models retrofitting options if we know about the
potentials.

Home Heating Technologies Overview, Tom Lienhard Garrett Brown: What is the payback on slide 11 [First cost of technologies]? In floor
radiant heat uses less than half the energy. Good if staying in the house for 20 years.
Need to work to overcome the first costs. When they do a good job.
Barry Kathrens: Comfort is another benefit. My woodshop has radiant floor heat and
adds like an extra dollar a day.
Tom Lienhard: Maybe we need an Air B&B for people to be able to try out a good
efficient house in the winter.
Kirsten Wilson: We were able to remove and replace the old heating system for an
additional $15,000 in an existing structure. But we are both engineers.
Jørgen Rasmussen: How does a CO2 heat pump compare. COP of 3, equal or better
than 96%, and is about $5,000 for the unit.
Brian Parker: I came here from California where they were more sophisticated about
these matters. I’ve had trouble finding HVAC contractors who could do certain efficiency
calculations. Either they wouldn’t show up or they didn’t come back. Yes, it is a design
issue and requires meeting with the right HVAC installers to make these things happen.
Tom Lienhard: 10% humidity when cold in continental climate works the same way. 72
degrees feels like 64 degrees since heat can’t transfer. At 45% relative humidity, 72
degrees feels like 72 degrees. This also affects heat pumps here where there is general
not as much humidity.
Tom Lienhard: The RTF uses zones 1, 2 and 3. Avista is in zones 2 and 3. The map in
slide #15 calls these zones 4, 5 and 6.
Slide 19 is referring to RTF zones 2 and 3.
Steve Johnson: So a BTU of natural gas is about one third the cost of a BTU of
electricity? Yes.
Jørgen Rasmussen: But are they CO2 equivalent? Doesn’t Kendall Yards [Spokane
housing development near downtown] have all heat pumps? Not all. There are one or
two heat pumps per condo and the rest are resistance heat.
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6

Pauline Drury: Sounds like CO2 heat pumps are something for reducing heat. Is this for
the source of electricity because I have a personal feeling that we should be reducing
carbon? These are CO2 heat pumps that use CO2 in the system.
Jørgen Rasmussen: Greenhouse gas free because CO2 is less potent than other
refrigerants.
Gerry Snow: More penetration of renewables makes the power budget (E&G) move to
electrification, like British Columbia, and even more extreme as hydrogen in natural gas
pipes. Where is the trade off? If it’s a capacity issue, more storage is better.
Resource Adequacy and Effective Load Carrying Capability, James Gall
Steve Johnson: Balancing area has performance standards. Different kind of things.
Obligations to meet load within the house. NPCC quote.
Steve Johnson: You don’t model natural gas fuel disruptions? No, we don’t assume
pipeline or storage disruptions. This study is not cost, just availability.
Steve Johnson: Power Council, couldn’t you just get something from another. We have
a winter problem.
Amy Wheeless: Becoming more summer peaking regionally. Yes and no. Summer is
more consistent than winter.
Steve Johnson: Don’t have a good way of moving up summer or winter temperatures to
set “benefits” of global warming for resource adequacy. The means are changing, but
the extremes not so much.
James Gall: Wind improves reliability, but not by as much as thought. There is lots of
variation site-to-site so more work is needed to pick the right number to use for reliable
wind capacity – 5 to 10% range is probably right.
Clint Kalich: Does the Power Council still use 5% for wind?
Mike Starrett: Northwest capacity contribution for Columbia Gorge wind is 3% on its
own, 9.5% when integrated with hydro. Solar is 3% and higher when integrated.
Steve Johnson: Their model accounts for energy at night allowing more daytime hydro.
Avista’s model does too.
James Gall: Need to consider correlation with very low temperatures in Montana
compared to us. So we need more studies. Solar helps a little bit at 2.2% by moving
hydro and if we peak in February. We had one of our last peaks with zero wind and
solar for a week. This study considers demand response at 10 times per year now,
ELCC (Effective Load Carrying Capability) would go up if there were more times per
year.
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7

Steve Johnson: Is the curve used to develop the LOLP (loss of load probability)
accurate? Yes, if want to use renewables to back up LOLP, need to add multiples of the
renewable resources to get a better chance they are available when needed. Learned
from the past model.
Amy Wheeless: Why not reduce gas more?
James Gall: Storage moves and loses energy. The losses vary by the type of storage
like lithium ion or hydrogen. Storage needs to be paired with something to charge it.
Matt Nykiel: Does this include carbon (cost)? No, but about 5 times more expensive.
Clint Kalich: About 6 times. This is for peaking capacity, so only runs about 5 percent of
the time for reliability or low hydro conditions.
Mike Starrett: I have some questions about the numbers in the slides that can’t be
shown online.
Steve Johnson: Diversity – Avista could build a whole bunch and pay full cost while
helping everyone else. It’s great to think of one big utility, but we don’t share the fixed
costs.
Clint Kalich: Today, we are already long as a region. This is an additional surplus
needed to charge these batteries. At a certain point, it doesn’t help more. Is this
incremental energy? This is how much wind and storage is needed to help.
Mike Starrett: More midday curtailment. Policy changes a little bit later. In Aurora, are
those resources being curtailed so that adding more renewables lowers the value of
them?

2019 Electric IRP Key Case Assumptions
Steve Johnson: Fully electric percentage? (Slide #9, Electric Vehicles) We don’t have
the all-electric percentages broken out. Rendall Farley might. There is less separation
between all-electric EVs and plug-in hybrids.
Steve Johnson: Looking at the causal effect, if all these things are different, volatility
may be different for loads, uses, etc.
Steve Johnson: Not a normal distribution? No, it isn’t.
Jennifer Snyder: BPA has a forward looking study for hydro conditions (due to climate
change). Briefly, Avista expects the same amount of water for hydro, but the timing of it
moves from the spring to the winter based on the studies we have reviewed.
Garret Brown: Was the last hydro year good? Hydro was really good the first six months
and worse the rest of the year. About 5% lower regionally, but Avista did better than the
regional average.
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8

Matt Nykiel: What is the time frame for coal prices deadline to comment? Proposals in
February, comment deadline a week or so after the next TAC meeting [February 6] and
scenarios could be a few weeks later.
Steve Johnson: Not sure of not doing a risk analysis for climate changes to hydro.
Mike Starrett: BPA came in and did a presentation last meeting (Power Council) and in
person to the council. Is it a sensitivity or not? More winter rain, so a shortage from
winter to summer.
Steve Johnson: You have examples of what it looks like when it warms. You could do a
scenario or something like a single year look at it.
Rachelle Farnsworth: How do you include the risk associated with Colstrip? We have a
slide for that.
Steve Johnson: There will be a different value for renewables before and after
greenhouse gas prices. The shadow price is not going down much.
Clint Kalich: But people who waited and bought after I-937 paid less.
Matt Nykiel: No one wants to pay $20 per dekatherm, but there is a cost.

Futures and Scenarios, James Gall and John Lyons
Jennifer Snyder: I would be more comfortable using 2020 instead of 2025 (for the start
date of carbon pricing).
Steve Johnson: Another approach setting an objective function with an objective
function.
Steve Johnson: We should probably set up a meeting with Brad (Cebulko) and others to
go through this.
Matt Nykiel: Why only Washington? It was for a WUTC request. A later slide shows a
scenario for all of Avista’s service territory.
Steve Johnson: Look at the Northwest Natural IRP for their natural gas price for any
divergent numbers.
Steve Johnson: Will you include the updated forced outage rates for Colstrip? Yes, we
will use the most recent forced outage rates.
Matt Nykiel: Changes in ownership structure in Colstrip Units 3 and 4.
Steve Johnson: If not operating, an exit provision.
Page 207 Avista Corp. 2020 Electric IRP Appendices
9

Steve Johnson: You should make sure to have a letter shielding any employees with
knowledge of what would be paid in the future for the ownership interest in Lancaster.
Avista Corporation sold its ownership interest in Lancaster in 2006.
Public Counsel (phone): Is the social cost of carbon included in its own case? It is one
of three futures, treated at the same time.
Amy Wheeless: Spreadsheet available by the end of the week or early next week? Yes.
Matt Nykiel: Will there be a breakdown of basic assumptions for Colstrip? Costs and
when they are expected to occur.
Matt Nykiel: What happens if someone walks away (from Colstrip), can you show how
costs get reapportioned? Would need to check on what could happen.

Page 208 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Tuesday, April 16, 2019 Avista Headquarters, Conference Room 130

Topic Time Staff Introductions and TAC 2 Recap 9:00 Lyons

Regional Legislative Update 9:10 Lyons

IRP Transmission Planning Studies 9:30 Rolstad

Break 10:30 Distribution Planning Within the IRP 10:45 Fisher Lunch 12:00 Conservation Potential Assessment 1:00 AEG

Demand Response Potential Assessment 2:00 AEG

Break 3:00 Pullman Smart Grid Demonstration Project 3:15 Doege Review E3 Study – Resource Adequacy in the Pacific 3:45 Gall
Northwest

Adjourn 4:30
Page 209 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
November 27, 2018
Page 210 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next two years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2 Page 211 Avista Corp. 2020 Electric IRP Appendices
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 in all or some of the process
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3 Page 212 Avista Corp. 2020 Electric IRP Appendices
TAC #2 Recap –November 27, 2018
•Introductions and TAC 1 Recap, Lyons
•Modeling Process Overview, Gall
•Generation Resource Options, Gall
•Home Heating Technologies Overview, Lienhard
•Resource Adequacy and Effective Load Carrying
Capability, Gall
•Key Assumptions, Gall and Lyons
•Futures and Scenarios, Gall and Lyons
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-
company/integrated-resource-planning
4 Page 213 Avista Corp. 2020 Electric IRP Appendices
Updates –Rattlesnake Flat Wind PPA
•Issued RFP June 6, 2018 to capture low renewables pricing
resulting from expiring PTC and ITC
•Bids for over 2,000 MW from 40 wind and solar offers
•9/19/18: 150 MW Rattlesnake Flat Wind (Clearway Energy)
•Contract signed March 7, 2019
•Construction begins May 2019 and scheduled to be online 12/31/20
•About 12 miles southeast of Lind, Washington on 20,000 acres
5 Page 214 Avista Corp. 2020 Electric IRP Appendices
Rattlesnake Flat Wind Project
6 Page 215 Avista Corp. 2020 Electric IRP Appendices
Today’s Agenda
•9:00 –Introductions and TAC 2 Recap, Lyons
•9:10 –Regional Legislative Update, Lyons
•9:30 –IRP Transmission Planning Studies, Rolstad
•10:30 – Break
•10:45 –Distribution Planning within the IRP, Fisher
•Noon –Lunch
•1:00 –Conservation Potential Assessment, AEG
•2:00 –Demand Response Potential Assessment, AEG
•3:00 – Break
•3:15 –Pullman Smart Grid Demonstration Project, Doege
•3:45 –Review E3 Study –Resource Adequacy in the Pacific
Northwest, Gall
•4:30 –Adjourn
7 Page 216 Avista Corp. 2020 Electric IRP Appendices
TAC 4 Topics
•TAC 4 on Tuesday, August 6, 2019
–Natural Gas Price Forecast
–Electric Market Forecast
–Energy and Peak Load Forecast
–Existing Resource Overview (Colstrip, Lancaster, and
other resources)
–Final Resource Needs Assessment
•TAC 5: Tuesday, October 15, 2019
•TAC 6: Tuesday, November 19, 2019
8 Page 217 Avista Corp. 2020 Electric IRP Appendices
2019 Electric IRP
Regional Legislative Update
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
April 16, 2019
Page 218 Avista Corp. 2020 Electric IRP Appendices
Washington Legislation
•SB 5981: Greenhouse gas emissions cap and trade program
–Public hearing held on March 21 in the Senate Environment, Energy and
Technology Committee. No further action scheduled.
•HB 1257: Energy efficient buildings and natural gas conservation
–Governor requested for new conservation requirements for natural gas utilities by
setting energy performance standards for commercial buildings and utility
administered incentive program for early energy performance retrofits. Authorizes
utilities to propose renewable natural gas (RNG) procurement program and
voluntary RNG tariffs. Passed House 3/29/19 and put on Senate Floor calendar.
•HB 1444: Appliance efficiency standards
–Department of Commerce requested minimum efficiency and testing standards
for certain appliances. Passed House 3/5/19 and on Senate Floor calendar.
•HB 1512: Electrification of transportation
–Allows electrification of transportation plan and incentives. Passed both
chambers.
•HB 1126 Distributed resource planning
–Declare state policy that utility DER planning process accomplish certain goals
and require Legislature to conduct an initial review of the state's policy by
January 1, 2023. 2 Page 219 Avista Corp. 2020 Electric IRP Appendices
Washington SB 5116 Clean Electricity Bill
•Governor’s clean electricity bill –100 percent carbon neutral by
2030
•Eliminates coal-fired electricity serving Washington customers by
12/31/25,
•100 percent carbon neutral resources by 2030
•Eliminating use of fossil-fuel generation to serve Washington load
beginning in 2045
•Passed Senate and House, back to Senate to approve House
changes
•2% annual cost cap
•Must consider the social cost of carbon for conservation evaluation
and selection, developing IRP and clean energy plans, and
evaluating and selecting intermediate and long-term resources
3 Page 220 Avista Corp. 2020 Electric IRP Appendices
Idaho and Montana Updates
Idaho: No major legislative proposals impacting the IRP
Montana:
•SB 331: Allow preapproval of 150 MW additional from Colstrip unit 4
for NorthWestern. Passed Senate.
•SB 201: revise requirements to hold mine permits to make sure
Rosebud Mine pensions are paid. Passed House and Senate.
•SB 252: Revise Montana Facility Siting Act to allow a coal mining
permit owner to get coal from outside of the Rosebud Mine. Passed
and back to Senate with amendments.
•HB 476:low interest loans from Montana Board of Investment for
NorthWestern to acquire additional interest in Colstrip and Talen to
replace coal supply agreement. Passed House and Senate.
•SB 189: Carbon Tax bill tabled.
4 Page 221 Avista Corp. 2020 Electric IRP Appendices
Oregon Update
HB 2020: Greenhouse gas cap and trade
•Establishes a cap and trade program for entities with 25,000 tons or
more of greenhouse gas emissions. Creates the Carbon Policy
Office within Oregon Department of Administrative Services and
directs the Director of Carbon Policy Office to adopt Oregon Climate
Action Program by rule.
5 Page 222 Avista Corp. 2020 Electric IRP Appendices
IRP Transmission Planning Studies
Tracy Rolstad, Transmission Planning
Third Technical Advisory Committee Meeting
April 16, 2019
Page 223 Avista Corp. 2020 Electric IRP Appendices
Education
•Tracy Rolstad
–Diploma, Naval War College, College of Naval
Command and Staff
–BSEE, University of Idaho
–Nuclear Navy
•Nuclear Operational Prototype (S1C)
•Nuclear Power School (Reactor Operator)
•Electronics Technician School
–Radar, Communications, etc.
–Professional Technical Education
•Too numerous to list…
2 Page 224 Avista Corp. 2020 Electric IRP Appendices
Resume…
–Avista Corporation
•Senior Pwr Sys Consultant, System Planning
•WECC DS Chair, WECC TSS Chair
–Utility System Efficiencies
•Senior Power Systems Analyst
–The Bonneville Power Administration
•Senior Engineer, System Operations
–The Joint Warfare Analysis Center
•EP Senior Analyst, PACOM Chief of Targets
•Special Technical Operations Action Officer
–Nuclear Navy (Attack Submarines)
•Chief Petty Officer (ETC/SS)
•Engineering Watch Supervisor
3 Page 225 Avista Corp. 2020 Electric IRP Appendices
Something Novel About Me
4 Page 226 Avista Corp. 2020 Electric IRP Appendices
FERC Standards of Conduct
Non-public transmission information can not be
shared with Avista Merchant Function employees
There are Avista Merchant Function employees
attending today
We will not be sharing any non-public transmission
information (OASIS is the place where this
information is made public)
5 Page 227 Avista Corp. 2020 Electric IRP Appendices
Agenda
•Introduction to Avista System Planning
•Useful information about Transmission Planning
•Recent Avista projects
•Generation Interconnection Study Process
•Integrated Resource Plan (IRP) Requests
•Large Generation Interconnection Queue
6 Page 228 Avista Corp. 2020 Electric IRP Appendices
Introduction to Avista System Planning
Avista’s System Planning Group includes:
•Transmission Planning
•Distribution Planning
•And we all care about:
–Federal, regional, and state compliance
–Regional system coordination
–Reliable electric service
•We provide transmission service
–To anyone
–To any type of generation or load
•We are ambivalent about type (must perform though)
7 Page 229 Avista Corp. 2020 Electric IRP Appendices
Information About Transmission Planning
•We care about the Bulk Electric System (BES)
–Our 115 kV and 230 kV facilities (>100 kV)
•If the Avista BES looks like it won’t reliably
deliver electrons to our customers in the near or
distant future, we put together plans to fix it
–“Corrective Action Plans”
–Mandated and Described in NERC TPL-001-4
•We live in the world of NERC Mandatory
Standards
–Energy Policy Act of 2005
8 Page 230 Avista Corp. 2020 Electric IRP Appendices
TPL-001-4
•Describes outages we must study
–P0: everything online and working
–P1: single facility outages, like a transformer
–P2 to P5: increasing levels of outages
–P6: any combination of two facilities
9 Page 231 Avista Corp. 2020 Electric IRP Appendices
TPL-001-4
•A couple of NERC directives for the faults above
–“The System shall remain stable”
–“Applicable Facility Ratings shall not be exceeded”
–“An objective of the planning process is to minimize
the likelihood and magnitude of Non-Consequential
Load Loss following planning events”
10 Page 232 Avista Corp. 2020 Electric IRP Appendices
Two Approaches to Reliability Issues
•Transmission Operators (TO) are guided by
significantly different standards than
Transmission Planners (TP).
•TO standards provide flexibility that TP
standards do not allow
–Operators can do anything to SAVE the
interconnected system
•Planners hopefully give them the tools to do this
–We HAVE changed our ways since 2007 (NERC stds)
»Inverse dog years are utility years
11 Page 233 Avista Corp. 2020 Electric IRP Appendices
We Are Recovering From This…
A quote from the late 90’s: “That’s our stuff, we will take the hit and shed load if needed.”
12 Page 234 Avista Corp. 2020 Electric IRP Appendices
Recent Transmission Projects
13
Benton –Othello 115 kV Rebuild (still ongoing)
Westside xfmr replacement/station rebuild
Page 235 Avista Corp. 2020 Electric IRP Appendices
Non Wires (or perhaps no new wires)
•Avista made “non-wires” Columbia Grid
workshop happen (held at PSE HQ)
14 Page 236 Avista Corp. 2020 Electric IRP Appendices
Non Wire Solutions are always evaluated
•We are documenting this with more clarity
•Non wires REQUIRE robust wires to perform
–Smartwire evaluation (our wires are too small!)
•Avista is working on the transmission fundamentals
15 Page 237 Avista Corp. 2020 Electric IRP Appendices
New wires…same footprint
•Small wire replacement
–Mostly copper replacement
•Facilitates use of SmartWires technology
–But practically eliminates the need in the near term
»It DOES literally physical support the devices…
Avista Planning has been studying these
since 2015. Partnered with U of I as well
sponsoring R&D on DFACTS
ACSS @ 200C
tremendous ratings
-or-Trap Wire…
16 Page 238 Avista Corp. 2020 Electric IRP Appendices
Evaluated Batteries for T-1-1
•TPL-001-4 T-1-1 Evaluation
–Double transformer outages
•Shawnee 230/115 kV
–Concurrent with outage of Moscow 230/115 kV
•Could we mitigate performance issues with storage?
–Yes…but…
»We would need a 100 MW battery
•Charge is 8 hours, discharge for 12 to 16 hours
•A third transformer is a better solution
•Robust performance and much less $$$$
17 Page 239 Avista Corp. 2020 Electric IRP Appendices
Generation Interconnection Study Process
Process for Generation Requests
•Two sources:
•External developers
•Enter via the OATT
•Internal IRP requests
•Feasibility Lite Study…then OATT
•AVA Merchant MUST follow the OATT just like external parties
•Typical process:
•Hold a scoping meeting to discuss particulars
•Outline a study plan
•Augment WECC approved cases for our studies
•Analyze the system against the standards
•Publish our findings and recommendations
18 Page 240 Avista Corp. 2020 Electric IRP Appendices
2019 IRP TransmissionCost Estimates
Station Request (MW)POI Voltage Cost Estimate ($ million)
Kootenai County (GF)100 230 kV 2
Kootenai County (GF)200/300 230 kV 80-100
Rathdrum 25/50/100 115 kV <1
Rathdrum 200 115 kV 55
Rathdrum 50/100 230 kV <1
Rathdrum 200 230 kV 60
Benewah 100/200 230 kV <1
Tokio 50/100 115 <1, 20
Othello/Lind 50/100/200 115 kV Queue Issues
Lewiston/Clarkston 100/200 230 kV <1
Northeast 10 115 kV <1
Kettle Falls 12 115 kV <1
Kettle Falls 24/100/124 115 kV <20
Long Lake 68 115 kV 33
Monroe Street 80 115 kV 2
Post Falls 10 115 kV <1
Cabinet Gorge 110 230 kV <14
[1]Preliminary estimates are given as -25% to +75%19
RAS changes
everything!
Page 241 Avista Corp. 2020 Electric IRP Appendices
Current Queue
20 Page 242 Avista Corp. 2020 Electric IRP Appendices
Monroe Street: 80 MW
21
•3 miles of 115 kV
Page 243 Avista Corp. 2020 Electric IRP Appendices
Post Falls: 10 MW to 20 MW
22
•Interconnection Only
Page 244 Avista Corp. 2020 Electric IRP Appendices
Questions?
Avista OASIS link:
http://www.oasis.oati.com/avat/index.html
23 Page 245 Avista Corp. 2020 Electric IRP Appendices
Electric Distribution Within the IRP
Damon Fisher, System Planning
Third Technical Advisory Committee Meeting
April 16, 2019
Page 246 Avista Corp. 2020 Electric IRP Appendices
Goals of Electric Distribution Planning
•Ensure electric distribution infrastructure to
serve customers now and in the future with a
focus on:
–Safety
–Reliability
–Capacity
–Efficiency
–Level of service
•Voltage, Power Quality, etc.
–Operational flexibility
–Meet Corporate/Regulatory goals
2 Page 247 Avista Corp. 2020 Electric IRP Appendices
North Spokane Study
3 Page 248 Avista Corp. 2020 Electric IRP Appendices
Study Area Map
4 Page 249 Avista Corp. 2020 Electric IRP Appendices
Total Area Demand 8/10/18
5 Page 250 Avista Corp. 2020 Electric IRP Appendices
Feeder Demand 8/10/18
6 Page 251 Avista Corp. 2020 Electric IRP Appendices
Add two 5MW 6 Hour Batteries
7 Page 252 Avista Corp. 2020 Electric IRP Appendices
Feeder Demand with Batteries
8 Page 253 Avista Corp. 2020 Electric IRP Appendices
Modest Solar Installation
9
Assumes addition of 1.5 MW of solar per feeder
or 9 MW total solar capacity Page 254 Avista Corp. 2020 Electric IRP Appendices
Perspective ~ 4MW 4 Hour Battery vs.
60MW 8,760 Hour Substation
200ft
Substation/Transmission- $5 Million
Batteries (10MW with 6 hours)-~$25 Million
10 Page 255 Avista Corp. 2020 Electric IRP Appendices
Distribution Battery Benefits
–Peak shaving
–Outage remediation (Islanded)
–Operational flexibility (back up a feeder)
–Generation shifting
11 Page 256 Avista Corp. 2020 Electric IRP Appendices
Other Projects
•New Flint Road Substation
–Offload overloaded feeders in Airway Heights
12 Page 257 Avista Corp. 2020 Electric IRP Appendices
Other Projects
•Huetter Road Substation
–Offload overloaded feeders in Coeur d’Alene
13 Page 258 Avista Corp. 2020 Electric IRP Appendices
Other Projects
•New Colbert Substation
–Offload overloaded Colbert Feeders
14 Page 259 Avista Corp. 2020 Electric IRP Appendices
Conclusion
15 Page 260 Avista Corp. 2020 Electric IRP Appendices
Questions?
16 Page 261 Avista Corp. 2020 Electric IRP Appendices
Energy solutions. Delivered.
2018 ELECTRIC CPA RESULTS SUMMARY
Prepared for Avista Energy
April 5, 2019Page 262 Avista Corp. 2020 Electric IRP Appendices
| 2Applied Energy Group · www.appliedenergygroup.com
AGENDA
Topics
AEG Introduction
Approach
Summary of Findings
Comparison with 2016 Potential Study
DR Analysis
Supplemental Slides
Sector-Level Results
Summer DR Impacts
Standalone DR Analysis
Page 263 Avista Corp. 2020 Electric IRP Appendices
| 3Applied Energy Group · www.appliedenergygroup.com
ABOUT AEG
Planning
Baseline studies
Market
assessment studies
Program design &
action plans
End-use forecasting
EM&V
EE portfolio & targeted programs
Demand response programs & dynamic pricing
Pilot design & experimental design
Behavioral programs
Implementation &
Technical Services
Engineering review, due-diligence, QA/QC
M&V, modeling &
simulation, onsite
assessments
Technology R&D and data tools (DEEM)
Program admin,
marketing,
implementation,
application processing
Market Research
Program / service pricing
optimization
Process evaluations
Market assessment /
saturation surveys
Customer satisfaction /
customer engagement
Market segmentation
VISION DSMTM Platform
Full DSM lifecycle tracking & reporting
Page 264 Avista Corp. 2020 Electric IRP Appendices
| 4Applied Energy Group · www.appliedenergygroup.com
Including Potential Studies and End-Use Forecasting
AEG has conducted more than 60 planning studies for more than 40 utilities /
organizations in the past five years.
AEG has a team of 11 experienced Planning staff plus support from AEG’s
Technical Services and Program Evaluation groups
AEG EXPERIENCE IN PLANNING
Northwest & Mountain:Avista Energy*BPA*Cascade Natural GasChelan PUDCheyenne LFPColorado Electric*Cowlitz PUD*Avista*
Inland P&L*Oregon Trail ECPacifiCorp*PNGCPGE*Seattle City Light*Tacoma Power*
HECOLADWPNV Energy*Public Service New Mexico* State of HawaiiState of New MexicoXcel/SPS
Ameren Illinois*Ameren Missouri*Citizens EnergyEmpire District ElectricIndianapolis P&L*Indiana & Michigan Utilities
Kansas City Power & Light MERCNIPSCO*Omaha Public Power DistrictState of MichiganVectren Energy*
Central Hudson G&E*Con Edison of NY*New Jersey BPUPECO EnergyPSEG Long IslandState of Maryland (BG&E, DelMarva, PEPCO, Potomac Edison, SMECO)
Midcontinent ISO*EEI/IEE*EPRI FERC
OG&EKentucky PowerSouthern Company (APC,GPC, Gulf Power, MPC)TVA
Page 265 Avista Corp. 2020 Electric IRP Appendices
Approach
Page 266 Avista Corp. 2020 Electric IRP Appendices
| 6Applied Energy Group · www.appliedenergygroup.com
OverviewOVERVIEW OF AEG’S APPROACH
Market Characterization
•Avista control totals•Customer account data
•Secondary data
•Avista market research
Identify Demand-Side Resources
•EE technologies
•EE measures
•Emerging
Baseline Projection
•Avista Load Forecast•Customer growth
•Standards and building codes•Efficiency options
•Purchase Shares
Potential Estimation
•Technical•Technical Achievable
•Economic Screen (TRC and UCT) are handled by Avista’s IRP in this study
Page 267 Avista Corp. 2020 Electric IRP Appendices
| 7Applied Energy Group · www.appliedenergygroup.com
Prioritization of Avista Data
Data from Avista was prioritized when available, followed by regional data, and finally well-vetted national data.
•2013 Residential GenPop Survey
•Customer Account Database
•Forecast data and load research
•Recent-year accomplishments and plans
•NEEA studies (RBSA 2016, CBSA 2014, IFSA)
•RTF and Power Council methodologies, ramp rates, and measure assumptions
•U.S. DOE’s Annual Energy Outlook
•U.S. DOE’s projections on solid state lighting technology improvements
•Technical Reference Manuals and California DEER
•AEG Research
KEY SOURCES OF DATA
Page 268 Avista Corp. 2020 Electric IRP Appendices
| 8Applied Energy Group · www.appliedenergygroup.com
•Focus of the study is to explore a wide range of options for reducing annual energy use
•This study develops two sets of estimates:
•Technical potential (TP): everyone choosesefficient option when equipment fails
•Technical Achievable Potential (TAP) is a subset of TP that accounts for customer preference
and likelihood to adopt through
utility-and non-utility driven mechanisms
•In addition to these estimates, the study produces cost data for the
TRC and UCT tests that can be used by Avista’s IRP process to select
energy efficiency measures in competition with other resources
TWO LEVELS OF SAVINGS ESTIMATES
Technical
Technical
Achievable
Power Council Methodology
Page 269 Avista Corp. 2020 Electric IRP Appendices
| 9Applied Energy Group · www.appliedenergygroup.com
New Activities for 2019 IRP
From the Avista 2017 Electric IRP Acknowledgement Attachment (UE-161036):
In its comments in this docket, Commission Staff wrote that it has concerns with how the Company performs its conservation potential assessment (CPA), such as the Company’s exclusion of conservation measures from the CPA prior to determining its technical potential.16 We share Staff’s concern. It is critical that the Company achieve all cost-effective conservation, not only because this is required under the Energy Independence Act, but also because conservation and efficiency resources are the foundation of a least-cost resource stack.
In its 2019 IRP, the Company must ensure the entity performing the CPA evaluates and includes the following information:
1.All conservation measures excluded from the CPA, including those excluded prior to technical potential determination.
2.The rationale for excluding any measure.
3.A description, and source, of Unit Energy Savings data for each measure included in the CPA.
4.An explanation for any differences in economic and achievable potential savings.
The Company should also share its proposed energy efficiency measure lists with the Conservation Advisory Group prior to completing the CPA.
•Determine whether or not to move the T&D benefits estimate to a forward looking value versus a historical value.
•Determine if a study is necessary to estimate the potential and costs for a winter and summer residential demand response program and along with an update to the existing commercial and industrial analysis.
•Use the utility cost test methodology to select conservation potential for Idaho program options.
2017-2018 ACTION PLAN
Page 270 Avista Corp. 2020 Electric IRP Appendices
| 10Applied Energy Group · www.appliedenergygroup.com
Exclusions from CPA
Recommended Activity:
In the 2019 IRP, ensure that the entity performing the Conservation Potential
Assessment (CPA) evaluates and includes the following information:
•All conservation measures excluded from the CPA, including those excluded prior
to technical potential determination;
•Rationale for excluding any measure;
•Very few measures were excluded from the current CPA prior to estimation of
technical potential. Those explicitly excluded were:
Some emerging tech measures where available cost or savings data was insufficient for characterization
Highly custom commercial and industrial controls/process measures that were instead captured under a retrocommissioning or strategic energy management program
•Measures that did not pass the economic screen were still counted in within achievable technical potential, allowing Avista to review for inclusion in programs if
portfolio-level cost-effectiveness allows.
MEASURE SCREENING
Page 271 Avista Corp. 2020 Electric IRP Appendices
| 11Applied Energy Group · www.appliedenergygroup.com
Documentation of Savings and Other Assumptions
Recommended Activity:
•Description of Unit Energy Savings (UES) for each measure included in the CPA; specify how it was derived and the source of the data;
•The measure list developed during the CPA includes descriptions of each measure included. AEG will provide this as an appendix to the final report.
•Source documentation for assumptions, including UES, lifetime, and costs
(including NEIs) may be found in the “Measure Summary” spreadsheet delivered as an appendix to the final report.
This will include the name of the source and version (if applicable)
MEASURE DOCUMENTATION
Page 272 Avista Corp. 2020 Electric IRP Appendices
| 12Applied Energy Group · www.appliedenergygroup.com
Explanation of Difference between Achievable and Economic
Recommended Activity:
•Provide an explanation for any differences in economic and achievable potential savings.
•Use the utility cost test methodology to select conservation potential for Idaho program options
•This round of the CPA delivers the full Achievable Technical potential for all
measures along with the associated TRC and UCT levelized costs ($/MWh) for each measure.
Avista’s IRP process will then perform its own economic considerations
•As both TRC and UCT levelized costs are provided, Idaho potential can be
evaluated using UCT costs as recommended.
ECONOMIC POTENTIAL
Page 273 Avista Corp. 2020 Electric IRP Appendices
| 13Applied Energy Group · www.appliedenergygroup.com
Assess Potential Value of Summer Peak and Residential
Recommended Activity:
•Determine if a study is necessary to estimate the potential and costs for a winter and summer residential demand response program and along with an
update to the existing commercial and industrial analysis.
•The DR analysis included Summer as well as winter impacts, and Residential
program options, so that Avista will have the needed data to evaluate possible program combinations for DR
DEMAND RESPONSE
Page 274 Avista Corp. 2020 Electric IRP Appendices
Summary of Findings
Page 275 Avista Corp. 2020 Electric IRP Appendices
| 15Applied Energy Group · www.appliedenergygroup.com
Potential Summary –WA & ID All SectorsENERGY EFFICIENCY POTENTIAL
Projections indicate that energy savings of ~1.1% of baseline consumption per year are Technically Achievable.
•152 GWh (17 aMW) in biennium period (2021-2022)
•976 GWh (111 aMW) by 2030
•This level of savings offsets future load growth
-
2,000
4,000
6,000
8,000
10,000
12,000
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
0
50
100
150
200
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
Annual Incremental Potential
Technical Achievable Potential (GWh)Technical Potential (GWh)
Page 276 Avista Corp. 2020 Electric IRP Appendices
| 16Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –WA & ID, All Sectors
Summary of Energy Savings (GWh), Selected
Years 2040
Reference Baseline (GWh)8,291.9 8,334.1 8,518.5 8,994.6 10,375.9
Cumulative Savings (GWh)
Technical Achievable Potential 71.4 151.6 439.3 976.3 1,973.7
Technical Potential 156.1 310.2 777.4 1,505.6 2,490.1
Energy Savings (% of Baseline)
Technical Achievable Potential 0.9%1.8%5.2%10.9%19.0%
Technical Potential 1.9%3.7%9.1%16.7%24.0%
Incremental Savings (GWh)
Technical Achievable Potential 71.4 81.1 108.4 114.4 102.4
Technical Potential 156.1 155.6 165.5 145.7 87.2
0%
5%
10%
15%
20%
25%
30%
2021 2022 2025 2030 2040
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
-
500
1,000
1,500
2,000
2021 2024 2027 2030 2033 2036 2039
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
Page 277 Avista Corp. 2020 Electric IRP Appendices
| 17Applied Energy Group · www.appliedenergygroup.com
Cumulative Potential Summary –WA & ID All SectorsEE POTENTIAL -TOP MEASURES
Technical Achievable Potential, Ranked by Savings in 2030 (MWh)
Low Cost
Rank
2022 Achievable
Technical Potential
Savings (MWh)
2030 Achievable
Savings (MWh)
1 -Linear Lighting
2 -Ductless Mini Split Heat Pump (Ducted Forced Air)
3 -High-Bay Lighting
4 -Ductless Mini Split Heat Pump (Zonal)
5 -Water Heater (<= 55 Gal)
6 -Area Lighting
7 -ENERGY STAR Home Design
8 -Thermostat -Connected
9 -Windows -Cellular Shades
10 -Advanced New Construction Design -Zero Net Energy
11 -Dishwasher
12 -Water Heater -Low-Flow Showerheads
13 -General Service Screw-in
14 -Ventilation
15 -Space Heating -Heat Recovery Ventilator
16 -High-Bay Lighting
17 -Refrigeration -Evaporative Condenser
18 -Monitor
19 -Windows -Low-e Storm Addition
20 -RTU
Total of Top 20 Measures 51,000.4 33.65%480,369.0 49.21%
Total Cumulative Savings 151,553.0 100.00%976,256.8 100.00%
High Cost
Page 278 Avista Corp. 2020 Electric IRP Appendices
| 18Applied Energy Group · www.appliedenergygroup.com
Top Measure Notes
•Some expensive or emerging measures have significant potential, but may not be selected by the IRP due to costs
•Highlighted in orange on previous slide
•Heat Pump measures, including DHPs and HPWHs, have significant
energy benefits, however since heat pumps revert to electric resistance
heating during extreme cold, they have no effect on winter peak
•In addition to being expensive, some emerging tech measures are
included in Technical Achievable which may not prove feasible for
programs at this time, but can be kept in mind for future programs,
e.g.:
•Advanced New Construction –Zero Net Energy
•Connected Home Control Systems
EE POTENTIAL
Page 279 Avista Corp. 2020 Electric IRP Appendices
| 19Applied Energy Group · www.appliedenergygroup.com
Top Measures -Winter Peak (MW)
Reduction by 2030
2030
MW
% of
Total
1 Commercial -Linear Lighting 6.5 6.2%
2 Residential -ENERGY STAR Home Design 5.8 5.5%
3 Commercial -High-Bay Lighting 4.9 4.7%
4 Residential -Thermostat -Connected 4.7 4.4%
5 Residential -Windows -Cellular Shades 3.9 3.7%
6 Commercial -Space Heating -Heat Recovery
Ventilator 3.3 3.1%
7 Residential -Advanced New Construction Design -
Zero Net Energy 2.8 2.6%
8 Residential -General Service Screw-in 2.5 2.4%
9 Residential -Insulation -Floor Installation 2.5 2.3%
10 Residential -Water Heater -Low-Flow
Showerheads 2.4 2.3%
11 Residential -Windows -Low-e Storm Addition 2.2 2.1%
12 Industrial -Destratification Fans (HVLS)2.0 1.9%
13 Residential -Building Shell -Infiltration Control 2.0 1.9%
14 Industrial -High-Bay Lighting 1.9 1.8%
15 Residential -Dishwasher 1.8 1.7%
16 Residential -Insulation -Wall Cavity Installation 1.7 1.6%
17 Residential -Ducting -Repair and Sealing 1.6 1.5%
18 Commercial -Commissioning 1.5 1.4%
19 Commercial -Interior Lighting -Networked Fixture
Controls 1.4 1.3%
20 Commercial -Destratification Fans (HVLS)1.3 1.2%
Total of Top Measures 56.5 53.5%
Total Technical Achievable Reduction (MW)105.6 100.0%
Peak Impacts –Technical Achievable Potential
Top Measures -Summer Peak (MW)
Reduction by 2030
2030
MW
% of
Total
1 Residential -Ductless Mini Split Heat Pump
(Ducted Forced Air)5.2 5.4%
2 Residential -Water Heater (<= 55 Gal)5.2 5.4%
3 Commercial -Linear Lighting 5.0 5.2%
4 Commercial -High-Bay Lighting 3.8 4.0%
5 Residential -Water Heater -Low-Flow
Showerheads 3.1 3.3%
6 Commercial -RTU 2.9 3.0%
7 Residential -ENERGY STAR Home Design 2.6 2.7%
8 Residential -Dishwasher 2.5 2.6%
9 Commercial -RTU -Advanced Controls 2.4 2.5%
10 Residential -Advanced New Construction Design -
Zero Net Energy 2.3 2.4%
11 Industrial -High-Bay Lighting 2.2 2.3%
12 Residential -General Service Screw-in 1.9 2.0%
13 Residential -Monitor 1.6 1.6%
14 Residential -Freezer -Decommissioning and
Recycling 1.5 1.5%
15 Commercial -Chiller -Variable Flow Chilled Water
Pump 1.5 1.5%
16 Commercial -RTU -Evaporative Precooler 1.5 1.5%
17 Residential -Advanced Power Strips -IR Sensing 1.4 1.4%
18 Commercial -Commissioning 1.2 1.3%
19 Residential -Stove/Oven 1.1 1.2%
20 Residential -Refrigerator -Decommissioning and
Recycling 1.1 1.2%
Total of Top Measures 50.1 52.1%
Total Technical Achievable Reduction (MW)96.0 100.0%
EE POTENTIAL -CONTINUED
Page 280 Avista Corp. 2020 Electric IRP Appendices
| 20Applied Energy Group · www.appliedenergygroup.com
WA & ID Technical Achievable Potential by 2030SUPPLY CURVES
$-
$0.20
$0.40
$0.60
$0.80
$1.00
- 500,000 1,000,000 1,500,000 2,000,000
Levelized
Cost of
Energy
($/kWh)
Cumulative Savings (MWh)
TRC Conservation Supply Curve, 2030
Technical Potential Technical Achievable Potential
$-
$0.20
$0.40
$0.60
$0.80
$1.00
- 500,000 1,000,000 1,500,000 2,000,000
Levelized
Cost of
Energy
($/kWh)
Cumulative Savings (MWh)
UCT Conservation Supply Curve, 2030
Technical Potential Technical Achievable Potential
Page 281 Avista Corp. 2020 Electric IRP Appendices
| 21Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Washington, All Sectors
Summary of Energy Savings (GWh), Selected
Years 2040
Reference Baseline (GWh)5,243.2 5,268.4 5,381.1 5,686.8 6,571.8
Cumulative Savings (GWh)
Technical Achievable Potential 47.2 100.0 288.5 636.5 1,272.0
Technical Potential 102.5 203.4 508.2 979.2 1,607.3
Energy Savings (% of Baseline)
Technical Achievable Potential 0.9%1.9%5.4%11.2%19.4%
Technical Potential 2.0%3.9%9.4%17.2%24.5%
Incremental Savings (GWh)
Technical Achievable Potential 47.2 53.4 71.1 74.0 64.7
Technical Potential 102.5 101.9 108.1 94.2 54.9
0%
5%
10%
15%
20%
25%
30%
2021 2022 2025 2030 2040
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
-
200
400
600
800
1,000
1,200
1,400
2021 2024 2027 2030 2033 2036 2039
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
Page 282 Avista Corp. 2020 Electric IRP Appendices
| 22Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Idaho, All Sectors
Summary of Energy Savings (GWh), Selected
Years 2040
Reference Baseline (GWh)3,048.7 3,065.7 3,137.4 3,307.8 3,804.1
Cumulative Savings (GWh)
Technical Achievable Potential 24.2 51.6 150.7 339.8 701.7
Technical Potential 53.6 106.8 269.2 526.3 882.8
Energy Savings (% of Baseline)
Technical Achievable Potential 0.8%1.7%4.8%10.3%18.4%
Technical Potential 1.8%3.5%8.6%15.9%23.2%
Incremental Savings (GWh)
Technical Achievable Potential 24.2 27.6 37.4 40.4 37.7
Technical Potential 53.6 53.7 57.4 51.5 32.4
-
200
400
600
800
1,000
1,200
1,400
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
2021 2022 2025 2030 2040
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
Page 283 Avista Corp. 2020 Electric IRP Appendices
Comparison with 2016 Potential Study
Page 284 Avista Corp. 2020 Electric IRP Appendices
| 24Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study
We are often asked to compare results between current and prior potential study estimates –it is important to define comparison parameters.
Aligning calendar years, rather than study years results in a more thorough comparison
•E.g. lighting potential in 2019 and 2021 is very different
Since we are no longer estimating potential in 2017-2020, potential for those years must be removed from the comparison
•First-Year Incremental Potential -2021
Prior Study: 4th year of potential
Current Study: first year
This reduces potential since it accounts for two extra high-UES lighting years before EISA
The previous study’s 20-year look ended in 2037, therefore we must remove2038-2040 from the comparison
•Cumulative Potential Comparisons –2021 through year 2036
This should have a minimal impact on potential since retrofits are mainly captured prior to this point
As a result, we can draw up to a 17 year comparison (2021-2037)
NOTES ON COMPARISON
Page 285 Avista Corp. 2020 Electric IRP Appendices
| 25Applied Energy Group · www.appliedenergygroup.com
ACHIEVABLE POTENTIAL COMPARISONComparison with Prior Potential Study (2021-2037 TAP)
0
200
400
600
800
1000
1200
2018 2019 2022 2027 2037
GWh
Idaho All-Sector TAP Comparison
Prior Study (2018-2020)
Prior Study (2021-2037)
Current Study
0
200
400
600
800
1000
1200
2018 2019 2022 2027 2037
GWh
Washington All-Sector TAP Comparison
Prior Study (2018-2020)
Prior Study (2021-2037)
Current Study
Sector
(All States)End Use
Prior CPA
2037 MWh
Current
Study 2037
MWh Diff.
Residential
Cooling 44,269 63,188 18,919
Heating 242,917 366,549 123,632
Water Heating 191,988 206,932 14,944
Interior Lighting 43,555 55,064 11,509
Exterior Lighting 8,102 10,986 2,884
Appliances 72,894 76,363 3,469
Electronics 39,573 47,688 8,115
Miscellaneous 8,910 24,586 15,676
Commercial
Cooling 108,883 100,887 -7,996
Heating 53,198 46,496 -6,702
Ventilation 73,836 60,660 -13,176
Water Heating 11,199 23,150 11,951
Interior Lighting 225,353 270,791 45,438
Exterior Lighting 81,887 100,530 18,643
Refrigeration 21,665 63,885 42,220
Food Preparation 23,287 23,200 -87
Office Equipment 25,305 11,713 -13,592
Miscellaneous 322 2,091 1,770
Industrial
Cooling 6,303 5,455 -849
Heating 4,370 11,528 7,158
Ventilation 6,472 5,775 -697
Interior Lighting 22,925 40,131 17,206
Exterior Lighting 9,500 10,952 1,452
Motors 122,296 47,316 -74,980
Process 14,848 9,987 -4,860
Miscellaneous 1,665 566 -1,099
Grand Total 1,465,522 1,686,470 220,948Page 286 Avista Corp. 2020 Electric IRP Appendices
| 26Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIAL
Washington -Comparison with Prior Study –Technical Achievable
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2021 2025 2029 2033 2037
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2021 2025 2029 2033 2037
MWh
Commercial
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2021 2025 2029 2033 2037
MWh
Industrial
Prior Study
Current Study
•2018-2020 already removed from
prior study values
Page 287 Avista Corp. 2020 Electric IRP Appendices
| 27Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIALIdaho -Comparison with Prior Study –Technical Achievable
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2021 2025 2029 2033 2037
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2021 2025 2029 2033 2037
MWh
Commercial
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2021 2025 2029 2033 2037
MWh
Industrial
Prior Study
Current Study
•2018-2020 already removed from
prior study values
Page 288 Avista Corp. 2020 Electric IRP Appendices
| 28Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study –Technical Achievable
Residential:
•Potential reduced due to RTF “Market Baseline” assumption substantially lowering screw-in lighting savings
•DOE expanded definition of “General Service” now includes reflectors, reducing exempted lighting potential
•Idaho residential has extra potential in emerging New Construction measures (less impactful in WA due to the strict energy code)
However these measures are very expensive and unlikely to be selected by IRP
•Increases in lighting potential primarily due to new linear and high-bay lighting technology combination with integrated fixture controls
•Decreases in weatherization, particularly in WA, reflecting continuing influence of building codes and construction trends
•Removed key large accounts from WA Industrial control totals so as not to treat these singular entities as an “average population” that would have regular ramp-up and measure installations
SECTOR-LEVEL NOTES
Page 289 Avista Corp. 2020 Electric IRP Appendices
DR Potential Results
Page 290 Avista Corp. 2020 Electric IRP Appendices
| 30Applied Energy Group · www.appliedenergygroup.com
Annual Winter Peak MW, Two ScenariosOVERALL PROJECTION
Winter Peak MW 2021 2022 2025 2030 2040
Baseline Projection
Market Potential
Potential (% of baseline)
Potential Projection -
500
1,000
1,500
2,000
MW
Baseline Forecast Potential Forecast
Summer Peak MW 2021 2022 2025 2030 2040
Baseline Projection
Market Potential
Potential (% of baseline)
Potential Projection -
500
1,000
1,500
2,000
MW
Baseline Forecast Potential Forecast
Page 291 Avista Corp. 2020 Electric IRP Appendices
| 31Applied Energy Group · www.appliedenergygroup.com
By 2040, by State and Option, TOU Opt-in ScenarioWINTER PEAK MW REDUCTIONS
Winter Potential in 2040 ID WA Grand
Total
DLC
DLC Central AC 0.00 0.00 0.00
DLC Water Heating 6.88 12.38 19.27
DLC Smart Thermostats -Cooling 0.00 0.00 0.00
DLC Smart Thermostats -Heating 7.14 12.60 19.74
DLC Smart Appliances 1.24 2.21 3.45
DLC Electric Vehicle Charging 0.39 0.74 1.14
Third Party Contracts 8.47 14.78 23.25
Rates
Time-of-Use Opt-in 2.47 4.72 7.20
Time-of-Use Opt-out
Variable Peak Pricing Rates 7.48 14.00 21.48
Real Time Pricing 0.21 0.38 0.58
Ancillary Services 0.93 1.55 2.48
Thermal Energy Storage 0.00 0.00 0.00
Battery Energy Storage 1.87 3.34 5.21
Behavioral 1.07 2.08 3.15
Grand Total 38.16 68.78 106.95
0 5 10 15 20 25
DLC Central AC
DLC Water Heating
DLC Smart Appliances
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating
DLC Electric Vehicle Charging
Third Party Contracts
Time-of-Use Opt-in
Time-of-Use Opt-out
Variable Peak Pricing Rates
Real Time Pricing
Ancillary Services
Thermal Energy Storage
Battery Energy Storage
Behavioral
Achievable Potential (MW)
Winter DR Potential in 2040
ID WA
Page 292 Avista Corp. 2020 Electric IRP Appendices
| 32Applied Energy Group · www.appliedenergygroup.com
By 2040, by State and Option, TOU Opt-in ScenarioSUMMER PEAK MW REDUCTIONS
Summer Potential in 2040 ID WA Grand
Total
DLC
DLC Central AC 2.85 4.92 7.78
DLC Water Heating 6.88 12.38 19.27
DLC Smart Thermostats -Cooling 1.24 2.21 3.45
DLC Smart Thermostats -Heating 2.94 5.06 8.00
DLC Smart Appliances 0.00 0.00 0.00
DLC Electric Vehicle Charging 0.39 0.74 1.14
Third Party Contracts 7.64 13.23 20.87
Rates
Time-of-Use Opt-in 2.35 4.58 6.93
Time-of-Use Opt-out 0.00 0.00 0.00
Variable Peak Pricing Rates 7.10 13.59 20.69
Real Time Pricing 0.19 0.33 0.52
Ancillary Services 0.85 1.40 2.25
Thermal Energy Storage 0.32 0.48 0.80
Battery Energy Storage 1.87 3.34 5.21
Behavioral 1.03 2.05 3.08
Grand Total 35.64 64.34 99.98
0 5 10 15 20 25
DLC Central AC
DLC Water Heating
DLC Smart Appliances
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating
DLC Electric Vehicle Charging
Third Party Contracts
Time-of-Use Opt-in
Time-of-Use Opt-out
Variable Peak Pricing Rates
Real Time Pricing
Ancillary Services
Thermal Energy Storage
Battery Energy Storage
Behavioral
Achievable Potential (MW)
Summer DR Potential in 2040
ID WA
Page 293 Avista Corp. 2020 Electric IRP Appendices
Comparison with 2016 Potential Study
Page 294 Avista Corp. 2020 Electric IRP Appendices
| 34Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study
There were several changes made to the previous DR Potential Study:
•Included Summer Peak in analysis
•This presentation will focus on Winter Potential only to directly compare to the previous study
•Included Residential Sector in analysis
•Changes to Measure Options this year:
•Critical Peak Pricing Variable Peak Pricing
•Firm Curtailment Third Party Contracts
•Prioritized Smart Thermostats over Space Heating Switches
•Note: Comparison between calendar years for DR does not remove previous year impacts like the EE comparison
NOTES ON COMPARISON
Page 295 Avista Corp. 2020 Electric IRP Appendices
| 35Applied Energy Group · www.appliedenergygroup.com
DR POTENTIAL COMPARISON OPT-INComparison with Prior Potential Study by State (
-
5.0
10.0
15.0
20.0
25.0
30.0
35.0
2021 2025 2029 2033 2037
MW
Washington Opt-In Comparison
Prior Study
Current Study C&I
-
5.0
10.0
15.0
20.0
25.0
30.0
35.0
2021 2025 2029 2033 2037
MW
Idaho Opt-In Comparison
Prior Study
Current Study C&I
Notes on comparison:
•2021 values for Prior study include ramp-up to participation from prior years, while current study is in its first year
•In the prior study, the AMI program was still in its early planning phase and rollout had to be assumed. In the current study, the AMI rollout is defined by Avista’s active program plan
Page 296 Avista Corp. 2020 Electric IRP Appendices
| 36Applied Energy Group · www.appliedenergygroup.com
Potential in year 2037 by sectorDLC COMPARISON TO PRIOR STUDY
DLC Options Option Current
Study
Previous
Study
Residential DLC Central AC -
DLC Water Heating 16.9
DLC Smart Appliances 3.0
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating 16.0
DLC Electric Vehicle Charging 1.0
Residential Total 37.0
C&I DLC Central AC -
DLC Water Heating 1.7
DLC Smart Appliances 0.4
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating 2.9
Third Party Contracts 23.2 17.8
DLC Controls 4.1
C&I Total 28.1 21.9
Page 297 Avista Corp. 2020 Electric IRP Appendices
| 37Applied Energy Group · www.appliedenergygroup.com
Potential in year 2037 by sectorRATES COMPARISON TO PRIOR STUDY
Rates Opt-in Option Current
Study
Previous
Study
Residential Time-of-Use Opt-in 5.8
Time-of-Use Opt-out -
Variable Peak Pricing Rates 16.9
Ancillary Services 0.2
Battery Energy Storage 4.3
Behavioral 3.1
Residential Total 30.3
C&I Time-of-Use Opt-in 1.3 0.7
Time-of-Use Opt-out -
Variable Peak Pricing Rates/ CPP 4.3 3.6
Real Time Pricing 0.6
Ancillary Services 2.3
Thermal Energy Storage -
Battery Energy Storage 0.7
C&I Total 9.2 4.3
Rates Opt-Out Option Current
Study
Previous
Study
Residential Time-of-Use Opt-in -
Time-of-Use Opt-out 19.7
Variable Peak Pricing Rates 5.2
Ancillary Services 0.2
Battery Energy Storage 4.3
Behavioral 3.1
Residential Total 32.5
C&I Time-of-Use Opt-in -
Time-of-Use Opt-out 7.4 3.9
Variable Peak Pricing Rates/ CPP 1.3 10.6
Real Time Pricing 0.2
Ancillary Services 2.3
Thermal Energy Storage -
Battery Energy Storage 0.7
C&I Total 11.9 14.5
Page 298 Avista Corp. 2020 Electric IRP Appendices
THANK YOU!
Kurtis Kolnowski, Senior Project [e-mail]
Ken Walter, Senior Energy Analyst
[e-mail]
Page 299 Avista Corp. 2020 Electric IRP Appendices
Sector EE Results
Page 300 Avista Corp. 2020 Electric IRP Appendices
| 40Applied Energy Group · www.appliedenergygroup.com
ENERGY EFFICIENCY POTENTIALPotential Summary –Residential
2021 2022 2025 2030 2040
Reference Baseline (GWh)2,528 2,543 2,607 2,783 3,319
Potential Forecasts (GWh)
Technical Achievable Potential 2,507 2,499 2,476 2,478 2,672
Technical Potential 2,480 2,448 2,367 2,307 2,528
Cumulative Savings (GWh)
Technical Achievable Potential 21 44 131 305 647
Technical Potential 48 96 240 475 791
Energy Savings (% of Baseline)
Technical Achievable Potential 0.8%1.7%5.0%11.0%19.5%
Technical Potential 1.9%3.8%9.2%17.1%23.8%
Incremental Savings (GWh)
Technical Achievable Potential 21 24 33 37 39
Technical Potential 48 48 51 47 34
Washington
2021 2022 2025 2030 2040
Reference Baseline (GWh)1,644 1,658 1,713 1,844 2,226
Potential Forecasts (GWh)
Technical Achievable Potential 1,633 1,635 1,643 1,675 1,845
Technical Potential 1,618 1,605 1,579 1,574 1,758
Cumulative Savings (GWh)
Technical Achievable Potential 11 23 70 168 382
Technical Potential 26 53 134 270 468
Energy Savings (% of Baseline)
Technical Achievable Potential 0.7%1.4%4.1%9.1%17.1%
Technical Potential 1.6%3.2%7.8%14.6%21.0%
Incremental Savings (GWh)
Technical Achievable Potential 11 12 18 22 25
Technical Potential 26 27 29 27 22
Idaho
-
500
1,000
1,500
2,000
2,500
3,000
3,500
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential -
500
1,000
1,500
2,000
2,500
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
Page 301 Avista Corp. 2020 Electric IRP Appendices
| 41Applied Energy Group · www.appliedenergygroup.com
Top Measures –Residential, Technical Achievable PotentialEE POTENTIAL -CONTINUED
Washington Idaho
Rank 2022 2025 2030
1 11,941
2 8,760
3 2,270
4 -Connected 7,472
5 3,509
6 -Cellular Shades 5,866
7 2,939
8 -Zero 1,342
9 -Low-Flow Showerheads 6,866
10 -in 3,839
54,804
Total Cumulative Savings 44,428 131,104
Rank 2022 2025 2030
1
2
3
4
5 -Connected
6 -Cellular Shades
7 -Zero
8 -Low-Flow Showerheads
9
10 -in
Total of Top 10 Measures 8,798 30,761 95,012 56.5%
Total Cumulative Savings 23,101 69,599 168,308 100.0%
Cooling
8%
Space
Heating
51%
Water
Heating
16%
Interior
Lighting
6%
Exterior
Lighting
2%
Appliances
8%
Electronics
7%Miscellaneous
2%Cooling
8%
Space
Heating
51%
Water
Heating17%
Interior
Lighting7%
Exterior
Lighting
2%
Appliances
8%
Electronics
6%
Miscellaneou
s
1%
Page 302 Avista Corp. 2020 Electric IRP Appendices
| 42Applied Energy Group · www.appliedenergygroup.com
ENERGY EFFICIENCY POTENTIALPotential Summary – Commercial
2021 2022 2025 2030 2040
Reference Baseline (GWh)2,162 2,166 2,196 2,292 2,562
Potential Forecasts (GWh)
Technical Achievable Potential 2,140 2,119 2,064 2,014 2,026
Technical Potential 2,114 2,073 1,966 1,862 1,859
Cumulative Savings (GWh)
Technical Achievable Potential 22 47 132 278 536
Technical Potential 47 93 230 430 703
Energy Savings (% of Baseline)
Technical Achievable Potential 1.0%2.2%6.0%12.1%20.9%
Technical Potential 2.2%4.3%10.5%18.7%27.4%
Incremental Savings (GWh)
Technical Achievable Potential 22 25 32 31 22
Technical Potential 47 46 49 40 18
Washington
2021 2022 2025 2030 2040
Reference Baseline (GWh)1,010 1,012 1,029 1,065 1,171
Potential Forecasts (GWh)
Technical Achievable Potential 999 990 965 929 906
Technical Potential 987 968 918 857 826
Cumulative Savings (GWh)
Technical Achievable Potential 11 22 64 136 264
Technical Potential 22 44 110 208 344
Energy Savings (% of Baseline)
Technical Achievable Potential 1.0%2.2%6.2%12.8%22.6%
Technical Potential 2.2%4.4%10.7%19.6%29.4%
Incremental Savings (GWh)
Technical Achievable Potential 11 12 16 15 11
Technical Potential 22 22 23 20 9
Idaho
-
500
1,000
1,500
2,000
2,500
3,000
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential -
200
400
600
800
1,000
1,200
1,400
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
Page 303 Avista Corp. 2020 Electric IRP Appendices
| 43Applied Energy Group · www.appliedenergygroup.com
Top Measures –Commercial, Technical Achievable PotentialEE POTENTIAL -CONTINUED
Washington Idaho
Rank 2022 2025 2030
1 15,024
2 -Bay Lighting 10,375
3 7,347
4 2,546
5 -Heat Recovery Ventilator 5,394
6 -Evaporative Condenser 5,245
7 2,334
8 -Networked Fixture 3,242
9 -Replace Single-Compressor 3,948
10 -Advanced Controls 1,213
Total of Top 20 Measures 16,084 56,669
131,925
Rank 2022 2025 2030
1
2 -Bay Lighting
3
4 -Heat Recovery Ventilator
5
6
7 -Evaporative Condenser
8 -Networked Fixture
9
10 -Replace Single-Compressor
Total of Top 20 Measures 7,882 27,849 71,428 52.5%
Total Cumulative Savings 22,325 63,909 136,133 100.0%
Cooling
15%Heating
9%
Ventilation
8%
Water
Heating
4%
Interior
Lighting
33%
Exterior
Lighting
14%
Refrigeration
13%
Food
Preparation
2%
Office
Equipment
2%
Miscellaneous
0%
Cooling
16%Heating
8%
Ventilation
8%
Water
Heating
4%
Interior
Lighting
33%
Exterior
Lighting
14%
Refrigeration
13%
Food
Preparation
2%
Office
Equipment2%
Miscellaneous
0%
Page 304 Avista Corp. 2020 Electric IRP Appendices
| 44Applied Energy Group · www.appliedenergygroup.com
ENERGY EFFICIENCY POTENTIALPotential Summary –Industrial
2021 2022 2025 2030 2040
Reference Baseline (GWh)553 559 578 612 691
Potential Forecasts (GWh)
Technical Achievable Potential 549 550 552 558 602
Technical Potential 546 544 540 538 578
Cumulative Savings (GWh)
Technical Achievable Potential 4 9 25 54 89
Technical Potential 7 15 38 74 114
Energy Savings (% of Baseline)
Technical Achievable Potential 0.8%1.6%4.4%8.8%12.9%
Technical Potential 1.3%2.6%6.6%12.2%16.4%
Incremental Savings (GWh)
Technical Achievable Potential 4 5 6 6 3
Technical Potential 7 7 8 7 3
Washington
2021 2022 2025 2030 2040
Reference Baseline (GWh)395 395 396 399 407
Potential Forecasts (GWh)
Technical Achievable Potential 392 389 379 364 351
Technical Potential 390 385 371 351 336
Cumulative Savings (GWh)
Technical Achievable Potential 3 6 17 35 56
Technical Potential 5 10 25 48 71
Energy Savings (% of Baseline)
Technical Achievable Potential 0.7%1.6%4.4%8.9%13.7%
Technical Potential 1.2%2.4%6.3%12.0%17.4%
Incremental Savings (GWh)
Technical Achievable Potential 3 3 4 3 2
Technical Potential 5 5 5 4 2
Idaho
-
50
100
150
200
250
300
350
400
450
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential -
100
200
300
400
500
600
700
800
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
Page 305 Avista Corp. 2020 Electric IRP Appendices
| 45Applied Energy Group · www.appliedenergygroup.com
Top Measures –Industrial, Technical Achievable PotentialEE POTENTIAL -CONTINUED
Washington Idaho
Rank 2022 2025 2030
1 -Bay Lighting 2,636
2 3,192
3 -Equipment Upgrade 1,890
4 -Leak Management 1,833
5 714
6 666
7 -Variable Speed Drive 713
8 -Variable Speed Drive 631
9 -Equipment Upgrade 926
10 -Networked Fixture 610
13,811
Total Cumulative Savings 8,883 25,481
Rank 2022 2025 2030
1 -Bay Lighting
2
3 -Equipment Upgrade
4 -Leak Management
5 -Variable Speed Drive
6
7
8 -Variable Speed Drive
9 -Equipment Upgrade
10 -Networked Fixture
Total Cumulative Savings 6,149 17,236 35,326 100.0%
Cooling
4%Heating
10%
Ventilation
3%
Interior
Lighting
24%
Exterior
Lighting
8%
Motors
44%
Process
7%
Miscellaneous
0%
Cooling
4%
Heating
10%Ventilation
3%
Interior
Lighting
22%
Exterior
Lighting
7%
Motors
46%
Process
8%
Miscellaneous
0%
Page 306 Avista Corp. 2020 Electric IRP Appendices
Additional Slides from Current Study
Page 307 Avista Corp. 2020 Electric IRP Appendices
| 47Applied Energy Group · www.appliedenergygroup.com
By 2040, by State and Option, TOU Opt-out ScenarioWINTER PEAK MW REDUCTIONS
Winter Potential in 2040 ID WA Grand
Total
DLC
DLC Central AC 0.00 0.00 0.00
DLC Water Heating 6.88 12.38 19.27
DLC Smart Thermostats -Cooling 1.24 2.21 3.45
DLC Smart Thermostats -Heating 0.00 0.00 0.00
DLC Smart Appliances 7.14 12.60 19.74
DLC Electric Vehicle Charging 0.39 0.74 1.14
Third Party Contracts 8.47 14.78 23.25
Rates
Time-of-Use Opt-in
Time-of-Use Opt-out 9.47 17.95 27.42
Variable Peak Pricing Rates 2.30 4.30 6.59
Real Time Pricing 0.06 0.12 0.18
Ancillary Services 0.93 1.55 2.48
Thermal Energy Storage 0.00 0.00 0.00
Battery Energy Storage 1.87 3.34 5.21
Behavioral 1.07 2.08 3.15
Grand Total 39.83 72.05 111.88
0 5 10 15 20 25 30
DLC Central AC
DLC Water Heating
DLC Smart Appliances
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating
DLC Electric Vehicle Charging
Third Party Contracts
Time-of-Use Opt-in
Time-of-Use Opt-out
Variable Peak Pricing Rates
Real Time Pricing
Ancillary Services
Thermal Energy Storage
Battery Energy Storage
Behavioral
Achievable Potential (MW)
Winter DR Potential in 2040
ID WA
Page 308 Avista Corp. 2020 Electric IRP Appendices
| 48Applied Energy Group · www.appliedenergygroup.com
SUMMER POTENTIAL IN 2040 BY STATE
(TOU OPT-OUT)
Summer Potential in 2040 ID WA Grand Total
Ancillary Services 0.8 1.4 2.2
DLC Central AC 2.9 4.9
12.4
2.2
4.2
0.1
2.1 3.1
0.5
3.3
-Cooling 5.1
-Heating
13.2
0.7 1.1
-of-Use Opt-in
-of-Use Opt-out 17.3
Page 309 Avista Corp. 2020 Electric IRP Appendices
Stand-Alone Results by Program
Page 310 Avista Corp. 2020 Electric IRP Appendices
| 50Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –WINTER DLC
Sector Option 2021 2022 2030 2040
Residential DLC Central AC ----
DLC Water Heating 1.4 4.3 15.6 17.5
DLC Smart Appliances 0.3 0.8 2.8 3.1
-Cooling
-Heating
-Cooling
-Heating
Page 311 Avista Corp. 2020 Electric IRP Appendices
| 51Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –SUMMER DLC
Sector Option 2021 2022 2030 2040
Residential DLC Central AC 0.5 1.4 5.4 6.2
DLC Water Heating 1.4 4.3 15.6 17.5
DLC Smart Appliances 0.3 0.8 2.8 3.1
DLC Smart Thermostats -Cooling
-Heating
-Cooling
-Heating
Page 312 Avista Corp. 2020 Electric IRP Appendices
| 52Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –WINTER RATES AND
OTHER OPTIONS
Sector Option 2021 2022 2030 2040
Residential Time-of-Use Opt-in
-of-Use Opt-out 22.1
0.1
-of-Use Opt-in
-of-Use Opt-out
1.1
-
Page 313 Avista Corp. 2020 Electric IRP Appendices
| 53Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –SUMMER RATES
AND OTHER OPTIONS
Sector Option 2021 2022 2030 2040
Residential Time-of-Use Opt-in
-of-Use Opt-out
-of-Use Opt-in
-of-Use Opt-out
Page 314 Avista Corp. 2020 Electric IRP Appendices
Smart Grid
Demonstration Project
2009 –2015 Pullman WA
www.smartgrid.gov/files/OE0000190_Battelle_FinalRep_2015_06.pdf
Page 315 Avista Corp. 2020 Electric IRP Appendices
Battelle NWBonneville Power
Administration
3 Tier
Areva
IBM
Netezza
Quality
Logic
Utility Partners
Avista
Benton PUD
City of Ellensburg
Flathead Electric
Idaho Falls Power
Lower Valley Energy
Milton-Freewater
Northwestern Energy
Peninsula Light
PGE
Seattle City Light
NETL
Page 316 Avista Corp. 2020 Electric IRP Appendices
Transactive System
Figure courtesy of PNNL study Transactive System, December 2017Page 317 Avista Corp. 2020 Electric IRP Appendices
Avista Demand Response
Smart thermostats
•Residential & Small Commercial
–Air-Conditioning
–& some electric heat loads
•Avg. 57 participants (up to 75)
•637 DR Events (Transactive & AGS)
–Duration 5 minutes -6 hours
Washington State University
Tier 1 HVAC (39 points)12 DR events
Tier 2 Chillers (9 points)5 DR events
Tier 3-5 Generators 5 DR events
Page 318 Avista Corp. 2020 Electric IRP Appendices
Smart Meter Usage Web Portal
Bill-to-Date & Usage Charts
Customer Engagement
and Energy Efficiency Usage notifications &
alerts between bills
Daily: Comparison
Weekly: Bill-to-date
Monthly: Budget threshold
Page 319 Avista Corp. 2020 Electric IRP Appendices
New Customer Programs
Smart Thermostat Rebates
Washington Smart Meter Roll-Out
New AMI Web-Portal Features
<demo AMI web-portal>
Notifications & Alerts
Add to Mobile AppPage 320 Avista Corp. 2020 Electric IRP Appendices
QUESTIONS…
COMMENTS…
Page 321 Avista Corp. 2020 Electric IRP Appendices
Resource Adequacy in the
Pacific Northwest
Serving Load Reliably under a Changing
Resource Mix
February 2019
Resource Adequacy in the
Pacific Northwest
Serving Load Reliably under a Changing
Resource Mix
Arne Olson, Sr. Partner
Zach Ming, Managing ConsultantPage 322 Avista Corp. 2020 Electric IRP Appendices
Outline
Study Background & Methodology
Results
•2018
•2030
•2050
•Capacity contribution of wind, solar, storage and demand response
Key Findings
2Page 323 Avista Corp. 2020 Electric IRP Appendices
STUDY BACKGROUND
& METHODOLOGY
Page 324 Avista Corp. 2020 Electric IRP Appendices
4
About This Study
The Pacific Northwest is expected to undergo
significant changes to its generation resource mix
over the next 30 years due to changing economics
and more stringent policy goals
•Increased penetration of wind and solar generation
•Retirements of coal generation
•Questions about the role of new natural gas generation
This raises questions about the region’s ability to serve load
reliably as firm generation is replaced with variable resources
This study was sponsored by 13 Pacific Northwest utilities to
examine Resource Adequacy under a changing resource mix
•How to maintain Resource Adequacy in the 2020-2030 time
frame under growing loads and increasing coal retirements
•How to maintain Resource Adequacy in the 2040-2050 time
frame under stringent carbon abatement goals
Historical and Projected GHG Emissions for OR and WA
Page 325 Avista Corp. 2020 Electric IRP Appendices
5
Study Sponsors
This study was sponsored by Puget Sound Energy, Avista,
NorthWestern Energy and the Public Generating Pool (PGP)
•PGP is a trade association representing 10 consumer-owned utilities in
Oregon and Washington.
E3 thanks the staff of the Northwest Power and Conservation Council for providing data and technical review
Page 326 Avista Corp. 2020 Electric IRP Appendices
6
Three Reliability Challenges on a
Deeply-Decarbonized Grid
High Load
Low Wind & Solar
Low Hydro Year
1
2
3
Loss of load
event of
nearly 48 hrs Loss of load
magnitude of
over 30 GW
The most challenging conditions in a deeply-decarbonized Pacific Northwest grid occur
when a multi-day cold snap coincides with low wind, solar and hydro production
Page 327 Avista Corp. 2020 Electric IRP Appendices
7
Long-run Reliability and Resource
Adequacy
This study focuses on long-run (planning) reliability, a.k.a. Resource
Adequacy (RA)
•A system is “Resource Adequate” if it has sufficient capacity to serve load across
a broad range of weather conditions, subject to a long-run standard for
frequency of reliability events, for example 1-day-in-10 yrs.
There is no mandatory or voluntary national standard for RA
•Each Balancing Authority establishes its own standard subject to oversight by
state commissions or locally-elected boards
•North American Electric Reliability Council (NERC) and Western Electric
Coordinating Council (WECC) publish information about Resource Adequacy but
have no formal governing role
Study uses a 1-in-10 standard of no more than 24 hours of lost load in 10
years, or no more than 2.4 hours/year
•This is the most common standard used across the industry
Page 328 Avista Corp. 2020 Electric IRP Appendices
8
Study Region –The Greater NW
The study region consists of the
U.S. portion of the Northwest
Power Pool (excluding Nevada)
It is assumed that any resource in
any area can serve any need
throughout the Greater NW region
•Study assumes no transmission
constraints or transactional friction
•Study assumes full benefits from
regional load and resource
diversity
•The system as modeled is more
efficient and seamless than the
actual Greater NW system
Balancing Authority Areas include: Avista, Bonneville
Power Administration, Chelan County PUD, Douglas
County PUD, Grant County PUD, Idaho Power,
NorthWestern Energy, PacifiCorp (East & West),
Portland General Electric, Puget Sound Energy, Seattle
City Light, Tacoma Power, Western Area Power
AdministrationPage 329 Avista Corp. 2020 Electric IRP Appendices
9
New wind and solar resources are added
across a geographically diverse footprint
The study considers additions nearly 100 GW of wind
and 50 GW of solar across the six-state region
The portfolios studied are significantly more diverse
than the renewable resources currently operating in
the region
•Each dot in the map represents a location where
wind and solar is added in the study
•NW wind is more diverse than existing Columbia Gorge
wind
New renewable portfolios are within the bounds of
current technical potential estimates, but are nearly an
order of magnitude higher than other studies have
examined
The cost of new transmission is assumed for delivery of
remote wind and solar generation but siting and
construction is not studied in detail
State Wind
WA 18
OR 27
CA 34
ID 18
MT 944
WY 552
UT 13
Total 1588https://www.nrel.gov/docs/fy12osti/51946.pdf
NREL Technical Potential (GW)
NW Wind
MT Wind
WY Wind
Solar
Additional
transmission
cost ($50/kW-yr)
associated with
MT and WY wind
Page 330 Avista Corp. 2020 Electric IRP Appendices
10
Additional metric definitions used for
scenario development
GHG Reduction %is the reduction below 1990 emission levels for the
study region
•The study region emitted 60 million metric electricity sector emissions in 1990
CPS %is the total quantity of GHG-free generation divided by retail
electricity sales
•“Clean Portfolio Standard” includes renewable energy plus hydro and nuclear
•Common policy target metric, including California’s SB 100
GHG-Free Generation %is the total quantity of GHG-free generation,
minus exported GHG-free generation, divided by total wholesale load
•Assumed export capability up to 6,000 MW
Renewable Curtailment %is the total quantity of wind/solar generation
that is not delivered or exported divided by total wind/solar generation
Page 331 Avista Corp. 2020 Electric IRP Appendices
11
The study considers Resource Adequacy needs under multiple scenarios
representing alternative resource mixes
2050 Scenarios Carbon Reduction
% Below 19901
GHG-Free
Generation %2 CPS %3
Carbon Emissions
(MMT)
Reference Case 16%60%63%50
60% GHG Reduction 60%80%86%25
80% GHG Reduction 80%90%100%12
90% GHG Reduction 90%95%108%6
98% GHG Reduction 98%99%117%1
100% GHG Reduction 100%100%123%0
2018-2030 Scenarios Carbon Reduction
% Below 19901
GHG-Free
Generation %2 CPS %3
Carbon Emissions
(MMT)
2018 Case4 -6%71%75%63
2030 Reference Case4 -12%61%65%67
2030 Coal Retirement 30%61%65%42
1Greater NW Region 1990 electricity sector emissions = 60 MMT/yr.
2GHG-Free Generation % = renewable + hydro + nuclear generation, minus exports, divided by total wholesale load
3CPS % = renewable + hydro + nuclear generation divided by retail electricity sales
42018 and 2030 cases assumes coal capacity factor of 60%
Page 332 Avista Corp. 2020 Electric IRP Appendices
12
Individual utility impacts will
differ from the regional impacts
Cost impacts in this study are presented from a societal perspective and
represent an aggregation of all costs and benefits within the Greater NW
region
•Societal costs include all investment (i.e. “steel-in-the-ground”) and operational
costs (i.e. fuel and O&M) that are incurred in the region
Cost of decarbonization may be higher or lower for individual utilities as
compared to the region as a whole
•Utilities with a relatively higher composition of fossil resources today are likely
to bear a higher cost than utilities with a higher composition of fossil-free
resources
Resource Adequacy needs will be different for each utility
•Individual systems will need a higher reserve margin than the Greater NW
region due to smaller size and less diversity
•Capacity contribution of renewables will be different for individual utilities due
to differences in the timing of peak loads and renewable generation production
Page 333 Avista Corp. 2020 Electric IRP Appendices
2030 RESULTS
Page 334 Avista Corp. 2020 Electric IRP Appendices
14
2030 Portfolios
5 GW net new capacity
by 2030 is needed for
reliability (450 MW/yr)
With planned coal
retirements of 3 GW, 8
GW of new capacity by
2030 is needed
(730 MW/yr)
If all coal is retired,
then 16 GW new
capacity is needed
(1450 MW/yr)
GHG Free Generation (%)61%61%
Carbon (MMT CO2)67 42
% GHG Reduction from 1990 Level -12%*31%
*Assumes 60% coal capacity factor
2018 2030
Page 335 Avista Corp. 2020 Electric IRP Appendices
15
The Northwest system will need 8 GW of
new effective capacity by 2030
2030 with No
New Capacity
2030 with 8 GW of
New Capacity
Annual LOLP (%)48%2.8%
LOLE (hrs/yr)106 2.4
EUE (MWh/yr)178,889 1,191
EUE norm (EUE/load)0.07%0.0004%
The 2030 system does not meet 1-in-10 reliability standard (2.4 hrs./yr.)
The 2030 system does not meet standard for Annual LOLP (5%)
Load growth and planned coal retirements lead to the need for 8 GW of new
effective capacity by 2030
Page 336 Avista Corp. 2020 Electric IRP Appendices
2050 RESULTS
Page 337 Avista Corp. 2020 Electric IRP Appendices
171CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Scenario Summary
Greater NW System in 2050
2050 Reference Scenario
Total cost of new resource
additions is $4 billion per year
(~$30 billion investment)
2018 2050
Additions Retirements
2 GW Wind
4 GW Solar
20 GW Gas
11 GW Coal
9 GW
net
increase
in firm
capacity
Page 338 Avista Corp. 2020 Electric IRP Appendices
181CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Scenario Summary
Greater NW System in 2050
4-hr
4-hr 4-hr
4-hr
6-hr
2018 2050
Page 339 Avista Corp. 2020 Electric IRP Appendices
19
Illustrating the Need for
Firm Capacity –January
10 Day Cold Stretch In January
Despite 60 GW of installed renewable capacity in the 80% reduction
scenario, gas and hydro are needed during low generation periods
80% Reduction Portfolio Including Gas
Gas & hydro ramp up during periods of high
load and low renewable production
Page 340 Avista Corp. 2020 Electric IRP Appendices
20
Illustrating the Need for
Firm Capacity –January
10 Day Cold Stretch In January
80% Reduction Case Without Gas
Without gas, the system is energy deficient during prolonged
stretches of low wind and solar production
Loss of Load
Page 341 Avista Corp. 2020 Electric IRP Appendices
21
Scenario Summary
2050 Emissions Reductions
4-hr
4-hr 4-hr
4-hr
6-hr20182050
Carbon (MMT CO2)50 25 12 6 1 -
CPS (%)1 63%86%100%108%117%123%
GHG Free Generation (%)2 60%80%90%95%99%100%
% GHG Reduction from 1990 level 16%60%80%90%98%100%
1CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Page 342 Avista Corp. 2020 Electric IRP Appendices
22
Scenario Summary
2050 Resource Use
4-hr
4-hr 4-hr
4-hr
6-hr20182050
Renewable Capacity (GW)13 34 49 59 83 143
Annual Renewable Curtailment (%)Low Low 4%10%21%47%
Gas Capacity (GW)32 26 24 20 14 0
Gas Capacity Factor (%)46%27%16%9%3%0%
1CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Page 343 Avista Corp. 2020 Electric IRP Appendices
23
2050 Annual Energy Balance
Load 309 TWh/yr
46%
Gas CF
27%
Gas CF
16%
Gas CF
9%
Gas CF
3%
Gas CF
0%
Gas CF
Gas capacity factor declines significantly at
higher levels of decarbonization
Significant curtailed renewable energy at
deep levels of carbon reductions
Page 344 Avista Corp. 2020 Electric IRP Appendices
24
Firm capacity is still needed for reliability under deep decarbonization
despite much lower utilization
Natural gas energy production declines substantially as the GHG
increases
Natural gas capacity is part of the least-cost mix of resources to
reduce carbon emissions to 1 million tons by 2050
All scenarios except 100% GHG reductions select more gas capacity
than exists on the system today (12 GW)
14 GW of gas
capacity needed
even under 98%
GHG Reduction
scenario
Despite retention of gas capacity
for reliability, capacity factor
declines precipitously as more
wind, solar, and storage are added
for decarbonization
Page 345 Avista Corp. 2020 Electric IRP Appendices
251CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Scenario Summary
2050 Costs
4-hr
4-hr 4-hr
4-hr
6-hr20182050
Marginal Carbon Reduction Cost
($/Metric Ton)
Base $0 -$80 $90 -
$190
$110 -
$230
$310 -
$700
$11,000 –
$16,000
Annual Cost Delta ($B)Base $0 -$2 $1 -$4 $2 -$5 $3 -$9 $16 -$28
Additional Cost ($/MWh)Base $0 -$7 $3 -$14 $5 -$18 $10 -$28 $52 -$89
Removing final 1% of carbon requires
additional $100b to $170b of investment
Page 346 Avista Corp. 2020 Electric IRP Appendices
26
Marginal Cost of GHG Reduction
80% GHG Free 90% GHG Free 95% GHG Free 99% GHG Free
86% CPS 100% CPS 108% CPS 117% CPS
Marginal cost of CO2 reductions at
90% GHG Reductions or greater
exceed most estimates of the
societal cost of carbon which
generally range from $50/ton to
$250/ton1, although some academic
estimates range up to $800/ton1
1 https://19january2017snapshot.epa.gov/climatechange/social-cost-carbon_.html;
https://www.nature.com/articles/s41558-018-0282-y
High Cost Range
Low Cost Range
$80
$190
$230
$700
$310
$110$90
Page 347 Avista Corp. 2020 Electric IRP Appendices
27
Marginal Cost of GHG Reduction
80% GHG Free 90% GHG Free 95% GHG Free 99% GHG Free 100% GHG Free
86% CPS 100% CPS 108% CPS 117% CPS 123% CPS
Marginal cost of absolute
100% GHG reductions vastly
exceeds societal cost of
carbon, confirming
conclusion on impracticality
Previous slide
High Cost
Range
Low Cost
Range
$80
$0
$190 $230 $700
$310$110$90
$16,000
$11,000
Page 348 Avista Corp. 2020 Electric IRP Appendices
28
100% Reduction
Portfolio Alternatives in 2050
6-hr
926-hr
4-hr
2018 2050
Clean baseload or biogas or
ultra-long duration storage
resource could displace
significant wind and solar
4-hr
Base Case
100% Zero
Carbon
Uncertain Technical/Cost/Political Feasibility
Clean baseload
would require
SMR or other
undeveloped
technology
Ultra-long
duration
storage
technology is
not
commercial
Biogas
potential is
uncertain
Carbon (MMT CO2)50 0 0 0 0
Annual Cost Delta ($B)Base $16-$28 $14-$21 $550-$990 $4 -$9
Additional Cost ($/MWh)Base $52-$89 $46-$69 $1,800-$3,200 $14 -$30Page 349 Avista Corp. 2020 Electric IRP Appendices
29
Renewable Land Use
2018 Installed Renewables
Technology Nameplate GW
Solar 1.6
NW Wind 5.3
MT Wind 0.6
WY Wind 1.2
Portland land area is 85k acres
Seattle land area is 56k acres
Oregon land area is 61,704k acres
Each point on the map indicates 200 MW.
Sites not to scale or indicative of site location.
Land use today ranges from
1.6 to 7.5x
the area of Portland and Seattle combined
Solar
Total
Land
Use
(thousand acres)
Wind -
Direct
Land
Use
(thousand acres)
Wind –
Total Land
Use
(thousand acres)
Today 12 19 223 –1,052
Page 350 Avista Corp. 2020 Electric IRP Appendices
30
Renewable Land Use
80% Reduction in 2050
Technology Nameplate GW
Solar 11
NW Wind 36
MT Wind 0
WY Wind 2
Solar
Total
Land Use
(thousand
acres)
Wind -
Direct
Land Use
(thousand
acres)
Wind -
Total
Land Use
(thousand
acres)
80%
Red
84 94 1,135 –
5,337
Portland land area is 85k acres
Seattle land area is 56k acres
Oregon land area is 61,704k acres
Each point on the map indicates 200 MW.
Sites not to scale or indicative of site location.
Land use in 80% Reduction case ranges from
8 to 37x
the area of Portland and Seattle combined
Page 351 Avista Corp. 2020 Electric IRP Appendices
31
Renewable Land Use
100% Reduction in 2050
Technology Nameplate GW
Solar 46
NW Wind 47
MT Wind 18
WY Wind 33
Portland land area is 85k acres
Seattle land area is 56k acres
Oregon land area is 61,704k acres
Solar
Total
Land Use
(thousand
acres)
Wind -
Direct
Land Use
(thousand
acres)
Wind -
Total
Land Use
(thousand
acres)
80%
Clean
84 94 1,135 –
5,337
100%
Red
361 241 2,913 –
13,701
Each point on the map indicates 200 MW.
Sites not to scale or indicative of site location.
Land use in 100% Reduction case ranges from
20 to 100x
the area of Portland and Seattle combined
Page 352 Avista Corp. 2020 Electric IRP Appendices
32
Wind ELCC varies widely by
location
Diverse
New MT/WY
New NW
Existing NW
Existing NW wind (mostly in Columbia Gorge)
provides very low capacity value due to strong
negative correlation with peak loads
New NW wind might have higher capacity value if
diverse resources can be developed
New MT/WY wind provides very high capacity value
due to strong winter winds that are positively
correlated to NW peak loads
Page 353 Avista Corp. 2020 Electric IRP Appendices
33
Effective capacity from wind, solar, storage, and demand response is limited
due to saturation effects
Diverse Wind (NW, MT, WY)Solar
6-Hr Storage Demand Response
ELCC = Effective Load Carrying Capability = firm
contribution to system peak load
Page 354 Avista Corp. 2020 Electric IRP Appendices
34
Value of Storage Duration
6-Hr Storage 12-Hr Storage
Storage Only
Storage + Diversity
Allocation
Storage Only
Storage + Diversity
Allocation
Increasing the duration of storage provides additional
ELCC capacity value, but there are still strong
diminishing returns even for storage up to a duration
of 12-hours
Page 355 Avista Corp. 2020 Electric IRP Appendices
KEY FINDINGS
Page 356 Avista Corp. 2020 Electric IRP Appendices
36
Key Findings (1 of 2)
1.It is possible to maintain Resource Adequacy for a deeply decarbonized Northwest
electricity grid, as long as sufficient firm capacity is available during periods of low
wind, solar and hydro production
o Natural gas generation is the most economic source of firm capacity, and adding new gas
capacity is not inconsistent with deep reductions in carbon emissions
o Wind, solar, demand response and short-duration energy storage can contribute but have
important limitations in their ability to meet Northwest Resource Adequacy needs
o Other potential low-carbon firm capacity solutions include (1) new nuclear generation,
(2) gas or coal generation with carbon capture and sequestration, (3) ultra-long duration
electricity storage, and (4) replacing conventional natural gas with carbon-neutral gas
2.It would be extremely costly and impractical to replace all carbon-emitting firm
generation capacity with solar, wind and storage, due to the very large quantities of
these resources that would be required
3.The Northwest is anticipated to need new capacity in the near-term in order to
maintain an acceptable level of Resource Adequacy after planned coal retirements
Page 357 Avista Corp. 2020 Electric IRP Appendices
37
Key Findings (2 of 2)
4.Current planning practices risk underinvestment in new capacity required to
ensure Resource Adequacy at acceptable levels
o Reliance on “market purchases” or “front office transactions” reduces the cost of
meeting Resource Adequacy needs on a regional basis by taking advantage of load and
resource diversity among utilities in the region
o However, because the region lacks a formal mechanism for counting physical firm
capacity, there is a risk that reliance on market transactions may result in double-
counting of available surplus generation capacity
o Capacity resources are not firm without a firm fuel supply; investment in fuel delivery
infrastructure may be required to ensure Resource Adequacy even under a deep
decarbonization trajectory
o The region might benefit from and should investigate a formal mechanism for sharing of
planning reserves on a regional basis, which may help ensure sufficient physical firm
capacity and reduce the quantity of capacity required to maintain Resource Adequacy
The results/findings in this analysis represent the Greater NW region
in aggregate, but results may differ for individual utilities
Page 358 Avista Corp. 2020 Electric IRP Appendices
Thank You!
Energy and Environmental Economics, Inc. (E3)
101 Montgomery Street, Suite 1600
San Francisco, CA 94104
Tel [phone]
Web http://www.ethree.com
Arne Olson, Senior Partner ([e-mail])
Zach Ming, Managing Consultant ([e-mail])
Page 359 Avista Corp. 2020 Electric IRP Appendices
39
This study utilizes E3’s Renewable
Energy Capacity Planning (RECAP) Model
Resource adequacy is a critical concern under
high renewable and decarbonized systems
•Renewable energy availability depends on the
weather
•Storage and Demand Response availability
depends on many factors
RECAP evaluates adequacy through time-
sequential simulations over thousands of
years of plausible load, renewable, hydro,
and stochastic forced outage conditions
•Captures thermal resource and transmission
forced outages
•Captures variable availability of renewables &
correlations to load
•Tracks hydro and storage state of charge
72°
Storage Hydro DR
RECAP calculates reliability
metrics for high renewable
systems:
•LOLP:Loss of Load Probability
•LOLE:Loss of Load Expectation
•EUE:Expected Unserved Energy
•ELCC:Effective Load-Carrying
Capability for hydro, wind, solar,
storage and DR
•PRM:Planning Reserve Margin
needed to meet specified LOLE
Information about E3’s RECAP model can be found here:
https://www.ethree.com/tools/recap-renewable-energy-capacity-planning-model/
Page 360 Avista Corp. 2020 Electric IRP Appendices
40
RECAP calculates a number of metrics
that are useful for resource planning
Annual Loss of Load Probability (aLOLP) (%):is the probability of a
shortfall (load plus reserves exceed generation) in a given year
Annual Loss of Load Expectation (LOLE) (hrs/yr):is total number of
hours in a year wherein load plus reserves exceeds generation
Annual Expected Unserved Energy (EUE) (MWh/yr):is the expected
unserved load plus reserves in MWh per year
Effective Load Carrying Capability (ELCC) (%):is the additional load met
by an incremental generator while maintaining the same level of system
reliability (used for dispatch-limited resources such as wind, solar,
storage and demand response)
Planning Reserve Margin (PRM) (%):is the resource margin above 1-in-
2-year peak load, in %, that is required in order to maintain acceptable
resource adequacy
Page 361 Avista Corp. 2020 Electric IRP Appendices
41
“ELCC” is used to determine effective capacity contribution from wind, solar,
storage and demand response
Effective load carrying capability (ELCC) is the quantity of ‘perfect
capacity’ that could be replaced or avoided with dispatch-limited
resources such as wind, solar, hydro, storage or demand response while
providing equivalent system reliability
The following slides present ELCC values calculated using the
2050 80% GHG Reduction Scenario as the baseline conditions
Original system
LOLE
LOLE improves
after wind/solar/
storage/DR
Reduction in perfect
capacity to return to
original system LOLE
= ELCC
Page 362 Avista Corp. 2020 Electric IRP Appendices
42
2030
Load (GW)
Peak Load (Pre-EE)50.0
Peak Load (Post-EE)47.0
PRM 12%
PRM 5.0
Total Load Requirement 52.0
Resources / Effective Capacity (GW)
Coal 8.0
Gas 20.0
Bio/Geo 0.6
Imports 2.0
Nuclear 1.0
DR 1.0
Nameplate
Capacity (GW)ELCC (%)Capacity
Factor (%)
Hydro 19.0 35.0 56%44%
Wind 0.6 7.1 9%26%
Solar 0.2 1.6 14%27%
Storage 0.0
Total Supply 52.0
2030 Load and Resource Balance
8 GW new
gas capacity
needed by
2030
Wind and solar contribute
little effective capacity
with ELCC* of 9% and 14%
*ELCC = Effective Load Carrying Capability =
firm contribution to system peak loadPage 363 Avista Corp. 2020 Electric IRP Appendices
43
2050
80%
Reduction
90%
Reduction
100%
Reduction
Load (GW)
Peak (Pre-EE)65 65 65
Peak (Post-EE)54 54 54
PRM (%)9%9%7%
PRM 5 5 4
Total Load
Requirement 59 59 57
Resources / Effective Capacity (GW)
Coal 0 0 0
Gas 24 20 0
Bio/Geo 0.6 0.6 0.6
Imports 2 2 0
Nuclear 1 1 1 Nameplate Capacity (GW)ELCC (%)Capacity Factor (%)
DR 1 1 1 80% Red.90% Red.100% Red.80% Red.90% Red.100% Red.80% Red.90% Red.100% Red.
Hydro 20 20 20 35 35 35 58%58%57%44%44%44%
Wind 7 11 21 38 48 96 19%22%22%35%36%37%
Solar 2.0 2.2 7.5 11 11 46 19%21%16%27%27%27%
Storage 1.6 1.8 5.8 2.2 4.4 29 71%41%20%N/A N/A N/A
Total Supply 59 59 57
2050 Load and Resource Balance
Wind ELCC* values are higher
than today due to significant
contribution from MT/WY wind
*ELCC = Effective Load Carrying Capability =
firm contribution to system peak loadPage 364 Avista Corp. 2020 Electric IRP Appendices
Attendees: TAC 3, Tuesday, April 16, 2019 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; James Gall, Avista; Leona Doege, Avista; Amber Gifford, Avista; Kurtis Kolnowski, AEG; Ken Walter, AEG; Brian Parker, 350.org; John Barber, Rockwood Retirement Community; Doug Howell, Sierra Club; Barry Kathrens, 350.org; Ryan Finesilver, Avista; Clint Kalich, Avista; Dave Van Hersett, Avista Customer; Matt Nykiel, Idaho Conservation League; Amy Wheeless, NW Energy Coalition; Michael
Eldred, Idaho Public Utilities Commission; Rachelle Farnsworth, Idaho Public Utilities Commission; Aimee Higby, Washington Utilities and Transportation Commission; Jennifer Snyder, Washington Utilities and Transportation Commission; Xin Shane, Avista; Terrence Browne, Avista; Scott Wilson, Avista; Damon Fisher, Avista; Tracy Rolstad, Avista; John Gross, Avista; Chris Zentz, National Grid; Eric Lee, 4Sight
Energy; and Garrett Brown, Avista.
Phone Participants:
Sarah Laycock, Washington State Attorney General’s Office plus two others; Mike
Starrett, Power Council; Nancy Esteb, NW Energy Coalition; and David Howarth,
National Grid Ventures.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista/Presenter responses are in italics,
and significant points raised by presenters that are not shown on the slides are also
included.

Introductions and TAC 2 Recap, John Lyons
Doug Howell: Request for studies, what has changed? Some studies, such as those
shutting down Colstrip at later dates, may no longer be necessary with the legislative
changes.
Matt Nykiel: Update on the RFP for wind and solar? Already included using information
from the recent RFP.
Dave Van Hersett: What is the length of the PPA for wind? 20 years with a confidential
price that we cannot make public. Lind Solar is also a 20-year PPA. The cost
assumption for new wind is in the low $30/MWh range and would roughly be the energy
portion of a customer bill.
Kathlyn Kinney: Is it cheaper than coal? Hard to compare old/new coal and the
attributes. Old coal is an existing sunk costs, lower costs to run, so can be cheaper for
an existing coal plant. Also, new coal plants cannot be built under Washington law.

Page 365 Avista Corp. 2020 Electric IRP Appendices
Regional Legislative Update, John Lyons
Dave Van Hersett: Cow power? Cow manure in a digester that counts as biomass
power.
1444 requires new electric water storage under the water heater provision.
Doug Howell: Coal-fired provision. 11 million tons of emissions makes me concerned
over resources being put into Colstrip. Provisions in the ownership contract not have to
pay for, and prolonging the life of the resource.
Dave Van Hersett: I prefer reliable resources that don’t raise my rates. Last 40 years
effect of forest fires. AVA vs. PSE.
Doug Howell: Cleanup costs Units 3 and 4 expected to be $780 million. Montana AG
superfund site which are often 2, 5 or 8 times more expensive to remediate than
expected.
Linda Faulkner Gervais: No matter where or how we will continue to discuss the capital
costs at Colstrip with the regulators.
Jennifer Snyder: Have you considered modeling the IRP out to 2045? Yes, we actually
look out 25 to 30 years, but have only shown 20 years in the IRP.
John Barber: The general thrust of Montana is opposite that of Washington. Yes.
SB 5116 also has a 2% cost cap for meeting the renewable portion of the law over 4-
year blocks to help with hydro variability.
Matt Nykiel: Is there an update on the coal contracts? Yes, the new mine owners that
took over after Westmoreland are honoring the contract through the end of 2019 and we
are working on a new contract.
Dave Van Hersett: What are in the [SB] 5116 rulemakings? Things such as the 2.5
discount rate for social cost of carbon.
Matt Nykiel: How prices might increase with coal contract? Are you using scenarios on
price for coal. We expect a new coal contract by the end of the year.

IRP Transmission Planning Studies, Tracy Rolstad
Doug Howell: [SB] 5116 transmission reliability? Experience of Federal rules are
relatively tight and give us the mechanisms to study it. State laws are a mix of resiliency
and reliability. They are probably not going to be more demanding than that table on
slide 9.
Dave Van Hersett: What is a non-wires solution? Perhaps a battery to discharge. Install
and operate series capacitors or reactors to increase power flow on lines or force power
Page 366 Avista Corp. 2020 Electric IRP Appendices
flow onto other lines to maximize utilization of existing transmission capacity. We want
to maximize existing infrastructure with these non-wires solutions.
Dave Van Hersett: What is the biggest battery? 100 MW in Australia, but it is still in
development.
James Gall: Battery duration is the challenge. Currently 4 hours, maybe up to 6 hours,
and we need 8 to 18 hours from a battery.
Location specific is the issue. Placement and duration.
Clint Kalich: Coordination – transformer sits there and performs as needed. Batteries –
is this a solution to many of our problems? $200 million versus a $2.5 million solution.
Novel idea, will it find a place where it performs well. The policy is up against the
technology. Give us enough money and we will make anything work.
Clint Kalich: Othello/Lind? About 800 MW in the queue in this area. There was about
2,000 MW in our RFP and a bunch if it was there.
Kathlyn Kinney: Looks to me like it makes smaller projects easier to build. In the past,
we have posted on Oasis here are the places where you can plug in certain amounts of
generation relatively cheap. Speculative developers can look at this and decide where
to go. Small numbers or really powerful parts of our system.
Jim Le Tellier: How does this work? We have to respect the queue and layer it on to
engage in queue management. On ramps/off ramps for a cluster study or look at it all
together instead of first come first served. Take or pay. Can sign a contract for
transmission.
Dave Van Hersett: What is RAS? Remedial action scheme. Only owner or developer of
generation agrees to be tripped for a line loss. Done all over the northwest. It saves the
need for a new transmission line. Not really at this time in the IRP process, but rotating
machines have bigger impacts of those in play in northwest for 40 years (non-wires
solution).
Doug Howell: Do you have to use it [RAS] often? It happens, but not often. BPA has
saved billions of dollars doing this.
Dave Van Hersett: Not your distribution, its transmission. How much of an addition to
transmission over the next 20 years? Good question. It depends on where it goes,
shaping intermittency. California’s load literally goes away during the day, but gets busy
at night. BC Hydro sells energy to California to cover the ramp up which could be a
challenge in the future. No empirical data yet, but very good modeling. Predictability is
quite a bit less now, it’s not your grandfather’s utility.
Jim Le Tellier: Fairly represent marginal cost for developers who pay those costs for us.
If another utility gets it, then they pay all or some of the network upgrades. The
lumpiness of these upgrades affords opportunities for others.
Page 367 Avista Corp. 2020 Electric IRP Appendices
James Gall: Small portion of costs relative to the grand scheme of things. Upfront costs
amortized over 50 years.
Dave Van Hersett: How does wind/solar affect the timing and different directions of our
transmission capability. It is behaving differently, but still operating. California is going to
become a net exporter and we will need to manage hydro differently.

Distribution Planning within the IRP, Damon Fisher
John Barber (Slide 5, August 10th, 106 degrees): Did load end higher than it began?
The day was hotter than the last and lines cut off by software.
Damon Fisher (Slide 8): Does the electric car load take away the ability to shift other
load at night?
John Barber: You said two Waikiki feeders serve Whitworth area. Rockwood is up there
too, when do batteries come in? That is in the middle of the most vulnerable area.
Jennifer Snyder: Do we look at one or more coordinated interventions targeted for
efficiency, whole package or by measure? Intend to look at a package. Feeder-by-
feeder, considering the costs of all solutions.
Dave Van Hersett: But the transmission guy said that batteries won’t work. Scale and
cost of problems being solved with batteries are different between distribution and
transmission.
Kathlyn Kinney: Curious if storage folks bear cost like Costco. We have an obligation to
serve where we credit them some of the cost of installation. Can’t really charge benefits
to the whole system.
Garrett Brown: Schedule 51 line extension tariffs for cost sharing that identifies all of the
components.
Slide #9: modest photovoltaic (rooftop solar) assumes 300 installs of 5 kW on feeder,
1.5 MW of solar per feeder.
Doug Howell (Slide 10): There doesn’t look to be any advantage to battery cost, is that
the full story? No, do we install a substation for $5 million or a $25 million battery with all
of the other benefits it provides? To who and when is the stated value happening? This
slide is what it looks like to the distribution system only.

Conservation Potential Assessment, AEG
James Gall: We have a need based on Grant’s load forecast. We want all resources to
compete at the same time so they are treated equally. Old way was back and forth
where errors could be made and could miss things mathematically.
Page 368 Avista Corp. 2020 Electric IRP Appendices
Jennifer Snyder: Every measure is individual against demand response and generation,
peak and energy level.
Clint Kalich: Customized avoided cost. May incentivize them based on cost, but that
doesn’t account for characteristics rather than lumping them together. Lowering risk
instead of iterating.
Barry Kathrens: Do we consider building codes with a solar requirement? No, we stick
to what is on the books. Why not? Would need to talk to the legislature, AEG could
supply some estimates. Energy efficiency is not as simple since there are real impacts
to the distribution system. Could try a scenario.
Doug Howell: What are TRC and UCT? Total Resource Cost is used in Washington and
Utility Cost Test is used in Idaho. UCT only looks at the portion of cost the utility bears,
so we don’t include customer benefits like saving water. More potential passes [for
programs] because of lower upfront costs.
Jennifer Snyder (Slide 8): everyone technical 100% (ramp rates with RTF).
Doug Howell: Look at doing a deep retrofit. That is the finance mechanism, so if cost
effective, we could do it. We are present valuing all of the benefits and costs. Bundling
all of the benefits.
Clint Kalich: Maybe we need to meet on this. Public vs. IOU, average low bundle, but a
lot of those programs wouldn’t fit.
PSE had a solicitation demonstration project [of a deep retrofit].
Jennifer Snyder: Achievement needs to stay cost effective at the portfolio level.
Doug Howell: Washington State study says we need deep efficiency and we are not
achieving that by missing the dynamic of how a building operates. This could be
encouraged with Avista financing – Housing Finance Corp.
Amy Wheeless: The whole building is not as well captured. The information is in there.
James Gall: We ignore how it [efficiency] is being funded. Incentives now, but loan
programs in the past.
Ryan Finesilver: We have a team of account executives that look at whole building
systems. This is based on more of a simple payback.
James Gall: We are doing something similar with the Catalyst Building
Doug Howell: Hope this is not outside of the IRP. This area is ripe for innovation.
James Gall: I think AEG is already doing this.
Curtis AEG: Possible to be done, but could do it with other studies.
Dave Van Hersett: Is this a government requirement?
Page 369 Avista Corp. 2020 Electric IRP Appendices
Amy Wheeless: There is a bill that would set large building, non-agriculture or industrial
– $75 million available if it passes.
Jennifer Snyder: TRC for ductless heat pumps. Did we include 2.5? Yes.
Amy Wheeless: Cold weather heat pumps? Yes, available, but they are five to 10 times
more expensive.
Slide 20. TRC goes negative. It doesn’t start at zero from a non-energy saving. Like not
paying to replace LEDs as often UCT never goes negative.
EISA – Energy Security Act of 2005. Next backstop in 2020 forces CFLs and LED is the
difference between 2019 and 2020. Standard practices will make LEDs the default.
Dave Van Hersett: Do we have data yet for pay for performance vs. estimated savings?
AEG Seattle City Light had this in the September GRAC meeting. We have some site
specific information, but didn’t have any numbers in mind. Third party EM&V.

Demand Response Potential Assessment, AEG
Doug Howell: On water heater, doesn’t 1444 require to be DR ready? Port required [on
the water heater] to be DR ready. The study does not capture this yet, since not in law
now.
Jennifer Snyder: What about energy efficiency and demand response overlapping
potential? Following the methodology of the Power Council, energy efficiency goes first.
John Barber: Does this shut off? Yes, but override and signup on insulated tank is
voluntary. Defer reheat until later.
Kurtis Kolnowski: 85% doesn’t apply to DR side, about 25%.
Amy Wheeless: Midwest utilities have been doing more DR when they don’t own
generation. Will even give a free water heater to customers when you agree to let them
control it.
Grant Forsyth (Slide 31): Behavioral – entirely up to the customer. Yes, suggestion.
Amy Wheeless: For the October BC event [natural gas transmission line rupture], did
you send out a gas event? Yes for Oregon. No for the electric side. It was a yes for PSE
for both.
Clint Kalich: What gap is third party contract filling in? Business program targeting
medium to large businesses, getting more energy efficiency since often dealing with a
facility measure with an intermediary.
Phone Participant: Similar impacts both ways, but more popular to have a third party.
We just pay for megawatts. Third party gets it [energy efficicency]. They can do more
Page 370 Avista Corp. 2020 Electric IRP Appendices
hand holding, more cost effective than a utility and have economies of scale doing the
programs with more than one utility.
James Gall: Large industrial customers are not on here, but we are doing back up
generation as non-spinning reserves similar to the PGE program.
Dave Van Hersett: Where does own electric generation fall? Based on our own study.
Would be used as a non-spinning reserve product that we would turn on if all hell
breaks loose.

Pullman Smart Grid Demonstration Project Review, Leona Doege
Dave Van Hersett: What was the population [of this pilot]? 75 installed out of 3,600
single family homes, but 57 to be called out in DR events.
Rachelle Farnsworth: So it was a yearlong program? It Ran from 2012 to August 2014.
Matt Nykiel: Were these only smart thermostat customers in Washington? No, both
Washington and Idaho. Idaho was added back after adding back gas programs.
Rachelle Farnsworth: Were there surveys of customers? Yes, we did a survey. Did you
notice offsets and would you do again? Very unlikely we would do this again, $400
payment for early participants. We used a local contractor who took two hours per
installation.
Grant Forsyth: Any analysis of age bias of who took meters? Early tech adopters, not
necessarily correlated with age.

E3 Study – Resource Adequacy in the Pacific Northwest, James Gall
This assumes the system operates as a single utility.
John Barber: Why not Nevada? It was a choice because at the time of the study, they
were voting on retail choice so they would have operated like California. They have
since voted this down.
Rachelle Farnsworth: Hydro? Same.
Barry Kathrens: Climate, should we assume to be more pessimistic? Assuming same
historical data using 80-year record. May change water shape and make it more volatile
with warming temperatures.
Dave Van Hersett (Slide 22): 2050 baseline is the load we have to meet. Yes.
Jennifer Snyder (Slide 25): So 60% in red can be achieved for little or no cost. Yes,
using the current trajectory for technology.
Page 371 Avista Corp. 2020 Electric IRP Appendices
Barry Kathrens: Using constant costs? No, using declining costs.
Dave Van Hersett: Generation and transmission only? Yes.
Jim Le Tellier: What does this compare to California?
AEG: High cost is about what we find in comparison to California.
James Gall: $2,200 to $4,000 to convert to an all-electric home.
Dave Van Hersett: What would drive me out? Cost. Converting all heating to natural gas
and everything else to electric may be a cheaper way to reduce emissions.
Clint Kalich (Slide 22): Interesting how economic. Societally, where should the dollars
be spent? It may be better spent in other areas.

Page 372 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Tuesday, August 6, 2019 Conference Room 130
Topic Time Staff
Introductions and TAC 3 Recap 9:00 Lyons

Washington SB 5116 and IRP Updates 9:10 Lyons Energy and Peak Load Forecast Update 9:30 Forsyth Natural Gas Price Forecast 11:00 Pardee
Lunch 12:00

Electric Price Forecast 1:00 Gall

Existing Resource Overview 2:00 Lyons

Final Resource Needs Assessment 3:00 Lyons Adjourn 4:00

Page 373 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 374 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next twenty years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2 Page 375 Avista Corp. 2020 Electric IRP Appendices
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 in all or some of the process
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3 Page 376 Avista Corp. 2020 Electric IRP Appendices
TAC #3 Recap –April 16, 2019
•Introductions and TAC 2 Recap, Lyons
•Regional Legislative Update, Lyons
•IRP Transmission Planning Studies, Rolstad
•Distribution Planning Within the IRP, Fisher
•Conservation Potential Assessment, AEG
•Demand Response Potential Assessment, AEG
•Pullman Smart Grid Demonstration Project, Doege
•E3 Study –Resource Adequacy in the Pacific Northwest, Gall
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-company/integrated-
resource-planning
4 Page 377 Avista Corp. 2020 Electric IRP Appendices
Today’s Agenda
9:00 –Introductions and TAC 3 Recap, Lyons
9:10 –Washington SB 5116 and IRP Updates, Lyons
9:30 –Energy and Peak Load Forecast Update, Forsyth
11:00 –Natural Gas Price Forecast, Pardee
Noon –Lunch
1:00 –Electric Price Forecast, Gall
2:00 –Existing Resource Overview, Lyons
3:00 –Final Resource Needs Assessment, Lyons
4:00 –Adjourn
5 Page 378 Avista Corp. 2020 Electric IRP Appendices
Future TAC Topics
•TAC 5: Tuesday, October 15, 2019
–Ancillary services and intermittent generation analysis
–Energy Imbalance Market analysis
–Review Preliminary PRS
–Market scenario results
–Preliminary Portfolio scenario results
•TAC 6: Tuesday, November 19, 2019
–Review of final PRS
–Market scenario results (continued)
–Final Portfolio scenario results
–Carbon cost abatement supply curves
–2020 IRP Action Items
6 Page 379 Avista Corp. 2020 Electric IRP Appendices
Washington SB 5116 and IRP Updates
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 380 Avista Corp. 2020 Electric IRP Appendices
Clean Energy Transformation Act (CETA)
•E2SSB 5116 Clean Energy Transformation Act (CETA)
•No coal serving Washington customers after 2025 or earlier
•Carbon neutrality beginning in 2030
–80% or greater clean energy requirement
–Alternate compliance options for up to 20%
–Penalties for non-compliance unless out of utility’s control or for reliability
–Four-year compliance periods beginning with 2030-33
•100% clean energy 2045
•2% incremental cost cap
•Many areas of additional rule making are required and discussed
later
2 Page 381 Avista Corp. 2020 Electric IRP Appendices
Other CETA Provisions
•A utility extending service to new customers through condemnation must comply with
the clean energy standard and Energy Independence Act (EIA)
•Utilities must assess and plan for obtaining enough funds to meet 60% of low-income
energy assistance need by 2030 and 90% by 2050
•By January 1, 2022, the company must begin filing four-year clean energy
implementation plans with the UTC
•Affirms the UTC authority to use alternative ratemaking mechanisms
•Clarifies the identification of used and useful property during a rate period for up to
four years
•Allows deferred accounting for up to three years for major projects in a utilities clean
energy action plan as part of its IRP
•Allows an imputed return on power purchase agreements of no less than the cost of
debt and no more than the authorized rate of return
•Includes federal incremental hydroelectricity in the definition of an eligible renewable
resource under the EIA
•Extends sales and use tax breaks for renewable resource until 2030 provided specific
labor standards are met
3 Page 382 Avista Corp. 2020 Electric IRP Appendices
CETA Rule Making
•WUTC opened Docket U-190485 for implementation of legislation passed in the 2019 legislative session
•Phase 0: July 1, 2019 to August 30, 2019
–Initiate rulemaking processes
–Docket U-190531: Inquiry into Valuation of Public Service Company Property Used and Useful after Rate Effective Date
–Timeline finalized after public comment
–Close IRP Rulemaking Docket No. U-161024, incorporate IRP procedural rules, RFP rules and Distributions System Planning in this docket
•Phase 1: August 2019 to January 1, 2021
–Results due by January 1, 2021
•Phase 2: Beginning January 1, 2021
–Results due on or before June 30, 2022
4 Page 383 Avista Corp. 2020 Electric IRP Appendices
Phase 1
•Publication of social cost of carbon with inflation rate
•Issue policy statement for Valuation of Public Service Company Property Used and Useful after Rate Effective Date (U-190531)
•Start four rulemakings and one policy statement
•IRP Updates
–IRP inputs, structure, public involvement process, outputs of Clean Energy Action Plans, social cost of carbon, equitable distribution of benefits, and assessment informed by cumulative impact analysis
•Used and useful standard policy statement
•EIA rulemaking
–Equitable distribution, definitions of low-income and energy assistance need, low-income efficiency target, and updated hydro eligibility and tracking
•Clean Energy Implementation Plan (CEIP) rulemaking
–Guidelines, equitable distribution of benefits, and incremental cost methodology
•Acquisition rulemaking
–Existing RFP work, ensure new standard met for construction and acquisition of property and the provision of electric service, and resource adequacy
5 Page 384 Avista Corp. 2020 Electric IRP Appendices
Phase 2 and Additional Projects
Start four rulemakings
1.Cumulative impact analysis
2.Carbon and electricity markets
3.Natural gas conservation
4.Natural gas IRP
Additional projects without statutory deadlines
•Interconnection standard
•Capital budgeting
•Distribution system planning
•Reliability and resiliency
•Demand response policy statement
•Pricing signals policy statement
•Pilot projects policy statement
•Rate making adequacy inquiry
6 Page 385 Avista Corp. 2020 Electric IRP Appendices
Load and Economic Forecasts: Redux
Grant D. Forsyth, Ph.D.
Chief Economist
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 386 Avista Corp. 2020 Electric IRP Appendices
Main Topic Areas
•Service Area Economy
•Peak Load Forecast
•Long-run Forecast
2 Painting: Jan Steen, 1640, Netherlands. As the Old Sing, Pipe the Young.Page 387 Avista Corp. 2020 Electric IRP Appendices
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3 Page 388 Avista Corp. 2020 Electric IRP Appendices
Distribution of Employment: Services and
Government are Dominant
Source: BLS, BEA and author’s calculations.4
Farm
2%
Private Goods
14%
Private Services
66%
Local
11% (61%)
State
4% (21%)
Federal
2%(9%)
Military
1%(8%)
Other
18%
WA-ID MSA Employment, 2018
Page 389 Avista Corp. 2020 Electric IRP Appendices
Non-Farm Employment Growth, 2009-2019
Source: BLS and author’s calculations.5
-6%
-4%
-2%
0%
2%
4%
6%
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Non-Farm Employment Growth Since June 2009
Avista WA-ID MSAs U.S.
Page 390 Avista Corp. 2020 Electric IRP Appendices
Non-Farm Employment: Finally Catching Up
Source: BLS and author’s calculations.6
90
95
100
105
110
115
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Non-Farm Employment Level Since 2007 (Dashed Shaded Box = Recession Period)
Avista WA-ID MSAs U.S.
Page 391 Avista Corp. 2020 Electric IRP Appendices
Population Growth: Recovering with
Employment Growth
Source: BEA, U.S. Census, and author’s calculations.7
1.9%
1.4%
1.2%
0.8%
0.5%0.5%
0.7%
1.0%
1.2%
1.7%
1.9%
1.8%
1.0%1.0%0.9%0.8%0.7%0.7%0.7%0.7%0.7%0.7%0.6%0.6%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
An
n
u
a
l

G
r
o
w
t
h
Population Growth in Avista WA-ID MSAs
Total Spokane+Kootenai+Nez Perce-Asotin, WA-ID MSA Pop. Growth U.S. Pop. Growth
Proxy for
Customer
Growth
Page 392 Avista Corp. 2020 Electric IRP Appendices
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8 Page 393 Avista Corp. 2020 Electric IRP Appendices
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial
loads.
•Based on monthly peak MW loads since 2004. The peak is pulled from hourly
load data for each day for each month.
•Explanatory variables include HDD-CDD and monthly and day-of-week dummy
variables. The level of real U.S. GDP is the primary economic driver in the
model—the higher GDP, the higher peak loads. Model was recently
recalibrated to allow GDP impact to differ between winter and summer.The
historical impacts of DSM programs are “trended” into the forecast.
•The coefficients of the model are used to generate a distribution of peak loads
by month based on historical max/min temperatures, holding GDP constant.
An expected peak load can then be calculated for the current year (e.g., 2019).
Model confirms Avista is a winter peaking utility for the forecast period;
however, the summer peak is growing at a faster than the winter peak.
•The model is also used to calculate the long-run growth rate of peak loads for
summer and winter using a forecast of GDP growth under the “ceteris paribus”
assumption for weather and other factors.
9 Page 394 Avista Corp. 2020 Electric IRP Appendices
GDP Growth Assumptions: 2019 IRP vs. 2017 IRP
10 Source: Various and author’s calculations.
2.5%
1.9%1.8%1.8%1.9%
2.1%2.1%2.1%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
2019 2020 2021 2022 2023
An
n
u
a
l

G
r
o
w
t
h
2019 GDP Growth 2017 GDP IRP Growth
Page 395 Avista Corp. 2020 Electric IRP Appendices
Current Peak Load Forecasts for Winter and
Summer, 2019-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
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
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2019-45
Winter 0.34%
Summer 0.44%
11 Page 396 Avista Corp. 2020 Electric IRP Appendices
Current and Past Peak Load Forecasts for
Winter Peak, 2011-2043
1,500
1,750
2,000
2,250
2,500
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
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
Me
g
a
w
a
t
t
s
Winter Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP
12 Page 397 Avista Corp. 2020 Electric IRP Appendices
Current and Past Peak Load Forecasts for
Summer Peak, 2011-2045
1,250
1,500
1,750
2,000
2,250
2,500
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
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
Me
g
a
w
a
t
t
s
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP13Page 398 Avista Corp. 2020 Electric IRP Appendices
Long-Term Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
14 Page 399 Avista Corp. 2020 Electric IRP Appendices
Basic Forecast Approach
2019
Time
2024 20452025
1)Monthly econometric model by
schedule for each class.2)Customer and UPC forecasts.
3)20-year moving average for “normal
weather.”4)Economic drivers: GDP, industrial
production, employment growth, population, price, natural gas
penetration, and ARIMA error
correction.5)Native load (energy) forecast derived
from retail load forecast.
1)Boot strap off medium term forecast.
2)Apply long-run load growth relationships to develop simulation model for high/low
scenarios.
3)Include different scenarios for renewable
penetration with controls for price elasticity,
EV/PHEVs, and natural gas penetration.
Medium Term Long Term
15 Page 400 Avista Corp. 2020 Electric IRP Appendices
The Long-Term Residential Relationship, 2020-
2040
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as
population growth, commercial
growth will follow residential,
and slow decline in industrial.
Assumed to be a function of
multiple factors including
renewable penetration, gas
penetration, and
EVs/PHEVs.
16 Page 401 Avista Corp. 2020 Electric IRP Appendices
Residential Customer Growth, 2020-2045
0.40%
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
20
2
0
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
Annual Residential Customer Growth Rates
2019 IRP Residential Customer Growth 2017 IRP Residential Customer Growth
Average annual growth rate from
2020-2045 = 0.78%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
Medium Term Long Term
17 Page 402 Avista Corp. 2020 Electric IRP Appendices
Residential Solar Penetration, 2008-2018
0.00%
0.05%
0.10%
0.15%
0.20%
0.25%
305,000 310,000 315,000 320,000 325,000 330,000 335,000 340,000 345,000
Sh
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e

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e
s
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Cu
s
t
o
m
e
r
s
Customers
Customer Penetration vs. Customers Since 2008
18
2008
2014
2015
2016
2017
2018
Page 403 Avista Corp. 2020 Electric IRP Appendices
Residential Solar Penetration, 2020-2045
19
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
20
2
0
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
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental Solar Customers
2017 IRP Base-Line Residential Solar Customers 2019 IRP Base-Line Residential Solar Customers
Current penetration is 0.25% and typical
size is 7,800 watts. By 2045, penetration
will be near 2.2% of residential customers
and average size of installed systems will
be 10,000+ watts.
Penetration was near 0.5% of
residential customers and average size
of installed systems was 6,000 watts.
Page 404 Avista Corp. 2020 Electric IRP Appendices
Residential EVs/PHEVs, 2020-2045
0
20,000
40,000
60,000
80,000
100,000
120,000
20
2
0
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
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2017 IRP Projected EV/PHEV 2019 IRP Projected EV/PHEV
Current ≈ 800
Forecast By 2045 Prob.
Low 45,000 50%
Middle 100,000 30%
High 250,000 20%
Weighted Average 103,000
20 Page 405 Avista Corp. 2020 Electric IRP Appendices
Residential EVs/PHEVs by Household Income
21 Source: EIA, Today in Energy, May 2018. Regional data from U.S. Census
Spokane +
Kootenai
12%Spokane +
Kootenai
7%
Page 406 Avista Corp. 2020 Electric IRP Appendices
EV/PHEV Gasoline CO2 Savings Avista
Service Territory
0
100,000
200,000
300,000
400,000
500,000
600,000
20
2
0
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
Estimated EV/PHEV Gasoline CO2 Reduction in Metric Tons
Estimated with DOE data. Assumes 5.18
metric tons of C02 per gasoline vehicle.
Savings = Number of EV/PHEV x 5.18
22 Page 407 Avista Corp. 2020 Electric IRP Appendices
Native Load Forecast, 2020-2045
900
950
1,000
1,050
1,100
1,150
1,200
1,250
20
2
0
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Native Load Forecast (no CWTR), Average Megawatts
2019 IRP Native Load Base-Line, No CWTR 2017 IRP Base-Line Native Load, No CWTR
2015 IRP Base-Line Native Load, No CWTR
Medium Term Long Term
23 Page 408 Avista Corp. 2020 Electric IRP Appendices
Net Solar and EV/PHEV Impact, 2020-2045
-5
0
5
10
15
20
25
30
35
40
20
2
0
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
aM
W
aMW Impact of Solar and EV/PHEV
2019 IRP Solar aMW (Load Reduction)2019 IRP EV/PHEV aMW (Load Addition)
2019 Net IRP Solar and EV/PHEV Impacts aMW
Long TermMedium Term
24 Page 409 Avista Corp. 2020 Electric IRP Appendices
Native Load Growth Forecast, 2020-2045
-0.2%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
20
2
0
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
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2019 IRP Base-Line Native Load Growth 2017 IRP Base-Line Native Load Growth25
EV/PHEV “Bend”
IRP Avg. Annual
Growth
2019 IRP 0.3%
2017 IRP 0.5%
Page 410 Avista Corp. 2020 Electric IRP Appendices
Residential UPC Growth: 2020-2045
26
-2.00%
-1.50%
-1.00%
-0.50%
0.00%
0.50%
1.00%
20
2
0
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
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth
2019 IRP Residential Base-Line UPC Growth
Page 411 Avista Corp. 2020 Electric IRP Appendices
Long-Term Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
27 Page 412 Avista Corp. 2020 Electric IRP Appendices
Monthly Conservation as a Share of Total
Actual Retail Load: Navigant Estimates
28
Ratio = 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑦𝑦𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑌𝑌
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
Ja
n
-
9
9
Au
g
-
9
9
Ma
r
-
0
0
Oc
t
-
0
0
Ma
y
-
0
1
De
c
-
0
1
Ju
l
-
0
2
Fe
b
-
0
3
Se
p
-
0
3
Ap
r
-
0
4
No
v
-
0
4
Ju
n
-
0
5
Ja
n
-
0
6
Au
g
-
0
6
Ma
r
-
0
7
Oc
t
-
0
7
Ma
y
-
0
8
De
c
-
0
8
Ju
l
-
0
9
Fe
b
-
1
0
Se
p
-
1
0
Ap
r
-
1
1
No
v
-
1
1
Ju
n
-
1
2
Ja
n
-
1
3
Au
g
-
1
3
Ma
r
-
1
4
Oc
t
-
1
4
Ma
y
-
1
5
De
c
-
1
5
Ju
l
-
1
6
Fe
b
-
1
7
Se
p
-
1
7
Ap
r
-
1
8
No
v
-
1
8
Ra
t
i
o

o
f

C
o
n
s
e
r
v
a
t
i
o
n

t
o

K
W
H

L
o
a
d

Energy Crisis
ARRA
Increased
Conservation
Activity
Page 413 Avista Corp. 2020 Electric IRP Appendices
Median Monthly Conservation as a Share of
Total Actual Retail Load: Navigant Estimates
29
Median Ratio Month t = Median𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸, excluding 2001
0.797%
0.693%
0.769%0.730%0.742%
0.816%0.856%
0.722%
0.661%
0.779%0.765%0.800%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Me
d
i
a
n

C
o
n
s
e
r
v
a
t
i
o
n

t
o

L
o
a
d

R
a
t
i
o
Page 414 Avista Corp. 2020 Electric IRP Appendices
Comparison of Native Load Forecasts, 2020-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
20
2
0
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
aM
W
aMW Load Comparision with Conservation
Base-Line Native Load Base-Line Native Load with Conservation Added Back30Page 415 Avista Corp. 2020 Electric IRP Appendices
Natural Gas
Tom Pardee, Manager of Natural Gas Planning
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 416 Avista Corp. 2020 Electric IRP Appendices
Agenda
•Market Dynamics
•Pipeline Transportation
•Renewable Natural Gas (RNG)
2
Page 417 Avista Corp. 2020 Electric IRP Appendices
3
Page 418 Avista Corp. 2020 Electric IRP Appendices
Canada
4
Page 419 Avista Corp. 2020 Electric IRP Appendices
Canada Natural Gas Production
Alberta 15
Bcf per day
British Columbia
0.5 Bcf per day
5
Page 420 Avista Corp. 2020 Electric IRP Appendices
300 Years of resources at current levels
6
Page 421 Avista Corp. 2020 Electric IRP Appendices
AECO cash vs. forwards
7
Page 422 Avista Corp. 2020 Electric IRP Appendices
Canadian Natural Gas Storage
8
Page 423 Avista Corp. 2020 Electric IRP Appendices
LNG Canada
Source: https://www.lngcanada.ca/about-lng-canada/
Daily liquefaction:
3.5 Bcf Or
1,025,749 MWh
9
Page 424 Avista Corp. 2020 Electric IRP Appendices
US
10
Page 425 Avista Corp. 2020 Electric IRP Appendices
US Natural Gas Production
11 Source: EIA
Page 426 Avista Corp. 2020 Electric IRP Appendices
80 Years of resources at current levels
12
Page 427 Avista Corp. 2020 Electric IRP Appendices
Henry Hub cash vs. forwards
13
Page 428 Avista Corp. 2020 Electric IRP Appendices
US Natural Gas Storage
14
Page 429 Avista Corp. 2020 Electric IRP Appendices
15
U.S. net exports of natural gas continue to grow in the
Reference case—
-14
-7
0
7
14
21
28
-5
0
5
10
2000 2010 2020 2030 2040 2050
Natural gas trade (Reference case)
trillion cubic feet
2018
history projections liquefied natural
gas (LNG)
exports
pipeline exports to
Mexico
Canada
pipeline imports
from
Canada
LNG imports
billion cubic feet per day
Source: EIA AEO 201915
Page 430 Avista Corp. 2020 Electric IRP Appendices
2020 IRP Henry Hub Natural Gas Price
Forecast: 2021-2040: $3.99 per Dth
16
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
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
$
p
e
r

D
t
h
Page 431 Avista Corp. 2020 Electric IRP Appendices
Pipeline Transportation
17
Page 432 Avista Corp. 2020 Electric IRP Appendices
Fugitive Emissions
•Unintended emissions from facilities or activities
(e.g., construction) that "could not reasonably
pass through a stack, chimney, vent, or other
functionally equivalent opening."
Fugitive emissions estimated at
0.783%
*This figure includes all
emissions from production,
transport & lost and
unaccounted for gas
Source –NEB for Canadian infrastructure and EIA for US infrastructure18
Page 433 Avista Corp. 2020 Electric IRP Appendices
GTN & NWP Fully Subscribed
•Contractually both pipelines are now fully
subscribed.
•Canadian producers signed up for new contracts in
order to get natural gas out of Canada and into
more lucrative markets.
GTN
NWP
19
Page 434 Avista Corp. 2020 Electric IRP Appendices
Avista Transport for Electric Generation
20
Page 435 Avista Corp. 2020 Electric IRP Appendices
AECO
Lancaster 49,000
Rathdrum 43,600
Boulder 5,400
98,000 DTh/Day*
Coyote Springs
53,550 DTh/Day*Stanfield
Malin
Pipeline Capacity
60,592 DTh/Day
Pipeline Capacity
26,388 DTh/Day
Current Transport & Gas Generation
* Based on the non-
coincidental winter peak-day
Boulder: 5,400
Coyote: 53,550
Lancaster: 49,000
Rathdrum: 43,600
Total: 151,550
Firm Rights: 60,592
Shortfall: 90,958
21
Page 436 Avista Corp. 2020 Electric IRP Appendices
Renewable Natural Gas (RNG)
22
Page 437 Avista Corp. 2020 Electric IRP Appendices
Source: Promoting RNG in WA State
23
RNG Process Overview
Page 438 Avista Corp. 2020 Electric IRP Appendices
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
Cedar HillsLandfill(KingCounty)
RooseveltLandfill(RepublicServices)KlickitatCountyPUD
SouthTreatmentPlant (KingCounty)PugetSoundEnergy
Landfills Wastewatertreatmentplants
Dairydigesters Municipalfood wastedigesters
Foodprocessingresiduals
Foodprocessedat compostfacilities
Landfills Wastewatertreatmentplants
Dairydigesters Municipalfood wastedigesters
Dth
Existing Projects
Near Term Projects
Medium Term Projects
24
Page 439 Avista Corp. 2020 Electric IRP Appendices
WA RNG Potential Bcf dth dth/day
Current 3.9 4,002,400 10,965
Near-Term 5.2 5,395,010 14,781
Mid-Term 5.6 5,729,010 15,696
Total 14.7 15,126,420 41,442
Avista Natural Gas Consumption
Avista Power Load 2018 23.4 24,114,712 66,068
Avista LDC Load 2018 33.4 34,456,500 94,401
Total Avista Consumption 58,571,212 160,469
Gas Consumption of CS2 50,000
North American Gas Reserves
Canadian Gas Reserves (300 years)1,828,891 1,885,586,517,900
U.S. Gas Reserves (80 years)2,459,000 2,535,229,000,000
Total NA Gas Reserves 4,287,891 4,420,815,517,900
WA RNG Potential Share of NA Gas Reserves 0.0003%
Renewable Natural Gas Comparison to Non-Renewable
Natural Gas Reserves
Page 440 Avista Corp. 2020 Electric IRP Appendices
Total Potential Annual Production = 32 Bcf
NREL Estimates –Idaho RNG
Source –Anaerobic
Landfills 3,712,221
Wastewater Treatment 6,196,531
Agriculture Manure 20,220,571
Source-Separated Organics (Solid Waste)2,311,354
Total 32,440,676
National Renewable Energy Laboratory, NREL Biofuels Atlas
26
Page 441 Avista Corp. 2020 Electric IRP Appendices
RNG $ per Dth/MMBtu
Source: Promoting RNG in WA State
Avista Owned and Operated
ID -WA
2035 Premium
Estimate ($ / Dth)
RNG -Landfills $7 -$10
RNG -Waste Water Treatment Plants (WWTP)$12 -$22
RNG -Agriculture Manure $28 -$53
RNG -Food Waste $29 -$53
27
Page 442 Avista Corp. 2020 Electric IRP Appendices
Page 443 Avista Corp. 2020 Electric IRP Appendices
2020 IRP Electric Market Price Forecast
James Gall, IRP Manager
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 444 Avista Corp. 2020 Electric IRP Appendices
Our Region
2 Source: NERC
Page 445 Avista Corp. 2020 Electric IRP Appendices
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Coal Geothermal Hydroelectric ConventionalNatural Gas Nuclear OtherOther Biomass Other Gases PetroleumPumped Storage Solar Thermal and Photovoltaic WindWood and Wood Derived Fuels
US Western Interconnect Generation
3 Source: EIA Data
Coal
Hydro
Natural Gas
Wind
Nuclear
Solar
Page 446 Avista Corp. 2020 Electric IRP Appendices
13
23 23
117
126
22
38 42
58
45
51
59
32 33
23 19
32 33
23 20 22
30 36
27 31 33 34
$0
$20
$40
$60
$80
$100
$120
$140
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
20
2
2
20
2
3
$
p
e
r

M
W
h
Mid-Columbia Flat Firm Price Index History
Energy Crisis
Natural Gas Market Tightens
Shale DevelopmentCheap Natural
Gas, good
hydro
Forwards
as of July
29, 2019
4 Page 447 Avista Corp. 2020 Electric IRP Appendices
2018 Fuel Mix Comparison (NW vs West)
US Western Interconnect Northwest Four States
5 Source: EIA Data
Page 448 Avista Corp. 2020 Electric IRP Appendices
Natural Gas vs. On-Peak Electric Prices
(2003-19)
6
$0
$10
$20
$30
$40
$50
$60
$70
$0 $2 $4 $6 $8 $10
Mi
d
-C
$

p
e
r

M
W
h
Stanfield $ per DTh
2018 & 2019
Page 449 Avista Corp. 2020 Electric IRP Appendices
Market Indicators
7
-$5
$0
$5
$10
$15
$20
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
St
a
n
f
i
e
l
d

x

7

-
Mi
d

C
Spark Spread
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
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
Po
w
e
r
/

G
a
s

x

1
0
0
0
Implied Market Heat Rate
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
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
$
p
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h
Daily Price Standard Deviation
Page 450 Avista Corp. 2020 Electric IRP Appendices
Western Greenhouse Gas Emissions Power Industry
Source: EPA
Adjusted for plants in the Western Interconnect system8
1980: 185 MMT
1990: 227 MMT
2008: 307 MMT
2017: 228 MMT
1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
WY 22 20 17 15 19 24 17 26 27 25 28 27 30 29 31 28 29 29 31 30 31 31 30 30 30 29 29 30 30 30 29 26 29 31 30 29 29 29
WA 8 8 6 7 7 8 5 8 9 9 7 8 10 10 12 8 11 9 12 11 14 14 12 14 14 14 10 12 13 13 13 7 6 12 12 11 9 10
UT 11 11 11 11 12 14 15 25 27 28 29 28 30 31 32 30 30 31 32 33 33 33 34 35 35 36 36 38 39 36 35 34 32 35 34 33 28 27
OR 1 2 1 1 1 1 - - - 1 2 4 4 4 5 3 3 3 6 6 7 9 7 8 8 8 6 10 10 9 10 6 7 9 8 9 8 7
NM 20 19 21 24 23 24 21 23 24 26 25 21 24 25 26 25 26 27 27 28 29 28 27 29 29 30 30 29 28 28 25 26 25 24 21 20 19 19
NV 11 13 14 13 15 12 16 15 18 17 17 18 19 18 20 18 20 19 21 22 25 24 21 23 25 26 17 17 18 18 17 15 15 15 16 14 14 12
MT 5 5 4 3 8 8 11 12 16 16 15 16 17 14 17 16 13 15 17 17 16 17 16 17 18 18 18 19 19 16 19 16 15 16 16 17 16 14
ID - - - - - - - - - - - - - - - - - 0 0 0 0 1 0 1 1 1 1 1 1 1 1 0 1 1 1 1 1 1
CO 21 23 24 23 25 27 26 27 28 30 31 30 31 32 33 32 34 34 35 36 39 41 40 40 40 41 42 43 41 38 40 39 39 39 38 37 37 36
CA 61 59 38 31 34 40 27 37 37 44 40 38 46 42 50 37 33 36 39 43 53 58 44 43 46 42 47 50 51 48 44 36 48 46 46 44 37 28
AZ 25 31 31 26 29 31 25 27 29 35 33 33 35 37 38 32 32 35 38 40 45 46 45 46 52 51 53 55 58 52 54 52 51 55 53 50 47 45
0
50
100
150
200
250
300
350
Mi
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Page 451 Avista Corp. 2020 Electric IRP Appendices
Northwest Greenhouse Gas Emissions
MT WA OR ID
9 Page 452 Avista Corp. 2020 Electric IRP Appendices
3rd party software-Aurora by Energy Exemplar
Electric market fundamentals-production cost
model
Simulates generation dispatch to meet load
Outputs:
–Market prices (electric & emission)
–Regional energy mix
–Transmission usage
–Greenhouse gas emissions
–Power plant margins, generation levels, fuel costs
–Avista’s variable power supply costs
Electric Market Modeling
10 Page 453 Avista Corp. 2020 Electric IRP Appendices
Stochastic Approach
Simulate Western Electric market hourly for next 25
years (2021-45)
–That is 175,248 hours for each study
Model 500 potential outcomes
–Variables include fuel prices, loads, wind, hydro, outages, and
inflation
–Simulating 87.6 million hours
Run time is about 14+ days on 20 processors
Why do we do this?
–Allows for complete financial evaluation of resource alternatives
–Without stochastic prices we cannot account for tail risk
11 Page 454 Avista Corp. 2020 Electric IRP Appendices
Modeled Western Interconnect Topology
12 Page 455 Avista Corp. 2020 Electric IRP Appendices
How Aurora derives hourly prices
Hydro (Must Run for Negative Pricing)
CCCT
Peakers
Demand
Hydro Availability
Fu
e
l

P
r
i
c
e
s
/
V
a
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i
a
b
l
e

O
&
M
Other Resource Availability
Nuclear/ Co-Gen/ Coal/ Other
Wind (Net PTC/REC)
Market Price
13 Note: minimum price is negative $25/ MWh (2018$)Page 456 Avista Corp. 2020 Electric IRP Appendices
Approach to New Resource Selection
•Baseline
–3rd party consultant new resource outlook
–known retirements
•Policy Constraints
–California, BC, and Alberta include CO2 price adder
–OR: Emissions Cap (3.6 million tons)
–WA: CETA: resources & social cost of carbon
–ID: Clean Power Plan Emission’s Intensity (delayed)
–No new coal-fired generation
–Uses existing state Renewable Portfolio Standards
•Resource Adequacy
–Achieve close to 1-in-20 loss of load probability (LOLP/LOLE)
Page 457 Avista Corp. 2020 Electric IRP Appendices
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Geothermal - - -90 70 24 76 104 52 104 26 104 26 104 26 104 26 104 76 114 86 124 96 134 140 156 160
Biomass - - -18 11 35 36 35 37 35 36 36 36 34 34 37 34 34 36 35 36 34 34 37 34 34 36
Hydro - - -182 40 19 23 30 29 25 29 30 28 40 31 36 39 58 51 56 54 51 58 56 56 56 58
Consumer Gen - - -3,092 357 367 378 390 402 414 427 439 452 466 480 494 510 525 541 557 574 592 610 628 647 667 687
Storage - - -1,267 551 659 667 587 480 480 331 671 660 748 795 849 897 941 1,050 1,308 1,358 1,500 1,600 1,598 1,600 1,601 1,600
Wind - - -3,522 445 419 215 640 846 896 993 1,070 1,095 1,070 1,462 1,236 1,450 1,632 2,078 3,145 4,127 3,308 3,399 4,576 3,510 5,656 3,294
Solar 3,400 3,400 3,400 6,102 3,915 4,304 3,676 3,582 3,195 3,082 4,313 5,029 1,662 2,562 3,778 3,834 3,539 3,320 2,240 3,367 2,583 7,705 4,168 3,985 5,079 5,052 8,910
NG Peaker 2,353 2,353 2,353 350 988 -880 1,422 -175 1,467 350 350 - - -1,230 175 440 175 587 412 237 400 175 1,111 1,659
NG CCCT 371 371 371 1,200 1,200 800 400 800 429 -400 1,200 300 400 829 -829 829 400 1,200 800 2,516 3,403 1,716 2,574 2,945 3,403
-
5,000
10,000
15,000
20,000
25,000
Me
g
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o
f

C
a
p
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y
New Resources Forecast-US West
Natural Gas: 49 GW
Wind: 50 GW
Solar: 110 GW
Storage: 24 GW
Customer: 15 GW
Other: 4 GW
15
Note 1: 2019-2021 additions are spread evenly between the 3 years,
these are all added in 2021 for modeling purposes
Note 2: Storage is assumed to be a blend of technologies, average of 3
hours duration in 2021, ramping to 6 hours average duration by 2045
DRAFT
Page 458 Avista Corp. 2020 Electric IRP Appendices
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Geothermal 19 19 19 -24 26 54 26 54 26 54 26 54 26 54 26 54 26 54 26 54 26 54 60 66 70 72
Biomass - - -11 11 10 11 11 11 10 12 10 10 10 11 10 10 10 11 10 10 10 11 10 10 10 11
Hydro 58 58 58 31 11 13 13 14 12 13 13 14 16 15 15 18 19 19 19 18 19 19 19 18 19 19 18
Consumer Gen 36 36 36 11 11 12 12 13 13 14 14 14 15 15 16 17 17 18 19 19 20 21 22 23 23 25 26
Storage - - -42 86 85 86 51 51 52 52 51 50 52 60 60 60 116 213 215 214 214 213 214 213 214 214
Wind 219 219 219 70 69 4 231 337 408 439 454 462 358 270 200 199 379 537 408 619 1,100 732 1,692 772 874 1,280 898
Solar 362 362 362 501 694 77 966 2,169 2,167 678 719 2,863 167 1,345 1,680 1,081 528 869 310 853 254 3,555 643 305 361 618 3,105
NG Peaker - - - - - -880 - - -880 175 - - - -880 -440 - - - - - - - -
NG CCCT - - - - - - - - - -400 400 300 - - - - - - - - - - -429 400 -
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Me
g
a
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a
t
t
s

o
f

C
a
p
a
c
i
t
y
New Resources Forecast-Northwest States
Natural Gas: 5 GW
Wind: 13 GWSolar: 27 GW
Storage: 3 GW
Customer: 0.5 GW
Other: 2 GW
16
Note 1: 2019-2021 additions are spread evenly between the 3 years,
these are all added in 2021 for modeling purposes
Note 2: Storage is assumed to be a blend of technologies, average of 3
hours duration in 2021, ramping to 6 hours average duration by 2045
DRAFT
Page 459 Avista Corp. 2020 Electric IRP Appendices
Resource Type Mix Forecast
(US Western Interconnect)
17
DRAFT
Fuel Type 2045 minus 2018aGW
Natural Gas -14.7
Hydro +1.4
Solar +28.7
Wind +14.9
Other +0.9
Coal -13.2
Nuclear -4.1
-
20,000
40,000
60,000
80,000
100,000
120,000
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
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
Av
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Page 460 Avista Corp. 2020 Electric IRP Appendices
Resource Type Mix Forecast
(NW States)
18
DRAFT
Fuel Type 2045 minus 2018aGW
Natural Gas -2.8
Hydro*-1.1
Solar +2.8
Wind +3.6
Other +0.7
Coal --1.9
Nuclear -1.1
Note: Hydro change is due to actual hydro vs. average hydro
-
5,000
10,000
15,000
20,000
25,000
30,000
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
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
Av
e
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a
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e

M
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s
Page 461 Avista Corp. 2020 Electric IRP Appendices
Stanfield Natural Gas Price Forecast
20-year levelized price: $3.98/Dth
25-year levelized price: $4.66/Dth
Note: Coefficient of variation (stdev/mean) in 2021 is 13%, in 2040, the volatility increases to 32%19
DRAFT
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
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
$
p
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D
e
k
a
t
h
e
r
m
Page 462 Avista Corp. 2020 Electric IRP Appendices
Mid-Columbia Electric Price Forecast
(Deterministic)
20
DRAFT
Levelized Prices
20 year 25 year
Flat: $25.03/MWh $26.06/MWh
On Peak: $25.07/MWh $25.92/MWh
Off Peak: $24.99/MWh $26.25/MWh
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
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
$
p
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Page 463 Avista Corp. 2020 Electric IRP Appendices
Mid-Columbia Electric Price Forecast
(Stochastic Flat Price Statistics)
Note: Coefficient of variation (stdev/mean) in 2021 is 28%, in 2040, the volatility increases to 42%21
DRAFT
20yr Levelized: $26.39 per MWh, 25 yr Levelized: $27.79 per MWh
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
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
$
p
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Page 464 Avista Corp. 2020 Electric IRP Appendices
Historical IRP Price Forecasts
(Annual Flat Prices)
22
DRAFT
Note: * Represents IRP forecast expected cases without carbon “taxes” in plant dispatch
$
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Page 465 Avista Corp. 2020 Electric IRP Appendices
Hourly Price Shape
23
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
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Hour
2025 Mid Columbia Average Prices-Avg: $22.83
Page 466 Avista Corp. 2020 Electric IRP Appendices
Hourly Price Shape
24
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
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W
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Hour
2030 Mid Columbia Average Prices-Avg: $25.17
Page 467 Avista Corp. 2020 Electric IRP Appendices
Hourly Price Shape
25
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
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M
W
h
Hour
2035 Mid Columbia Average Prices-Avg: $31.44
Page 468 Avista Corp. 2020 Electric IRP Appendices
Hourly Price Shape
26
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
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M
W
h
Hour
2040 Mid Columbia Average Prices-Avg: $33.70
Page 469 Avista Corp. 2020 Electric IRP Appendices
Hourly Price Shape
27
DRAFT
-$50
$0
$50
$100
$150
$200
$250
$300
$350
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
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M
W
h
Hour
2045 Mid Columbia Average Prices-Avg: $40.00
Page 470 Avista Corp. 2020 Electric IRP Appendices
0%
5%
10%
15%
20%
25%
30%
35%
40%
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
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Wind: Deterministic Solar: Deterministic
Wind: Stochastic Solar: Stochastic
Renewable Curtailments
2030: 0% to 5% curtailment
2045: 14% to 17% curtailment
2030: 4% to 9% curtailment
2045: 10% to 32% curtailment
Note: Both wind and solar use a -$8.00/MWh + inflation variable charge + PTC if available Page 471 Avista Corp. 2020 Electric IRP Appendices
Greenhouse Gas Emissions Forecast
(US Western Interconnect Total)
29
DRAFT
Mi
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Page 472 Avista Corp. 2020 Electric IRP Appendices
Greenhouse Gas Emissions Forecast
(Northwest-WA,OR,ID,MT)
30
DRAFT
-
5
10
15
20
25
30
35
40
45
19
8
0
19
8
2
19
8
4
19
8
6
19
8
8
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
20
3
2
20
3
4
20
3
6
20
3
8
20
4
0
20
4
2
20
4
4
Mi
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Page 473 Avista Corp. 2020 Electric IRP Appendices
-
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
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
LO
L
H
LO
L
P
Regional Resource Adequacy
31 Resource adequacy results are not detailed enough to judge regional resource
adequacy and are used for price forecasting only
2021 EUE:
392 MWh
2030 EUE:
51 MWh
2040 EUE:
743 MWh
DRAFT
Page 474 Avista Corp. 2020 Electric IRP Appendices
Electric Price Forecast Scenarios
•Social Cost of Carbon in Dispatch
•No CETA resource build
•Low Natural Gas Prices
•High Natural Gas Prices
32 Page 475 Avista Corp. 2020 Electric IRP Appendices
Social Cost of Carbon Price Forecast
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
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
$
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o
n
2007 $Nominal
Note: Inflation from 2007 uses CPI between 2007 and 2018, then 2% per year33Page 476 Avista Corp. 2020 Electric IRP Appendices
Scenario Price Forecast Results
Expected Case- Deterministic Scenario: No CETA
Scenario: SCC Scenario: Low NG Prices
Scenario: High NG Prices
34
DRAFT
Page 477 Avista Corp. 2020 Electric IRP Appendices
Scenario Levelized Prices
$26.06 $27.32
$45.71
$18.27
$36.10
$28.74 $30.12
$50.41
$20.15
$39.81
$0
$10
$20
$30
$40
$50
$60
Expected Case-
Deterministic
Scenario: No CETA Scenario: SCC Scenario: Low NG
Prices
Scenario: High NG
Prices
$
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M
W
h
20 yr 25 yr
35
DRAFT
Page 478 Avista Corp. 2020 Electric IRP Appendices
US Western Interconnect
Generation Mix Forecast by Scenario
(2040)
Expected Case-Deterministic Scenario: No CETA Scenario: SCC Scenario: Low NGPrices Scenario: High NGPrices
Natural Gas 13.0 13.5 7.7 13.9 12.9
Solar 28.9 28.1 27.9 28.8 28.9
Wind 16.7 16.7 28.3 16.6 16.7
Nuclear 4.2 4.2 4.0 4.2 4.2
Coal 5.9 6.0 1.6 5.2 6.1
Hydro 21.7 21.7 21.7 21.7 21.7
Other 4.4 4.4 3.4 4.4 4.3
-
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
36
DRAFT
Page 479 Avista Corp. 2020 Electric IRP Appendices
GHG Emission Forecast
US Western Interconnect
Expected Case- Deterministic
Scenario: No CETA
Scenario: SCC
Scenario: Low NG Prices
Scenario: High NG Prices
Northwest
Expected Case- Deterministic
Scenario: No CETA
Scenario: SCC
Scenario: Low NG Prices
Scenario: High NG Prices
37
DRAFT
Page 480 Avista Corp. 2020 Electric IRP Appendices
Colstrip Dispatch
38
Ca
p
a
c
i
t
y

F
a
c
t
o
r
DRAFT
Page 481 Avista Corp. 2020 Electric IRP Appendices
Existing Thermal Resource Overview
Darrell Soyars, Manager of Corporate Environmental Compliance
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 482 Avista Corp. 2020 Electric IRP Appendices
Purpose
•Review major environmental regulatory programs that may impact
current and future operations
•This is not intended to be a discussion or debate about past
practices or current approach to achieve compliance with these
programs
•Questions are welcome within the scope of this presentation
Page 483 Avista Corp. 2020 Electric IRP Appendices
Colstrip Environmental Considerations
3
Page 484 Avista Corp. 2020 Electric IRP Appendices
Colstrip Ownership Information
4
Colstrip Basic Data Colstrip Ownership Percentages
Colstrip
Unit #
Size
(MW)
Year
Online
Avista NorthWestern
Energy, LLC
PacifiCorp Portland
General
Electric
Talen
Energy,
LLC
Puget
Sound
Energy
Unit #1 333 1975 0%0%0%0%50%50%
Unit #2 333 1976 0%0%0%0%50%50%
Unit #3 805 1984 15%0%10%20%30%25%
Unit #4 805 1986 15%30%10%20%0%25%
Total 2,094 11%11%7%14%25%32%
•Generating Units 1 and 2: 333 MW each scheduled to shut down end of
2019, required to shut down by July 2022
•Generating Units 3 and 4: 805 MW each
•Assumed to operate until 2040, depreciation varies by owner
•Will not be serving Washington loads after 2025
Page 485 Avista Corp. 2020 Electric IRP Appendices
Air Quality –Montana Mercury Rule
•Program established 2010, mercury site-wide annual average below
0.9 lb/Tbtu
•Colstrip installed mercury oxidizer/sorbent injection system in 2010
•MDEQ recently concurred with our pollution equipment technology
review
•Units 3 & 4 operate in the 0.8 lb/Tbtu range
•No major changes expected
Page 486 Avista Corp. 2020 Electric IRP Appendices
Air Quality –Mercury Air Toxics Rule
Mercury Air Toxics (MATS) Rule:
•Program established 2016
•Particulate Matter (PM) used as a surrogate for air toxics
•PM site-wide 30-day rolling average below 0.030 lb/MMBtu
•PM and mercury are controlled by existing wet scrubbing equipment with injection
•Units 3 & 4 typically operate in the 0.024 lb/MMBtu range
•Both units exceeded permit limitations during second quarter testing in June 2018
•Root cause analysis led to corrective actions; reachieved compliance in September 2018
•Expect MDEQ penalty for emissions exceedances
•No major changes expected
Page 487 Avista Corp. 2020 Electric IRP Appendices
Air Quality –Regional Haze Rule
•Program established 1999, Improve visibility in Class 1 areas
•Federal plan for Montana was vacated by courts in 2015
•NOx is controlled by LoNOx burners, Overfire air and Smartburn
•MDEQ issued progress plan in 2017, now ready to take leadership of
program
•Request for Colstrip analysis due in late 2019 for next planning period
•Regional unit shutdowns would indicate that emissions are below glide
path
•No changes or additional pollution controls expected
Page 488 Avista Corp. 2020 Electric IRP Appendices
Air Quality
•Affordable Clean Energy (ACE) Rule
–Program established 9/16/19, replacement for Clean Power Plan (CPP)
•Reduce CO2 emissions by Heat Rate Improvements (HRI)
•MDEQ will determine future limitations based on evaluation of HRI technologies
•Cost and remaining useful life consideration
•MDEQ must submit plan by July 2022, unit compliance by 2024
•Impacts are unknown at this time
Page 489 Avista Corp. 2020 Electric IRP Appendices
Water Use
•Raw water is withdrawn from the Yellowstone River to Castle Rock Lake (a.k.a., the Surge Pond) via a 29-mile long pipeline.
•From the Surge Pond, water is piped to holding tanks at the Plant Site for use in boilers, cooling towers and scrubber systems.
•Fly ash from the scrubber system is transported to paste plants which remove excess water and deposit paste in disposal cells.
•Bottom ash is transported to holding ponds, dewatered, and then transported to disposal cells for evaporation.
•Clearwater from paste plants and dewatering is recirculated for reuse.
•All water is reused or lost through evaporation -Zero discharge facility.
Page 490 Avista Corp. 2020 Electric IRP Appendices
Three Storage Areas
–The Plant Site contains Generating Units 1 through 4 and several associated ponds (Avista share)
–The Units 3 & 4 EHP contains several ponds for the disposal of fly ash scrubber slurry/paste from Generating Units 3 and 4, and bottom ash from Generating Units 1 through 4, and is located approximately 2.5 miles southeast of the Plant Site. (Avista share)
–The Units 1 & 2 SOEP/STEP contains several ponds for the disposal of fly ash scrubber slurry/paste from Generating Units 1 and 2, and is located approximately 2 miles northwest of the Plant Site. (No Avista share)
Page 491 Avista Corp. 2020 Electric IRP Appendices
Page 492 Avista Corp. 2020 Electric IRP Appendices
Management Drivers
•Regulatory programs
–The Site Certificate originally issued including the amended 12(d) stipulation under the Major Facility Siting Act in Montana, Nov. 1975.
–Administrative Order on Consent (AOC) Regarding Impacts Related to Wastewater Facilities, MDEQ (July 2012), Settlement agreement entered (2016).
–Federal Coal Combustion Residual (CCR) Rule, 40 Code of Federal Regulations (CFR), April 2015.
•Operational facility
–Units 1 and 2 announced early shutdown at the end of 2019.
–Units 3 and 4 must maintain on-going operations
–Convert to dry ash storage by the end of 2022.
Page 493 Avista Corp. 2020 Electric IRP Appendices
Strategic Water Planning
•Master Plan originally developed in November 2015, Executive
Summary (Sept. 2016) is available on MDEQ-AOC website:
•http://deq.mt.gov/DEQAdmin/mfs/ColstripSteamElectricStation
•AOC public process will select actions to be performed and requires
Financial Assurance (FA) of approved plan amounts.
•AOC Process>Site Characterization>Cleanup Criteria and Risk
Assessment>Remedy Evaluation>Implement the selected remediation
•CCR Requirements tracking:
•https://www.talenenergy.com/generation/fossil-fuels/ccr-colstrip
Page 494 Avista Corp. 2020 Electric IRP Appendices
Plant Site Ponds
14
Page 495 Avista Corp. 2020 Electric IRP Appendices
Colstrip Units 3 & 4 Evaporative Ponds
15
Page 496 Avista Corp. 2020 Electric IRP Appendices
Major Water Activities
•Must remove Boron, Chloride and Sulfate in groundwater
•Achieve source control
–Close existing ash storage ponds
–Build water treatment system
–Dry ash storage
•Install and operate groundwater treatment system
•Achieve clean-up criteria
•Must take place regardless of plant operation
Page 497 Avista Corp. 2020 Electric IRP Appendices
Avista’s Financial Assurance Share
•Plant Site area
–Remedy Plan –$5,841,000 posted 12/21/18
–Closure Plan –$383,713 posted 2/1/19
•Units 3 & 4
–Remedy Plan –currently under review, expected late 2019
–Closure Plan – $6,793,050 posted 2/1/19
•Annual bond reconciliation required
Page 498 Avista Corp. 2020 Electric IRP Appendices
Colstrip Fuel Contract
•Coal supplier has emerged from bankruptcy and agreed to honor the current
contract, which ends 12/31/19
•New contract is being negotiated and results will be used to model Colstrip in
this IRP
Page 499 Avista Corp. 2020 Electric IRP Appendices
Modeled Colstrip Costs
19
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Fixed O&M 10.3 9.4 9.7 10.1 11.2
Coal Combustion Residuals O&M 0.4 0.6 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9
Existing Capital Revenue Requirement –WA 12.1 11.3 10.5 9.8 9.1 0.4
Existing Capital Revenue Requirement –ID 5.9 5.5 5.1 4.8 4.5 4.2 3.9 0.2
Traditional Capital Spending (Expensed)9.4 3.2 4.2 9.5 6.4
Asset Retirement Obligation Capital Revenue Requirement 1.7 1.7 1.6 1.6 1.5 1.5 1.4 1.4 1.3 1.3
Coal Combustion Residuals
Master Plan Capital Revenue Requirement 0.5 0.6 0.9 1.1 1.1 1.0 1.0 1.0 0.9 0.9
Total 40.3 32.3 32.9 37.8 34.7 8.0 7.2 3.5 3.1 3.1
Table does not include fuel and variable O&M costs
Coal Combustion Residuals O&M and Master Plan Capital Revenue Requirement, and Asset Retirement
Obligation Capital Revenue Requirement continue through 2045
Page 500 Avista Corp. 2020 Electric IRP Appendices
Lancaster Power Purchase Agreement
•Current PPA ends in October 2026
•Directly connect to either AVA or BPA transmission system
•Avista controls firm GTN transportation rights
•This IRP will evaluate an extension of this contract
Page 501 Avista Corp. 2020 Electric IRP Appendices
Thermal Plant Book Value and Remaining Depreciation
21
Thermal Plant Book Value
(millions)
Remaining Life
(years)
Boulder Park $ 17.4 20
Colstrip Units 3 and 4 $ 121.4 See Note
Coyote Springs 2 $ 124.8 21
Kettle Falls CT $ 3.7 24
Northeast $ 0.6 <2
Rathdrum $ 36.5 14
•This table includes land, total generation and transmission/interconnection
•Remaining life is for the generation, transmission may differ
•Numbers are from the end of 2018 and may change as pieces depreciate or new capital is added
•Colstrip modeling will use a 2025 for Washington and 2027 for Idaho
Page 502 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
Final Resource Need Assessment
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Page 503 Avista Corp. 2020 Electric IRP Appendices
Agenda
•2020 IRP Load & Resource Balance
•Avista’s Clean Energy Goals
•Energy Independence Act Renewable
Requirement Forecast
•Clean Energy Transformation Act Forecast
Page 504 Avista Corp. 2020 Electric IRP Appendices
Load & Resource Methodology Review
•Sum resource capabilities against loads
•Resource plans are subject to 5% LOLP analysis –
determines planning margins
•Capacity
–Planning Margin (14% Winter, 7% Summer)
–Operating Reserves and Regulation (~8%)
–Reduced by planned outages for maintenance
–Plant to largest deficit months between 1-and 18-hour analyses
•Energy
–Reduced by planned and forced outages
–Maximum potential thermal generation over the year
–80-year hydro average, adjusted down to 10th percentile
3 Page 505 Avista Corp. 2020 Electric IRP Appendices
One Hour Peak Load & Resource Position
4
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
0
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
Me
g
a
w
a
t
t
s
Page 506 Avista Corp. 2020 Electric IRP Appendices
18-Hour Sustained Peak L&R
5
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
0
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
Me
g
a
w
a
t
t
s
Page 507 Avista Corp. 2020 Electric IRP Appendices
1,000
1,200
1,400
1,600
1,800
2,000
2,200
-20 0 20 40 60 80 100
Me
g
a
w
a
t
t
s
Average Daily Temperature (Degree's Fehrenheit)
Load Variability (Temperature Variation)
Winter
Plan: 10
Degrees Summer
Plan: 80
Degrees
Winter Summer
90th Percentile 1,881 1,710
Mean 1,718 1,627
10th Percentile 1,565 1,542
90th -Mean 163 83
241 MW Planning
Margin @ 14%114 MW Planning
Margin @ 7%
6 Page 508 Avista Corp. 2020 Electric IRP Appendices
Energy Load & Resource Position
7
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
0
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
Me
g
a
w
a
t
t
s
Page 509 Avista Corp. 2020 Electric IRP Appendices
Avista’s Clean Energy Goal
2027 –100% carbon-neutral
2045 –100% clean electricity
How we will get there
Goals
It’s not just about generation –various solutions are necessary
Maintain focus on reliability and affordability
Natural gas plays an important part of a clean energy future
Cost effective technologies need to emerge and mature
8 Page 510 Avista Corp. 2020 Electric IRP Appendices
Avista Corporate Clean Energy Goals
9 Page 511 Avista Corp. 2020 Electric IRP Appendices
Washington State Clean Energy Goals
•Energy Independence Act or Initiative 937
–15% of Washington retail load after 2020
–Qualifying resources less any forward sales obligations
–Banking provisions mitigate year-to-year variation
–Addition of qualifying BPA and Wanapum, which are not included
in the chart. Will update when amounts are known.
•Clean Energy Transformation Act
10 Page 512 Avista Corp. 2020 Electric IRP Appendices
Washington Energy Independence Act
11
-
20
40
60
80
100
120
140
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
Wind Solar Wood EIA Goal
Page 513 Avista Corp. 2020 Electric IRP Appendices
Avista’s Washington CETA Goals
12 Page 514 Avista Corp. 2020 Electric IRP Appendices
Attendees: TAC 4, Tuesday, August 6, 2019 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Thomas Dempsey, Avista; Steve Johnson, Washington UTC; Brian
Parker, 350.org; Barry Kathrens, 350.org; Gerry Snow, Pacific Energy Research Associates; Michael Eldred, Idaho Public Utilities Commission; Terrence Browne, Avista; Greg Rahn, Avista; Ryan Ericksen, Avista; Mike Dillon, Avista; Ryan Finesilver, Avista; Jared Akins, Avista; Tom Pardee, Avista; Garrett Brown, Avista; Jaime Majure,
Avista; Clint Kalich, Avista; Scott Kinney, Avista; Jennifer Snyder, Washington Utilities
and Transportation Commission; Chris Zentz, National Grid; Kevin Davis, Inland Empire Paper; John Barber, Rockwood Retirement Communities; Dave Van Hersett, Residential Customer; Steve Wenke, Avista; Dennis Cakert, National Hydropower Association; Jose Phillips Rangel, Avista; Annie Gannon, Avista; and James Gall,
Avista.
Phone Participants:
Kevin Keyt, Idaho Public Utilities Commission; Idaho Office of Energy; Shelby Herber,
Idaho Conservation League; Tina Jayaweera, Northwest Power and Conservation
Council ; Mike Starrett, Northwest Power and Conservation Council; Fred Heutte,
Northwest Energy Coalition, and others who did not identify themselves.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses are in italics, and
significant points raised by presenters that are not shown on the slides are also
included.

Introductions and TAC 3 Recap and Washington SB 5116 and IRP Updates, John
Lyons
Steve Johnson: Is this the specific avoided cost for peak summer hours. Yes, avoided
cost of energy and capacity or summer; i.e., $1 per kWh month.
Clint Kalich: PRiSM technology allows us to calculate capacity values.
Steve Johnson: As we dispatch gas less, per unit increases so capacity value becomes
more. Attract more developers to the Northwest by showing them a price.
James Gall: Duration problem, 6-hour vs. 2-hour peak contribution.
Steve Johnson: Hours and frequency.
Clint Kalich: Disincent new energy and incent capacity.
Jennifer Snyder: Really like to see an actual target in Demand Response (DR) in this
IRP. James Gall: We expect this, but things that provide energy and capacity might
push DR out.

Page 515 Avista Corp. 2020 Electric IRP Appendices
Energy and Peak Load Forecast Update, Grant Forsyth
Dave Van Hersett: Is slide #6 a percentage scale. Yes, now 8-9% above where we were
in 2007.
Steve Johnson: Does the model capture recession events? Not really, timing is difficult
and we haven’t really beat the business cycle.
Steve Johnson: Load forecasts have consistently been high. Action Item to keep in mind
is to be responsive to economic downturns. Not saying that you need to change models,
but consider the impact of these actions. I now run the forecast twice a year to more
quickly see changes in the forecast.
Grant Forsyth: Slide #7 population growth is a proxy for customer growth. About 2011,
the natural birth/death rate with very little in-migration.
Dave Van Hersett: Where are they coming from? Mix of everywhere, but a lot from
California based on driver’s license surrenders. Also relocating business operations
from the west side of the state.
Greg Rahn: Does the blue bar [slide 7] imply more exposure to recessions. Yes.
Linda Gervais: How has DSM influenced summer/winter peak? Still winter peaking, but
summer peak is growing at a faster rate than winter because of a better economy,
warmer summers and adopting more air conditioning.
Steve Johnson: Data going back to 1890, is there some other explanation for the last 20
years? May inform gas dispatch for the four-year plan and reshape hydro. There are not
very good models for local temperature change. Imperfectly calculated risk.
Clint Kalich: Can the data even be loaded from those models? Are other utilities looking
at shorter periods [of weather data]? It is hard to explain the oscillation of weather using
historic data.
James Gall: There is a risk if we exclude past peaks from shorter time periods. Bigger
risk of missing a peak. Energy – short. Peak – capacity.
John Barber: New climate studies. Are they ready? Starting to “downscale” global
models, but no commonly accepted methodology to do this exists. Which study do you
choose? Which downscaling method to you use? We don’t know, but the University of
Washington and Oregon State University are working on this issue. We went to 20-year
average, but I’m still not comfortable enough with them yet to shift away from the
moving average.
Grant Forsyth: Slide 11 – actual, not weather normalized pre 2019.
James Gall: We plan for the tail events to maintain adequate supply.
Gerry Snow: Winter tail? Summer looks more like a bell curve. Long tail at low
temperatures, this is what we are worried about for capacity.
Page 516 Avista Corp. 2020 Electric IRP Appendices
James Gall: There is greater winter than summer variation.
Steve Johnson: There is a smaller area under the curve, so there may be fewer cold
events. NASA analysis for the 1950-1981 period for the temperature difference from
average, shows a bigger summer than a winter shift.
Steve Johnson: With EVs [electric vehicles], do you think you need more resources in
the next five years or later? No, our needs from resource retirements and contracts
ending are a greater impact than EVs.
Slide #15 – medium term forecast is now done twice yearly.
John Barber: Southerly parts of the country – looking at fleeing to places like here. May
be looking at climate refugees. Climate Council is looking at how climate and water is
changing, but there is still a substantial investment in these areas so what will be spent
on mitigation, so hard to work into the forecast.
Barry Kathrens: Won’t these impact us too? May impact other areas. They would be
impacted, but not as much. A lot of coastal regions are going to be going somewhere.
Slide 19 – PV is rooftop solar.
John Barber (Slide 19): About a 2% penetration rate? A generous forecast, but not
unreasonable.
Slide 20: About 13% electric vehicle penetration rate for residential.
Gerry Snow: Spokane transit may be the first big commercial EV customer.
Steve Johnson: Graph timing of EV. Tough to calculate because small changes up front
make huge changes later.
Steve Johnson (Slide 21): Don’t the wealthy buy most of the cars anyways? Yes, but we
also need a robust used market of EVs. Besides income, density is another predictor,
probably because of range issues. This curtails regional uptake of EVs.
Slide 22: Could have significant transportation emission savings. Still a net benefit per
year with the switch to EVs.
Steve Johnson (Slide 26): I’m confused, difference in UPC winter vs. summer. My
guess is a disproportional effect on UPC on summer because of heating.
Natural slowing of gas because of penetration, but not a specific cause.
Jim Le Tellier: Must be going to different meetings, because that is the next big thing for
environmental groups.
James Gall: It’s a very large cost for a small benefit with the extra cost of wiring.
Jim Le Tellier: Not an argument, just observing.
Page 517 Avista Corp. 2020 Electric IRP Appendices
Steve Johnson: Price of gas falls, but price of electricity is going up.
Gerry Snow: It might be cheaper to decarbonize gas, rather than getting rid of it.
Steve Johnson: If the cost per unit is high, plus low greenhouse gas benefits, there may
be a lot of pushback.
Steve Johnson: Strong enough population growth is overcoming no load growth.
Clint Kalich: Red bump on slide #25 (2023 to 2024), need to check why it is increasing.
Steve Johnson: Would like to leave feeling like he [Grant] can stand by the forecast. Big
forecasters still fundamentally different now. This is the best guess I’ve got now. All
sorts of weird stuff can happen.
Clint Kalich: We have low load growth and no immediate needs.
Steve Johnson: Lot of end use incentives. People want the service, not the thing. They
want cold milk, not electricity. Would like to see more focus on the service. More DSM
deployed and recognized. Tech geek out on the conservation side.
Jenifer Snyder: (Slide 26) 2020-2021 jump. Intermediate term probably enough
correction process going from further out. Pushes more to the long term. Price elasticity
assumption – price not statistically significant anymore using academic studies. Longer
term – no longer assume real price is constant, now increasing.
Steve Johnson: Colstrip remediation costs also impacting
Dave Van Hersett: Small in comparison.
Steve Johnson: Can be significant. We’ll see.
Substituting rising price for conservation in the long run.
Steve Johnson (Slide 29): Conservation adopted this year or actual effects. This is the
amount DSM said they got per month.
Jennifer Snyder: Savings in that year. Grant cumulatively builds them in. Persistence?
Assumes going forward in time.
Dave Van Hersett (slide 29): Is the 12% per year of 1%?
James Gall: More like 1% per year, the average of those.
Slide 30: Preliminary about 60% of black line.
Tina Jayaweera: How do codes and standards fit in?
James Gall: Transfers from programs to standards. Grant builds in a trend, pushed
forward, but there is no specific variable to change.
Page 518 Avista Corp. 2020 Electric IRP Appendices
Tina Jayaweera: About 2012, standards really increased. Hard because of the timing.
We have some estimates that can be shared. Yes, please. Masood has these.

Natural Gas Price Forecast, Tom Pardee
Gerry Snow (Slide 3): Is Jackson Prairie a geologic formation. Yes, an old aquifer.
There are no salt domes available regionally.
John Barber: Dth? Dekatherm, million BTU or 10 therms.
Fred Huette (slide 7): Numbers may be off a bit: 4.5 Bcf British Columbia and 10.5 Bcf
Alberta. The slide actually came from the Canadian government. We have all learned
more about gas north of the boarder.
Clint Kalich: Do you have statistics on the relative amounts of LNG vs. coal to China?
No.
Fred Huette: If LNG is at 3.5 Bcf, any sense of price impacts? Yes, in a few slides.
Basically, their own pipeline, so will take away capacity potentially, but new filled so it
lessens the impact to the AECO trading hub.
Slide #11: 90 Bcf yesterday. About half to electric generation. 120 Bcf /day by 2050.
Slide #12: “Proved” reserves – fairly economic and could be extracted if need be.
Fred Huette: Not sure I would agree with reserves. Definitely a lot less, maybe better if
we communicate offline about this. On EIA as well, about 400 Tcf, about 360 Tcf last
update.
Steve Johnson: What if solar gets really cheap, cost per mmBtu for gas products?
Depends by area. What does the curve look like? Actually negative in the Permian
where they are drilling for oil and natural gas is a byproduct. Marcellus is more of a dry
gas with a higher marginal cost to extract.
Jim Le Tellier: Could be a lot higher. Like solar curtailment, got to get rid of it. Yes.
What is the long term production cost if they have to pay back Wall Street? Typically, no
free cash flow. Typically a hockey stick with high initial production in the first year,
followed by less production, so they have to keep drilling. Now five days on average. Oil
projects are long-term and large capital, not so much with [natural] gas only producers.
Clint Kalich: Social policy might be more of a driver than investment.
Fred Huette: I have a somewhat different view. 80 years based on resources, not
proved reserves. 464 Tcf, about 30 Tcf consumption. We should probably get together
on this offline.
Grant Forsyth (Slide 15): Gas-fired generation in Canada? Or east?
Page 519 Avista Corp. 2020 Electric IRP Appendices
Steve Johnson: What is driving increasing prices?
Fred Huette: What is your opinion or view of the differential between AECO and Henry
Hub? Will it persist or is it temporary? Never expect it to persist, but producers are trying
to think about curtailing production to get closer to Henry Hub prices. Not sure why they
can’t, will seek normal returns.
Clint Kalich: Oil is a bigger driver.
Steve Johnson: 2011 with falling prices, suppliers still want to do shorter contracts
instead of long term. Is it because of fracked gas? A lot of them do hedge 3 to 5 years,
or less, to lock in margin.
Barry Kathrens: Can’t help thinking it might be a little low at 1 – 3%.
Gerry Snow: Is this based on CO2 equivalent? Yes, so different if flaring or leaking with
a 28 times multiplier for leaking.
Fred Huette: Interested again offline. It’s a difficult question with a lot of information
coming in. GWP [global warming potential] for 100 years is 33 or 36 times CO2, 20-year
is about 85. Atmospheric is 10 – 15 years, CO2 is much longer.
Steve Johnson: Has Avista examined the methodologies? No, haven’t seen if
methodology is available. It is set by the Canadian government and there is a tendency
towards less reporting.
Clint Kalich: So now we need to second guess federal studies?
Steve Johnson: The key is if you buy a product, you need to know it. Get a sense of risk
if they are off. It may be hard to calculate and may not be very willing to report it. Not
asking you to reinvent, but do you put a brand on it. Informing customers of what
product they are getting. Could just say it in the IRP. If the methodology is self-reporting
– it’s a red flag. If spot measurement, that’s better. Risk of non-cost effective
conservation.
Jim Le Tellier: How did they build that [CO2 reports]?
Clint Kalich: What do we do?
Tom Pardee: We have the date and documents. Should have a description of how they
developed the numbers.
Fred Huette: I know a fair bit about this issue. Five years ago, it was based on a lot of
engineering data. EDF managed a large research project on this issue and others, so
more data is folding into it and the numbers are getting better. Flaring is not a big issue
in the northwest, but probably a little bit. Probably Bakken and Permian oil dominated by
less gas infrastructure. Very little of this is coming to the Pacific Northwest. Data is
reported to the states and to the feds. The industry has an incentive to reduce flaring,
but the low prices don’t incent it.
Page 520 Avista Corp. 2020 Electric IRP Appendices
Fred Huette (Slide 21): Able to cover almost all times in non-firm in the past when there
was spare capacity, now no firm gas is left. Jackson Prairie rights are on the LDC [local
distribution company] side, so there is no interaction with it and generation.
Gerry Snow: Have you investigated into renewables to hydrogen? Yes, we also looked
at hydrogen at the same time. Renewable about $40/Dth to hydrogen to a fuel cell in
this IRP. It’s very good for long-term storage. There is also methanization, but at a
higher cost.
Fred Huette: Unsure with pumped storage. Very big and limited places.

Electric Price Forecast, James Gall
Dave Van Hersett (Slide 7): At night, use something else than solar. Every day’s price
and standard deviation of price (volatility).
Slide 7: Implied market heat rate equation.
Steve Johnson: What is causing higher 2018-2019 prices? Start up for fewer hours per
day, etc.
Fred Huette: In California last year, they are all out of range. Scarcity pricing for Aliso
Canyon storage and pipeline issues. Persistently high prices. Will these continue? Much
work is being done to calm down prices as things are fixed.
Fred Huette: Kevin Harris at Columbia Grid has studied the startup issue.
Fred Huette: High hydro, low gas burn, but fairly stable online.
Fred Huette: Will see higher emissions this year. Pretty stable market.
Clint Kalich (Slide 16): How do you reconcile resource need with the Council?
Jennifer Snyder (Slide 17): Does load growth include conservation? Yes, low level of
conservation assumed by the consultant.
Thomas Dempsey: What is the 2045 percentage clean? Over 80%, Northwest is 110%.
Western Interconnect excludes Canada and Mexico. Assumes Colstrip out of
Washington by 2025, but we assume there will likely be some generation out of Colstrip
still for other areas.
Fred Huette (Slide 17) Aurora inputs?
1. Future resource cost projections from a consultant, can’t tell you who, plus
incentives; and the vendor of Aurora. NREL annual technology report just
released 2019 update.
2. Solar, wind, storage. We can send out the cost assumptions. Solar plus
storage.
Page 521 Avista Corp. 2020 Electric IRP Appendices
3. Carbon pricing in model for future and existing resources. Washington uses
the social cost of carbon. Other states/provinces include their own
requirements – California, British Columbia, and Alberta.
4. Hydro modeling in Aurora is good, but not great. How do we modify it? 80-
year energy input plus how flexible (Power Council factors) for hydro.
Fred Huette (Slide 18): Are you doing anything to shock or perturb gas prices for
unexpected conditions? Yes, different hydro, load, gas prices, etc. for each of the 500
runs.
Dave Van Hersett: Do rising gas prices raise electric prices? Market prices are relatively
flat in real terms.
Fred Huette: What is the stochastic range? Using randomized draws.
Fred Huette (Slide 20): High load hours with 2026 being higher makes total sense. I’ve
actually studied the market in California. It is lower in the day than at night. The theory is
that gas plants are bidding in the evening and recovering their costs then. May not shift
total market revenue. Solar plus storage first reduces curtailment and then helps with
the ramp.
Steve Johnson: 8 to 16-hour is not relevant anymore.
Mike Dillon: Lot of seasonality, summer 20-21 hours for EIM buyers spike and it spikes
aggressively. The value of flexibility and instant capacity is more.
Clint Kalich (Slide 22): Gas has collapsed showing most of this.
Steve Johnson: Price spike volatility in gas prices. Smaller gas exposure diminishes
impact. More impactful for winter than summer.
Jim Le Tellier: This doesn’t agree with the articles in the paper making statements about
general shift of renewables blowing out bills.
Steve Johnson: The differential has collapsed, but capacity supply will explode in the
other direction.
Clint Kalich: So suppose we now have 5 cents for energy and 2 cents for capacity, we
will have 2 cents for energy and 5 cents for capacity in the future.
Steve Johnson (Slide 25): Why is March so high? Probably because of the ramp spiking
prices. Need to look at this. It is a penalty to turn back on. Not as much with higher
loads.
Fred Huette: A few slides ago, 2030/35/40. It is really great to see shifting prices and
resource availability.
John Barber (Sldie 31) EUE? Average load unserved.
Clint Kalich: Energy that would have to be curtailed in the market.
Page 522 Avista Corp. 2020 Electric IRP Appendices
Clint Kalich: PV [present value] of portfolios to run. Didn’t have to do the math or a
levelized cost, wholesale prices are down and retail price up.
Fred Huette: How did you apply the Social Cost of Carbon? Applied the Social Cost of
Carbon in dispatch for the entire Western Interconnect generation fleet.
Phone: Is the 2020 and 2035 levelized cost for deterministic with California and British
Columbia. Yes, in Expected Case. Social Cost of Carbon case overrides.

Existing Resource Overview, John Lyons
Gerry Snow: Limestone wet scrubbers? Yes.
Steve Johnson: There is a lot of water you can’t get rid of if the plant is off. The majority
of the water leaves through the stack and evaporation. The remedy and closure plan
gets to a net zero point about 30 years out on the current model.
Jim Le Tellier: Sometimes the preliminary estimates are off. Article in the Billings
Gazette was $700 million of cleanup costs [for contaminated water]. That number is for
all four units added together.
Gerry Snow: If you stop bringing in more water? About 470 million gallons on site now, it
was about 700 million gallons.
Fred Huette: What about the new [coal] contract? It will be an all-party contract.
Jennifer Snyder: Is Coyote Springs 2 getting a major redesign? GSU [generation step
up] transformer is the problem. Looking at breaking into individual phases outside of the
IRP, but using the IRP to help evaluate because of losses to winter capacity. Already
submitted a business case, but haven’t made a decision yet.

Final Resource Needs Assessment, John Lyons
Fred Huette: Tenth percentile for hydro? We look at the tenth percentile, enough in nine
out of 10 years. Others use critical water. One consistent month – 1937 was a bad
winter, but an average summer.

Page 523 Avista Corp. 2020 Electric IRP Appendices

2019 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Tuesday, October 15, 2019 Conference Room 130

Topic Time Staff
Introductions, Updates and TAC 4 Recap 9:30 Lyons

Energy Imbalance Market Update 10:00 Kinney Break 11:00 Storage and Ancillary Service Analysis 11:15 Shane
Lunch 12:00

Preliminary Preferred Resource Strategy 1:00 Gall
Break 2:00 Preliminary Portfolio Scenario Results 2:15 Gall Adjourn 3:30

Page 524 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
October 15, 2019
Page 525 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next twenty years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2 Page 526 Avista Corp. 2020 Electric IRP Appendices
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 in all or some of the process
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 was the latest to be able to complete studies in time for
publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3 Page 527 Avista Corp. 2020 Electric IRP Appendices
TAC #4 Recap –August 6, 2019
•Introductions and TAC 3 Recap, Lyons
•Washington SB 5116 and IRP Updates, Lyons
•Energy and Peak Load Forecast Update, Forsyth
•Natural Gas Price Forecast, Pardee
•Electric Price Forecast, Gall
•Existing Resource Overview, Lyons
•Final Resource Needs Assessment, Lyons
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-company/integrated-
resource-planning
4 Page 528 Avista Corp. 2020 Electric IRP Appendices
Today’s Agenda
9:30 –Introductions and TAC 4 Recap, Lyons
10:00 –Energy Imbalance Market Update, Kinney
11:00 – Break
11:15 –Storage and Ancillary Service Analysis, Shane
Noon –Lunch
1:00 –Preliminary Preferred Resource Strategy, Gall
2:00 – Break
2:15 –Preliminary Portfolio Scenario Results, Gall
3:30 –Adjourn
5 Page 529 Avista Corp. 2020 Electric IRP Appendices
Future TAC Topics
•TAC 6: Tuesday, November 19, 2019
–Review of final PRS
–Market scenario results (continued)
–Final Portfolio scenario results
–Carbon cost abatement supply curves
–2020 IRP Action Items
6 Page 530 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
Energy Imbalance Market Update
Scott Kinney, Director of Power Supply
Fifth Technical Advisory Committee Meeting
October 15, 2019
Page 531 Avista Corp. 2020 Electric IRP Appendices
Discussion
•Market Operations Today
–NW bilateral market
–California Independent System Operator (CAISO) market
•Western Energy Imbalance Market (EIM)
–How the EIM works
–Current participants
•Avista’s Decision to join the EIM
–Drivers
–Costs and benefits
•Project Status
2 Page 532 Avista Corp. 2020 Electric IRP Appendices
Organized Electric Markets
3 Page 533 Avista Corp. 2020 Electric IRP Appendices
NW Bilateral Market
•No organized market
•Utilities operate individually
–Buy/sell with counterparties or through electronic clearing house
•Monthly, day ahead and hourly
–Utilities hold extra resources to meet forecast error
•Can’t take advantage of regional load/resource diversity
–Must meet all NERC compliance requirements
–Perform transmission planning
–Facilitate transmission tariff and sales
•Less efficient
4 Page 534 Avista Corp. 2020 Electric IRP Appendices
The CAISO Market
•The California Independent System Operator (CAISO)
runs a full organized energy market in California
•Based in Folsom, CA, operational since 1998
•Utilities maintain ownership of generation and
transmission assets
•CAISO ensures sufficient resources to meet CA load
–Balancing Authority for members
–Day ahead dispatch plan
–Real-time resource dispatch
•Conducts long-term transmission planning
•Facilitates transmission tariff and sales
5 Page 535 Avista Corp. 2020 Electric IRP Appendices
What is the Western Energy Imbalance
Market?
•Operational since 2014 –CAISO and PacifiCorp
•The EIM is an economic based 5 minute in-hour regional
resource dispatch program
–Allows participants to lower energy costs
•Dispatch less expensive resources to meet in-hour load
obligations
•Increase revenue through the bidding of excess energy
•Monetize resources traditionally held for regulating reserves
–The EIM dispatches the most economic resource across its entire
market footprint every 5 minutes based on bid prices to balance
in-hour load and generation
6 Page 536 Avista Corp. 2020 Electric IRP Appendices
Why EIM?
7 Page 537 Avista Corp. 2020 Electric IRP Appendices
How the EIM Works
•Participants must show they can meet load obligations prior to the
operating hour, no leaning on the market
•Participants voluntarily submit resource availability, min/max, ramp
rates and price curves
•CAISO runs a security constraint (i.e. transmission) economic
dispatch every 5 minutes to obtain the optimal economic and reliable
resource solution for the EIM footprint
•Transmission congestion leads to price differentials
•CAISO sends a 5 minute dispatch request to selected resources to
meet overall footprint load obligation
•Generators and load are assigned a locational marginal price based
on the economic dispatch and transmission congestion
8 Page 538 Avista Corp. 2020 Electric IRP Appendices
EIM Supply Transfers Benefit Both Areas
9 Page 539 Avista Corp. 2020 Electric IRP Appendices
EIM Supply Transfers Benefit Both Areas
10 Page 540 Avista Corp. 2020 Electric IRP Appendices
http://www.caiso.com/TodaysOutlook/Pages/prices.aspx
Page 541 Avista Corp. 2020 Electric IRP Appendices
EIM Participants
•Members -CAISO, PAC, NVE,
PSE, APS, PGE, IPC,
Powerex, BANC (SMUD)
•Committed
–2020 –SCL, SRP
–2021 –PNM, NWE, LADWP, TID
–2022 –Avista, TEC, Tacoma, BPA
12
80% of
WECC
load
Page 542 Avista Corp. 2020 Electric IRP Appendices
EIM Gross Benefits
13 Page 543 Avista Corp. 2020 Electric IRP Appendices
Market Monitoring Phase 2015-2018
•Limited needs and risks
–Small renewable penetration
–Economics not compelling
–Other large technology projects
•Monitor market development
–Engage in public processes and meetings
•EIM Entity outreach and site visits
•CAISO Scheduling Coordinator certification
–June 2016
•Infrastructure evaluation
14 Page 544 Avista Corp. 2020 Electric IRP Appendices
Avista Decision Drivers and Risks
•In-hour market liquidity risks
–2018 summer issues
–NWE joining in 2021, BPA planning to join in 2022
•Renewable energy integration
–Rattlesnake Wind contract -145 MWs end of 2020
–Transmission interconnection queue >1000MW
–Avista’s clean energy goals
–State policies and regulations
•WA Clean Energy Bill
•WA PURPA changes
15 Page 545 Avista Corp. 2020 Electric IRP Appendices
Avista Decision Drivers and Risks cont.
•Economics
–Customer benefits
–Risks of not joining
•Reduction in current optimization opportunities
•Higher resource dispatch costs
16 Page 546 Avista Corp. 2020 Electric IRP Appendices
Avista EIM Costs and Benefits
•Estimated EIM costs
–$21 –26 M start-up
–$3.5 –4.0 M on-going
•Anticipate 12+ new FTE for on-going support
•Estimated annual benefits
–Full range $ 2 –12 M
–Expected range $3.5 -9.2 M
–Base $5.8 M
17 Page 547 Avista Corp. 2020 Electric IRP Appendices
Utility EIM Cost/Benefit Comparison ($M)
18
PAC NVE PSE APS PGE IPC AVA
Actual Costs 21.0 11.5+22.0 16.0 22.0 12.0+21.5
Studied
Benefits 35.1 10.8 14.1 4.9 3.5 4.1 5.8
2018 Actual
Benefits 61.7 25.6 13.7 45.3 27.6 26.9 ?
Page 548 Avista Corp. 2020 Electric IRP Appendices
Project Status
•Officer approval on April 15 to join EIM
–Go-live April 1, 2022
•CAISO Contract
–Signed Integration Agreement on April 25
•System Integrator –Utilicast
•Current efforts
–Upgrade/replace meters and generation controls
–Expand telecomm networks
–Request For Proposals for EIM applications
•Issued Outage Management RFP on August 13
•Issued Bid to Bill RFP on September 17
–ADSS enhancements
–Staffing plan and training
19 Page 549 Avista Corp. 2020 Electric IRP Appendices
20 Page 550 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
Storage and Ancillary Services Analysis
Xin Shane, Senior Power Supply Analyst
Fifth Technical Advisory Committee Meeting
October 15, 2019
Page 551 Avista Corp. 2020 Electric IRP Appendices
Challenges of Energy Storage Valuation
Source: Northwest Power and Conservation Council white paper on the
value of energy storage to the future power system
2 Page 552 Avista Corp. 2020 Electric IRP Appendices
Value Stream Definition
•Frequency Response: Automatic generator response to grid frequency
excursions
•Contingency Reserves: Reserves available for grid emergencies
•Regulation: Instant response to system load fluctuations
•Load Following: Follows system load fluctuations
•Arbitrage: Store energy when price is low and discharge when price is high
•Avoided Curtailment: Storing energy during times of oversupply to avoid
generation curtailment
•Peaking Capacity: Ensure sufficient capacity to meet forecast peak demand
•Energy: Optimizes energy timing to meet load
•T&D Deferral: Reduce loading on transmission paths and loading on
distribution circuits during peak demand periods
•Volt/Var: Provide reactive power within the distribution system to maintain
nominal grid voltage and enhance the power carrying capability of transmission
system
•Outage Mitigation: Help with unplanned outages with back-up power for
reliability and resilience
3 Page 553 Avista Corp. 2020 Electric IRP Appendices
Avista Decision Support System
4 Page 554 Avista Corp. 2020 Electric IRP Appendices
Battery Study Overview
•Turner Energy Storage Project –1 MW, 3.7 MWh
vanadium redox flow battery
•Partnered with PNNL to study operational use cases for
the Clean Energy Funds grant.
•Study focuses on regulation and reserves
5
Turner Energy Storage Project, Pullman, WA
Page 555 Avista Corp. 2020 Electric IRP Appendices
Battery Operating Characteristics
Charge
Discharge
State of Charge (SOC) –An expression of the present battery capacity as a
percentage of maximum capacity.
Power –instantaneous kilowatts.6 Page 556 Avista Corp. 2020 Electric IRP Appendices
Modeling Overview
Targeted Battery Rating
•Max Capacity – 1.0 MW
•Max Storage –3.7 MWh
Applied Battery in Model
•Max Capacity – 10 MW
•Max Storage –37 MWh
-$10.0
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
$70.0
(12.0)
(7.0)
(2.0)
3.0
8.0
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97
10
1
10
5
10
9
11
3
11
7
12
1
12
5
12
9
13
3
13
7
14
1
14
5
14
9
15
3
15
7
16
1
16
5
Hourly Battery Discharge
Net Discharge MCMktPrice
MW
7 Page 557 Avista Corp. 2020 Electric IRP Appendices
Price Volatility Impact
8 Page 558 Avista Corp. 2020 Electric IRP Appendices
Benefit Evaluation
Scenario Power Price Gas Price Benefits
1st Run Forecasted Monthly Forward $5.00/kW-yr
2nd Run Year 2016 Power
Index Price
Monthly Forward $6.63/kW-yr
3rd Run Year 2014 Power
Index Price
Year 2014 Daily $36.32/kW-yr
9 Page 559 Avista Corp. 2020 Electric IRP Appendices
Pumped Hydro Study
Operating Characteristics
10 Page 560 Avista Corp. 2020 Electric IRP Appendices
Pumped Hydro Scenarios and Results
System Configuration Target
Project
Scaling
Incremental Value
($)
Incremental
Value
($/kw-yr)
Avista System 3 by 400 MW 100%$19,412,500 $ 16.18
Avista System 3 by 100 MW 25%$ 6,772,468 $ 22.57
Avista System 3 by 40 MW 10%$ 3,057,399 $ 25.48
Avista System 3 by 20 MW 5%$ 1,598,433 $ 26.64
Hydro Reduction 3 by 40 MW 10%$ 4,730,827 $ 39.42
Noxon 1 120 Cabinet 1 65 Long Lake 1 22 Little Fall 1 8.5
Noxon 2 120 Cabinet 2 78 Long Lake 2 22 Little Fall 2 8.5
Noxon 3 120 Cabinet 3 79 Long Lake 3 22 Little Fall 3 8.5
Noxon 4 120 Cabinet 4 68 Long Lake 4 22 Little Fall 4 8.5
Noxon 5 135
11 Page 561 Avista Corp. 2020 Electric IRP Appendices
Pumped Hydro Incremental Value Results
12 Page 562 Avista Corp. 2020 Electric IRP Appendices
Future Energy Storage Analyses
•Re-evaluate energy storage options in a shorter term
energy market
•Analyze different energy storage technologies
•Updated pumped storage hydropower technologies
•Study with different levels of wind and solar penetration
13 Page 563 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated Resource Plan
DRAFT “Preferred” Resource Strategy
James Gall, IRP Manager
Fifth Technical Advisory Committee Meeting
October 15, 2019
Page 564 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
What Are Avista’s Physical Resource
Needs?
Main focus: Winter Peak (e.g. cold week in January)
Avista is also short in summer and on an annual average basis
beginning in 2027
-
500
1,000
1,500
2,000
2,500
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
Me
g
a
w
a
t
t
s
Available Resources Net Requirement
Gap
2026: 14 MW
2027: 302 MW
2030: 325 MW
2035: 495 MW
2040: 537 MW
Key Losses:
Colstrip: 2025*
Lancaster: 2026
Mid-C: 2030
Northeast: 2035
2 * Colstrip is assumed offline at the end of 2025 for planning purposes only. Avista’s ultimate decisions regarding
Colstrip are still to be determined.
Page 565 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Washington SB5116 Clean Requirements
2026: Colstrip can no longer serve Washington Load
2030: 80% energy delivered over a four-year period is clean and 20% can be RECs
2045: Goal to be 100% clean (will require new technology to stay under cost cap)
Gap
2030: 54 aMW
2035: 130 aMW
2040: 182 aMW
2045: 353 aMW
Key Losses:
Mid-C: 2030
Lind: 2039
Rattlesnake: 2040
Palouse: 2043
Assumes: Idaho customers sell offsets to Washington Customers
0
100
200
300
400
500
600
700
800
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
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2
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8
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2
9
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20
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20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Washington Existing Qualifying Resources
Idaho Available Hydro RECs
Washington Net Requirement
Washington Retail Sales
3 Page 566 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Avista’s Clean Electricity Goal
0
200
400
600
800
1,000
1,200
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
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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
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0
20
4
1
20
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2
20
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20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Total Existing Resources System Retail Sales (aMW)
2027: 100% net clean portfolio wide (cost effective considerations)
2045: 100% clean (cost effective considerations and technology)
Gap
2027: 339 aMW
2030: 360 aMW
2035: 426 aMW
2040: 448 aMW
2045: 562 aMW
4 Page 567 Avista Corp. 2020 Electric IRP Appendices
Resource Options
Clean
•Wind (WA/OR/MT)
•Solar (WA/ID/OR)
•Biomass (WA/ID)
•Hydro Upgrades (MS, LL)
•Hydro (Mid-C)
•Hydro (BPA)
•Geothermal
•Nuclear
•Energy Efficiency
•Demand Response
Other
•Natural Gas CT
•Natural Gas CCCT
•Storage
–Pumped hydro
–Lithium-ion batteries
–Liquid air
–Hydrogen
–Flow batteries
•Regional Transmission
5 Page 568 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Preferred Resource Strategy Decision
Process
•Uses Mixed Integer Program (MIP) to find least cost solution
meeting capacity, energy, and renewable constraints for the system
between 2021 and 2045.
•Only known model with full co-optimization of energy efficiency and
demand response with supply side resources.
–Capable of co-optimization of T&D system with power system
•Accounts for societal preference Washington state planning criteria
–(Social Cost of Carbon, 10% cost advantage from energy efficiency,
upstream pipeline emissions, etc.)
•Non-modeled utility revenue requirements assumes an increase of
two percent per year.
6 Page 569 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Av
e
r
a
g
e

M
e
g
a
w
a
t
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s
Energy Efficiency Results
45% increase
Note: excludes T&D losses7Page 570 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Where is the Cost Effective Energy
Efficiency Savings?
Residential
40%
Commercial
49%
Industrial
11%
2040 Customer Class Savings
0.7
1.2
1.4
3.4
4.0
4.3
5.2
5.2
5.4
5.8
7.3
11.2
14.0
30.0
44.6
0 10 20 30 40 50
Office Equipment
Process
Miscellaneous
Food Preparation
Cooling
Heating
Electronics
Refrigeration
Motors
Appliances
Ventilation
Space Heating
Exterior Lighting
Water Heating
Interior Lighting
Average Megawatts
2040 Cumulative Savings
8 Page 571 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Washington Biennial EIA Energy
Efficiency Goal (2021/22)
9
Biennial Conservation Approved
Target (MWh)
Based on
2020 IRP
Based on
2017 IRP
CPA Pro-Rata Share 72,338 73,636
Behavioral Program Savings N/A 15,386
Distribution and Street Light Efficiency 504 749
EIA Target 72,842 89,771
Decoupling Threshold 3,642 4,489
Total Utility Conservation Goal 76,484 94,260
Excluded Programs (NEEA)-14,016 -9,986
Utility Specific Conservation Goal 62,468 84,274
Decoupling Threshold -3,642 -4,489
EIA Penalty Threshold 58,826 79,785
73,636 72,338
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2017 IRP 2020 IRP
MW
h
Biennial Pro-Rate Share (10 yr)
Page 572 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
$0
$20
$40
$60
$80
$100
$120
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
k
W
-yr
Capacity Value
Energy Efficiency Avoided Cost
Energy, $26.44
Clean Premium,
$16.35
Losses, $2.61
Preference, $4.54
$0
$10
$20
$30
$40
$50
$60
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
M
W
h
Energy Value
$49.95/MWh $101.27/kW-yr
10 Page 573 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
- 20 40 60 80 100 120
$
p
e
r

k
W
-yr
Megawatts
Demand Response
Summer Programs Evaluated
•Central A/C
•Smart Thermostats-Cooling
•Thermal Energy Storage
11
25 MW Load Control is also included, but not shown as its prices would likely be negotiated
Cost Effective Start Dates Shown in Red
2026: Variable Peak Pricing2029: Time of Use
2029: Industrial Load Control
2030: Smart Thermostats
2043: Ancillary Services (TBD)
Page 574 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
2022-2025 Generation Action Plan
•2022-2023 RFP
–Early acquisition to take advantage of tax credits
–Anticipate 300 MW Wind PPA (84 aMW)
•100 MW in MT and 200 MW in NW
•locations depend on transmission availability
–Solar could replace wind depending on pricing and future price shape forecasts
–Potential for additional resource acquisitions in support of Avista’s clean
electricity goal subject to reliability and affordability considerations.
•2024: Kettle Falls Upgrade
–Incrementally increase Kettle Falls generating capability by installing larger sized
equipment as part of modernization
•2025: 222 MW, Colstrip removed
–Per CETA, Colstrip will not serve Washington loads after 12/31/2025
–The plants future for Idaho customers or wholesale transactions is yet to be
determined
12 Page 575 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
2026-2030 Generation Action Plan
•2026: 150 MW, Pumped Hydro
–Assumes low cost, long duration pumped hydro solution is available.
–If resource is not available or price exceeds cost effectiveness tests, siting a
similar sized NG peaker is the next least cost option.
–Sizing will depend on reliability requirements of future power supply system.
•2026: 24 MW, Rathdrum Upgrade
–Increases each unit by 6 MW using a supplemental compression technology or
alternative technology.
•2026: Lancaster PPA expires in October
•2027: 200 MW, MT Wind
–Utilizes Colstrip transmission,
–if not available additional NG and renewables are required.
•2027: 8 MW, Post Falls Upgrade
–Increase generating capability as part of modernization project to maintain FERC
licensing requirements.
13 Page 576 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
2031-2040 Generation Action Plan
•2031: Attempt to renew Mid-C PPA contracts
•2033: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2035: Northeast CT retires
•2035: 68 MW Long Lake 2nd Powerhouse
–Seek certification as an eligible resource
•either as 2nd powerhouse and/or reconfiguration of single new powerhouse.
–Begin licensing process
–Optimize the site for cost, capacity, and environmental concerns
–Earlier on-line date may be possible
–NG Peaker and renewable resource would be alternative to this project
•2036: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2038: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2039: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
14 Page 577 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
2040-45 Generation Action Plan
•2041: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2042-2045: 300 MW Wind PPA Replacement
–Existing PPAs begin to expire
–Repowering is likely necessary
•2043: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2042-2045: 250 MW x 4 hour, Lithium-ion (or lowest cost alternative)
•2044: 50 MW, solar w/ 50 MW x 4 hour storage
15 Page 578 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
DRAFT Preferred Resource Strategy
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 85 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2033: 25 MW x 16 hr Liquid Air Storage
2035: 55 MW, Northeast CT retires
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 25 MW x 16 hr, Liquid Air Storage
2038: 25 MW x 16 hr, Liquid Air Storage
2039: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr, Liquid Air Storage
2043: 2.5 MW, Demand Response
2042-2045: 225 MW x 4 hr, Lithium-ion
2044: 50 MW, Solar w/ 50 MW x 4hr, Storage
16
Load reduction of 152 aMW due to Energy Efficiency by 2040
Page 579 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Reliability Study Results
•14% planning margin without Colstrip and non-
dispatchable resources is too low.
•LOLP analysis was re-studied without Colstrip to
determine the required planning margin to achieve 5%
LOLP with NG CTs-this resulted in a ~16% planning
margin
•The resulting draft reliability metrics for the PRS are:
17
Reliability Metric Draft PRS Result TAC 2 Adequate
System Result
LOLP 7.0%4.9%
LOLH 3.10 1.85
LOLE 0.25 0.16
EUE 552.3 MWh 318.7 MWhPage 580 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLYPRS Comparison to Corporate Clean
Electricity Goal
Goal: Serve customers with 100% cost effective clean electricity
-
200
400
600
800
1,000
1,200
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
"Clean" Market Purchases
Clean Generation
Sales Forecast
PRS meets 89% of corporate goal by 2027
Notes:1) Prior to 2030, Avista is a net energy seller to the market2) “Clean” market purchases is measured as the regional
generation mix’s CO2 mix compared to a CCCT18Page 581 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
PRS: Greenhouse Gas Emissions Forecast
(1.0)
(0.5)
-
0.5
1.0
1.5
2.0
2.5
3.0
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
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Net Market Purchases/Sales
New Resources
Current Resources
2018 Actual
Total Net Emissions
80% to 85% net reduction after 2027
19 Page 582 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Ce
n
t
s

p
e
r

k
W
h
Re
v
e
n
u
e

R
e
q
u
i
r
e
m
e
n
t

(
M
i
l
l
i
o
n
s
)
Rev. Req.
Rev. Req. + 1 Stdev
Rev. Req. 95th Percentile
Avg Rate
PRS: Cost/Rate Forecast
20
System PVRR: $11.777 billion
2030 Rate: 10.3 cents/kWh
2045 Rate: 14.1 cents/kWh
Note: Assumes non-power supply modelled costs escalate at 2 percent per yearPage 583 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
In
c
r
e
m
e
n
t
a
l

C
o
s
t
Cost Comparison between PRS and LC
Portfolio w/o CETA
Notes: State allocation factors and resource designation will affect these results for each state21Page 584 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Avoided Cost of Generation Calculation
Methodology
•Energy value:hourly mark to market value of delivered energy in the wholesale
market (i.e. Mid-C index).
•Capacity value:total portfolio revenue requirement difference between a portfolio
meeting capacity targets versus a portfolio only relying on the spot energy market.
The difference is divided by the added capacity additions (MW) to estimate $ per kW.
Rates are levelized and tilted to begin with first deficit.
•Clean premium:total portfolio revenue requirement difference between a portfolio
meeting CETA versus a portfolio only meeting the capacity requirements. This
difference is divided by added generated MWh. Rates are levelized and tilted to begin
with first expected acquisition year.
•Clean premium with tax incentives: Same as clean premium calculation except the
federal tax subsidies continue.
22 Page 585 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Avoided Costs
23
Year
(S/MWh)
On-
($/MWh)
Off-
($/MWh ($/MWh)
($/MWh
($/kW-
year)
2021 19.67 22.64 0.00 0.0
2022 19.98 22.75 9.33 0.0
2023 20.44 23.05 9.52 0.0
2024 21.61 24.09 9.71 0.0
2025 22.76 25.19 9.90 0.0
2026 24.27 26.40 10.10 97.3
2027 23.57 25.27 10.30 99.3
2028 25.02 26.26 10.51 101.2
2029 25.92 26.80 10.72 103.3
2030 26.72 27.08 10.93 105.3
2031 29.46 29.66 11.15 107.4
2032 29.78 29.95 11.38 109.6
2033 31.22 30.74 11.60 111.8
2034 32.83 31.94 11.83 114.0
2035 33.66 32.64 12.07 116.3
2036 35.82 34.82 12.31 118.6
2037 36.12 34.58 12.56 121.0
2038 38.81 37.40 12.81 123.4
2039 38.60 37.13 13.07 125.9
2040 38.52 36.80 13.33 128.4
2041 39.09 37.74 13.59 131.0
2042 38.98 37.99 13.87 133.6
2043 40.24 39.51 14.14 136.2
2044 46.10 45.29 14.43 139.0
2045 43.94 43.11 14.71 141.8
15 yr Levelized 24.58 26.11 9.38 58.5
20 yr Levelized 26.44 27.55 9.87 67.8
25 yr Levelized 27.86 28.77 10.27 74.3Page 586 Avista Corp. 2020 Electric IRP Appendices
DRAFT ONLY
Challenges and Considerations
•Ultimate disposition of Colstrip
•State resource allocation
•Achieving Avista clean electricity goal
•Transmission needs and issues
–Integration of transmission & distribution needs into a fully Integrated Resource Plan
–System impacts of third party generation resources
•Storage issues
–Physical requirements for resource adequacy and grid reliability
–Economic needs for integration of renewable generation
–Storage technology and cost improvements
•Rulemaking and permitting impacts on the preferred resource options
•Market development to accommodate increased variable generation and
acquisition
24 Page 587 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated Resource Plan
Draft Portfolio Scenario Analysis
James Gall, IRP Manager
Fifth Technical Advisory Committee Meeting
October 15, 2019
Page 588 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Scenario Overview
•Use same electric price forecast-but different resource
assumptions.
•Use optimization to create portfolio, but use different
constraints for each scenario.
•View financial results of each portfolio along with
resource selection.
•Portfolio results with different market assumptions will be
provided at the next TAC meeting.
•No reliability analysis are completed for portfolio
scenarios.
2 Page 589 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Portfolio
outside of
portfolio
constraints
Efficient Frontier Overview
Ri
s
k
Cost
Least cost-
highest risk
portfolio
Highest
cost-least
risk portfolio
In-efficient
portfolio
3 Page 590 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Scenarios
1. Preferred Resource Strategy
2. Least Cost Plan-w/o CETA
3. Clean Resource Plan: 100% net clean by 2027
4. Rely on energy markets only (no capacity or renewable additions) w/o CETA
5. 100% net clean by 2027, and no CTs by 2045
6. Least Cost Plan w/o pumped storage or Long Lake as options
7. Colstrip extended to 2035 w/o CETA
8. Colstrip extended to 2035 w/ CETA
9. Least Cost Plan w/ higher pumped storage cost
10. Least Cost w/ federal tax credits extended
11. Clean Resource Plan w/ federal tax credits extended
12. Least Cost Plan w/ low load growth (flat loads-low economic/population growth)
13. Least Cost Plan w/ high load growth (high economic/population growth)
14. Least Cost Plan w/ Lancaster PPA extended five years (financials will not be public)
Others: Efficient frontier portfolio (least risk, 75/25, 50/50, and 25/75)
4 Page 591 Avista Corp. 2020 Electric IRP Appendices
DRAFT
20
3
0

P
o
w
e
r

S
u
p
p
l
y

C
o
s
t

S
t
d
e
v
2021-45 Levelized Annual Revenue Requirement
Least Risk
25/75
50/50
75/25
Least Cost
Efficient Frontier Results
#4: Rely on Energy Markets Only
#2: Least Cost Plan w/o CETA
#7: Colstrip Extended w/o CETA
#1: PRS
#10: LC w/
Tax Credits
Extended#8: Colstrip
Extended w/ CETA
#3 Clean Resource Plan
#11 Clean
Resource Plan w/ Tax Credits
#5 No CTs by 2045
#6 Least Cost w/o P/S or Long Lake
#9: LC w/ higher P/S costs
5 Page 592 Avista Corp. 2020 Electric IRP Appendices
DRAFT
2030 Portfolio Resource Selection
6
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Page 593 Avista Corp. 2020 Electric IRP Appendices
DRAFT
2040 Portfolio Resource Selection
7
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Page 594 Avista Corp. 2020 Electric IRP Appendices
DRAFT
2045 Portfolio Resource Selection
8
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Page 595 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Annual Cost Comparison
9
PVRR (Millions)
Page 596 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Rate Comparison
sorted by 2045 rates
10
Cents per kWh
Page 597 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Portfolio Tail Risk
(95th percentile minus expected cost, excludes Social Cost of Carbon)
11 Page 598 Avista Corp. 2020 Electric IRP Appendices
DRAFT
PVRR Risk Adjusted Comparison
Sorted by TailVar w/o Social Cost of Carbon (SCC)
12
$11.0
$12.0
$13.0
$14.0
$15.0
$16.0
$17.0
10. LeastCost w/federal taxcreditsextended
12. LCPLowEconomicGrowth
4. Rely onEnergyMarketsOnly w/oCETA
1. LeastCost Plan/PRS
11. CRPw/ federaltax creditsextended
8. Colstrip2035 w/CETA
14. LCP w/LancasterPPA
9. LCP w/Higher P/Scost
6. LCP w/oPS/Hydro 7. Colstrip2035 w/oCETA
2. LCP-w/o CETA 2. LCP-w/o CETA EfficientFrontier:25%Risk/75%Cost
13. LCPHighEconomicGrowth
3. CleanResourcePlan(CRP)
EfficientFrontier:50%Risk/50%Cost
5. CRP-No CTs EfficientFrontier:75%Risk/25%Cost
EfficientFrontier:Least Risk
PV
R
R

(
B
i
l
l
i
o
n
s
)
Page 599 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Annual Greenhouse Gas Comparison
13
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s

o
f

C
O
2
(e
q
u
i
v
e
l
e
n
t
)
Page 600 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Annualized Greenhouse Gas Emissions
(Levelized using 2.5% discount rate)
2.64
1.36
1.19
1.10
1.08
0.93
0.86
0.83
0.83
0.82
0.80
0.80
0.80
0.74
0.69
0.66
0.63
0.63
0.63
0.00 0.50 1.00 1.50 2.00 2.50 3.00
2018 (excluding market effects)
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
4. Rely on Energy Markets Only w/o CETA
2. LCP- w/o CETA
14. LCP w/ Lancaster PPA
10. Least Cost w/ federal tax credits extended
13. LCP High Economic Growth
6. LCP w/o PS/Hydro
1. Least Cost Plan/ PRS
9. LCP w/ Higher P/S cost
12. LCP Low Economic Growth
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 25% Risk/75% Cost
Efficient Frontier: 50% Risk/50% Cost
3. Clean Resource Plan (CRP)
5. CRP- No CTs
11. CRP w/ federal tax credits extended
Annualized Millions of Metric Tons of Greenhouse Gases
14 Page 601 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Ch
a
n
g
e

i
n

L
e
v
e
i
z
e
d

C
o
s
t

D
e
l
t
a

f
r
o
m

P
o
r
t
f
o
l
i
o

#
2

(M
i
l
l
i
o
n
s
)
Change in Levelized GHG Emissions from Portfolio #2 (Millions)
Cost vs GHG Emissions
#1-PRS
#3-Clean Resource Plan
#4-Rely on Energy Markets Only (w/o
CETA)
#5-Clean Resource Plan-No CTs
#6-LCP w/o PS/Hydro #7-Colstrip 2035 w/o CETA
#8-
Colstrip 2035 w/
CETA
#10-LCP w/
Federal Tax Credits Extended
#9-LCP w/
Higher P/S Cost
#11-CRP w/ Federal
Tax Credits Extended
#12-LCP Low Economic
Growth
#14-LCP w/ Lancaster PPA extended
#13-LCP High
Economic Growth
15
Implied Carbon Levelized Carbon Prices#1. PRS: $27/metric ton
#2. CRS: $120/metric ton
#5. CRS No CTs: $141/metric ton
Page 602 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Scenario Results Summary Table
16 Note: Costs do not include Social Cost of Carbon
Portfolio
Number Portfolio name
Cost 2021-
2045 (PVRR)
(millions)
Cost 2021-
2030 (PVRR)
(millions)
2030 Risk
(millions)
2030 Rate
(c/kWh)
2045 Rate
(c/KWh)
Levelized
R.R.
Page 603 Avista Corp. 2020 Electric IRP Appendices
Appendix
Detailed Resource Portfolios
Page 604 Avista Corp. 2020 Electric IRP Appendices
DRAFT1) Preferred Resource Strategy
Least Reasonable Cost Plan
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 85 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2033: 25 MW x 16 hr, Liquid Air Storage
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 25 MW x 16 hr, Liquid Air Storage
2038: 25 MW x 16 hr, Liquid Air Storage
2039: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr, Liquid Air Storage
2043: 2.5 MW, Demand Response
2042-2045: 225 MW x 4 hr, Lithium-ion
2044: 50 MW, Solar w/ 50 MW x 4hr, Storage
18
Load reduction of 152 aMW due to Energy Efficiency by 2040
Page 605 Avista Corp. 2020 Electric IRP Appendices
DRAFT2) Least Cost Plan
w/o CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 52 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027: 245 MW, Natural Gas CT
2031-2040
2031: 75 MW, Mid-C PPA Renew
2033: 25 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 84 MW, Natural Gas CT
2036: 9 MW, Demand Response
2038: 25 MW x 16 hr, Liquid Air Storage
2040: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041-2042: 50 MW x 16 hr, Liquid Air Storage
2043-2045: 450 MW x 4 hr, Lithium-ion
19
Load reduction of 131 aMW due to Energy Efficiency by 2040
Page 606 Avista Corp. 2020 Electric IRP Appendices
DRAFT
3) Clean Resource Plan
100% net clean by 2030
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2025-2030: 39 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027-2029: 300 MW, NW Solar
2028-2030: 100 MW, Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW Long Lake 2nd
Powerhouse
2033: 50 MW, NW Solar
2035: 55 MW, Northeast CT retired
2036-2040: 125 MW Solar w/ 125 MW x 4 hr. Storage
2038: 10 MW Solar
2039: 50 MW x 4 hr, Liquid Air Storage
2033-2040: 46 MW, Demand Response
2041-2045
2041-2043: 300 MW Wind PPA Renew
2042-2044: 75 MW x 16 hr Liquid Air Storage
2045: 5 MW Solar
2045: 50 MW Solar w/ 50 MW x 4 hr Storage
2045: 50 MW x 4 hr, Lithium-ion
20
Load reduction of 175 aMW due to Energy Efficiency by 2040
Page 607 Avista Corp. 2020 Electric IRP Appendices
DRAFT4) Rely on Energy Markets Only
(no capacity or renewable additions)
2021-2030
2026: 222 MW, Colstrip removed
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2031-2040
2035: 55 MW, Northeast CT retired 2041-2045
21
Load reduction of 102 aMW due to Energy Efficiency by 2040
Page 608 Avista Corp. 2020 Electric IRP Appendices
DRAFT5) 100% Net Clean by 2027
and No CTs by 2045
2021-2030
2022: 150 MW, Solar
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2025-2027: 39 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027-2029: 300 MW, NW Solar
2028-2030: 100 MW, NW Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd
Powerhouse
2033: 50 MW, NW Solar
2033-2035: 46 MW, Demand Response
2035: 55 MW, Northeast CT retired
2036-2040: 135 MW Solar w/ 125 MW x 4 hr, Storage
2039-2040: 250 MW x 16 hr Liquid Air Storage
2040: 50 MW Pumped Hydro
2035: 154 MW, Rathdrum CTs removed
2041-2045
2041-2043: 300 MW Wind PPA Renew
2043: 9 MW, Kettle Falls CT removed
2043: 25 MW, Boulder Park removed
2043-2045: 50 MW x 4 hr, Lithium-ion
2042-2044: 125 MW x 16 hr Liquid Air Storage
2045: 10 MW Solar
2045: 50 MW Solar w/ 50 MW x 4 hr, Storage
2045: 175 MW Pumped Hydro
2045: 100 MW Small Nuclear
2045: 75 MW Biomass
2045: 302 MW, Coyote Springs 2 removed
22
Load reduction of 174 aMW due to Energy Efficiency by 2040
Page 609 Avista Corp. 2020 Electric IRP Appendices
DRAFT
6) Least Cost Plan
w/o pumped storage or Long Lake
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 129 MW, Natural Gas CT
2027: 30 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-2032: 55 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 84 MW, Natural Gas CT
2039: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW Wind PPA
Renew
2042: 25 MW x 16 hr, Liquid Air Storage
2043-2045: 150 MW Solar w/ 150 MW x 4 hr, Storage
2044-2045: 75 MW x 4 hr, Lithium-ion
2044: 25 MW x 16 hr Liquid Air Storage
23
Load reduction of 149 aMW due to Energy Efficiency by 2040
Page 610 Avista Corp. 2020 Electric IRP Appendices
DRAFT
7) Colstrip Extended to 2035 w/o CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 25 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2028-2030: 61 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 25 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035-2036: 252 MW, Natural Gas CT
2036: 100 MW, MT Wind
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042: 25 MW x 16 hr Liquid Air Storage
2042-2045: 450 MW x 4 hr, Lithium-ion
24
Load reduction of 129 aMW due to Energy Efficiency by 2040
Page 611 Avista Corp. 2020 Electric IRP Appendices
DRAFT
8) Colstrip Extended to 2035 w/ CETA
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2028: 39 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032-2035: 46 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 200 MW, MT Wind
2036: 132 MW, Natural Gas CT
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2042-2045: 75 MW, Solar w/ 75 MW x 4 hr, Storage
2042-2045: 125 MW x 4 hr, Lithium-ion Storage
2045: 25 MW x 16 hr Liquid Air Storage
25
Load reduction of 143 aMW due to Energy Efficiency by 2040
Page 612 Avista Corp. 2020 Electric IRP Appendices
DRAFT9) Least Cost Plan
w/ higher pumped storage cost
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2028: 109 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 90 MW, Natural Gas CT
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 25 MW x 16 hr Liquid Air Storage
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2035-2040: 100 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW, Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2044: 25 MW x 16 hr Liquid Air Storage
2044: 10 MW, Solar
2044: 25 MW x 4 hr, Lithium-ion
2045: 50 MW x 4 hr, Lithium-ion
2045: 50 MW Solar w/ 50 MW x 4 hr Storage
26
Load reduction of 155 aMW due to Energy Efficiency by 2040
Page 613 Avista Corp. 2020 Electric IRP Appendices
DRAFT10) Least Cost Plan
w/ Federal Tax Credits Extended
2021-2030
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 175 MW Pumped Hydro
2026: 283 MW, Lancaster PPA expires
2027: 100 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2027-2030: 60 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 25 MW, Demand Response
2035: 84 MW, Natural Gas CT
2035: 55 MW, Northeast CT retired
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2041-2042: 300 MW, Wind PPA Renew
2043: 25 MW, Pumped Hydro
2044-2045: 150 MW NW Solar
2044-2045: 150 MW, Solar w/ 150 MW x 4 hr Storage
2044-2045: 100 MW x 4 hr, Lithium-ion
27
Load reduction of 144 aMW due to Energy Efficiency by 2040
Page 614 Avista Corp. 2020 Electric IRP Appendices
DRAFT11) Clean Resource Plan
w/ Federal Tax Credits Extended
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2026: 39 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 200 MW, MT Wind
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027-2029: 300 MW, NW Solar
2027: 8 MW, Post Falls Upgrade
2028: 50 MW, Solar
2028: 50 MW, Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd Powerhouse
2033: 60 MW, Solar
2033-2035: 46 MW, Demand Response
2035: 55 MW, Northeast CT retired
2036-2040: 135 MW, Solar w/ 125 MW x 4 hr Storage
2039: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2042: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2043-2045: 200 MW x 4 hr, Lithium-ion
2045: 55 MW, Solar w/ 50 MW x 4 hr of Storage
28
Load reduction of 173 aMW due to Energy Efficiency by 2040
Page 615 Avista Corp. 2020 Electric IRP Appendices
DRAFT12) Least Cost Plan
w/ Low Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2027: 55 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 75 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 68 MW Long Lake 2nd
Powerhouse
2038-2039: 30 MW Demand Response
2041-2045
2041: 25 MW x 4 hr, Lithium-ion
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2044-2045: 75 MW Solar w/ 75 MW x 4 hr Storage
29
Load reduction of 152 aMW due to Energy Efficiency by 2040
Page 616 Avista Corp. 2020 Electric IRP Appendices
DRAFT13) Least Cost Plan
w/ High Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2029: 85 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 200 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2030: 68 MW Long Lake 2nd
Powerhouse
2031-2040
2031-2033: 75 MW, Mid-C PPA Renew
2035: 84 MW Natural Gas CT
2035: 55 MW, Northeast CT retired
2037-2040: 100 MW x 16 hr Liquid Air Storage
2041-2045
2041-43: 100 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043-2045: 125 MW x 4 hr, Lithium-ion
2044: 25 MW Pumped Hydro
2044-2045: 75 MW Solar w/ 75 MW x 4 hr Storage
30
Load reduction of 152 aMW due to Energy Efficiency by 2040
Page 617 Avista Corp. 2020 Electric IRP Appendices
DRAFT14) Least Cost Plan
w/ Lancaster PPA Extended Five Years
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2027: 8 MW, Post Falls Upgrade
2030: 30 MW, Demand Response
2031-2040
2031-2032: 75 MW, Mid-C PPA Renew
2031-2032: 55 MW Demand Response
2032: 257 MW, Lancaster PPA expires
2032: 200 MW MT Wind
2032: 84 MW Natural Gas CT
2032: 68 MW Long Lake 2nd
Powerhouse
2035: 55 MW, Northeast CT retired
2035: 84 MW Natural Gas CT
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW, Solar w/ 25 MW x 4 hr Storage
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW, Wind PPA Renew
2042-2045: 225 MW x 4 hr, Lithium-ion
2043: 25 MW x 16 hr Liquid Air Storage
2044: 50 MW, Solar w/ 50 MW x 4 hr Storage
2045: 2.5 MW, Demand Response
31
Load reduction of 141 aMW due to Energy Efficiency by 2040
Page 618 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Least Risk Plan
2021-2030
2022: 150 MW, NW Solar
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 257 MW, Lancaster PPA expires
2027: 308 MW, Natural Gas CCCT
2027-2028: 200 MW, MT Wind
2028-2030: 300 MW, NW Solar
2029-2030: 200 MW, NW Solar
2029-2030: 200 MW, Small Nuclear
2030: 308 MW, Natural Gas CCCT
2031-2040
2035: 55 MW, Northeast CT retired 2041-2045
2045: 5 MW, Solar
2045: 100 MW, NW Wind
2043-45: 50 MW, Mid-C PPA Renew
32
Load reduction of 67 aMW due to Energy Efficiency by 2040
Note: The least Least Risk Portfolio minimizes risk for 2030Page 619 Avista Corp. 2020 Electric IRP Appendices
DRAFT
25% Risk/ 75% Cost Plan
2021-2030
2022: 50 MW, NW Solar
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Solar
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 175 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 30 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2030: 170 MW, Solar w/ 25 MW x 4 hr Storage
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 55 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 25 MW x 16 hr Liquid Air Storage
2038: 25 MW x 16 hr Liquid Air Storage
2039: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW, Pumped Hydro
2044: 5 MW
2044: 25 MW x 4 hr, Lithium-ion
2044: 25 MW x 16 hr Liquid Air Storage
2045: 50 MW, Solar w/ 50 MW x 4 hr Storage
2045: 100 MW, NW Wind
2045: 50 MW x 4 hr, Lithium-ion
33
Load reduction of 143 aMW due to Energy Efficiency by 2040
Page 620 Avista Corp. 2020 Electric IRP Appendices
DRAFT
50% Risk/ 50% Cost Plan
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 60 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2028-2030: 300 MW, Solar w/ 300 MW x 4hr storage
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 25 MW, Demand Response
2035: 84 MW, Natural Gas CT
2035: 55 MW, Northeast CT retired
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2044: 100 MW x 16 hr Liquid Air Storage
2043-2044: 75 MW x 4 hr, Lithium-ion
2044: 50 MW, solar w/ 50 MW x 4hr storage
2045: 25 MW Pumped Hydro
34
Load reduction of 146 aMW due to Energy Efficiency by 2040
Page 621 Avista Corp. 2020 Electric IRP Appendices
DRAFT
75% Risk/ 25% Cost Plan
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 25 MW, NW Solar
2026: 257 MW, Lancaster PPA expires
2027: 308 MW, Natural Gas CCT
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2028-2030: 300 MW, Solar w/ 300 MW x 4hr storage)
2030: 50 MW, Small Nuclear
2031-2040
2035-2039: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2039: 30 MW, Demand Response
2041-2045
2042: 25 MW, Demand Response
2043: 25 MW, Pumped Hydro
2044: 150 MW x 4 hr, Lithium-ion
2045: 25 MW, Pumped Hydro
35
Load reduction of 125 aMW due to Energy Efficiency by 2040
Page 622 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Future Scenarios For Next TAC meeting
•Alternative load forecasts
–Electrification and roof top solar
–Economic cycles
•Electric market price scenarios
–Each of the previous scenarios w/ alternative prices
–Least cost strategies w/ alternative prices
•Other scenarios?
–For this IRP or the next
36 Page 623 Avista Corp. 2020 Electric IRP Appendices
DRAFT
Carbon Abatement Curve Proposal
•Use “Expected Case” market forecast
•No change to capacity build
•Add generator/load in 100 MW in NW area
•Estimate “system” emission reduction by difference between 2030 expected case and
sensitivity
•Estimate cost of reduction concept
•Calculate the estimated societal $/metric ton
•Abatement options in Avista’s system
–Generation sources:
•Add: solar, wind, hydro, storage, storage + renewable
•Remove: CCCT, CT, coal
–End uses: water heater, furnaces, (to NG, away from NG), energy
efficiency
–Transportation: Electric vehicle vs gasoline/diesel
•Results at next TAC meeting
37 Page 624 Avista Corp. 2020 Electric IRP Appendices
Attendees: TAC 5, Tuesday, October 15, 2019 at Avista Headquarters in Spokane, Washington:
Logan Callen, City of Spokane; Darrell Soyars, Avista; Terrence Browne, Avista; Garrett Brown, Avista; Zach Genta, Clenera; Clint Kalich, Avista; Linda Gervais, Avista; Justin Cowley, Clear Water Paper; John Barber, Rockwood Retirement Community; Dave Van Hersett, Customer; Kirsten G. Wilson, WA DES Energy Program; Jennifer Snyder, Washington Utilities and Transportation Commission; Jason Thackston, Avista; Cadie
Olsen, City of Spokane; Kathlyn Kinney, Biomethane, LLC; Tom Pardee, Avista; James Gall, Avista; Collins Sprague, Avista; Greg Rahn, Avista; John Lyons, Avista; Rachelle Farnsworth, Idaho Public Utilities Commission; Amy Wheeless, Northwest Energy Coalition; Jim Le Tellier, 350 Spokane; David Howarth, National Grid Ventures; Michael Eldred, Idaho Public Utilities Commission; Barry Kathrens, 350 Spokane.org; and Grant
Forsyth, Avista.
Phone Participants:
John Chatburn, Idaho Office of Energy and Mineral Resources; Damon Zentz, City of
Spokane; Nancy Esteb, Renewable Energy Coalition; and remaining phone participants
did not identify themselves.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses are in italics, and
significant points raised by presenters that are not shown on the slides are also
included.

Introductions, Updates and TAC 4 Recap, John Lyons
No additional notes or commentary.

Energy Imbalance Market Update, Scott Kinney
Dave Van Hersett: What is an organized market? Will talk about organized markets later
in the presentation.
John Barber: Is this just a bunch of people calling back and forth? Yes, but there is
more electronic communication now.
Dave Van Hersett: Kind of like the ICP? Yes, going back quite a ways.
Kathlyn Kinney: What percentage of electricity do we have to buy? Depends. Spring,
we are a net seller. Summer, we may go to market, usually at the Mid-Columbia trading
prices. It changes depending on the company’s needs and the market prices.
Jim Le Tellier: Hydro percentage in mix? About 50%.
Page 625 Avista Corp. 2020 Electric IRP Appendices
Dave Van Hersett: Is CAISO by hour? It’s a day ahead, 15 minute and a five minute
market. Looking for optimized resources to impact dispatch cost. Readjust resources
differently based on economics as we get closer to real time.
Dave Van Hersett: Who owns CAISO? A government agency with a board selected by
the Governor of California.
Dave Van Hersett: Easier to construct [new resources]? Maybe, because it is looking at
a bigger footprint.
Dave Van Hersett: Savings? Cost savings for customers based on a past operations.
Dave Van Hersett: I’m struggling with what’s the downside since ours is among the
lowest cost in the region. Do we go up and others go down? Will talk about that later,
but we expect more revenues and cheaper dispatch.
Jason Thackston (Slide 7): We do this already outside the day, but not inside the hour
Since the 1980s we have been doing this on the hour.
Dave Van Hersett: Saying hour-by-hour, now into the 5 minute market? Yes, good way
of putting it.
Cadie Olsen: What drove early adopters? Renewable energy penetration. Lower
dispatch (30 - 35%), load following costs, and some by Commissions and economics.
Jim Le Tellier: Why did PacifiCorp join? Utah, load pockets in Oregon. Better
optimization between both utilities.
Slide 13: A little bit optimistic numbers based on methodology, but they are indicative.
Dave Van Hersett: Gross revenue for Avista? $800 to $900 million gross revenue
requirement required. This is just the in-hour part.
Jason Thackson: 3% of power supply expenses.
Jim Le Tellier: Does the entire EIM share a transmission grid? Yes, participants still own
their transmission. They allocate a percentage for market transactions. Allow anything
to be used within the hour if not already paid for. Transmission is in effect free for EIM
transactions.
Dave Van Hersett: Will EIM reduce staff? No, we are actually adding bodies.
Technology and models allow us to trade within the hour.
Slide 15 – It was getting difficult for us to find a trading partner around the summer of
2018. There was not enough market liquidity. All of the utilities around us –
Northwestern Energy, BPA, Idaho Power – joined or are joining the EIM.
Jim Le Tellier: Where is Rattlesnake Wind located? The Othello area, in Washington.
Page 626 Avista Corp. 2020 Electric IRP Appendices
Scott Kinney: PURPA changes. Recent changes in Washington expanded size
qualifying for different costs and from 5 to 15 years. We have seen additional requests
for PURPA. Prices are still falling, probably for a period of time as more renewables are
added to the system.
Clint Kalich: Energy only. But, if bringing capacity, projects will get more benefit.
Capacity over winter nights will be getting even more benefit.
Who do we talk to about PURPA? Either Clint Kalich or Steve Silkworth.
Dave Van Hersett: Is there a disadvantage to being in this group? The large technology
commitment is costly. Do they get to call on our resources? Only if we voluntarily bid in.
Jennifer Snyder: How often? Every five minutes. Hydro flex makes sense every hour.
Dave Van Hersett: Typically, what is the technology needed for the EIM? Outage
management system, bidding system, and settlement system.
Dave Van Hersett (slide 17): $6 million net. No, gross. 8 to 9-year breakeven. Show
chart 18. Most utilities actually seeing 3 to 5 times the study benefits.
Jennifer Snyder: When was the study done? 2017 and updated in 2018; and cost done
in 2015 and updated in 2018.
Dave Van Hersett: If Avista keeps getting more renewables, does this help? Absolutely,
expect about a 35% reduction in costs to integrate renewables. Flex hour hydro allows
us to bid in.
Dave Van Hersett: In the long run, higher base of renewables might be better in the long
term. Yes, Idaho Power is similar to us and we see a similar market potential.
Jim Le Tellier: Nice to have economic benefits, but many non-economic benefits that
they might have even joined for.
Cadie Olsen: In the penultimate slide, how many city people are you interfacing with?
Our citizens are our customers with 700 connections plus a generation interconnect.
Touchpoints at generators. Not anticipating city resources being bid into the EIM.
Jim Le Tellier: As far as interconnection renewables, are they being drawn from other
states? Wind from Montana? Yes, includes renewables from other areas.
Kirsten Wilson: Any preliminary evaluation of the shutdowns with PG&E? Some
assessment, but minimal from the EIM’s perspective. More exposure in California with
the only participant.
Scott Kinney: More opportunity to integrate resources. Possibility depending on size and
capability and controls. Costs may exceed benefits.
Jim Le Tellier: As Colstrip goes offline, will there be more gas or renewables? James
will be covering that later today.
Page 627 Avista Corp. 2020 Electric IRP Appendices
Logan Callen (Slide 18): PSE? More aggressive air study assumption and not as
integrated through BPA.
Amy Wheeless: As Seattle comes online, will there be more benefit for PSE? Yes, we
would expect it.
Dave Van Hersett: Does this affect our ability to stand alone? No, we are required to be
resource sufficient to be able to bid in to the EIM.
Scott Kinney: People vs. algorithms. Dispatch is fully automated for dispatch changing
but still have a final human check. This may change over time.

Storage and Ancillary Storage Analysis, Xin Shane
Dave Van Hersett: What is an example of an ancillary service? Regulation.
Dave Van Hersett: Can you get all out that you put in? No, only about 70% round trip
efficiency, which is the downfall of this type of storage.
Clint Kalich (Slide 6): Only about 10% of the 1 MW cap to pull hard off system. Only a
small amount of the total can be quickly used.
Barry Kathrens: Is capacity seasonal? Did not consider it in this study. Engineers say
there are many different factors like temperature.
Rachelle Farnsworth: Is the typical performance for this type of battery to charge and
recharge? Yes, when price is high it is discharging and when low it is charging.
John Barber: Was Avista’s battery shut down? Yes. It was the first one made by the
manufacturer and was shut down for mechanical issues.
Jason Thackston: The battery had a leak on a customer’s premises, so we removed it.
Cadie Olsen: Did you learn anything different from other empirical studies? Speed
affecting overall efficiency, system setting comprehensive operational mod, testing
linear model and refining it.
Kirsten Wilson: Intent was to study quite a few (seven) operating scenarios and how
batteries responded. Different parts worked on different streams.
David Howarth: When you say one third, is that equivalent to water availability or two
thirds hydro? Capped two units on Noxon Rapids and one unit on Cabinet Gorge –
cascading system.
Jim Le Tellier: Pumping from lower to higher levels? Yes, that is what we are studying.
Two reservoirs with a two way turbine.
Dave Van Hersett: Two way is pump or generate? Yes.
Page 628 Avista Corp. 2020 Electric IRP Appendices
Dave Van Hersett: Could we do that at Noxon Rapids?
Jason Thackston: Not a reservoir at Noxon. Hard when licensing is challenging, not a
closed system.
Jim Le Tellier: With the EIM there could be pumped storage in other regions. Some in
Montana is already permitted.
Jim Le Tellier: Astronomical starting cost, but a lot more benefit going forward to
consider.
Clint Kalich: Some comments for the regulators in the room to consider on slide #12. It
is difficult and complicated to do these studies. If we can create ancillary services, the
value lies in arbitrage. The left 1/3 of hydro in the portfolio, and then saw the benefits of
arbitrage. Most of the value is when we get energy in the system whether owned, PPA,
or cheaper to just store renewables.
David Howarth: With the existing hydro flexibility on the system, wondering on a low
hydro year how it affects flexibility. Modestly ancillary benefit in low hydro years.
Dave Van Hersett: Are we not looking at pumped storage yet? Next presentation.
Amy Wheeless: Not that many pumped storage projects in the northwest. Got to wait
until after lunch.

Preliminary Preferred Resource Strategy, James Gall
Jim Le Tellier: Does Avista have an R&D department? We keep up with developments
and participate in new technologies. Idaho funds some R&D. We dabble, but are not
focused on R&D.
Jason Thackston: University District, Energy Impact Partners Fund investor and Clean
Energy Grants.
Scott Kinney (Slide 3): How much could we drop the gap by renewing contracts as they
expire, economic competition, and repowering of worn out wind projects?
Matt Nykiel: How are Idaho RECs managed and sold. RECs are recorded and
transferred in WREGIS.
Jim Le Tellier: The goal doesn’t sound real positive. If you have to have new
technology, we want to see Avista as a leader.
Jason Thackston: We are working in the western US and using the Clean Energy Grant.
Jennifer Snyder: You are part of NEAA too.
Kathlyn Kinney: Does EIM help? It helps us manage, but is not a capacity market.
Page 629 Avista Corp. 2020 Electric IRP Appendices
Scott Kinney: EIM participants have to show how they can meet their own resource
needs.
Matt Nykiel (Slide 4): Are there asterisks to Avista’s goals [100% clean] that we can
read about?
Jason Thackston: The web site has a section. It is correct there is not a lot of detail on
it. We need to see improvement on energy storage. 6 pm on a January night is our peak
load and battery storage is not there yet. We are still working on it ourselves. Your
definition of affordability may be different than mine. Hypothetically, is 15% worth it?
Across the river from here, no. And we have to do this in a way that maintains reliability.
Matt Nykiel: Is Avista conducting a survey showing what is affordable?
Barry Kathrens: Is this a thing from the Nadine [Woodward mayoral] debate? No,
difference was between completely 100% renewable versus an aspirational goal.
Sometimes the details in politics don’t always line up.
Amy Wheeless (Slide 5): Hydro from BPA, doesn’t respond to an RFP? We can’t just
assume BPA hydro availability. They have told us an RFP is not how they typically want
to interact.
Jim Le Tellier: BPA power is $90? Yes, that is what they are required to sell at.
Fred Huette: Transmission is a separate discussion. BPA hydro, know they have
interest in a PGE capacity deal. Difficulties in how to model it, but not leave an
impression that we are not interested in it. Maybe we could model it as northwest
capacity.
Matt Nykiel: What is social cost of carbon cost? $80 for Washington portion, see the last
TAC meeting presentations for more details.
Rachelle Farnsworth (Slide 6): How will you be excluding additional costs for Idaho?
Like the Social Cost of Carbon. Model solves for a peaker, only Washington has the
cost. Then we allocate costs between the two states. Would depend on what we would
do without the law. If Idaho needs wind, they pay their part. If not, all of the costs go to
Washington. Also assign price of RECs, incremental cost of the resource over market,
to transfer from Washington to Idaho.
Rachelle Farnsworth: Building in costs. Need to keep track of additional costs that
should not be attributed to Idaho.
Matt Nykiel: If the decision is made to keep it left open, how would Colstrip get allocated
[after 2025]? Not sure yet, it would be a Rates questions and handled outside of the
IRP.
Rachelle Farnsworth: Just because Washington doesn’t take the electrons, there are
still remediation costs they are responsible for.
Page 630 Avista Corp. 2020 Electric IRP Appendices
Jennifer Snyder: Treating things as of today until 2025. After that, CETA allows recovery
for remediation.
Matt Nykiel: Incremental Idaho costs post 2025.
Jim Le Tellier: On Colstrip, if Westmoreland completely goes under, do the five owners
have other coal sources.
Jason Thackston: Six owners, but the air permit doesn’t permit new coal. The new coal
contract is being finalized.
Slide 11: Red is cost effective, black is not cost effective and orange maybe cost
effective.
Amy Wheeless (Slide 11): Is this based on AEG? Yes. Water heating does – with and
without CETA required device. Not sure why yet. Didn’t originally include. Added it back
two weeks ago and will follow up later.
Fred Huette: Not CETA, 1444, unless they (Commerce) grants some sort of extension.
With a cost per kW-year well under $100/kW-year. What is the name of the consultant?
AEG.
Jennifer Snyder: For variable peak pricing and time of use, are there plans to have
pilots? Still have to figure that out. Probably about 10 different things that will still have
to be sorted out to make these happen.
Fred Huette (Slide 13): Effectively, Montana wind is a 40% capacity value. Yes, capacity
contribution could be different. All sites are not equal. Also, if it is really cold here and in
Montana, they [wind turbines] shut down about 25 degrees below zero. Probability of
minus 25 in Montana and really cold here.
Fred Huette: Really first of utilities putting direct value for Montana winter wind capacity.
May consider across Montana. Appreciate the work.
Kathlyn Kinney: Where does renewable natural gas fit in? Who gets it and at what cost.
Levelized cost is $10 - $20 per Dth. You can sell the RIN to drive down the cost, but
then the renewableness goes away. Can it clean up gas? Yes. Will it be available?
Maybe, but will it go to power, the LDC, or will it even be developed? Not modeled yet,
but as its gets closer to 100%, renewable natural gas competes.
Jim Le Tellier: What is the problem with transmission? Is it off, transmission rights
allocation, and overbuilding wind. We own a portion of the line from Montana and have
a BPA contract for the rest.
David Howarth: What is long duration for storage? 40 hours per week.
Amy Wheeless (Slide 13): Not too many sites [pumped hydro]? Probably four to five
sites and one with long duration. Will require more time and money to find other viable
sites. What’s available particularly for open loop?
Page 631 Avista Corp. 2020 Electric IRP Appendices
Fred Huette (Slide 14): Liquid air. Haven’t hear much about it, but love the efficiency.
Yes, sub 70% efficiency, longer duration, long project life, and better if co-located with a
thermal plant.
Kirsten Wilson (Slide 15): Last round of the Clean Energy Grant funding went to
Tacoma for Praxair for liquid air storage. We tried for that funding too.
Matt Nykiel: What is the risk of a stranded asset, like a gas plant in 2026 or will be
required to be offset with RECs. It looks at all costs. Mandate, no.
Rachelle Farnsworth: How is the liquid air modeled? Based on cost projections.
Pumped hydro is number 1 for long duration, liquid air is number two for long duration
and lithium ion is number 3 when paired with solar for the tax credit plus the value of
short term storage.
Slide 17: Reliability. This is where portfolio could change. Colstrip is two relatively small
and significantly reliable units. 14% to 16% planning margin.
Fred Huette (Slide 17): Why does size make an impact on reliability? Redundancy of
two smaller units in the model. How much do we control versus how much we rely on
our neighbors. Yes, now; later not so much. This is a regional, not just and Avista issue.
Jennifer Snyder: Through 2045? No, 2030 only on the reliability study. We are on the
high side because of a single 320 MW resource out of 1,700 MW, the largest utility shaft
risk for a single unit in the west.
Scott Kinney (Slide 18): To clarify, this is system, not just Washington.
Clint Kalich: PURPA requires us to pay for energy and capacity, but we don’t pay a
clean premium under PURPA. We regard that as a put for the developer.
Matt Nykiel (Slide 24): Getting back to the transmission issue at Colstrip, there are at
least five other utilities. Does Avista lose out if they don’t make a decision? We are
contractually covered until the late 2020s.

Preliminary Portfolio Scenario Results, James Gall
No notes to add.

Page 632 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
Tuesday, November 19, 2019 Conference Room 130
Topic Time Staff
Introductions and TAC 5 Recap 9:30 Lyons

Review of PRS 9:45 Gall
Break 10:45 Portfolio Scenario Results 11:00 Gall Lunch 12:00

Portfolio Scenario Results Continued 1:00 Gall

Break 2:00 2020 IRP Action Items & Overview 2:15 Lyons Adjourn 3:00

Page 633 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Sixth Technical Advisory Committee Meeting
November 19, 2019
Page 634 Avista Corp. 2020 Electric IRP Appendices
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next twenty years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2 Page 635 Avista Corp. 2020 Electric IRP Appendices
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 in all or some of the process
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 was the latest to be able to complete studies in time for
publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3 Page 636 Avista Corp. 2020 Electric IRP Appendices
TAC #5 Recap –October 15, 2019
•Introductions and TAC 4 Recap, Lyons
•Energy Imbalance Market Update, Kinney
•Storage and Ancillary Service Analysis, Shane
•Preliminary Preferred Resource Strategy, Gall
•Preliminary Portfolio Scenario Results, Gall
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-company/integrated-
resource-planning
4 Page 637 Avista Corp. 2020 Electric IRP Appendices
Today’s Agenda
9:30 –Introductions and TAC 5 Recap, Lyons
9:45 –Review of PRS, Gall
10:45 – Break
11:00 –Portfolio Scenario Results, Gall
Noon –Lunch
1:00 –Portfolio Scenario Results Continued, Gall
2:00 – Break
2:15 –2020 IRP Action Items and Overview, Lyons
3:00 –Adjourn
5 Page 638 Avista Corp. 2020 Electric IRP Appendices
2020 IRP and 2021 IRP Key Dates
•Draft IRP released to TAC members December 18, 2019
•Comments from TAC members are to be returned to Avista by
January 15, 2020
•IRP team will be available to address comments with
individual TAC members or the entire group if needed
•This IRP will be published February 28, 2020
•Washington IRP due date moved for all IOUs: draft due
January 1, 2021 and final IRP due April 1, 2021 to allow time
for CETA rule making
6 Page 639 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated Resource Plan
“Preferred” Resource Strategy
James Gall, IRP Manager
Sixth Technical Advisory Committee Meeting
November 19, 2019
Page 640 Avista Corp. 2020 Electric IRP Appendices
What Are Avista’s Physical Resource
Needs?
Main focus: Winter Peak:
Includes 14% Planning Margin + Reserves
Avista is also short in summer and on an annual average basis
beginning in 2027
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Available Resources Net Requirement
Gap
2026: 14 MW
2027: 302 MW
2030: 325 MW
2035: 495 MW
2040: 537 MW
Key Losses:
Colstrip: 2025*
Lancaster: 2026
Mid-C: 2030
Northeast: 2035
2 * Colstrip is assumed offline at the end of 2025 for planning purposes only. Avista’s ultimate decisions regarding
Colstrip are still to be determined.
Page 641 Avista Corp. 2020 Electric IRP Appendices
Washington SB5116 Clean Requirements
2026: Colstrip can no longer serve Washington Load
2030: 80% energy delivered over a four-year period is clean and 20% can be RECs
2045: Goal to be 100% clean (will require new technology to stay under cost cap)
Gap
2030: 54 aMW
2035: 130 aMW
2040: 182 aMW
2045: 353 aMW
Key Losses:
Mid-C: 2030
Lind: 2039
Rattlesnake: 2040
Palouse: 2043
Assumes: Idaho customers sell offsets to Washington Customers
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Idaho Available Hydro RECs
Washington Net Requirement
Washington Retail Sales
3 Page 642 Avista Corp. 2020 Electric IRP Appendices
Avista’s Clean Electricity Goal
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Total Existing Resources System Retail Sales (aMW)
2027: 100% net clean portfolio wide (cost effective considerations)
2045: 100% clean (cost effective considerations and technology)
Gap
2027: 339 aMW
2030: 360 aMW
2035: 426 aMW
2040: 448 aMW
2045: 562 aMW
4 Page 643 Avista Corp. 2020 Electric IRP Appendices
Resource Options
Clean
•Wind (WA/OR/MT)
•Solar (WA/ID/OR)
•Biomass (WA/ID)
•Hydro Upgrades (MS, LL)
•Hydro (Mid-C)
•Hydro (BPA)
•Geothermal
•Nuclear
•Energy Efficiency
•Demand Response
Other
•Natural Gas CT
•Natural Gas CCCT
•Storage
–Pumped hydro
–Lithium-ion batteries
–Liquid air
–Hydrogen
–Flow batteries
•Regional Transmission
5 Page 644 Avista Corp. 2020 Electric IRP Appendices
Preferred Resource Strategy Decision
Process
•Uses Mixed Integer Program (MIP) to find least cost solution
meeting capacity, energy, and renewable constraints for the system
between 2021 and 2045.
•Only known model with full co-optimization of energy efficiency and
demand response with supply side resources.
–Capable of co-optimization of T&D system with power system
•Accounts for societal preference Washington state planning criteria
–(Social Cost of Carbon, 10% cost advantage from energy efficiency,
upstream pipeline emissions, etc.)
•Non-modeled utility revenue requirements assumes an increase of
two percent per year.
6 Page 645 Avista Corp. 2020 Electric IRP Appendices
Changes Since Last TAC meeting
•Lowered Montana wind peak contribution due to
transmission losses
•Increased long-duration pumped storage
capacity contribution
•Increased planning margin in PRiSM to end with
a reliable system
7 Page 646 Avista Corp. 2020 Electric IRP Appendices
Reliability Study Results
•22.6% planning margin (14% + reserves) without Colstrip and non-
dispatchable resources is too low.
•The resulting draft reliability metrics for the PRS required an
equivalent 24.6% planning margin (equivalent to 350 MW of CTs):
8
Reliability
Metric
PRS (TAC 6)PRS (TAC 5)Updated
Adequate
System (w/o
Colstrip & w/
CTs)
TAC 2
Adequate
System
Result (w/
Colstrip &
CTs)
LOLP 5.3%7.0%5.2%4.9%
LOLH 2.02 3.10 1.79 1.85
LOLE 0.17 0.25 0.14 0.16
EUE 330 MWh 552 MWh 264 MWh 318.7 MWh
Page 647 Avista Corp. 2020 Electric IRP Appendices
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2017 IRP 2020 IRP
Energy Efficiency Results
45% increase
Note: excludes T&D losses9Page 648 Avista Corp. 2020 Electric IRP Appendices
Where is the Cost Effective Energy
Efficiency Savings?
Residential
40%
Commercial
49%
Industrial
11%
2040 Customer Class Savings
0.7
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44.6
0 10 20 30 40 50
Office Equipment
Process
Miscellaneous
Food Preparation
Cooling
Heating
Electronics
Refrigeration
Motors
Appliances
Ventilation
Space Heating
Exterior Lighting
Water Heating
Interior Lighting
Average Megawatts
2040 Cumulative Savings
10 Page 649 Avista Corp. 2020 Electric IRP Appendices
Preferred Resource Strategy
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 175 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2025-2030: 76 MW, Demand Response
2026/27: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 32 MW, Demand Response
2035: 55 MW, Northeast CT retires
2035: 68 MW, Long Lake 2nd
Powerhouse
2036-40: 75 MW x 16 hr, Liquid Air Storage
2037: 1 MW Demand Response
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042: 2.5 MW, Demand Response
2042-2045: 300 MW Wind PPA Renew
2042-2045: 300 MW x 4 hr, Lithium-ion
2044: 55 MW, Solar w/ 50 MW x 4hr, Storage
11
Load reduction of 187 aMW due to Energy Efficiency by 2045
Page 650 Avista Corp. 2020 Electric IRP Appendices
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Demand Response
Summer Programs Evaluated
•Central A/C
•Smart Thermostats-Cooling
•Thermal Energy Storage
12
25 MW Load Control is also included, but not shown as its prices would likely be negotiated
Cost Effective Start Dates
Shown in Red
2025: Variable Peak Pricing
2029: Smart Thermostats
2029: Industrial Load Control
2031: Time of Use
2031: Third Party Contracts
2037: Real Time Pricing
2042: Ancillary Services
Page 651 Avista Corp. 2020 Electric IRP Appendices
2022-2025 Generation Action Plan
•2022-2023 RFP
–Early acquisition to take advantage of federal tax credits
–Anticipate 300 MW Wind PPA (84 aMW)
•100 MW in MT and 200 MW in NW
•locations depend on transmission availability/price
–Solar could replace wind depending on pricing and future price shape forecasts
–Potential for additional resource acquisitions in support of Avista’s clean
electricity goal subject to reliability and affordability considerations.
•2024: Kettle Falls Upgrade
–Incrementally increase Kettle Falls generating capability by installing larger sized
equipment as part of modernization
•2025: 222 MW, Colstrip removed
–Per CETA, Colstrip will not serve Washington loads after 12/31/2025
–The plants future for Idaho customers or wholesale transactions is yet to be
determined
13 Page 652 Avista Corp. 2020 Electric IRP Appendices
2026-2030 Generation Action Plan
•2026: 175 MW, Pumped Hydro
–Assumes low cost, long duration pumped hydro solution is available.
–If resource is not available or price exceeds cost effectiveness tests, siting a
similar sized NG peaker is the next least cost option.
–Sizing will depend on reliability requirements of future power supply system.
•2026: 24 MW, Rathdrum Upgrade
–Increases each unit by 12 MW using a supplemental compression technology or
alternative technology.
•2026: Lancaster PPA expires in October
•2026/27: 200 MW, MT Wind
–Utilizes Colstrip transmission,
–If not available, additional NG and renewables are required.
•2027: 8 MW, Post Falls Upgrade
–Increase generating capability as part of modernization project to maintain FERC
licensing requirements.
14 Page 653 Avista Corp. 2020 Electric IRP Appendices
2031-2040 Generation Action Plan
•2031: Attempt to renew Mid-C PPA contracts
•2035: Northeast CT retires
•2035: 68 MW Long Lake 2nd Powerhouse
–Seek CETA certification as an eligible resource
•either as 2nd powerhouse and/or reconfiguration of single new powerhouse.
–Begin licensing process
–Optimize the site for cost, capacity, and environmental concerns
–Earlier on-line date may be possible
–NG Peaker and renewable resource would be alternative to this project
•2036: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2038: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2040: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
15 Page 654 Avista Corp. 2020 Electric IRP Appendices
2040-45 Generation Action Plan
•2041: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2042-2045: 300 MW Wind PPA Replacement
–Existing PPAs begin to expire
–Repowering is likely necessary
•2042-2045: 300 MW x 4 hour, Lithium-ion (or lowest cost alternative)
•2044: 55 MW, solar w/ 50 MW x 4 hour storage
16 Page 655 Avista Corp. 2020 Electric IRP Appendices
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"Clean" Market Purchases
Clean Generation
Sales Forecast
PRS Comparison to Corporate Clean
Electricity Goal
Goal: Serve customers with 100% cost effective clean electricity
PRS meets 89% of corporate goal by 2027
Notes:1) Prior to 2030, Avista is a net energy seller to the market2) “Clean” market purchases is measured as the regional
generation mix’s CO2 mix compared to a CCCT17
2027 Gap: 1 million MWh
Page 656 Avista Corp. 2020 Electric IRP Appendices
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20
3
3
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5
Mi
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M
e
t
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T
o
n
s
Net Market Purchases/Sales
New Resources
Current Resources
2018 Actual
Total Net Emissions
Total Net Emissions w/ EV Offsets
PRS: Greenhouse Gas Emissions Forecast
80% to 85% net reduction after 2027
18
Note: Electrification of transportation lowers Avista’s emissions below zero as offsetting
petroleum emissions are lower then Avista’s power related emissionsPage 657 Avista Corp. 2020 Electric IRP Appendices
0
5
10
15
20
25
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
20
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n
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p
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k
W
h
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)
Rev. Req.
Rev. Req. + 1 Stdev
Rev. Req. 95th Percentile
Avg Rate
PRS: Cost/Rate Forecast
19
System PVRR: $11.83 billion
Today’s Rates: 8.4 c/kWh Idaho and 8.9 c/kWh Washington
2030 Rate: 10.4 cents/kWh
2045 Rate: 14.1 cents/kWh
Note: Assumes non-power supply modelled costs escalate at 2 percent per yearPage 658 Avista Corp. 2020 Electric IRP Appendices
Cost Comparison between PRS and LC
Portfolio w/o CETA
Note: State allocation factors and resource designation will affect these results for each state
In
c
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C
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Page 659 Avista Corp. 2020 Electric IRP Appendices
Avoided Costs- Power
Methodology
Energy Prices: Electric market price forecast
Capacity Price: Cost difference between building
resources to meet capacity needs as compared to
not building any new capacity. This cost is divided
by the amount of added capacity and is levelized
and tilted (2% inflation) based on the first capacity
deficit year.
Clean Premium:Difference in total cost of the
PRS and the Least Cost Portfolio to meet capacity.
This cost is divided by the amount of additional
dispatch energy and is levelized and tilted (2%
inflation)starting with the first year of renewable
acquisition.
Clean Premium (w/ Tax Incentive): This shows
the premium associated with renewables assuming
the resource includes either the PTC or ITC.
21 Page 660 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated Resource Plan
Scenario and Sensitivity Analysis
James Gall, IRP Manager
Sixth Technical Advisory Committee Meeting
November 19, 2019
Page 661 Avista Corp. 2020 Electric IRP Appendices
Agenda
•Portfolio analysis using the stochastic “expected
case” market forecast
•Portfolio analysis with alternative market prices
(deterministic)-sensitivity analysis
•Electrification scenario
2 Page 662 Avista Corp. 2020 Electric IRP Appendices
Portfolio Scenarios
Page 663 Avista Corp. 2020 Electric IRP Appendices
Portfolio Scenario Overview
•Uses same electric price forecast, but different resource
assumptions.
•Use optimization to create portfolio, but use different
constraints for each scenario.
•View financial results of each portfolio along with
resource selection.
•No reliability analyses are completed for portfolio
scenarios.
4 Page 664 Avista Corp. 2020 Electric IRP Appendices
Scenarios
1. Preferred Resource Strategy
2. Least Cost Plan-without CETA
3. Clean Resource Plan: 100% net clean by 2027
4. Rely on energy markets only (no capacity or renewable additions) without CETA
5. 100% net clean by 2027, and no CTs by 2045
6. Least Cost Plan without pumped storage or Long Lake as options
7. Colstrip extended to 2035 without CETA
8. Colstrip extended to 2035 with CETA
9. Least Cost Plan with higher pumped storage cost
10. Least Cost with federal tax credits extended
11. Clean Resource Plan with federal tax credits extended
12. Least Cost Plan with low load growth (flat loads-low economic/population growth)
13. Least Cost Plan with high load growth (high economic/population growth)
14. Least Cost Plan with Lancaster PPA extended five years (financials will not be public)
15. Least Cost Plan with one Colstrip unit operating through 2035
Others: Efficient Frontier portfolio (least risk, 75/25, 50/50, and 25/75)
5 Page 665 Avista Corp. 2020 Electric IRP Appendices
Load Scenarios
Forecast Winter Peak Low Load Scenario Winter Peak
High Load Scenario Winter Peak Forecast Annual Average
Low Load Scenario Annual Average High Load Scenario Annual Average
Scenarios are based on changing GDP assumptions: The
change effects employment and population growth leading
to load changes.
+152 MW
-136 MW
+96 aMW
-89 aMW
6 Page 666 Avista Corp. 2020 Electric IRP Appendices
Portfolio
outside of
portfolio
constraints
Efficient Frontier Overview
Ri
s
k
Cost
Least cost-
highest risk
portfolio
Highest
cost-least
risk portfolio
Inefficient
portfolio
7 Page 667 Avista Corp. 2020 Electric IRP Appendices
$0
$10
$20
$30
$40
$50
$60
$900 $1,000 $1,100 $1,200 $1,300
20
3
0

P
o
w
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r

S
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p
p
l
y

C
o
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t

S
t
d
e
v
2021-45 Levelized Annual Revenue Requirement
Least Risk25/75
50/50
75/25
Least Cost
Efficient Frontier Results
#4: Rely on Energy Markets Only
#2: Least Cost Plan w/o CETA#7:
Colstrip
Extended w/o CETA #1: PRS#10: LC w/
Tax Credits
Extended
#8: Colstrip
Extended w/
CETA
#3 Clean Resource Plan
#11 Clean Resource Plan
w/ Tax Credits
#5 No CTs by 2045
#6 Least Cost w/o P/S or Long Lake
#9: LC w/ higher P/S costs
8 Note: excludes portfolios after #12
Page 668 Avista Corp. 2020 Electric IRP Appendices
2030 Portfolio Resource Selection
9
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Page 669 Avista Corp. 2020 Electric IRP Appendices
2040 Portfolio Resource Selection
10
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Page 670 Avista Corp. 2020 Electric IRP Appendices
2045 Portfolio Resource Selection
11
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Page 671 Avista Corp. 2020 Electric IRP Appendices
Annual Cost Comparison
12
PVRR (Millions)
Page 672 Avista Corp. 2020 Electric IRP Appendices
Rate Comparison
sorted by 2045 rates
13
Cents per kWh
Page 673 Avista Corp. 2020 Electric IRP Appendices
Portfolio Tail Risk
(95th percentile minus expected cost, excludes Social Cost of Carbon)
14 Page 674 Avista Corp. 2020 Electric IRP Appendices
PVRR Risk Adjusted Comparison
Sorted by TailVar without Social Cost of Carbon (SCC)
15
$11.0
$11.5
$12.0
$12.5
$13.0
$13.5
$14.0
$14.5
$15.0
10. LeastCost w/federal taxcreditsextended
12. LCPLowEconomicGrowth
4. Rely onEnergyMarketsOnly w/oCETA
8. Colstrip2035 w/CETA
1. LeastCost Plan/PRS
14. LCP w/LancasterPPA
11. CRPw/ federaltax creditsextended
9. LCP w/Higher P/Scost
7. Colstrip2035 w/oCETA
6. LCP w/oPS/Hydro 2. LCP-w/o CETA 2. LCP-w/o CETA EfficientFrontier:25%Risk/75%Cost
13. LCPHighEconomicGrowth
EfficientFrontier:50%Risk/50%Cost
3. CleanResourcePlan(CRP)
5. CRP-No CTs EfficientFrontier:75%Risk/25%Cost
EfficientFrontier:Least Risk
PV
R
R

(
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Page 675 Avista Corp. 2020 Electric IRP Appendices
Annual Greenhouse Gas Comparison
16
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(e
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)
Page 676 Avista Corp. 2020 Electric IRP Appendices
Annualized Greenhouse Gas Emissions
(Levelized using 2.5% discount rate)
17 Page 677 Avista Corp. 2020 Electric IRP Appendices
-$60
-$40
-$20
$0
$20
$40
$60
$80
$100
-0.6 -0.4 -0.2 0.0 0.2 0.4 0.6Ch
a
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t
f
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i
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#
2

(M
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s
)
Change in Levelized GHG Emissions from Portfolio #2 (Millions)
Cost vs. GHG Emissions
#1-PRS
#3-Clean Resource Plan
#4-Rely on Energy
Markets Only (w/o
CETA)
#5-Clean Resource Plan-No CTs
#6-LCP w/o PS/Hydro #7-Colstrip
2035 w/o CETA
#8-
Colstrip
2035 w/ CETA
#10-LCP w/ Federal Tax
Credits Extended
#9-LCP w/ Higher P/S
Cost
#11-CRP w/ Federal Tax Credits Extended
#12-LCP Low Economic Growth
#14-LCP w/ Lancaster
PPA extended
#13-LCP High
Economic Growth
Implied Carbon Levelized Carbon Prices#1. PRS: $55/metric ton
#3. CRS: $144/metric ton
#5. CRS No CTs: $167/metric ton
18 Page 678 Avista Corp. 2020 Electric IRP Appendices
Scenario Results Summary Table
19 Note: Costs do not include Social Cost of Carbon, but included in optimization
Portfolio
Number Portfolio name
Cost 2021-
2045 (PVRR)
(millions)
Cost 2021-
2030 (PVRR)
(millions)
2030 Risk
(millions)
2030 Rate
(c/kWh)
2045 Rate
(c/KWh)
Levelized
R.R.
Page 679 Avista Corp. 2020 Electric IRP Appendices
Resource Acquisition Decision Chart
(Excluding Energy Efficiency)
20

( g gy y)

2020-21 “Clean
Energy” RFP: 221 aMW
2021 Capacity RFP: Up to 345 MW Net Winter Capacity
Colstrip Closure Timing (2026 - 2035)
2020-2025 2026-2030 2030+
Solar/ Wind/ Hydro
Wind Location
Solar Location/Storage
Long Lake Clean Energy Determination
Determine: 2nd Powerhouse vs Combined Powerhouse
Permit and Construct Natural Gas CT or Alternative Technology
Spokane River Licensing Process Long Lake Construction
MT Wind RFP: 58 - 94 aMW
Long Duration Pumped Storage Availability/Price
Existing Regional Capacity
Construction of Natural Gas CT
Long Duration Pumped Storage
Natural Gas CT Permitting & Siting
Hydro Flexibility
Storage Technology (Availability, Price, and Duration)
Existing Natural Gas CT Resources Options
Early Demand Response Acquisition Demand Response Programs (85 MM)
Kettle Falls Upgrade Process (12 MW) (Turbine, generator, ancillary, fuel yard)
2026: Rathdrum CT Upgrade (24 MW)
Post Falls Re-Development (8 MW)
PPA Renegotiation/ Renewable Energy RFPs
Renegotiate Mid-C Hydro PPAs
Page 680 Avista Corp. 2020 Electric IRP Appendices
Idaho Rate Impact for Clean Resource
Strategy
Compares CRS (#3) cost to Idaho’s LC strategy cost, then adjusts
Costs down for REC sales at three different prices
Average Prices: Low-$4/REC, Mid-$6.40/REC, High-$15.40/REC
0%
5%
10%
15%
20%
25%
20
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21 Page 681 Avista Corp. 2020 Electric IRP Appendices
Observations
•Resource acquisitions and decisions are highly dependent on
resource availability to be determined in a RFP.
•Colstrip continuing to 2035 is 0.3% higher cost then operating until
2025, (but rate per kWh is slightly lower due to changes in
conservation). Keeping one unit running does not improve
economics.
•CETA cost caps are likely to be in place closer to 2045.
•Idaho rates will be impacted by REC prices from its sales potential
and how resources are allocated between states.
•Avista’s GHG emissions will lower, but the amount depends on
timing of resources and method for accounting for regional
emissions.
•Low load scenario illustrates resource need if greater energy
efficiency is gained.
22 Page 682 Avista Corp. 2020 Electric IRP Appendices
Market Price Sensitivities
Page 683 Avista Corp. 2020 Electric IRP Appendices
Market Price Sensitivity Analysis
•Use different market prices for each of the 14
portfolios
•Results in 70 sensitivities
•Market sensitivities include:
–Expected Case (deterministic)
–No CETA
–Low natural gas prices
–High natural gas prices
–Social cost of carbon (west-wide dispatch-tax
method)
24 Page 684 Avista Corp. 2020 Electric IRP Appendices
Change in Cost (PVRR)
Sensitivity as Compared to Expected Case
25 Page 685 Avista Corp. 2020 Electric IRP Appendices
Change in Cost (PVRR)
Portfolio as Compared to PRS
26 Page 686 Avista Corp. 2020 Electric IRP Appendices
Change in Levelized GHG Emissions
Sensitivity as Compared to Expected Case
27 Page 687 Avista Corp. 2020 Electric IRP Appendices
Change in Levelized GHG Emissions
Portfolio as Compared to PRS
28 Page 688 Avista Corp. 2020 Electric IRP Appendices
Sensitivity Observations
•Modeling the electric market place with and without CETA shows
only modest changes in costs, but without CETA generally increases
costs as electric market prices are higher.
•Low natural gas prices decrease portfolio costs and high natural gas
prices increase costs, although scenarios with more gas turbines are
more sensitive to gas prices changes-low natural gas prices are
likely to increase Avista’s GHG emissions, while higher prices may
not for Avista, but could for other markets.
•Modeling SCC as a tax increases Avista’s cost, but lowers Avista’s
emissions. The PRS is still a lower cost alternative then other
scenarios in this sensitivity.
29 Page 689 Avista Corp. 2020 Electric IRP Appendices
Electrification Scenario
Page 690 Avista Corp. 2020 Electric IRP Appendices
Electrification Scenario
•Increase electric vehicles
•Increase roof-top solar
•Reduction in end-use natural gas penetration
31 Page 691 Avista Corp. 2020 Electric IRP Appendices
Service Territory Electric Vehicle Forecast
Expected Case
High EV Penetration
32 Page 692 Avista Corp. 2020 Electric IRP Appendices
Electric Vehicle Impact to
Peak & Energy Load Forecast
Energy
Peak
33 Page 693 Avista Corp. 2020 Electric IRP Appendices
Avoided Direct Vehicle Emissions
Expected Case
High EV penetration
34 Page 694 Avista Corp. 2020 Electric IRP Appendices
Customers with Roof-top Solar
Expected Case
High Roof-Top Solar Penetration
35 Page 695 Avista Corp. 2020 Electric IRP Appendices
Roof-Top Solar Load Changes
Energy
Winter Peak
SummerPeak
36 Page 696 Avista Corp. 2020 Electric IRP Appendices
End Use Natural Gas Penetration
NG LDC Electrification
Expected Case
37 Page 697 Avista Corp. 2020 Electric IRP Appendices
Avista’s 2017 Natural Gas Daily Demand
(Core Washington Demand)
1/
1
/
2
0
1
7
1/
1
/
2
0
1
7
1/
1
/
2
0
1
7
1/
1
/
2
0
1
7
2/
1
/
2
0
1
7
2/
1
/
2
0
1
7
2/
1
/
2
0
1
7
3/
1
/
2
0
1
7
3/
1
/
2
0
1
7
3/
1
/
2
0
1
7
4/
1
/
2
0
1
7
4/
1
/
2
0
1
7
4/
1
/
2
0
1
7
4/
1
/
2
0
1
7
5/
1
/
2
0
1
7
5/
1
/
2
0
1
7
5/
1
/
2
0
1
7
6/
1
/
2
0
1
7
6/
1
/
2
0
1
7
6/
1
/
2
0
1
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6/
1
/
2
0
1
7
7/
1
/
2
0
1
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7/
1
/
2
0
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7
7/
1
/
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8/
1
/
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8/
1
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1
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9/
1
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9/
1
/
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9/
1
/
2
0
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10
/
1
/
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10
/
1
/
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10
/
1
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11
/
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11
/
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/
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/
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/
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12
/
1
/
2
0
1
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12
/
1
/
2
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7
12
/
1
/
2
0
1
7
De
k
a
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e
r
m
s
38 Page 698 Avista Corp. 2020 Electric IRP Appendices
NW Electric Utility Load Shape
(All Electric vs. Mix Natural Gas/Electric)
Avista Native Load
Chelan County Public Utility District No. 1
39 Page 699 Avista Corp. 2020 Electric IRP Appendices
Converting Core Natural Gas to Electric
Residential,
61.5%
Commercial,
36.5%
Industrial, 2.0%
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
5 Degrees
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
35 Degrees
Water Heat, 10.0%
Space Heat, 85.0%
Process, 5.0%
5 Degrees
Water Heat, 30.0%
Space Heat, 60.0%
Process, 10.0%
35 Degrees
Annual customer type End use by temperature Efficiency by temperature
Residential Example Residential Example
40
Page 700 Avista Corp. 2020 Electric IRP Appendices
End-Use Natural Gas Load Changes
Energy
Winter Peak
Summer Peak
41 Page 701 Avista Corp. 2020 Electric IRP Appendices
Associated Greenhouse Gas Emissions
From “Former” LDC Natural Gas Customers
42 Page 702 Avista Corp. 2020 Electric IRP Appendices
Total Load Changes
Energy
Winter Peak
Summer Peak
43 Page 703 Avista Corp. 2020 Electric IRP Appendices
2045 Cost Impacts
•Power System requires additional $365 million (25% increase)1
•Assumes an additional 1,080 MW new NG CT peakers, 520 MW
Solar, 1,100 MW storage to meet new system peak load
•Greenhouse gas emissions
•Cost per metric ton: $397 per metric ton for the savings in 2045-
over the 25 years the levelized cost of reduction is $1,942 per metric
ton.
–Does not include changes in Natural Gas LDC existing infrastructure costs
–Does not include load related distribution/transmission investments (this will increase estimate)
–Does not include EV incremental cost over petroleum alternative (this is unknown)
–Does not include home owner equipment and wiring costs (this will increase estimate)
MMT PRS + LDC
NG
Electrification
Scenario Change
Electric utility emissions 0.41 +0.28
Avoided petroleum emissions -0.53 -0.76
LDC natural gas emissions 0.43 -0.43
Total emissions 0.31 -0.91
44 1) Estimate is net of natural gas commodity savingsPage 704 Avista Corp. 2020 Electric IRP Appendices
Observations
•Electric vehicle penetration will have an impact on future resource needs-
how customers use the energy will drive resource decisions.
•Electric vehicles will drive regional emissions lower, but Avista’s emissions
higher.
•Additional rooftop solar makes no material change in winter capacity
planning, but lowers average energy and likely drives rates higher due to
lower kWh sales.
•Electrification of natural gas space and water heating significantly increase
winter load profiles.
•Additional heating electrification will likely result in natural gas peakers due
to duration requirements and may costs result in modest savings of GHG
emissions without significantly lowering storage costs.
•Heating electrification costs significantly exceed the Social Cost of Carbon.
•Externality costs can be significant: transmission, distribution, and direct
home owner and should be considered in policy making.
Page 705 Avista Corp. 2020 Electric IRP Appendices
Appendix
Detailed Resource Portfolios
Page 706 Avista Corp. 2020 Electric IRP Appendices
Preferred Resource Strategy
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 175 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2025-2030: 76 MW, Demand Response
2026/27: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 32 MW, Demand Response
2035: 55 MW, Northeast CT retires
2035: 68 MW, Long Lake 2nd
Powerhouse
2036-40: 75 MW x 16 hr, Liquid Air Storage
2037: 1 MW Demand Response
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042: 2.5 MW, Demand Response
2042-2045: 300 MW Wind PPA Renew
2042-2045: 300 MW x 4 hr, Lithium-ion
2044: 55 MW, Solar w/ 50 MW x 4hr, Storage
47
Load reduction of 187 aMW due to Energy Efficiency by 2045
Page 707 Avista Corp. 2020 Electric IRP Appendices
2) Least Cost Plan
without CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, Pumped Hydro
2026: 257 MW, Lancaster PPA expires
2026-2030: 85 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027: 92 MW, Natural Gas CT
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 84 MW, Natural Gas CT
2038: 25 MW x 16 hr, Liquid Air Storage
2039: 25 MW x 4 hr, Lithium-Ion
2040: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041-2042: 50 MW x 16 hr, Liquid Air Storage
2043: 55 MW Natural Gas CT
2045: 53 MW x 4 hr, Lithium-ion
2045: 3 MW Demand Response
48
Load reduction of 166 aMW due to Energy Efficiency by 2045
Page 708 Avista Corp. 2020 Electric IRP Appendices
3) Clean Resource Plan
100% net clean by 2030
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2023-2027: 64 MW, Demand Response
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2027-2030: 325 MW, Solar
2029: 20 MW Geothermal
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW Long Lake 2nd
Powerhouse
2032: 21 MW Demand Response
2033-2040: 195 MW Solar w/ 150 MW x 4 hr. Storage
2035: 55 MW, Northeast CT retired
2037: 23 MW Demand Response
2041-2045
2041-2043: 300 MW Wind PPA Renew
2042: 25 MW x 16 hr Liquid Air Storage
2043-45: 225 MW x 4 hr, Lithium-ion
2040-45: 70 MW Solar w/ 50 MW x 4 hr. Storage
2045: 3 MW, Demand Response
49
Load reduction of 213 aMW due to Energy Efficiency by 2045
Page 709 Avista Corp. 2020 Electric IRP Appendices
4) Rely on Energy Markets Only
(no capacity or renewable additions)
2021-2030
2026: 222 MW, Colstrip removed
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2031-2040
2035: 55 MW, Northeast CT retired 2041-2045
50
Load reduction of 127 aMW due to Energy Efficiency by 2045
Page 710 Avista Corp. 2020 Electric IRP Appendices
5) 100% Net Clean by 2027
and No CTs by 2045
2021-2030
2022: 150 MW, Solar
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2025-2027: 64 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027-2028: 275 MW, NW Solar
2030: 50 MW, NW Solar
2029: 20 MW, Geothermal
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd
Powerhouse
2031: 21 MW, Demand Response
2033: 55 MW, NW Solar
2035: 55 MW, Northeast CT retired
2036-2040: 140 MW Solar w/ 125 MW x 4 hr, Storage
2037: 23 MW, Demand Response
2040: 200 MW x 16 hr Liquid Air Storage
2040: 75 MW Pumped Hydro
2035: 154 MW, Rathdrum CTs removed
2041-2045
2041-2043: 300 MW Wind PPA Renew
2043: 9 MW, Kettle Falls CT removed
2043: 25 MW, Boulder Park removed
2042-2044: 125 MW x 16 hr Liquid Air Storage
2043-45: 28 MW x 4 hr, Lithium-ion
2045: 302 MW, Coyote Springs 2 removed
2045: 130 MW Solar w/ 75 MW x 4 hr, Storage
2045: 225 MW Pumped Hydro
2045: 100 MW Small Nuclear
2045: 50 MW Biomass
51
Load reduction of 214 aMW due to Energy Efficiency by 2045
Page 711 Avista Corp. 2020 Electric IRP Appendices
6) Least Cost Plan
w/o pumped storage or Long Lake, meeting CETA
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 245 MW, Natural Gas CT
2027: 55 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-2035: 53 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 200 MW, MT Wind
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW Wind PPA
Renew
2041: 25 MW x 16 hr, Liquid Air Storage
2044-2045: 150 MW x 4 hr, Lithium-ion
2044: 25 MW x 16 hr Liquid Air Storage
2045: 100 MW Solar w/ 100 MW x 4 hr, Storage
2045: 20 MW, Geothermal
52
Load reduction of 177 aMW due to Energy Efficiency by 2045
Page 712 Avista Corp. 2020 Electric IRP Appendices
7) Colstrip Extended to 2035 w/o CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 200 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 92 MW, Natural Gas CT
2027: 8 MW, Post Falls Upgrade
2028-2030: 85 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035: 84 MW, Natural Gas CT
2038: 25 MW x 16 hr Liquid Air Storage
2039: 25 MW x 4 hr, Lithium-ion
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042: 25 MW x 16 hr Liquid Air Storage
2043: 55 MW, Natural Gas CT
2045: 53 MW x 4 hr, Lithium-ion
2045: 3 MW, Demand Response
53
Load reduction of 166 aMW due to Energy Efficiency by 2045
Page 713 Avista Corp. 2020 Electric IRP Appendices
8) Colstrip Extended to 2035 w/ CETA
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 250 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2028: 64 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-2032: 45 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 200 MW, MT Wind
2041-2045
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2044: 50 MW, Solar w/ 50 MW x 4 hr, Storage
2045: 175 MW x 4 hr Lithium-ion
2045: 3 MW, Demand Response
54
Load reduction of 182 aMW due to Energy Efficiency by 2045
Page 714 Avista Corp. 2020 Electric IRP Appendices
9) Least Cost Plan
w/ 30 Percent higher pumped storage cost
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 75 MW, Pumped Storage
2027: 92 MW, Natural Gas CT
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2027-2030: 76 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-32: 32 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2036-2040: 75 MW x 16 hr Liquid Air Storage
2039: 3 MW, Demand Resonse
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW, Wind PPA Renew
2042-45: 303 MW x 4 hr, Lithium-ion
2044: 50 MW Solar w/ 50 MW x 4 hr Storage
55
Load reduction of 189 aMW due to Energy Efficiency by 2045
Page 715 Avista Corp. 2020 Electric IRP Appendices
10) Least Cost Plan
w/ Federal Tax Credits Extended
2021-2030
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 175 MW Pumped Hydro
2026: 283 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2025-2030: 85 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 23 MW, Demand Response
2035: 92 MW, Natural Gas CT
2035: 55 MW, Northeast CT retired
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2042: 300 MW, Wind PPA Renew
2042: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW x 16 hr Liquid Air Storage
2044-2045: 150 MW, Solar w/ 150 MW x 4 hr Storage
2043-2045: 100 MW x 4 hr, Lithium-ion
56
Load reduction of 181 aMW due to Energy Efficiency by 2045
Page 716 Avista Corp. 2020 Electric IRP Appendices
11) Clean Resource Plan
w/ Federal Tax Credits Extended
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2027: 76 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 200 MW, MT Wind
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027-2028: 300 MW, NW Solar
2027: 8 MW, Post Falls Upgrade
2029: 20 MW, Geothermal
2030: 25 MW, Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd Powerhouse
2033-2035: 32 MW, Demand Response
2035: 55 MW, Northeast CT retired
2033-2040: 250 MW, Solar w/ 225 MW x 4 hr Storage
2041-2045
2041-2042: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2042-2045: 225 MW x 4 hr, Lithium-ion
2044: 3 MW, Demand Response
2044-45: 75 MW, Solar w/ 75 MW x 4 hr of Storage
57
Load reduction of 203 aMW due to Energy Efficiency by 2045
Page 717 Avista Corp. 2020 Electric IRP Appendices
12) Least Cost Plan
with Low Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2027: 85 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 100 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 68 MW Long Lake 2nd
Powerhouse
2038: 23 MW Demand Response
2041-2045
2042-2045: 300 MW Wind PPA Renew
2041-2045: 225 MW x 4 hr Storage
2045: 10 MW, Solar
58
Load reduction of 180 aMW due to Energy Efficiency by 2045
Page 718 Avista Corp. 2020 Electric IRP Appendices
13) Least Cost Plan
with High Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2040: 109 MW, Demand Response
2026: 111 MW, Colstrip Unit 3 removed
2026: 250 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031-2033: 75 MW, Mid-C PPA Renew
2033: 48 MW Natural Gas CT
2035: 68 MW Long Lake 2nd
Powerhouse
2035: 55 MW, Northeast CT retired
2035: 111 MW, Colstrip Unit 4 removed
2037: 48 MW Natural Gas CT
2040: 25 MW x 16 hr Liquid Air Storage
2040: 3 MW, Demand Response
2041-2045
2041-43: 75 MW x 16 hr Liquid Air Storage
2041-2045: 205 MW Solar w/ 200 MW x 4 hr Storage
2042-2045: 300 MW Wind PPA Renew
2043-2044: 200 MW x 4 hr, Lithium-ion
2045: 20 MW, Geothermal
59
Load reduction of 181 aMW due to Energy Efficiency by 2045
Page 719 Avista Corp. 2020 Electric IRP Appendices
14) Least Cost Plan
with Lancaster PPA Extended Five Years
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2027: 8 MW, Post Falls Upgrade
2030: 30 MW, Demand Response
2031-2040
2031-2032: 75 MW, Mid-C PPA Renew
2031-2035: 78 MW Demand Response
2032: 257 MW, Lancaster PPA expires
2032: 245 MW Natural Gas CT
2035: 55 MW, Northeast CT retired
2035: 200 MW MT Wind
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW, Wind PPA Renew
2042-2044: 150 MW x 4 hr, Lithium-ion
2041: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW x 16 hr Liquid Air Storage
2045: 100 MW, Solar w/ 100 MW x 4 hr Storage
2045: 20 MW, Geothermal
60
Load reduction of 177 aMW due to Energy Efficiency by 2045
Page 720 Avista Corp. 2020 Electric IRP Appendices
15) Least Cost Plan
with Colstrip Unit #4 extended until 2035
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 211 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2027: 8 MW, Post Falls Upgrade
2030: 30 MW, Demand Response
2031-2040
2031-2032: 75 MW, Mid-C PPA Renew
2031-2035: 78 MW Demand Response
2032: 257 MW, Lancaster PPA expires
2032: 245 MW Natural Gas CT
2035: 55 MW, Northeast CT retired
2035: 200 MW MT Wind
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW, Wind PPA Renew
2042-2044: 150 MW x 4 hr, Lithium-ion
2041: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW x 16 hr Liquid Air Storage
2045: 100 MW, Solar w/ 100 MW x 4 hr Storage
2045: 20 MW, Geothermal
61
Load reduction of 178 aMW due to Energy Efficiency by 2045
Page 721 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP
Action Items and IRP Chapter Overview
John Lyons, Ph.D.
Sixth Technical Advisory Committee Meeting
November 19, 2019
Page 722 Avista Corp. 2020 Electric IRP Appendices
Analytical Action Items
•Determine ancillary services costs and benefits for intermittent and
storage resources
•Research emission profiles for different types of resource construction and
manufacturing
•Research the purchase of a third-party electric price forecast and then use
that forecast to run our own dispatch analysis
•CETA issues and rulemaking:
–Low income issues
–Greenhouse gas emissions reporting
–IRP requirements and future reporting
•Consider if IRP needs to be split between states because of timing and
new requirements
•Consider the combination of the electric and natural gas IRPs
•Continued analysis for Colstrip post 2025
2 Page 723 Avista Corp. 2020 Electric IRP Appendices
Resource Action Items
•Determine plan for Long Lake expansion and file with appropriate
agencies concerning if the project meets CETA and licensing issues
•Continued pursuing pumped storage opportunities
•Conduct further transmission network studies for integration of
renewables and contingency CTs
•2020 RFP for renewable energy capacity (2022-2023 online)
•2021 RFP for capacity resources (on-line by 2026)
•Additional studies for the eventual shutdown of Northeast CT
3 Page 724 Avista Corp. 2020 Electric IRP Appendices
Other 2020 Action Items
•Other areas of concern or suggestions?
•Please call or email the planning team with any
suggestions or added Action Items
4 Page 725 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP Chapters
1.Executive Summary
2.Introduction, IRP Requirements, and Stakeholder
Involvement
3.Economic and Load Forecast
4.Existing Supply Resources
5.Energy Efficiency and Demand Response
6.Long-Term Position
7.Transmission & Distribution Planning
8.Generation and Storage Resource Options
9.Market Analysis
10.Preferred Resource Strategy
11.Portfolio Scenarios
12.Action Plan
5 Page 726 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP Chapters 1 –3
•Chapter 1: Executive Summary
–High level summary of 2020 IRP and PRS
•Chapter 2: Introduction, IRP Requirements, Stakeholder
Involvement
–TAC overview and rules guiding IRP development
•Chapter 3: Economic and Load Forecast
–Economic conditions in Avista’s service territory
–Avista’s energy and peak forecasts
–Load forecast scenarios
6 Page 727 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP Chapters Ch. 4 –6
•Chapter 4: Existing Supply Resources
–Avista’s resources
–Contractual resources and obligations
–Avista’s natural gas pipeline overview
•Chapter 5: Energy Efficiency and Demand Response
–Conservation Potential Assessment
–Greenhouse gas offset calculation
–Demand response opportunities
•Chapter 6: Long-Term Position
–Reliability adequacy and reserve margins
–Resource requirements
–7 Page 728 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP Chapters Ch. 7 –8
•Chapter 7: Transmission and Distribution Planning
–Overview of Avista’s Transmission System
–Future Upgrades and Interconnections
–Transmission Construction Costs and Integration
–Merchant Transmission Plan
–Overview of Avista’s Distribution System
–Future Upgrades and Interconnections (includes project
evaluated with DER alternative)
8 Page 729 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP Chapters Ch. 8 –9
•Chapter 8: Generation and Storage Resource Options
–New Resource Options
–Avista Plant Upgrades
•Chapter 9: Market Analysis
–Marketplace
–Federal and State Environmental Policies
–Fuel Price Forecasts
–Market Price Forecast
–Scenario Analysis
9 Page 730 Avista Corp. 2020 Electric IRP Appendices
2020 Electric IRP Chapters Ch. 10 –12
•Chapter 10: Preferred Resource Strategy
–Resource Selection Process
–Preferred Resource Strategy
–Efficient Frontier Analysis
•Chapter 11: Portfolio Scenarios
–Portfolio Scenarios
–Resource Avoided Cost
•Chapter 12: Action Plan
–2017 Action Plan Summary
–2020 Action Plan
10 Page 731 Avista Corp. 2020 Electric IRP Appendices
Remaining 2020 IRP Schedule
•December 18, 2019 –external draft released to TAC
•January 15, 2020 –external draft comments due
•February 28, 2020 –2020 Electric IRP published and available to the
public on Avista’s web site
•Public comments period determined by the Commissions and posted
on their respective web sites
•January 4, 2021 –Draft IRP due for Washington
•April 1, 2021 –File 2021 IRP in Washington
•Aug 31, 2021-File 2021 IRP in Idaho
•TAC schedule for next IRP(s) will be available after we determine if
the IRP needs to be bifurcated between Idaho and Washington
11 Page 732 Avista Corp. 2020 Electric IRP Appendices
Attendees: TAC 6, Tuesday, November 19, 2019 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Xin Shane, Avista; Kevin Calhoun, Tyr Energy; Andrew Argetsinger, Tyr Energy; Barry Kathrens, 350.org; Michael Eldred, Idaho Public Utilities Commission; Clint Kalich, Avista; Shelby Herber, Idaho Conservation League; Matt Nykiel, Idaho Conservation League; John Barber, Rockwood Retirement Communities; Dave Van Hersett, Residential Customer; Kirsten Wilson, Washington State DES Energy; Cadie
Olsen, City of Spokane; Jason Thackston, Avista; Rachelle Farnsworth, Idaho Public Utilities Commission; Darrell Soyars, Avista; Collins Sprague, Avista; Terrence Browne, Avista; Garrett Brown, Avista; Grant Forsyth, Avista; Logan Callen, City of Spokane; James Gall, Avista. David Howarth, National Grid; and Jaime Majure, Avista.
Phone Participants:
Jennifer Snyder, Washington UTC; Mike Starrett, Northwest Power and Conservation
Council; Cassie Koerner, Idaho Public Utilities Commission; Amy Wheeless, Northwest
Energy Coalition; Nancy Esteb, Renewable Energy Coalition; and several guest
participants who did not identify themselves.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses from the presenter are in
italics, and significant points raised by presenters that are not shown on the slides are
also included. Bracketed comments provide additional details and updates.
Introductions and TAC 5 Recap, John Lyons
Matt Nykiel: Will the Idaho and Washington IRPs come back together? Not sure, we will
discuss later today and with both state Commissions.
Cadie Olsen: With the limited availability of people to do economic analysis for CETA,
has that slowed down the work?
John Lyons: Agencies have been working on it [CETA], but there have been staffing
issues. The Washington UTC has a schedule laid out for the next few years for all of the
rulemaking required for CETA.
Review of PRS, James Gall
Matt Nykiel: What is the status of the coal contract?
Jason Thackston: We haven’t signed the contract yet, but are very close and fully
expect it to be signed by the end of the year. [Avista signed a new contract in early
December 2016 for coal through the end of 2024.]
Clint Kalich: Can you clarify the statistic 70% green? 70% of our retail sales for
Washington and Idaho.
Page 733 Avista Corp. 2020 Electric IRP Appendices
Matt Nykiel: A similar question as part of the RECs, Avista’s goal is for both states. How
will both be met since selling Idaho RECs to Washington makes it harder to meet the
goal?
Jason Thackston (Slide 3): The purpose of this slide is to show the status of our ability
to comply with the Washington law. That leads into the 100% goal.
Matt Nykiel: How does the model handle situations where it is rainy and windy in
Spokane, but sunny in Montana? Let’s factor in potential at other places, not just here at
the office at Avista. We apply a factor for different locations for availability. 100% on
average or net 100%? We’ll get to that later as well.
James Gall (Slide 5): Solar includes bifacial panels with a single axis tracker. Hydro
includes Long Lake and Post Falls upgrades. We removed the Monroe Street upgrade
from the PRS discussed in the last TAC meeting. Wind includes offshore.
Clint Kalich: For BPA, is that federal hydro? Price is based on a gas plant, but the actual
generation may or may not be federal hydro.
James Gall: Geothermal is not in our region; but is outside our region in southern Idaho,
Nevada (in the last RFP), and in Utah that could get here. Nuclear is another option, but
it is too big for Avista. Modular nuclear of 100 MW is clean and the right size, but will
probably not be commercially available for quite some time. Energy efficiency has been
used by Avista since the 1970s, we have saved over 200 MW on average.
Matt Nykiel: How are wind and solar being modeled? All wind and solar are modeled as
a PPA with different locations. On-system wind and solar have an interconnection cost
and off-system locations have wheeling costs. Each resource type is assigned a peak
credit for contribution to peak loads.
James Gall: Liquid air storage is easy to scale, with long duration storage requiring
more tanks – the same as hydrogen. Flow batteries are both four-hour for vanadium
flow and zinc oxide batteries. Both of these are higher initial cost than lithium ion, but
have a 20-year lifespan instead of 10 years. Regional transmission as a supply
resource is crossed out because we don’t know what will be on the other side of the
transmission line in the future.
Matt Nykiel (Slide 6): Is the social cost of carbon $50 to $60? $80 in 2021. Can you
explain how pipeline upstream emissions are modeled? Losses to move gas on pipeline
and releases from gas wells. We get all of our gas from Canada, mainly Alberta. The
Canadians have a report that shows a little bit less than 1%, times the amount of gas. I
don’t know the name of the document, but it will be in the IRP document.
Slide #7: The lower Montana wind capacity factor is used to account for transmission
losses. We moved to the upper end of pumped hydro storage projects after talking more
with developers. This makes it more reliable like a gas plant. And we added more
planning margin.
Page 734 Avista Corp. 2020 Electric IRP Appendices
Dave Van Hersett (Slide 7): How many hours [for pumped hydro]? 40 to 80 hours.
Dave Van Hersett (Slide 10): Is water heating switching from electric to natural gas? No,
it is for heat pump water heaters. We will cover what you are talking about later today.
Slide 11: Modeling versus actual acquisition. We think 100 MW from Montana and 100
MW from the Northwest, but anyone can bid into an RFP and provide the wind power.
Mike Starrett: Is the procedural expectation from the Washington Commission an
acknowledgment? The IRP is acknowledged and then any resources we acquire go into
a future rate case. We show a need to answer the prudency question in a general rate
case. CETA will have a Clean Energy Action Plan.
Jennifer Snyder: Yes, as of right now, it is a rate case prudency question. Clean Energy
Action Plan will be covered later.
Slide 11: Changed pumped hydro up from 150 MW to 175 MW in the PRS and
increased demand response from 2021 to 2030.
Dave Van Hersett: DR is? Demand response, we will get to that later.
Mike Starrett: The presumption is that it goes away, but have you looked at attributes of
Lancaster going forward? Yes, we are showing that later.
Matt Nykiel (Slide 12): Did you model opt in versus opt out? Didn’t model it, but about
50 percent more. We have an estimate of it. Dave, did this answer your question? Yes.
Jason Thackston (Slide 13): 2022/23 acquisitions come online. Issue an RFP spring of
next year. Online by at least 2022, but we will look at later dates in an RFP if they are
better prices. We would rather do an RFP first, then the IRP. This is our best guess
now. Colstrip cannot serve Washington customers after 2025, but could still serve
Idaho’s one third share or get other owners to agree to shut down.
Matt Nykiel: If it [Colstrip] is not cost effective, it is no longer prudent. Colstrip could
operate at minimums or we could sell it, but we could not unilaterally shut it down
ourselves.
John Barber: On the pumped hydro projects, are there others interested? Yes, the
projects are much bigger than we need. There are other parties interested and they
would need even more participants.
Matt Nykiel: With the cost effectiveness caveat, how does that make the business goal
different than business as usual? Other strategies are RECs with CTs [combustion
turbines] to green up the portfolio. We don’t want to jeopardize our customer’s livelihood
for an aspirational goal.
Matt Nykiel: What is that cost effectiveness test?
Jason Thackston: Good question. We are struggling with that too. There was a lot of
squirming in April. We continue to look at the impact of the goal while maintaining
Page 735 Avista Corp. 2020 Electric IRP Appendices
reliability. This goal is aligning ourselves internally. We totally get that from the business
side of things. Gap with how it is marketed and caveats they signal are super important.
Idaho resources are producing for Idaho customers, but are also going to Washington.
There is a signal there so that customers can make an informed decision. This is good
feedback. Thanks.
Dave Van Hersett: Increasing my bills is lowering my reliability.
Jason Thackston: The ideal outcome is 2025-2030. Our CFO always notes that hope is
not a strategy. Rattlesnake Flat is a good example. It is a good alternative even though
we didn’t have a need expressly then.
James Gall: We will issue an RFP in the spring, if more resources come in that would
lower rates; we will get the extra resources.
John Barber: With liquid air, is it taking it down to the Nitrogen or just the Oxygen? We
will need to ask Thomas Dempsey about this. [The liquid air doesn’t separate out the
gases, it uses ordinary air without separating the different gases].
Clint Kalich: Can we retrofit the back end of our gas turbines? We were going down that
path, but last I heard it may not work. So, maybe.
Barry Kathrens: If there is a positive balance, there is more available for [hydro] storage.
We only have two facilities with storage that are already being used. It is already serving
the purpose you are describing.
Jason Thackston: Some hydro can store over seasons, like in Juneau [Alaska]. Building
more generation would force more water over spillways because there will still be the
same amount of water over time.
Matt Nykiel (Slide 17): Back in 2026, Action Plans features for Idaho customers, the use
of Colstrip for customers is undetermined. I’m grappling with it still being used. You are
talking about problems I think about every day. We are always going to run our system
as a whole, but there is a cost allocation issue.
Matt Nykiel: Easy answer from my point of view. There is a balance that has to be
maintained.
Jason Thackston: You may think it is easy, but it is probably more complicated than you
think.
Barry Kathrens: How does a state line affect climate policy? It determines state energy
policy.
Dave Van Hersett (Slide 18): Emissions are less because you are getting rid of gas
burning in my Corvette.
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Matt Nykiel: Do other utilities model this [reduced car emissions] even though others
made this choice? CETA is working on this for incentives [on electrification of
transportation].
Clint Kalich: There is precedence in energy conservation. Absent that incentive, the
conservation measure may not be installed.
Jason Thackston: Avista has already incented infrastructure for this to enable adoption.
Someone chooses to fly and purchase offsets. Utilities are showing this.
John Lyons: This is the free rider problem. Did you purchase a particular energy
efficient refrigerator for energy savings, the $50 rebate, or because it looks really good
in your kitchen.
Garrett Brown (Slide 19): Is this just residential? It is an average rate for all classes
according.
Matt Nykiel: Does it include the social cost of carbon? It is included in the decision, but
not in the rate. It is averaged all together.
Darrell Soyars: Transmission and distribution – yes, assumes 2 percent growth.
Dave Van Hersett: About one third generation plus distribution plus one-third
transmission on my bill. There are four components with the common costs.
Mike Starrett: When going through rates, it sounds like a composite rate. Can you
characterize it for a single residential customer? No, the best way is to look at it going
bar to bar [on the graph]. We probably need to get more descriptive on that. Is the cost
consistent? This slide is not getting into the scope of how to assign costs to different
customer classes.
Prewritten comments from Dave Van Hersett for his last TAC meeting:
November 19, 2019
Dave’s Reflections on the IRP process 1989 to 2019:
I am 80 now and it is time for me to retire and spend more time chasing grandkids and
my wife.
Quote from Mark Twain: “Twenty years from now you will more disappointed by the
things you didn’t do than by the ones you did do. So, throw off the bow lines. Sail away
from the safe harbor. Catch the trade winds with your sails. Explore. Discover”.
1. Dave’s: background
a. Fifth Generation Spokane Native
b. North Central High School 1957, WSU 1962 Mechanical Engineering,
MBA
c. Veteran, USAF selected Outstanding Procurement Officer USAF 1966
d. Avista residential customer since 1967.
Page 737 Avista Corp. 2020 Electric IRP Appendices
e. Power Plant Developer: Coal, Gas Turbines and Renewable Biomass
Fuels (wood, straw & garbage)
f. Commercial and Industrial Conservation Program Business Development
g. Professional Engineer Retired
h. Technical Advisory Committee Member for Avista’s Biannual Integrated
Resource Plan since 1989.

2. Utility is a Three leg stool: customers, capital & utility.
All three are dependent upon each other to be successful. Customers provide a
steady market, investors require a secure and steady return to make an
investment and a staff is the resource to make it happen.
3. Population dictates constant growth at 2% per year
For decades the population growth for the Inland Empire has been about 2% per year.
This constant for long term planning and almost eliminates the risk of losing market or
the customer load for the utility. Thus we have a risk free environment for both the
utility and the investor.
4. Population: 1957, 2019, 2045 : World, USA, WA State, Spokane
5. World pollution contribution & competitive in USA and world
Points to consider:
a. The population growth is the driving factor for all future generation
planning and the operations of the utility to provide services to its
customers. A very low risk profile.
b. Note that the USA is a minority player in the world pollution production.
Even if we reduced our pollution to zero the remaining world countries
Page 738 Avista Corp. 2020 Electric IRP Appendices
would still be producing the majority of pollution. We only have a minor
impact. Countries like China, India and Pakistan each with over a billion
population have the major impact on the pollution to the world
environment. The only result of our zero pollution is to eliminate our
competitive advantage in the world market as a result of our higher
production costs that incorporate significant environmental controls.
c. Nobody is addressing the uncontrolled population explosion on our planet.
The population growth is the root of all demand for resources and
generation of pollution.

6. Utility has Lost objective to serve customers,
I have observed that the utilities have lost their way on their path to serving their
customers. The customers are the utilities life line and reason for existence. In the last
20 years there have been 13 towns in their service area that have lost their main source
of existence, their forest service industries, or sawmills. The utilities have focused on
meeting the concerns of the one percenters, like the Serria Club, instead of serving and
meeting the needs of their customers.
Spokane, Post Falls, Coeur d’Alene, Newport, Sandpoint, Usk, Ione, Kettle Falls,
Northport, Naples, Bonners Ferry, Samuels, Kellogg to name a few.
7. Accommodate and kowtowing to the one percenters : Environmental
groups and greenies.
I have witnessed the domination of the Sierra Club at our IRP meetings. These
representatives are not actual customers of Avista and only bring their message to go
green with no liability on their part for the higher costs we customers will have to pay
and the devastation to our natural resources. Note that less than 1% of the Avista
customers actually participate in the environmental programs offered by Avista.
Examples such as the higher cost Solar and Wind rates for power. Another example is
when the Montana Greenies made a two hour presentation at the IRP meeting to lobby
Avista to withdraw from Colstrip and utilize higher cost wind and solar. None of these
presenters were actual customers of Avista and they came to Avista because they could
not convince their Montana Legislature to terminate Colstrip. I call these Green parties
the 1 percenters (1%) and that I have represent 99% of the Avista customers. These
1% have been accommodated by the Avista IRP staff to a much higher degree than
they actually represent in the Avista customer base.
8. East WA different from Western WA
Eastern Washington population is more conservative than Western WA population.
This is confirmed by the differences of the political representatives. Democrats in
Western WA and Republican majority in Eastern WA. Eastern WA has a lower
population density and the industry base is mining, forest products and farming. We
Page 739 Avista Corp. 2020 Electric IRP Appendices
harvest our natural resources with hard work and longtime husbanding of these natural
resources.
9. UTC to protect customers from utility
In the three legs of the utility business the UTC protects the customers from abuses by
the utilities. The UTC was brought about because of abuses by utilities over the years.
10. UTC to differentiate between East and West WA on implementation of
regulations.
It is my contention that the UTC should take into account the differences between the
East and Western Washington populations in their implementation of the regulations.
We do not need nor do we want to include higher cost Green generation. We want
lower cost and more reliable fossil fuel generation.
11. Loss of forest products industry & towns since 1980’s
Since the 80’s there has been a major loss of industry in the forest products area towns.
13 of these towns in Avista’s service area have lost their sawmills, and the thousands of
jobs they provided for the past 100 or more years. The utility catered to the
environmental movement, (ie. 1%ers) and did not aggressively fight for their continued
existence of the forest products industry and their longtime customer base.
12. Installing High cost wind and solar, no benefits to customers, revenues go
outside of customers.
The utility is bending and accommodating the installation of higher cost wind and solar
generation who’s investment is bringing no real value to the Avista customer base. The
costs to support these green generation resources sends our utility payments to
investors outside of our service area. These green resources require subsidies to make
them somewhat closer to the costs of traditional resources. The cost of green
generation resources increases the overall cost of power to the customers.
13. Opportunity to revise forest products industry and improve forest
production/reduce fire
The May 2019 passage of the CETA act creates a market opportunity for the inland
empire forests and barren lands. If one assumes that the Green Movement and
population growth will continue into the future, we have the barren lands without
population and forests that grow independent of politics that create a business
opportunity for our area. We can develop Green generation resources for sale to other
utilities utilizing our local natural resources and labor.
14. Dark side of Green: cost and eliminates competitive position of PNW and
customers.
The Dark side of Green is the much higher cost and less reliable generation resources
to replace the long time reliable fossil fuel generation resources. An analysis was
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prepared by several PNW utilities that concluded that the cost to implement the Green
Resources by 2045 would result in increasing our power cost by three times. This cost
information has not been included in the efforts of the 1%ers. Increasing our power
costs by three times will eliminate our competitiveness of our industries here in the
PNW and the world. This will then result in the further loss of jobs for our population
and a weakening of Avista’s customer base.
15. Cogeneration: small to large: approx. 100 mw.
The Avista load is approximately 1500 MW. The potential for cogeneration is in the
order of 100 MW. This is minor part of the generation resources but is a major
enhancement for the customer. The utility has bypassed the opportunity to create a
customer based generation resource in favor of higher cost wind and solar.
Implementing a customer based generation resources will build a stronger customer
base by proving another revenue source for the customers investing and operating
businesses in Avista’s service area. It is to the advantage of all of the Avista customers
to have a financially sound customer base. Instead the utility has focused on easier
generation resources such as combustion turbines green power to provide for new load
growth. The potential for customer based cogeneration is small percentage of total load
and would require aggressive and cunning promotion by Avista. This is a proven skill of
the Avista staff.
16. Use Renewable biomass generation to firm up wind and solar
We are fortunate to have established forests that can provide a renewable fuel supply
for biomass generation for generations to come. These biomass plants are ideal for
firming up wind and solar generation when the latter are not operational. We owe this to
our customers.
17. Garbage is 50% biomass and renewable: 1 ton per person per year
Garbage has the same heating value as a fuel as forest residues. People generate 1
ton of garbage per year and it is renewable. 50% of the garbage is paper products.
This is the same fuel as renewable forest residues. Garbage as a fuel supply will
generate about 5% of the annual energy needs of the population. In turn using it as a
fuel will eliminate long term creation of unusable lands created by the land fills that
garbage is hauled to. We will need these lands for coming populations.
18. Never understood the Utility customer conservation programs.
One of my pet peeves is the utility conservation programs presented to the IRP
meetings. I have been confused and could not understand the terminology used by the
presenters to justify their projected conservation savings. There seemed to be a double
standard for customer sponsored conservation projects as compared to inhouse
improvements. Remember that the conservation funds come from the customer for the
customer, not for the exclusive benefit of the utility. Example of double standard, Avista
Page 741 Avista Corp. 2020 Electric IRP Appendices
smart meters vs customer information system improvements to reduce energy
consumption.
19. IRP staff very skilled and very good. Just need their efforts directed to
customer enhancement.
The Avista Staff involved with the production of the IRP are very skilled and we are
grateful that they are working on this product. They have to generate a viable 20 year
plan taking into account all of the technical and political variables. This is not an easy
task and they should be acknowledged and complemented for their fine work.
20. Utility legacy for 2020’s: dedicated to bring back forest products industry
utilizing renewable forests, not leaving the forests for a fuel for forest fires.
You have the opportunity to generate and leave a customer oriented legacy of utilizing
our region renewable and natural resources to provide for future energy needs. You
also have the opportunity to bring back the forest products industry to all of the towns in
our region. The objectives of the one percenters is not in our best interests as their
goals promote forest fires, degradation of our renewable forests and loss of jobs for our
customers.
21. Develop Limited potential of customer based generation and utilization of
regions renewable biomass resources. Provides stronger customer base
for all and benefits the utility and the capital providers.
We should be continually working to enhance the viability of our customer base, the
foundation and reason for the existence of the utility. Not kowtowing to the goals and
demands of the 1%. The customer base has demonstrated and stated their desires by
less than 1% participating in the conservation programs to utilize wind and solar
options. Thus 99% want reliable low cost and reliable electric and gas service.
22. What is your legacy going to be? Selling company for bonus or enhancing
your customer base by bringing back forest products industry?
Providing employment for our children of the future or under utilizing our
natural resources?
My vision for your legacy would be to take advantage of the recent CETA legislation
passed by the 1% to bring back our region forest natural resources, bringing back the
jobs and economies of the past, restoring industry in the towns that have lost jobs,
reduce the potential of destructive forest fires, improve the production of the forests.
We know that we will have the need for more jobs every year and you have the
resources and skills to make this happen. The customers need reliable and low cost
energy services. The utility needs a stable and viable customer base. The capitalists
need a reliable low risk market to attract their investments.
In closing it has been my privilege to participate in the IRP Process. I appreciate
and thank you all for your efforts to integrate the demands and objectives of the
Page 742 Avista Corp. 2020 Electric IRP Appendices
many interests wanting a piece of the requirement to provide long term reliable
energy resources for your customers. Keep in mind that customers want low
cost reliable energy supplies, the 1% have social goals in mind. Dave😊😊
Background for Presentation
• Population Growth Establishes Demand for Energy
o Slide #1of Population Growth of Spokane, WA state and World
• Spokane current electric load is 300 Megawatts
• Inland Northwest Resources
o Mining available Mineral Resources
o Forests that grow renewable lumber products and biomass fuels annually
o Garbage
• Utilities Regulated by Washington Utilities and Transportation Commission
(WUTC)
o Requires utilities to provide low cost, reliable electric power to customers
o Monitors compliance with State and Federal regulations.
o Requires a Biannual Integrated Resource Plan providing power for next 20
years.
• Clean Energy Transformation Act (CETA) May 7, 2019
o Commits Washington to an electricity supply free of greenhouses gas
emissions by 2045
o Eliminate Coal and Carbon fuels.
o Require Renewable Energy Resources such as Wind, Solar and Biomass
(Wood)
o When fully implemented electric rates will triple
• Less than 1% of Avista customers purchase higher cost Wind and Solar Electric
rate option.
• Description of Wind Power Plant (Palouse Wind Project: 30 MW)
o Slide #2 comparing Wind Power Plant to Sea First Building.
o Slide #3 with 556 Wind Power Plants located in Spokane
o Spokane Wind Power investment $450,000,000
• Description of Solar Power Plant (Lind Washington Solar Project: 28 MW, 170
acres)
o Slide #4 of 28 Megawatt Wind Solar Project located on 201 acres farm
lands
o Slide #5 of 860,000 solar panels on 2100 Acres in Spokane
o Spokane Solar Power investment $300,000,000
• Description of Avista’s 53 MW Biomass Wood Fueled Project at Kettle Falls
o Slide #6 Avista’s Project Brochure
o 250 Megawatt Biomass Project Investment: $625,000,000
Utilizing Inland Empire Biomass Forest residues for Electric Power Generation
Page 743 Avista Corp. 2020 Electric IRP Appendices
o Provide power when wind does not blow and sun does not shine
o Harvest natures renewable biomass resource rather than letting it rot on
ground
o Reduce fuel for major forest fires
o Bring back vibrant forest products industry, its jobs and towns to Inland
Empire
Biomass Power potential from Inland Empire Forests – 670 Megawatts of
Dispatchable Power
o Hogg fuel steam generation (50 MW) Kettle Falls Power Plant
 Slide #7 Hogged or ground up unused parts of sawmill production
 Slide #8 Ground up logging residues
 Historically burned in wigwam burners at sawmills
o Logging residues (200 MW)
o Thinning stagnant lodgepole stands (200 MW)
 Timber growth from past forest fires, undesirable timber
o Cogeneration at sawmills (90 to 150 MW)
o Wheat Straw (add 10%)
o Municipal Refuse (50 MW)
 1 ton garbage per person per year
 10,000 tons per year per megawatt
 500,000 population of Spokane area
Unique Economic Development Opportunity
o We have large forest areas, dry land farming acreages, low population
o A population that would favor development of its renewable and dispatchable
resources.
o Wind and solar additions to utility systems require a dispatchable resource to
make wind and solar a reliable dispatchable resource.
o Recent rash of forest fires makes a strong case to change the forest
management practices of today to minimize the probability of and size of
forest fires.
o Power generated from a biomass fuel source qualifies as a Renewable
Energy Credit (REC). This is a product that other utilities purchase to offset
generation from non- renewable resources.
Implementation Plan
o Put together a collation of Inland Empire elected officials, US Forest Service
in Colville, area sawmills and Avista to sponsor a program to:
 Produce a reliable Renewable Biomass Fuel Supply
 Reduce likelihood of forest fires
 Improve yield from our region forests
 Bring back the forest products industry to the inland empire
Page 744 Avista Corp. 2020 Electric IRP Appendices
o Seek Representative Cathy McMorris Rogers to assist in sponsoring
legislation to make this happen. She is from Kettle Falls and knows the forest
products industry.

Portfolio Scenario Results, James Gall
Matt Nykiel (Slide 5): Is Colstrip operating in portfolios 10 and 11? Yes, those portfolios
assume that CETA doesn’t exist.
Rachelle Farnsworth: Question on reliability for these portfolios. I haven’t validated
them. They are likely close to being reliable, but cannot guarantee it. Numbers 4 and 5
are concerning, but the PRS is reliable. It was not as certain in the last TAC meeting,
but the PRS is reliable now.
Matt Nykiel: Do I understand right that numbers 2 through 15 have not been tested for
reliability? We are more comfortable with the plans that include all of the existing
turbines. Taking reliable units away from a portfolio makes it more unreliable.
Matt Nykiel: Is it a double counting issue?
Clint Kalich (Slide 6): Surplus capacity is benefitting renewables now. It will be different
if we retire resources. As we add more renewables, diversity is a benefit. But, more
renewables need more backstop.
Slide 14: At least some of them with the social cost of carbon. All except for the ones
without CETA. Number 15 shows with the social cost of carbon – risk plus cost.
Dave Van Hersett (Slide 19): Are those are the retail rates that include transmission and
distribution? Correct.
Garrett Brown (Slide 20): On top, what hydro is that? BPA, Mid-C utilities bidding in.
Slide 21: Shows what is the cost of Idaho keeping the RECs for themselves.
Clint Kalich (Slide 21): Are rates backwards? No, losing the opportunity to sell RECs to
Washington or to someone else.
Dave Van Hersett: Haven’t sold them [Idaho share of RECs] yet? Right, this is the cost
of keeping the RECs for Idaho.
Garrett Brown: What happens to the RECs today? Washington buys Idaho’s share of
qualifying hydro RECs from Idaho for I-937. Palouse RECs are sold in the market or to
Washington customers for I-937. Rattlesnake Flat RECs will likely be sold in the early
years.
Matt Nykiel (Slide 19): For portfolios #15, 7 and 8; I assume the party’s shares in costs
for Colstrip remain the same. Yes, we only pay for our share. If, in the highly unlikely
situation where an owner didn’t pay their share, the plant dispatch would be lowered by
Page 745 Avista Corp. 2020 Electric IRP Appendices
their ownership amount. Number 15 shows the scenario where all of the shared costs
are paid for by one unit.
Rachelle Farnsworth (Slide 19): Why is number 2 high risk? There is no renewable
acquisition in that scenario, so there is more variability. So #2 has a fixed price, but also
includes fuel variability.
Matt Nykiel: What are the Idaho risks with portfolio #3 – Avista’s goal? They are the
economic cost of the clean energy goal. So, Avista’s goal should be 100% clean for
Washington only.
Dave Van Hersett (Slide 25): When you say social cost of carbon, is that a tax? This
assumes it is a tax, but we don’t know where it [the money] goes. It is an extra cost of
generation that is borne by customers.
David Howarth (Slide 27): Is this system wide or just in Washington? This is just Avista
emissions, but the wider market prices effect Avista’s dispatch of resources.
Barry Kathrens (Slide 33): What is the service territory population?
Grant Forsyth: About one million electric only with 1.9 cars per household.
Dave Van Hersett (Slide 34): Is that emissions net of generation? Just the petroleum
emissions avoided from more electric cars, we will talk about the rest of the emissions
later.
Grant Forsyth (Slide 37): The households we serve have about 70% natural gas
penetration. Assumes new homes are going all electric or switching from gas to electric
when appliances fail.
Mike Starrett (Slide 38): Assuming that is all powered by electric resistance heat? Yes,
we will get to that in the next slides.
Dave Van Hersett (Slide 44): Is the arithmetic on the right side correct? [Slide fixed
before posting].
Clint Kalich: It looks like the bigger bang for the buck is petroleum. Did you do a one off
calculation on this? No, but will if you direct me to since you’re the boss. No, you’re still
self-directed.
Mike Starrett: I don’t disagree with the analysis; it is fundamentally balanced, wondering
about new homes including air conditioning connection between the supply side and
gas/electric? A lot of our distribution feeders are peaking in the summer because of heat
plus load. Then adding an EV [electric vehicle] is less of an issue in the winter. Air
conditioning is about 7 kW and an electric furnace is about 11-12 kW.
Dave Van Hersett: Will there be an all source RFP for capacity? Yes, capacity and
associated energy.
Page 746 Avista Corp. 2020 Electric IRP Appendices
Mike Starrett: Expand on previous opportunity for seasonal or term? Winter focused
need, but we do not limit by season.

2020 IRP Action Items and Overview, John Lyons
No additional notes for this topic.
Page 747 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated
Resource Plan

Appendix B – 2020 Electric IRP
Work Plan

Page 748 Avista Corp. 2020 Electric IRP Appendices

Updated Work Plan for Avista’s
2020 Electric Integrated Resource Plan

February 27, 2019

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Page 2

2020 Electric Integrated Resource Planning (IRP) Work Plan

The Company’s updated work plan is submitted in compliance with Order 01 in Docket No. UE-
180738 dated February 15, 2019. Due to the numerous legislative proposals in the States of
Washington, Montana, and Oregon that will have major impacts on the regional electric market,
Avista petitioned the Washington Utilities and Transportation Commission for a temporary
exemption from WAC 480-100-238(4) to change the filing date of its next IRP from August 31,
2019, to February 28, 2020 with an updated work plan to be filed February 28, 2019.

This updated work plan outlines the process Avista will follow to develop its 2020 Electric IRP to
be filed with the Washington and Idaho Commissions by February 28, 2020. Avista uses a public
process to solicit technical expertise and feedback throughout the development of the IRP through
a series of Technical Advisory Committee (TAC) meetings. Avista held the first TAC meeting for
this IRP on July 25, 2018.

The 2020 IRP process will be similar to those used to produce the previous IRPs. Avista will use
Aurora for electric market price forecasting, resource valuation and for conducting Monte-Carlo
style risk analyses of the electric market place. Aurora modeling results will be used to select the
Preferred Resource Strategy (PRS) and alternative scenario portfolios using Avista’s proprietary
PRiSM model. This tool fills future capacity and energy (physical/renewable) deficits using an
efficient frontier approach to evaluate quantitative portfolio risk versus portfolio cost while
accounting for environmental laws and regulations. Qualitative risk evaluations involve separate
analyses. Avista will utilize its proprietary Avista Decision Support System or ADSS model to
conduct analyses to evaluate reserve products such as ancillary services and intermittent
generation. Avista contracted with Applied Energy Group (AEG) to conduct conservation and
demand response potential studies. Exhibit 1 shows the updated 2020 IRP timeline and the process
to identify the PRS is in Exhibit 2.

Avista intends to use both detailed site-specific and generic resource assumptions in development
of the 2020 IRP. The assumptions combine Avista’s research of similar generating technologies,
engineering studies, and the Northwest Power and Conservation Council’s studies. Avista will rely
on third party and consulting studies for storage resources. Avista will model renewable resources
as power purchase agreements rather than utility-owned assets where it is more economic. This
IRP will study renewable portfolio standards, environmental costs, sustained peaking requirements
and resource adequacy, energy efficiency programs, energy storage and demand response. The
IRP will develop a strategy that meets or exceeds renewable portfolio standards, greenhouse gas
emissions regulations, or other regulations passed by our governing states.

Avista intends to create a PRS based on market and policy assumptions in the expected case based
on the results of pending state energy legislation. The expected case is based on known or likely
drivers affecting the company and energy industry. The IRP will include scenarios to address
alternative futures in the electric market and public policy. TAC meetings help determine the
underlying assumptions used in the expected case, market scenarios and portfolio studies. The IRP
process is very technical and data intensive; public comments are welcome and we encourage
Page 750 Avista Corp. 2020 Electric IRP Appendices

Page 3

timely input and participation for inclusion into the process so the plan can be submitted according
to the schedule in this Work Plan.

The following topics and meeting times may change depending on the availability of presenters
and requests for additional topics from the TAC members. The timeline and proposed agenda
items for TAC meetings follows:

 TAC 1: Completed on Thursday, July 25, 2018:
o TAC meeting expectations and IRP process overview,
o Review of 2017 IRP acknowledgement & policy statements,
o 2017 IRP action plan update,
o Hydro One merger agreement’s impact on the 2019 IRP,
o Demand and economic forecast, and
o Review the 2019 IRP draft Work Plan.

 TAC 2: Completed on Tuesday, November 27, 2018:
o Modeling process overview, including Aurora and PRiSM,
o Generation options (cost & assumptions),
o Resource adequacy and effective load carrying capability (ELCC) analysis,
o Overview of home heating technologies and efficiency,
o Expected case key assumptions (regional loads, CO2 regulation, etc.), and
o Discuss market and portfolio scenarios.

 TAC 3: Tuesday, April 16, 2019:
o Regional legislative update,
o IRP Transmission planning studies,
o Distribution planning within the IRP,
o Pullman Smart Grid Demonstration Project review,
o Pacific Northwest Pathways to 2050 Study,
o Conservation Potential Assessment (AEG), and
o Demand Response Potential Assessment (AEG).

 TAC 4: Tuesday, August 6, 2019:
o Natural gas price forecast,
o Electric market forecast,
o Energy and peak load forecast,
o Existing resource overview – Colstrip, Lancaster and other resources, and
o Final resource needs assessment.

 TAC 5: Tuesday, October 15, 2019:
o Ancillary services and intermittent generation analysis,
o Energy Imbalance Market analysis,
o Review Preliminary PRS,
o Market scenario results,
o Preliminary Portfolio scenario results,
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Page 4

 TAC 6: Tuesday, November 19, 2019:
o Review of final PRS,
o Market scenario results (continued),
o Final Portfolio scenario results,
o Carbon cost abatement supply curves, and
o 2020 IRP Action Items.

 Draft IRP released to TAC members December 1, 2019. Comments from TAC
members are to be returned to Avista by January 15, 2020. Avista’s IRP team will be
available for conference calls to address comments with individual TAC members or
with the entire group if needed.

2020 Electric IRP Draft Outline

This section provides a draft outline of the major sections in the 2020 Electric IRP. This outline
may change based on IRP study results and input from the TAC.

1. Executive Summary
2. Introduction and Stakeholder Involvement
3. Economic and Load Forecast
a. Economic Conditions
b. Avista Energy & Peak Load Forecasts
c. Load Forecast Scenarios
4. Existing Supply Resources
a. Avista Resources
b. Contractual Resources and Obligations
5. Energy Efficiency and Demand Response
a. Conservation Potential Assessment
b. Demand Response Opportunities
6. Long-Term Position
a. Reliability Planning and Reserve Margins
b. Resource Requirements
c. Reserves and Flexibility Assessment
7. Transmission Planning
a. Overview of Avista’s Transmission System
b. Future Upgrades and Interconnections (includes project evaluated with DER alternative)
c. Transmission Construction Costs and Integration
d. Merchant Transmission Plan
8. Distribution Planning
a. Overview of Avista’s Distribution System
b. Future Upgrades and Interconnections (includes project evaluated with DER alternative)
9. Generation and Storage Resource Options
a. New Resource Options
b. Avista Plant Upgrades

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Page 5

10. Market Analysis
a. Marketplace
b. Federal and State Environmental Policies
c. Fuel Price Forecasts
d. Market Price Forecast
e. Scenario Analysis
11. Preferred Resource Strategy
a. Resource Selection Process
b. Preferred Resource Strategy
c. Efficient Frontier Analysis
12. Portfolio Scenarios
a. Portfolio Scenarios
b. Resource Avoided Cost
c. Carbon Cost Abatement Supply Curves
13. Action Plan1
a. 2017 Action Plan Summary
b. 2020 Action Plan

1 The Action Plan chapter will become Chapter 14 and a new chapter will be added in the event state legislation
requires additional documentation regarding clean energy.
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Page 6

Exhibit 1: 2020 Electric IRP Timeline
Task Target Date
Identify Avista’s supply resource options
(update as needed by July 2019)
Completed
Finalize demand response options & costs Completed
Finalize energy efficiency options April 2019
Transmission & Distribution studies due April 2019
Determine portfolio & market future studies June 2019
Begin Aurora market modeling June 2019
Due date for study requests from TAC members June 15, 2019
Finalize natural gas price forecast July 1, 2019
Finalize datasets/statistics variables for risk studies July 2019
Update and finalize energy & peak forecast July 2019
Finalize PRiSM model assumptions August 2019
Simulation of risk studies “futures” complete September 2019
Simulate market scenarios in Aurora September 2019
Evaluate resource strategies against market futures and scenarios October 2019
Present preliminary study and PRS to TAC November 2019
Writing Tasks
File Updated 2020 IRP Work Plan February 28, 2019
Prepare report and appendix outline June 2019
Prepare text drafts October 2019
Prepare charts and tables October 2019
Internal draft released at Avista October and
November 2019
External draft released to the TAC December 1, 2019
Comments and edits from TAC due January 15, 2020
Final editing and printing February 2020
Final IRP submission to Commissions and TAC February 28, 2020
________________________________________________________________________

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Page 7

Exhibit 2: 2020 Electric IRP Modeling Process

Preferred Resource StrategyAURORA
“Wholesale Electric
Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation Trends
Existing Resources
Avista Load Forecast
Energy,Capacity,& RPSBalances Generation/StorageOptions & Costs
T&DProjects/Costs
Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided Costs
Demand Response Measures/Costs
Environmental
Policy
Page 755 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated
Resource Plan

Appendix C – Confidential
Historical Generation Operating
Data

Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160

Page 756 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated
Resource Plan

Appendix D – AEG Conservation
Potential Assessment

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Energy Solutions. Delivered. 
AVISTA CONSERVATION POTENTIAL
ASSESSMENT FOR 2021-2040
February 21, 2020
Report prepared for:
AVISTA CORPORATION
Page 758 Avista Corp. 2020 Electric IRP Appendices

This work was performed by
Applied Energy Group, Inc. (AEG)
500 Ygnacio Valley Rd, Suite 250
Walnut Creek, CA 94596
Project Director: K. Kolnowski
Project Manager: K. Walter
Project Team: K. Marrin
B. Bushong
T. Williams

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CONTENTS
1 INTRODUCTION ............................................................................................ 9
Abbreviations and Acronyms .............................................................................................. 10
2 ANALYSIS APPROACH AND DATA DEVELOPMENT ............................................ 13
Overview of Analysis Approach .......................................................................................... 13
LoadMAP Model ...................................................................................................... 13 Definitions of Potential ............................................................................................ 15 Market Characterization ........................................................................................ 15 Baseline Projection .................................................................................................. 17 Conservation Measure Analysis .............................................................................. 17 Representative Conservation Measure Data Inputs ............................................. 19 Conservation Potential ........................................................................................... 21
Data Development .............................................................................................................. 22
Data Sources ........................................................................................................... 22 AEG Data ................................................................................................................. 23
Other Secondary Data and Reports ...................................................................... 24
Data Application ................................................................................................................. 24
Data Application for Market Characterization ..................................................... 24
Data Application for Market Profiles ...................................................................... 25
Data Application for Baseline Projection .............................................................. 25
Conservation Measure Data Application .............................................................. 31
Data Application for Technical Achievable Potential ......................................... 32
3 MARKET CHARACTERIZATION AND MARKET PROFILES ...................................... 33
Energy Use Summary ............................................................................................................ 33
Residential Sector ................................................................................................................ 34
Commercial Sector .............................................................................................................. 41
Industrial Sector .................................................................................................................... 48
4 BASELINE PROJECTION ................................................................................. 53
Residential Sector ................................................................................................................ 53
Annual Use ............................................................................................................... 53
Commercial Sector Baseline Projections ............................................................................ 56
Annual Use ............................................................................................................... 56
Industrial Sector Baseline Projections ................................................................................. 59
Annual Use ............................................................................................................... 59
Summary of Baseline Projections across Sectors and States ............................................. 61
Annual Use ............................................................................................................... 61
5 CONSERVATION POTENTIAL .......................................................................... 62
Overall Summary of Energy Efficiency Potential ................................................................ 62
Summary of Annual Energy Savings ....................................................................... 62
Summary of Conservation Potential by Sector .................................................................. 66
Residential Conservation Potential ..................................................................................... 67
Commercial Conservation Potential .................................................................................. 73
Industrial Conservation Potential ............................................................................... 78
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6 DEMAND RESPONSE POTENTIAL ..................................................................... 83
Market Characterization ..................................................................................................... 83
Market segmentation .............................................................................................. 83 Customer Counts by Segment ............................................................................... 84 Forecasts of Winter and Summer Peak Demand................................................... 85 System and Coincident Peak Forecasts by State ................................................. 87 Equipment End Use Saturation ............................................................................... 88
DSM Program Options .......................................................................................................... 90
Program Descriptions .............................................................................................. 90 Program Assumptions and Characteristics ............................................................ 93 Other Cross-cutting Assumptions ......................................................................... 100
DR Potential and Cost Estimates ....................................................................................... 101
Integrated Potential Results ................................................................................. 101 Winter TOU Opt-in Scenario .................................................................................. 101 Cost Results ............................................................................................................ 105
Winter TOU Opt-out Scenario ............................................................................... 106
Cost Results ............................................................................................................ 110
Summer TOU Opt-in Scenario ............................................................................... 111
Cost Results ............................................................................................................ 115
Summer TOU Opt-out Scenario ............................................................................ 116
Cost Results ............................................................................................................ 120
Stand-alone Potential Results ............................................................................... 121
Winter Results ......................................................................................................... 121
Cost Results ............................................................................................................ 125
Summer Results ...................................................................................................... 126
Cost Results ............................................................................................................ 130
A MARKET PROFILES .......................................................................................................... A-1
B MARKET ADOPTION (RAMP) RATES .................................................................................. B-1
C MEASURE DATA .............................................................................................................. C-1
D HB 1444 IMPACT ANALYSIS .............................................................................................D-1

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LIST OF FIGURES
Figure 2-1 LoadMAP Analysis Framework ................................................................................... 14
Figure 2-2 Approach for Conservation Measure Assessment ................................................... 18
Figure 3-1 Sector-Level Electricity Use in Base Year 2017, Washington .................................... 33
Figure 3-2 Sector-Level Electricity Use in Base Year 2017, Idaho .............................................. 34
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................................. 36
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2017), Idaho ... 37
Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017),
Washington ................................................................................................................. 38
Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Idaho ..... 38
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................................. 42
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Idaho
..................................................................................................................................... 43
Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2017), Washington ..... 44
Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2017), Idaho .............. 45
Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All
Industries, WA ............................................................................................................. 48
Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All
Industries, ID ................................................................................................................ 49
Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington ............................. 54
Figure 4-2 Residential Baseline Projection by End Use – Annual Use per Household,
Washington ................................................................................................................. 55
Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho ...................................... 56
Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household,
Idaho ........................................................................................................................... 56
Figure 4-5 Commercial Baseline Projection by End Use, Washington ...................................... 58
Figure 4-6 Commercial Baseline Projection by End Use, Idaho ................................................ 58
Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington ................................ 60
Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho .......................................... 60
Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined .................................. 61
Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy),
Washington ................................................................................................................. 64
Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho ....... 64
Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh),
Washington ................................................................................................................. 65
Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho ...... 65
Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)
..................................................................................................................................... 66
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Washington .................................................................................................. 68
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Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Idaho ............................................................................................................ 68
Figure 5-8 Residential Technical Achievable Savings Forecast (Cumulative GWh),
Washington ................................................................................................................. 70
Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulative GWh), Idaho .... 72
Figure 5-10 Commercial Conservation Savings (Energy), Washington ...................................... 74
Figure 5-11 Commercial Conservation Savings (Energy), Idaho ................................................ 74
Figure 5-12 Commercial Technical Achievable Savings Forecast (Cumulative GWh),
Washington ................................................................................................................. 76
Figure 5-13 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Idaho
..................................................................................................................................... 78
Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual
Energy), Washington .................................................................................................. 79
Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual
Energy), Idaho ............................................................................................................ 80
Figure 5-16 Industrial Technical Achievable Savings Forecast (Cumulative GWh),
Washington ................................................................................................................. 81
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho
..................................................................................................................................... 82
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)
..................................................................................................................................... 87
Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter) ... 88
Figure 6-3 Summary of Potential Analysis for Avista (TOU Opt-In Winter Peak MW
@Generator) ............................................................................................................. 102
Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)
................................................................................................................................... 107
Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator) ............ 112
Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator) ........................ 117
Figure 6-7 and Table A-1 show the winter demand savings from individual DR options for
selected years of the analysis. These savings represent stand-alone savings
from all available DR options in Avista’s Washington and Idaho service
territories. .................................................................................................................. 121
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator) ............ 122
Figure 6-9 Summary of Summer Potential by Option (MW @Generator) ............................... 127

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LIST OF TABLES
Table 1-1 Explanation of Abbreviations and Acronyms ........................................................... 10
Table 2-1 Overview of Avista Analysis Segmentation Scheme ................................................ 16
Table 2-2 Example Equipment Measures for Central AC – Single-Family Home ..................... 20
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing ........................ 20
Table 2-4 Number of Measures Evaluated ................................................................................ 20
Table 2-5 Data Applied for the Market Profiles ........................................................................ 26
Table 2-6 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP .... 27
Table 2-7 Residential Electric Equipment Standards ................................................................ 28
Table 2-8 Commercial Electric Equipment Standards .............................................................. 29
Table 2-9 Industrial Electric Equipment Standards ................................................................... 30
Table 2-10 Data Needs for the Measure Characteristics in LoadMAP ...................................... 31
Table 3-1 Avista Sector Control Totals (2017), Washington ...................................................... 33
Table 3-2 Avista Sector Control Totals (2017), Idaho ................................................................ 34
Table 3-3 Residential Sector Control Totals (2017), Washington .............................................. 34
Table 3-4 Residential Sector Control Totals (2017), Idaho ....................................................... 35
Table 3-5 Average Market Profile for the Residential Sector, 2017, Washington ................... 39
Table 3-6 Average Market Profile for the Residential Sector, 2017, Idaho ............................. 40
Table 3-7 Commercial Sector Control Totals (2017), Washington ........................................... 41
Table 3-8 Commercial Sector Control Totals (2017), Idaho ..................................................... 42
Table 3-9 Average Electric Market Profile for the Commercial Sector, 2017, Washington .... 46
Table 3-10 Average Electric Market Profile for the Commercial Sector, 2017, Idaho.............. 47
Table 3-11 Industrial Sector Control Totals (2017) ....................................................................... 48
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2017, Washington ......... 51
Table 3-13 Average Electric Market Profile for the Industrial Sector, 2017, Idaho ................... 52
Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington ................... 54
Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho ............................. 55
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington ................. 57
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho ........................... 57
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington ................................ 59
Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho .......................................... 59
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined .................................. 61
Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington ................................ 63
Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho .......................................... 63
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and
ID ................................................................................................................................. 66
Table 5-4 Residential Conservation Potential (Annual Energy), Washington ......................... 67
Table 5-5 Residential Conservation Potential (Annual Energy), Idaho ................................... 67
Table 5-6 Residential Top Measures in 2019 (Annual Energy, MWh), Washington .................. 69
Table 5-7 Residential Top Measures in 2019 (Annual Energy, MWh), Idaho ............................ 71
Table 5-8 Commercial Conservation Potential (Annual Energy), WA ..................................... 73
Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho ........................ 73
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Table 5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington ............... 75
Table 5-11 Commercial Top Measures in 2019 (Annual Energy, MWh), Idaho ......................... 77
Table 5-12 Industrial Conservation Potential (Annual Energy), WA ........................................... 78
Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho ...................................... 79
Table 5-14 Industrial Top Measures in 2019 (Annual Energy, GWh), Washington ..................... 81
Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho ............................... 82
Table 6-1 Market Segmentation ................................................................................................ 84
Table 6-2 Baseline C&I Customer Forecast by State and Customer Class .............................. 84
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) ............................................. 85
Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................................... 86
Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................................... 86
Table 6-6 2017 End Use Saturations by Customer Class, Washington...................................... 89
Table 6-7 2017 End Use Saturation by Customer Class, Idaho ................................................. 89
Table 6-8 Class 1 DSM Products Assessed in the Study............................................................. 93
Table 6-9 DSM Steady-State Participation Rates (% of eligible customers) ............................ 95
Table 6-10 DSM Per Participant Impact Assumptions ................................................................. 96
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington)...... 97
Table 6-12 Marketing, Recruitment, Incentive, and Development Costs (Washington) .......... 98
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho) ............... 99
Table 6-14 Marketing, Recruitment, Incentive, and Development Costs (Idaho) ................. 100
Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator) .......... 103
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW
@Generator) ............................................................................................................. 104
Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW
@Generator) ............................................................................................................. 105
Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter) ........................................... 106
Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator) .... 108
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW
@Generator) ............................................................................................................. 109
Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
................................................................................................................................... 110
Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter ........................................ 111
Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator) ....... 113
Table 6-24 Achievable DR Potential by Option for WashingtonTOU Opt-In (Summer MW
@Generator) ............................................................................................................. 114
Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW
@Generator) ............................................................................................................. 115
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In ......................................... 116
Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator) . 118
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW
@Generator) ............................................................................................................. 119
Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW
@Generator) .................................................................................................... 120
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Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out ..................................... 121
Figure 6-7 and Table 6-31 show the winter demand savings from individual DR options for
selected years of the analysis. These savings represent stand-alone savings
from all available DR options in Avista’s Washington and Idaho service
territories. .................................................................................................................. 121
Table 6-32 Achievable DR Potential by Option (Winter MW @Generator) ............................. 123
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator) ... 124
Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator) ............. 125
Table 6-35 DR Program Costs and Potential (Winter) ............................................................... 126
Table 6-36 Achievable DR Potential by Option (Summer MW @Generator) .......................... 128
Table 6-37 Achievable DR Potential by Option for Washington (Summer MW @Generator) 129
Table 6-38 Achievable DR Potential by Option for Idaho (Summer MW @Generator) .......... 130
Table 6-39 DR Program Costs and Potential – Summer ............................................................ 131
Table A-1 Washington Residential Single Family Market Profile ................................................... A-2
Table A-2 Washington Residential Multi Family Market Profile ..................................................... A-3
Table A-3 Washington Residential Mobile Home Market Profile .................................................. A-4
Table A-4 Washington Residential Low-Income Market Profile .................................................... A-5
Table A-5 Washington Commercial Large Office Market Profile ................................................. A-6
Table A-6 Washington Commercial Small Office Market Profile .................................................. A-7
Table A-7 Washington Commercial Retail Market Profile ............................................................ A-8
Table A-8 Washington Commercial Restaurant Market Profile .................................................... A-9
Table A-9 Washington Commercial Grocery Market Profile ...................................................... A-10
Table A-10 Washington Commercial Health Market Profile ....................................................... A-11
Table A-11 Washington Commercial College Market Profile ..................................................... A-12
Table A-12 Washington Commercial School Market Profile ....................................................... A-13
Table A-13 Washington Commercial Lodging Market Profile .................................................... A-14
Table A-14 Washington Commercial Warehouse Market Profile ............................................... A-15
Table A-15 Washington Commercial Miscellaneous Market Profile .......................................... A-16
Table A-16 Washington Industrial Market Profile ......................................................................... A-17
Table A-17 Idaho Residential Single Family Market Profile ......................................................... A-18
Table A-18 Idaho Residential Multi Family Market Profile ........................................................... A-19
Table A-19 Idaho Residential Mobile Home Market Profile ........................................................ A-20
Table A-20 Idaho Residential Low-Income Market Profile .......................................................... A-21
Table A-21 Idaho Commercial Large Office Market Profile ....................................................... A-22
Table A-22 Idaho Commercial Small Office Market Profile ........................................................ A-23
Table A-23 Idaho Commercial Retail Market Profile .................................................................. A-24
Table A-24 Idaho Commercial Restaurant Market Profile .......................................................... A-25
Table A-25 Idaho Commercial Grocery Market Profile .............................................................. A-26
Table A-26 Idaho Commercial Health Market Profile ................................................................. A-27
Table A-27 Idaho Commercial College Market Profile .............................................................. A-28
Table A-28 Idaho Commercial School Market Profile ................................................................ A-29
Table A-29 Idaho Commercial Lodging Market Profile .............................................................. A-30
Table A-30 Idaho Commercial Warehouse Market Profile ......................................................... A-31
Table A-31 Idaho Commercial Miscellaneous Market Profile ........................................... A-32
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Table A-32 Idaho Industrial Market Profile .................................................................................. A-33
Table D-1 Impacts of HB 1444 on EE Potential ......................................................................... D-1

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INTRODUCTION
Avista Corporation (Avista) engaged Applied Energy Group (AEG) to conduct a Conservation Potential
Assessment (CPA). The CPA is a 20-year study, performed in accordance with Washington Initiative 937 (I-
937), that provides data on conservation resources to support development of Avista’s 2019 Integrated
Resource Plan (IRP). AEG first performed an electricity CPA for Avista in 2013. We have also performed gas
CPA studies in 2014 and 2016 and an assessment of demand-response potential in 2014. This study updates
Avista’s last electric CPA, which AEG performed in 2017.
Since 2017, additional information became available and there was also a desire for more granularity,
corresponding to increasing sophistication in CPA studies. Therefore, this study provided enhanced
analysis compared to the previous studies.
 The base-year for the analysis was brought forward from 2017 to 2017.
 For the residential sector, the study incorporated Avista’s GenPOP residential saturation survey from
2012. This provided the foundation for the base-year market characterization and energy market
profiles. The Northwest Energy Efficiency Alliance’s (NEEA’s) 2014 Residential Building Stock
Assessment (RBSA) supplemented the GenPOP survey.
 For the commercial sector, analysis was performed for the major building types in the service
territory. Results from the 2017 Commercial Building Stock Assessment (CBSA), including hospital
and university data, provided useful information for this characterization.
 This study also incorporated changes to the list of energy conservation measures, as a result of
research by the Regional Technical Forum (RTF). In particular, LED lamps continue to drop in price
and provide a significant opportunity for savings even under new market transformation
assumptions by the RTF.
 Some measure data from the Seventh Power Plan (Seventh Plan) has been updated to reflect
progress in the last two years.
 The study incorporates updated forecasting assumptions that line up with the most recent Avista
load forecast.
 Analysis of economic potential was excluded from this study. Avista will screen for cost-effective
opportunities directly within the IRP model. As such, economic potential and achievable potential
have been replaced by a Technical Achievable Potential case.
 In addition to analyzing annual energy savings, the study also estimated the opportunity for
reduction of summer and winter peak demand. This involved a full characterization by sector,
segment and end use of peak demand in the base year.
 Finally, this year’s study included an update to the 2017 assessment of demand-response potential,
including analysis of residential programs as well as commercial and industrial (C&I), and options for
both summer and winter demand reduction.
Since economic achievable potential is not included in this CPA, it is not possible to compare achievable
potential results with CPAs prior to 2017. When making comparisons to the previous study we will focus
on Technical Achievable Potential. Compared to the 2017 Study, 10-year technical achievable
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Avista Conservation Potential Assessment for 2021-2040| Introduction 
  | 10 Applied Energy Group • www.appliedenergygroup.com
potential has increased to 110.1 aMW from 105.8 aMW. This is a net effect of changes in the measure list,
market transformation, and baseline growth.
Abbreviations and Acronyms
Table 1-1 provides a list of abbreviations and acronyms used in this report, along with an explanation.
Table 1-1 Explanation of Abbreviations and Acronyms
Acronym Explanation 
ACS American Community Survey 
AEO Annual Energy Outlook forecast developed by EIA 
AHAM Association of Home Appliance Manufacturers  
AMI Advanced Metering Infrastructure 
AMR Automated Meter Reading 
Auto‐DR Automated Demand Response 
B/C Ratio Benefit to Cost Ratio 
BEST AEG’s Building Energy Simulation Tool 
C&I Commercial and Industrial 
CAC Central Air Conditioning 
CFL Compact fluorescent lamp 
CPP Critical Peak Pricing 
C&I Commercial and Industrial 
DHW Domestic Hot Water 
DLC Direct Load Control 
DR Demand Response 
DSM Demand Side Management 
EE Energy Efficiency 
EIA Energy Information Administration 
EUL Estimated Useful Life 
EUI Energy Usage Intensity  
FERC Federal Energy Regulatory Commission 
HH Household 
HID High intensity discharge lamps 
HVAC Heating Ventilation and Air Conditioning 
ICAP Installed Capacity 
IOU Investor Owned Utility 
LED Light emitting diode lamp 
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Avista Conservation Potential Assessment for 2021-2040| Introduction 
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Acronym Explanation 
LoadMAP AEG’s Load Management Analysis and Planning™ tool 
LCOE Levelized cost of energy 
MW Megawatt 
NPV Net Present Value 
O&M Operations and Maintenance 
PCT Programmable Communicating Thermostat 
RTU Roof top unit 
TRC Total Resource Cost test 
UEC Unit Energy Consumption  
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ANALYSIS APPROACH AND DATA DEVELOPMENT
This section describes the analysis approach taken for the study and the data sources used to develop the
potential estimates.
Overview of Analysis Approach
To perform the potential analysis, AEG used a bottom-up approach following the major steps listed below.
We describe these analysis steps in more detail throughout the remainder of this chapter.
1. Perform a market characterization to describe sector-level electricity use for the residential,
commercial, and industrial sectors for the base year, 2017.
2. Develop a baseline projection of energy consumption and peak demand by sector, segment, and
end use for 2017 through 2039.
3. Define and characterize several hundred conservation measures to be applied to all sectors,
segments, and end uses.
4. Estimate technical and Technical Achievable Potential at the measure level in terms of energy and
peak demand impacts from conservation measures for 2021-2040.
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 EPRI National Potential Study and numerous utility-specific forecasting and
potential studies since that time. Built in Excel, the LoadMAP framework (see Figure 2-1) is both accessible
and transparent and has the following key features.
 Embodies the basic principles of rigorous end-use models (such as EPRI’s REEPS and 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.
 Uses a simple logic for appliance and equipment decisions. Other models available for this purpose
embody complex decision choice algorithms or diffusion assumptions, and 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
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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
lighting is distinct from refrigerators and freezers.
 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 or income
level).
 Can incorporate conservation measures, demand-response options, combined heat and power
(CHP) and distributed generation options and fuel switching.
Consistent with the segmentation scheme and the market profiles we describe below, the LoadMAP model
provides projections of baseline energy use by sector, segment, end use, and technology for existing and
new buildings. It also provides forecasts of total energy use and energy-efficiency savings associated with
the various types of potential.1
Figure 2-1 LoadMAP Analysis Framework

1 The model computes energy and peak-demand forecasts for each type of potential for each end use as an intermediate calculation.
Annual-energy and peak-demand 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).
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Definitions of Potential
In this study, the conservation potential estimates represent gross savings developed for two levels of
potential: technical potential and Technical Achievable Potential. These levels are described below.
 Technical Potential is defined as the theoretical upper limit of conservation potential. It assumes
that customers adopt all feasible measures regardless of their cost. At the time of existing
equipment failure, customers replace their equipment with the efficient option available. In new
construction, customers and developers also choose the most efficient equipment option.
In new construction, customers and developers also 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 developed by the
NWPCC for its Seventh Power Plan, applied to 100% of the applicable market. This case is a
theoretical construct and is provided primarily for planning and informational purposes.
 Technical Achievable Potential refines Technical Potential by applying customer participation
rates that account for market barriers, customer awareness and attitudes, program maturity, and other
factors that may affect market penetration of DSM measures. We used achievability assumptions from
the Council’s Seventh Plan, adjusted for Avista’s recent program accomplishments, as the customer
adoption rates for this study. For the technical achievable case, ramp rates are applied to at most 85%
of the applicable market, per Council methodology. This achievability factor represents potential which
can reasonably be acquired by all mechanisms available, regardless of how conservation is achieved.
Thus, the market applicability assumptions utilized in this study include savings outside of utility
programs.2
Details regarding the market adoption factors appear in Appendix B.
Market Characterization
The first step in the analysis approach is market characterization. In order 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. This characterization begins with a segmentation of Avista’s electricity
footprint to quantify energy use by sector, segment, end-use application, and the current set of
technologies used. We rely primarily 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)
that are relevant in the Avista service territory. The segmentation scheme for this project is presented in
Table 2-1.

2 Council’s 7th Power Plan applicability assumptions reference an “Achievable Savings” report published August 1, 2007.
http://www.nwcouncil.org/reports/2007/2007-13/
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Table 2-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description 
1  Sector Residential, commercial, industrial 
2 Segment 
Residential: single family, multifamily, manufactured home, low 
income 
Commercial: small office, large office, restaurant, retail, grocery, 
college, school, health, lodging, warehouse, and miscellaneous 
Industrial: total 
3  Vintage Existing and new construction 
4 End uses Cooling, lighting, water heat, motors, etc. (as appropriate by 
sector) 
5 Appliances/end uses and 
technologies 
Technologies such as lamp type, air conditioning equipment, 
motors 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
electricity sales in the base year to allocate sales to each customer segment. We used Avista data and
secondary sources to allocate energy use and customers to the various sectors and segments such that
the total customer count, energy consumption, and peak demand matched the Avista system totals from
2017 billing data. This information provided control totals at a sector level for calibrating the LoadMAP
model to known data for the base-year.
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and technology.
A market profile includes the following elements:
 Market size is a representation of the number of customers in the segment. For the residential
sector, it is number of households. In the commercial sector, it is floor space measured in square
feet. For the industrial sector, it is overall electricity use.
 Saturations define the fraction of homes or square feet with the various technologies. (e.g., homes
with electric space heating).
 UEC (unit energy consumption) or EUI (energy-use index) describes the amount of energy
consumed in 2017 by a specific technology in buildings that have the technology. For electricity,
UECs are expressed in kWh/household for the residential sector, and EUIs are expressed in
kWh/square foot for the commercial sector.
 Annual Energy Intensity for the residential sector represents the average energy use for the
technology across all homes in 2017. It is computed as the product of the saturation and the UEC
and is defined as kWh/household for electricity. For the commercial sector, intensity, computed as
the product of the saturation and the EUI, represents the average use for the technology across all
floor space in 2017.
 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 GWh.
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 Peak Demand for each technology, summer peak and winter peak are calculated using peak
fractions of annual energy use from AEG’s EnergyShape library and Avista system peak data.
The market characterization results, and the market profiles are presented in Chapter 3.
Baseline Projection
The next step was to develop the baseline projection of annual electricity use and summer peak demand
for 2018 through 2040 by customer segment and end use without new utility programs. The end-use
projection includes the impacts of relatively certain codes and standards which will unfold over the study
timeframe. All such mandates that were defined as of September 2018 are included in the baseline. The
baseline projection is the foundation for the analysis of savings from future conservation efforts as well
as the metric against which potential savings are measured.
Inputs to the baseline projection include:
 Current economic growth forecasts (i.e., customer growth, income growth)
 Electricity price forecasts
 Trends in fuel shares and equipment saturations
 Existing and approved changes to building codes and equipment standards
 Avista’s internally developed sector-level projections for electricity sales
We also developed a baseline projection for summer and winter peak by applying the peak fractions from
the energy market profiles to the annual energy forecast in each year.
We present the baseline-projection results for the system as a whole and for each sector in Chapter 4.
Washington HB 1444
As this CPA neared its conclusion, the state of Washington passed HB 14443, which establishes new
efficiency rules for several appliance and equipment categories. While the CPA models were not rebuilt to
incorporate these new standards, we did estimate the impacts of these new standards in terms of measure
potential that would be moved into the baseline by this ruling. We present the details of this estimate in
Appendix D.
Conservation Measure Analysis
This section describes the framework used to assess the savings, costs, and other attributes of
conservation measures. These characteristics form the basis for measure-level cost-effectiveness analyses
as well as for determining measure-level savings. For all measures, AEG assembled information to reflect
equipment performance, incremental costs, and equipment lifetimes. We used this information, along with
the Seventh Plan’s updated ramp rates to identify technical achievable measure potential.
Conservation Measures
Figure 2-2 outlines the framework for conservation measure analysis. The framework for assessing savings,
costs, and other attributes of conservation measures involves identifying the list of measures to include in
the analysis, determining their applicability to each market sector and segment, fully characterizing each
measure, and calculating the levelized cost of energy ($/MWh). Potential measures include the
replacement of a unit that has failed or is at the end of its useful life with an efficient unit, retrofit or early

3 https://app.leg.wa.gov/billsummary?BillNumber=1444&Year=2019&initiative=
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replacement of equipment, improvements to the building envelope, the application of controls to optimize
energy use, and other actions resulting in improved energy efficiency.
We compiled a robust list of conservation measures for each customer sector, drawing upon Avista’s
measure database, the Regional Technical Forum (RTF), and the Seventh Plan deemed measures database,
as well as a variety of secondary sources. This universal list of conservation measures covers all major
types of end-use equipment, as well as devices and actions to reduce energy consumption.
Since an economic screen was not performed in this Study, we have instead calculated the levelized cost
of energy (LCOE) for each measure evaluated. This value, expressed in dollars per first-year megawatt
hour (MWh) saved, can be used by Avista’s IRP model to evaluate cost effectiveness. To calculate a
measure’s LCOE, first-year measure costs, annual non-energy benefits, and annual operations and
maintenance (O&M) costs are levelized over a measure’s lifetime, then divided by the first-year savings in
MWh. Note that while non-energy benefits are typically included in the numerator of a traditional Total
Resource Cost (TRC) economic screen, the LCOE benefits have not been monetized. Therefore, these
benefits are instead subtracted from the costs portion of the test. These benefits are not included in the
Utility Cost Test (UCT) used in Idaho.

Figure 2-2 Approach for Conservation Measure Assessment

The selected measures are categorized into two types according to the LoadMAP taxonomy: equipment
measures and non-equipment measures.
 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 refrigerator that replaces a standard efficiency refrigerator. For equipment measures,
many efficiency levels may be available for a given technology, ranging from the baseline unit (often
determined by code or standard) up to the most efficient product commercially available. For
instance, in the case of central air conditioners, this list begins with the current federal
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standard SEER 13 unit and spans a broad spectrum up to a maximum efficiency of a SEER 21 unit.
The Seventh Plan’s “Lost Opportunity” ramp rates are primarily applied to equipment measures.
 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 refrigerator or air
conditioner). An example would be a programmable thermostat that is pre-set to run heating and
cooling systems only when people are home. Non-equipment measures can apply to more than one
end use. For instance, addition of wall insulation will affect the energy use of both space heating
and cooling. The Seventh Plan’s “Retrofit” ramp rates are primarily applied to no-equipment
measures. Non-equipment measures typically fall into one of the following categories:
1. Building shell (windows, insulation, roofing material)
2. Equipment controls (thermostat, compressor staging and controls)
3. Equipment maintenance (cleaning filters, changing setpoints)
4. Whole-building design (building orientation, advanced new construction designs)
5. Lighting retrofits (assumed to be implemented alongside new LEDs at the equipment’s normal
end of life)
6. Displacement measures (ceiling fan to reduce use of central air conditioners)
7. Commissioning and retrocommissioning (initial or ongoing monitoring of building energy systems
to optimize energy use)
We developed a preliminary list of conservation measures, which was distributed to the Avista project
team for review. The list was finalized after incorporating comments and is presented in the appendix to
this volume.
Once we assembled the list of conservation measures, the project team characterized measure savings,
incremental cost, service life, and other performance factors, drawing upon data from the Avista measure
database, the Seventh Power Plan, the RTF deemed measure workbooks, simulation modeling, and other
well-vetted sources as required.
Representative Conservation Measure Data Inputs
To provide an example of the conservation measure data, Table 2-2 and Table 2-3 present examples of
the detailed data inputs behind both equipment and non-equipment measures, respectively, for the case
of residential CAC in single-family homes. Table 2-2 displays the various efficiency levels available as
equipment measures, as well as the corresponding useful life, energy usage, and cost estimates. The
columns labeled “On Market” and “Off Market” reflect equipment availability due to codes and standards
or the entry of new products to the market. Note that in this example no standards come into play and
therefore all options are available throughout the forecast.
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Table 2-2 Example Equipment Measures for Central AC – Single-Family Home
Efficiency Level Useful Life (yrs) Equipment Energy Usage 
(kWh/yr) 
On Off 
Cost Market Market 
SEER 13.0  10 to 20  $2,097   1,383  2017  n/a 
SEER 14.0 10 to 20 $2,505  1,284 2017 n/a 
SEER 15.0 10 to 20 $2,913  1,199  2017 n/a 
SEER 16.0 10 to 20 $3,321  1,124 2017 n/a 
SEER 18.0 10 to 20 $4,140  999  2017 n/a 
SEER 20.0 10 to 20 $4,955  899 2017 n/a 

Table 2-3 lists some of the non-equipment measures applicable to a CAC in an existing single family home.
LCOE values for all measures are evaluated based on the lifetime costs of the measure divided by the first-
year savings. The total costs and savings are calculated for each year of the study and depend on the base
year saturation of the measure, the applicability4 of the measure, and the savings as a percentage of the
relevant energy end uses.
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing
End Use Measure Saturation 
in 2017 Applicability Lifetime 
(yrs) 
Measure 
Installed Cost 
Energy 
Savings (%) 
Cooling  Insulation ‐ Ceiling Installation 0.00%  4.11%  45  $1,230.69   30.17% 
Cooling Insulation ‐ Wall Cavity Installation 0.00% 5.73% 45 $2,622.52  6.10% 
Cooling  Ducting ‐ Repair and Sealing  22.84%  40.00%  20  $656.94  6.29% 
Cooling Windows ‐ High Efficiency/ENERGY STAR 67.43% 75.00% 45 $3,966.55  9.63% 
Cooling  Thermostat ‐ Connected 4.00%  60.00%  5  $259.00   6.00% 

Table 2-4 summarizes the number of measures evaluated for each segment within each sector.
Table 2-4 Number of Measures Evaluated
Sector Total Measures  
Measure 
Permutations w/ 
2 Vintages 
Measure 
Permutations w/ 
Segments  
Residential  88 176 704 
Commercial 130 260 2,860 
Industrial 111 222 222 
Total Measures Evaluated 329 658 3,786 

4 The applicability factors take into account whether the measure is applicable to a particular building type and whether it is feasible to
install the measure. For instance, attic fans are not applicable to homes where there is insufficient space in the attic or there is no attic at
all.
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Conservation Potential
The approach we used for this study to calculate the conservation potential adheres to the approaches
and conventions outlined in the National Action Plan for Energy-Efficiency (NAPEE) Guide for Conducting
Potential Studies (November 2007).5 The NAPEE Guide represents the most credible and comprehensive
industry practice for specifying conservation potential. As described in Chapter 2, two types of potential
were developed as part of this effort: Technical Potential and Technical Achievable Potential.
 Technical potential is a theoretical construct that assumes the highest efficiency measures that
are technically feasible to install are adopted by customers, regardless of cost or customer
preferences. Thus, determining the technical potential is relatively straightforward. LoadMAP
“chooses” the efficient equipment options for each technology at the time of equipment
replacement. In addition, it installs all relevant non-equipment measures for each technology to
calculate savings. LoadMAP applies the savings due to the non-equipment measures one-by-one to
avoid double counting of savings. The measures are evaluated in order of their LCOE ratio, with the
measure with the lowest LCOE values (most likely to be cost effective) applied first. Each time a
measure is applied, the baseline energy use for the end use is reduced and the percentage savings
for the next measure is applied to the revised (lower) usage.
 Technical Achievable Potential refines Technical Potential by applying market adoption rates for
each measure that estimate the percentage of customers who would be likely to select each
measure, given consumer preferences (partially a function of incentive levels), retail energy rates,
imperfect information, and real market barriers and conditions. These barriers tend to vary,
depending on the customer sector, local energy market conditions, and other, hard-to-quantify
factors. In addition to utility-sponsored programs, alternative acquisition methods, such as improved
codes and standards and market transformation, can be used to capture portions of these
resources, and are included within the Technical Achievable Potential, per 7th Power Plan
methodology.
The calculation of Technical Potential is a straightforward algorithm. To develop estimates for Technical
Achievable Potential, we develop market adoption rates for each measure that specify the percentage of
customers that will select the highest–efficiency economic option. For Avista, the project team began with
the ramp rates specified in the Seventh Plan conservation workbooks but modified these to match Avista
program history and service territory specifics. We examined historic program results for the most recent
program years. We then adjusted the 2021 Technical Achievable Potential for these measures to
approximately match the historical results. This provided a starting for 2021 potential that was aligned to
historic results. In future years, the potential factors increased to a maximum of 85%, 55% for emerging
technologies, to model increasing market acceptance and program improvements. For measures within
the Seventh Plan, the Council’s prescribed ramp rates were used. For measures outside the Seventh Plan,
AEG assigned ramp rates comparable to similar measures within the Seventh Plan. The market adoption
rates for each measure appear in Appendix B.
Results of all the potentials analysis are presented in Chapter 5.

5 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.
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Data Development
This section details the data sources used in this study, followed by a discussion of how these sources
were applied. In general, data sources were applied in the following order: Avista data, Northwest data,
and well-vetted national or other regional secondary sources.
Data Sources
The data sources are organized into the following categories:
 Avista data
 Northwest Energy Efficiency Alliance data
 Northwest Power and Conservation Council data
 AEG’s databases and analysis tools
 Other secondary data and reports
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
 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 an economic growth forecast by sector; electric load forecast;
peak-demand forecasts at the sector level; and retail electricity price history and forecasts.
 Economic information: Avista Power provided a discount rate and line loss factor. Avoided costs
were not provided due to the economic screen being moved to the IRP model.
 Avista program data: Avista provided information about past and current programs, including
program descriptions, goals, and achievements to date.
Northwest Energy Efficiency Alliance Data
The Northwest Energy Efficiency Alliance conducts research on an ongoing basis for the Northwest region.
The following studies were particularly useful for this study:
 Northwest Energy Efficiency Alliance, Residential Building Stock Assessment II, Single-
Family Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-
Assessment-II-Single-Family-Homes-Report-2016-2017.pdf
 Northwest Energy Efficiency Alliance, Residential Building Stock Assessment II,
Manufactured Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-
Assessment-II-Manufactured-Homes-Report-2016-2017.pdf
 Northwest Energy Efficiency Alliance, Residential Building Stock Assessment II,
Multifamily Buildings Report 2016-2017, https://neea.org/img/documents/Residential-Building-
Stock-Assessment-II-Multifamily-Homes-Report-2016-2017.pdf
 Northwest Energy Efficiency Alliance, 2014 Commercial Building Stock Assessment,
December 16, 2014, http://neea.org/docs/default-source/reports/2014-cbsa-final-report_05-dec-
2014.pdf?sfvrsn=12
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 Northwest Energy Efficiency Alliance, 2014 Industrial Facilities Site Assessment,
December 29, 2014, http://neea.org/docs/default-source/reports/2014-industrial-facilities-stock-
assessment-final-report.pdf?sfvrsn=6
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.
 Regional Technical Forum Deemed Measures. The NWPCC Regional Technical Forum
maintains databases of deemed measure savings data, available at
http://www.nwcouncil.org/energy/rtf/measures/Default.asp .
 Northwest Power and Conservation Council Seventh Plan Conservation Supply Curve
Workbooks. To develop its Seventh Power Plan, the Council used workbooks with detailed
information about measures, available at
https://nwcouncil.app.box.com/v/7thplanconservationdatafiles
 Northwest Power and Conservation Council, 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. Generalized Least Square (GLS) versions of these load shapes are
available at https://nwcouncil.app.box.com/s/gacr21z8i89hh8ppk11rdzgm6fz4xlz3
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: For more than 10 years, AEG staff has maintained profiles of end-
use consumption for the residential, commercial, and industrial sectors. These 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 Energy Information
Administration 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 the
HVAC-related measures.
 AEG’s EnergyShape™: AEG’s load shape database was used in addition to the Council’s load
shape database for comparative purposes. This database of load shapes includes the following:
o Residential – electric load shapes for ten regions, three housing types, 13 end uses
o Commercial – electric load shapes for nine regions, 54 building types, ten end uses
o Industrial – electric load shapes, whole facility only, 19 2-digit SIC codes, as well as various 3-
digit and 4-digit SIC codes
 AEG’s Database of Energy Efficiency Measures (DEEM): AEG maintains an extensive
database of measure data for our studies. Our database draws 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.
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 Recent studies. AEG has conducted numerous studies of EE potential in the last five years. We
checked our input assumptions and analysis results against the results from these other studies,
which include Tacoma Power, Idaho Power, PacifiCorp, Ameren Missouri, Vectren Energy,
Indianapolis Power & Light, Tennessee Valley Authority, Ameren Missouri, Ameren Illinois, and
Seattle City Light. In addition, we used the information about impacts of building codes and
appliance standards from recent reports for the Edison Electric Institute6.
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main sources are
identified below.
 Annual Energy Outlook. The Annual Energy Outlook (AEO), conducted each year by the U.S.
Energy Information Administration (EIA), presents yearly projections and analysis of energy topics.
For this study, we used data from the 2017 AEO.
 Local Weather Data: Weather from NOAA’s National Climatic Data Center for Spokane, WA was
used as the basis for building simulations.
 EPRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we
apply to electricity prices, household income, home size and heating and cooling.
 Database for Energy Efficient Resources (DEER). The California Energy Commission and
California Public Utilities Commission (CPUC) sponsor this database, which is designed to provide
well-documented estimates of energy and peak demand savings values, measure costs, and
effective useful life (EUL) for the state of California. We used the DEER database to cross check the
measure savings we developed using BEST and DEEM.
 Other relevant regional sources: These include reports from the Consortium for Energy
Efficiency (CEE), the Environmental Protection Agency (EPA), and the American Council for an
Energy-Efficient Economy (ACEEE).
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 electricity use and households/floor space for the
residential, commercial and industrial sectors, we used Avista billing data and customer surveys to
estimate energy use.
 For the residential sector, Avista estimated the numbers of customers and the 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 American

6 AEG staff has prepared three white papers on the topic of factors that affect U.S. electricity consumption, including
appliance standards and building codes. Links to all three white papers are provided:
http://www.edisonfoundation.net/IEE/Documents/IEE_RohmundApplianceStandardsEfficiencyCodes1209.pdf
http://www.edisonfoundation.net/iee/Documents/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf.
http://www.edisonfoundation.net/iee/Documents/IEE_FactorsAffectingUSElecConsumption_Final.pdf

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Community Survey (ACS) regarding housing types and income and found that the Avista
segmentation corresponded well with the ACS data. (See Chapter 3 for additional details.)
 To segment the commercial and industrial 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 commercial and
industrial sectors to better group energy use by facility type and predominate end uses. (See
Chapter 3 for additional details.)
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are shown in Table
2-5. To develop the market profiles for each segment, we did the following:
1. Developed control totals for each segment. These include market size, segment-level annual
electricity use, and annual intensity.
2. Used the Avista GenPOP Survey, NEEA’s RBSA, NEEA’s CBSA, NEEA’s IFSA, and AEG’s Energy Market
Profiles database to develop existing appliance saturations, appliance and equipment characteristics,
and building characteristics.
3. Ensured calibration to control totals for annual electricity sales in each sector and segment.
4. Compared and cross-checked with other recent AEG studies.
5. Worked with Avista staff to vet the data against their knowledge and experience.

Data Application for Baseline Projection
Table 2-5 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.
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Table 2-5 Data Applied for the Market Profiles
Model Inputs Description Key Sources 
Market size  Base‐year residential dwellings, commercial 
floor space, and industrial employment 
Avista billing data 
Avista GenPOP Survey 
NEEA RBSA and CBSA 
AEO 2017‐2018 
Annual intensity 
Residential: Annual use per household 
Commercial: Annual use per square foot 
Industrial: Annual use per employee 
Avista billing data 
AEG’s Energy Market Profiles 
NEEA RBSA and CBSA 
AEO 2017‐2018 
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 
NEEA RBSA and CBSA 
AEG’s Energy Market Profiles 
UEC/EUI for each end‐
use technology 
UEC: Annual electricity use in homes and 
buildings that have the technology 
EUI: Annual electricity use per square 
foot/employee for a technology in floor space 
that has the technology 
NWPCC RTF and Seventh Plan and 
RTF 
HVAC uses: BEST simulations using 
prototypes developed for Idaho  
Engineering analysis 
DEEM 
Recent AEG studies 
Appliance/equipment 
age distribution Age distribution for each technology 
RTF and NWPCC Seventh Plan data 
NEEA regional survey data  
Utility saturation surveys  
Recent AEG studies 
Efficiency options for 
each technology 
List of available efficiency options and annual 
energy use for each technology 
AEG DEEM 
AEO 2017‐2018 
DEER 
RTF and NWPCC Seventh Plan data 
Previous studies 
Peak factors Share of technology energy use that occurs 
during the peak hour EnergyShape database 

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Table 2-6 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 and C&I sectors 
Avista load forecast 
AEO 2017‐2018 economic growth 
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 
Shipments data from AEO and 
ENERGY STAR 
AEO 2017‐2018 regional forecast 
assumptions7 
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 
AEO 2017‐2018 

In addition, we implemented assumptions for known future equipment standards as of September 2018,
as shown in Table 2-6, Table 2-7 and Table 2-8. The assumptions tables here extend through 2025, after
which all standards are assumed to hold steady.

7 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2016), which utilizes
the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated equipment
purchase options to match manufacturer shipment data for recent years and then held values constant for the study period. This removes
any effects of naturally occurring conservation or effects of future EE programs that may be embedded in the AEO forecasts.
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Table 2-7 Residential Electric Equipment Standards8
End Use Technology 2017 2018 2019 2020 2021   2022 2023 2024 2025 
Cooling Central AC SEER 13.0 
  Room AC EER 10.8 
Cooling/ Air‐Source Heat Pump SEER 13.0 / HSPF 8.2  SEER 14.0 / HSPF 9.0 Heating 
Water Heating Water Heater  EF 0.95   (<=55 gallons) 
  Water Heater  EF 2.0 (Heat Pump Water Heater)   (>55 gallons) 
Lighting General Service Advanced Incandescent  
(~20 lumens/watt) Advanced Incandescent (~45 lumens/watt)  
  Linear Fluorescent T8 (92.5 lm/W lamp)  
Appliances Refrigerator 25% more efficient than the 1997 Final Rule (62 FR 23102)   Freezer 
  Clothes Washer IMEF 1.84 / WF 4.7                   
  Clothes Dryer 3.73 Combined EF                   
Miscellaneous Furnace Fans Conventional ECM                 

8 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
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Table 2-8 Commercial Electric Equipment Standards9

End Use Technology 2017 2018 2019 2020 2021 2022 2023 2024 2025
Cooling
Chillers 2007 ASHRAE 90.1
RTUs EER 11.9/11.2
PTAC EER 9.8 EER 11.0
Cooling/
Heating
Heat Pump EER 11.0/ EER 11.4/
COP 3.3 COP 3.3
PTHP EER 10.4/COP 3.1
Ventilation All Constant Air Volume/Variable Air Volume
Lighting
General Service Advanced Incandescent Advanced Incandescent
(~20 lumens/watt) (~45 lumens/watt)
Linear Lighting T8 (82.5 lm/W lamp)
High Bay 51.2 lm/W Metal Halide (55.6 lm/W)
Refrigeration
Walk-In COP 3.2 COP 6.1
Reach-In 32 kWh/sqft
Glass Door 12-28% more efficient than EPACT 2005
Open Display 1,537 kWh/ft 1,453 kWh/ft
Icemaker 6.1 kWh/100 lbs.
Food Service Pre-Rinse 1.6 GPM 1.0 GPM
Motors All Expanded EISA 2007

9 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
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Table 2-9 Industrial Electric Equipment Standards10

End Use Technology 2017 2018 2019 2020 2021 2022 2023 2024 2025
Cooling
Chillers 2007 ASHRAE 90.1
RTUs EER 11.9/11.2
PTAC EER 9.8 EER 11.0
Cooling/
Heating
Heat Pump EER 11.0/ EER 11.4/
COP 3.3 COP 3.3
PTHP EER 10.4/COP 3.1
Ventilation All Constant Air Volume/Variable Air Volume
Lighting
General Service Advanced Incandescent Advanced Incandescent
(~20 lumens/watt) (~45 lumens/watt)
Linear Lighting T8 (82.5 lm/W lamp)
High Bay 51.2 lm/W Metal Halide (55.6 lm/W)
Motors All Expanded EISA 2007

10 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
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Conservation Measure Data Application
Table 2-9 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 2-10 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 measure data 
NWPCC workbooks, RTF 
NWPCC Seventh Plan 
conservation workbooks 
BEST 
AEG DEEM 
AEO 2017‐2018 
DEER 
Other secondary sources 
Peak Demand Impacts 
Savings during the peak demand periods are specified 
for each electric measure. These impacts relate to the 
energy savings and depend on the extent to which 
each measure is coincident with the system peak. 
Avista measure data 
BEST 
AEG DEEM 
EnergyShape 
 Costs 
Equipment Measures: Includes the full cost of 
purchasing and installing the equipment on a per‐
household, per‐square‐foot, per employee or per 
service point basis for the residential, commercial, 
and industrial sectors, respectively. 
Non‐equipment measures: Existing buildings – full 
installed cost. New Construction ‐ the costs may be 
either the full cost of the measure, or as appropriate, 
it may be the incremental cost of upgrading from a 
standard level to a higher efficiency level. 
Avista measure data 
NWPCC workbooks, RTF 
NWPCC Seventh Plan 
conservation workbooks 
AEG DEEM 
AEO 2017‐2018 
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 measure data 
NWPCC workbooks, RTF 
NWPCC Seventh Plan 
conservation workbooksAEG 
DEEM 
AEO 2017‐2018 
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. 
Avista measure data 
NWPCC workbooks, RTF 
NWPCC Seventh Plan 
conservation workbooks 
AEG DEEM 
DEER 
Other secondary sources 
On Market and Off 
Market Availability 
Expressed as years for equipment measures to reflect 
when the equipment technology is available or no 
longer available in the market. 
AEG appliance standards and 
building codes analysis 
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Data Application for Technical Achievable Potential
To estimate Technical Achievable Potential, two sets of parameters are needed to represent customer
decision making behavior with respect to energy-efficiency choices.
 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. Like the 2016 CPA, we applied the “Retrofit” ramp
rates from the Seventh Power Plan directly as diffusion curves. For technical potential, these rates
summed up to 100% by the 20th year for most measures. Emerging technologies summed to 65% by
the 20th year.
 Adoption rates. Customer adoption rates or take rates are applied to technical potential to
estimate Technical Achievable Potential. For equipment measures, the Council’s “Lost Opportunity”
ramp rates were applied to technical potential with a maximum achievability of 85% for most
measures and 55% for emerging technologies. For non-equipment measures, the Council’s “Retrofit”
ramp rates have already been applied to calculate technical diffusion. In this case, we multiply each
of these by 85% for most measures and 55% for emerging technologies to calculate Technical
Achievable Potential. Adoption rates are presented in Appendix B.

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MARKET CHARACTERIZATION AND MARKET PROFILES
In this section, we describe how customers in the Avista service territory use electricity in the base year of
the study, 2017. 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
Total electricity use for the residential, commercial, and industrial sectors for Avista in 2017 was 7,954
GWh; 5,311 GWh (WA) and 2,643 GWh (ID). As shown in the tables below, in both states the residential
sector accounts for 49% of the annual energy use, followed by commercial at 41% of the annual energy
use. In terms of winter peak demand, the total system peak in 2017 was 1,649 MW: 1,117 (WA) and 532 MW
(ID). In both states, the residential sector contributes the most to the winter peak.
Figure 3-1 Sector-Level Electricity Use in Base Year 2017, Washington

Table 3-1 Avista Sector Control Totals (2017), Washington
Sector Annual Electricity % of Winter Peak Demand % of 
Use (GWh) Annual Use (MW) Winter Peak 
Residential 2,607 49% 551 49% 
Commercial 2,200 41% 473 42% 
Industrial 504 9% 93 8% 
Total 5,311 100% 1,117 100% 

Residential
49%
Commercial
41%
Industrial
10%
Annual Use (GWh)
Residential
49%
Commercial
42%
Industrial
9%
Winter Peak (MW)
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Figure 3-2 Sector-Level Electricity Use in Base Year 2017, Idaho

Table 3-2 Avista Sector Control Totals (2017), Idaho
Sector Annual Electricity % of Winter Peak Demand % of 
Use (GWh) Annual Use (MW) Winter Peak 
Residential 1,250 47% 256 48% 
Commercial 1,027 39% 200 38% 
Industrial 366 14% 76 14% 
Total 2,643 100% 532 100% 
Residential Sector
The total number of households and electricity sales for the service territory were obtained from Avista’s
customer database. In 2017, there were 222,837 households in the state of Washington that used a total
of 2,607 GWh with winter peak demand of 551 MW. Average use per customer (or household) at 11,699
kWh is about average compared to other regions of the country. We allocated these totals into four
residential segments and the values are shown in Table 3-3.
Table 3-4 shows the total number of households and electricity sales in the state of Idaho. In 2017, there
were 112,001 households that used a total of 1,250 GWh with winter peak demand of 256 MW. Average
use per customer (or household) was 11,158 kWh.
Table 3-3 Residential Sector Control Totals (2017), Washington
Segment Number of 
Customers Electricity Use % of Annual 
Annual 
Use/Customer 
(kWh/HH) 
Winter Peak 
    Single Family 135,485 1,825 70% 13,473 378 
    Multifamily 12,479 101 4% 8,084 27 
    Mobile Home 8,022 97 4% 12,125 19 
    Low Income 66,851 583 22% 8,728 128 
    Total 222,837 2,607 100% 11,699 551 

Residential
49%
Commerci
al
41%
Industrial
10%
Annual Use (GWh)
Residential
49%
Commerci
al
42%
Industrial
9%
Winter Peak (MW)
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Table 3-4 Residential Sector Control Totals (2017), Idaho
Segment Number of 
Customers 
Electricity 
Use 
% of 
Annual 
Annual Use/Customer 
(kWh/HH) 
Winter 
Peak 
Single Family 68,097 873  70% 12,815  175 
Multifamily 5,488 42 3% 7,681 11 
Mobile Home 5,040 58  5% 11,522  11 
Low Income 33,376 277 22% 8,293 60 
Total 112,001  1,250  100% 11,158  256 

As we describe in the previous chapter, 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 3-5 (WA) and Table 3-6 (ID). Segment-specific market profiles are presented in
Appendix A.
Figure 3-3 (WA) and Figure 3-4 (ID) show the distribution of annual electricity use by end use for all
customers. Two main electricity end uses —appliances and space heating— account for approximately
55% of total use. Appliances include refrigerators, freezers, stoves, clothes washers, clothes dryers,
dishwashers, and microwaves. The remainder of the energy falls into the water heating, lighting, cooling,
electronics, and the miscellaneous category – which is comprised of furnace fans, pool pumps, electric
vehicles, and other “plug” loads (all other usage not covered by those listed in Table 3-5 and Table 3-6
such as hair dryers, power tools, coffee makers, etc.).
The charts also show estimates of winter peak demand by end use. As expected, heating is the largest
contributor to winter peak demand, followed by appliances, lighting, and water heating.
Figure 3-5 (WA) and Figure 3-6 (ID) present the electricity intensities by end use and housing type. Single
family homes have the highest use per customer at 13,473 kWh/year (WA) and 12,815 kWh/year (ID).
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Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2017), Washington

Cooling
5%
Space Heating
35%
Water Heating
13%
Interior Lighting
7%
Exterior Lighting
2%
Appliances
20%
Electronics
6%
Miscellaneous
12%
Annual Use by End Use
Space Heating
49%
Water Heating
14%
Interior Lighting
10%
Exterior Lighting
3%
Appliances
18%
Electronics
2%
Miscellaneous
4%
Winter Peak Demand
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Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2017), Idaho

Cooling
4%
Space Heating
34%
Water Heating
15%
Interior Lighting
7%
Exterior Lighting
2%
Appliances
21%
Electronics
6%
Miscellaneous
11%
Annual Use by End Use
Cooling
0%
Space Heating
47%
Water Heating
15%
Interior Lighting
10%
Exterior Lighting
3%
Appliances
19%
Electronics
2%Miscellaneous
4%
Winter Peak Demand
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Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Washington

Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Idaho

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000
Single Family
Multifamily
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
0 2000 4000 6000 8000 10000 12000 14000
Single Family
Multifamily
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Table 3-5 Average Market Profile for the Residential Sector, 2017, Washington
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 30.6%  1,087  333  74.2 
Cooling Room AC 23.5% 401 95 21.1 
Cooling Air‐Source Heat Pump 15.0%  1,178  176  39.3 
Cooling Geothermal Heat Pump 0.7% 1,139 7 1.7 
Cooling Evaporative AC 1.2%  533 6  1.4 
Space Heating Electric Room Heat 25.6% 5,176 1,325 295.2 
Space Heating  Electric Furnace 9.1%  10,447  951  212.0 
Space Heating Air‐Source Heat Pump 15.0% 10,485 1,570 349.9 
Space Heating  Geothermal Heat Pump 0.7%  5,207 34  7.6 
Space Heating Secondary Heating 59.3% 371 220 49.0 
Water Heating  Water Heater <= 55 Gal  53.3%  2,719  1,450  323.2 
Water Heating Water Heater > 55 Gal 3.8% 3,437 131 29.3 
Interior Lighting  General Service Screw‐in  100.0%  633  633  141.2 
Interior Lighting Linear Lighting 100.0% 98 98 21.8 
Interior Lighting  Exempted Screw‐In 100.0% 43 43  9.6 
Exterior Lighting Screw‐in 100.0% 217 217 48.3 
Appliances Clothes Washer 92.0% 79 72  16.1 
Appliances Clothes Dryer 49.5% 735 364 81.0 
Appliances Dishwasher 77.2%  378  292  65.1 
Appliances Refrigerator 94.0% 705 663 147.7 
Appliances Freezer 55.5%  565  313  69.8 
Appliances Second Refrigerator 27.7% 812 225 50.0 
Appliances Stove/Oven 70.2%  440  309  68.9 
Appliances Microwave 94.8% 125 118 26.4 
Electronics Personal Computers 64.9%  161  105  23.3 
Electronics Monitor 129.6% 62 80 17.8 
Electronics Laptops 77.0% 42 33  7.2 
Electronics TVs 178.5% 114 203 45.3 
Electronics Printer/Fax/Copier 73.0% 42 31  6.9 
Electronics Set‐top Boxes/DVRs 145.0% 99 143 31.9 
Electronics Devices and Gadgets 100.0%  108  108  24.0 
Miscellaneous Electric Vehicles 0.1% 4,324 6 1.3 
Miscellaneous  Pool Pump 0.3%  3,500 12  2.7 
Miscellaneous Pool Heater 0.1% 3,517 3 0.7 
Miscellaneous  Hot Tub / Spa 0.4%  2,032 8  1.9 
Miscellaneous Furnace Fan 59.6% 183 109 24.3 
Miscellaneous  Well pump 1.5%  550 8  1.8 
Miscellaneous Miscellaneous 100.0% 1,204 1,204 268.2 
 Total       11,699  2,606.9 

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Table 3-6 Average Market Profile for the Residential Sector, 2017, Idaho
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 31.1%  1,045  326  36.5 
Cooling Room AC 17.6% 445 78 8.8 
Cooling Air‐Source Heat Pump 8.6%  1,127 97  10.9 
Cooling Geothermal Heat Pump 0.5% 1,140 6 0.7 
Cooling Evaporative AC 1.5%  517 8  0.9 
Space Heating Electric Room Heat 23.5% 6,790 1,596 178.8 
Space Heating  Electric Furnace 11.3%  9,715  1,099  123.1 
Space Heating Air‐Source Heat Pump 8.6% 10,425 901 100.9 
Space Heating  Geothermal Heat Pump 0.5%  5,487 29  3.2 
Space Heating Secondary Heating 48.0% 394 189 21.2 
Water Heating  Water Heater <= 55 Gal  50.4%  2,921  1,472  164.9 
Water Heating Water Heater > 55 Gal 5.1% 3,227 163 18.3 
Interior Lighting  General Service Screw‐in  100.0%  634  634  71.0 
Interior Lighting Linear Lighting 100.0% 98 98 11.0 
Interior Lighting  Exempted Screw‐In 100.0% 43 43  4.8 
Exterior Lighting Screw‐in 100.0% 216 216 24.2 
Appliances Clothes Washer 85.2% 82 69  7.8 
Appliances Clothes Dryer 60.2% 754 453 50.8 
Appliances Dishwasher 77.6%  381  296  33.2 
Appliances Refrigerator 93.2% 703 655 73.4 
Appliances Freezer 52.6%  563  296  33.2 
Appliances Second Refrigerator 27.8% 812 226 25.3 
Appliances Stove/Oven 63.3%  388  246  27.5 
Appliances Microwave 91.2% 126 115 12.9 
Electronics Personal Computers 57.1%  163 93  10.4 
Electronics Monitor 114.1% 62 71 7.9 
Electronics Laptops 79.7% 43 34  3.8 
Electronics TVs 175.6% 115 202 22.6 
Electronics Printer/Fax/Copier 67.1% 43 29  3.2 
Electronics Set‐top Boxes/DVRs 92.8% 100 92 10.4 
Electronics Devices and Gadgets 100.0%  108  108  12.1 
Miscellaneous Electric Vehicles 0.1% 4,324 6 0.7 
Miscellaneous  Pool Pump 0.1%  3,500 5  0.5 
Miscellaneous Pool Heater 0.0% 0 0 0.0 
Miscellaneous  Hot Tub / Spa 0.5%  950 5  0.6 
Miscellaneous Furnace Fan 59.7% 458 274 30.6 
Miscellaneous  Well pump 0.0% 0 0  0.0 
Miscellaneous Miscellaneous 100.0% 928 928 103.9 
 Total      11,158  1,249.7 

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Commercial Sector
The total electric energy consumed by commercial customers in Avista’s service area in 2017 was 2,200
GWh (WA) and 1027 GWh (ID). Avista billing data, CBSA and secondary data were used to allocate this
energy usage to building type segments and to develop estimates of energy intensity (annual kWh/square
foot). Using the electricity use and intensity estimates, we infer floor space which is the unit of analysis in
LoadMAP for the commercial sector. The values are shown in Table 3-7 (WA) and Table 3-8 (ID). The
average building intensities by segment are based on regional information from the CBSA, therefore the
intensity is the same both states. However, due to the different mix of building types overall end use mix
is different as shown in Figure 3-9 and Figure 3-10.
Table 3-7 Commercial Sector Control Totals (2017), Washington
Segment 
Electricity Sales % of Total 
Intensity 
(GWh) Usage 
Small Office 194 9% 16.4 
Large Office 543 25% 19.3 
Restaurant 111 5% 41.8 
Retail 286 13% 13.1 
Grocery 198 9% 46.3 
College 94 4% 13.9 
School 123 6% 8.0 
Health 147 7% 29.9 
Lodging 85 4% 12.7 
Warehouse 104 5% 5.4 
Miscellaneous 316 14% 10.4 
Total 2,200 100% 14.5 

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Table 3-8 Commercial Sector Control Totals (2017), Idaho
Segment Electricity Sales % of Total Intensity (GWh) Usage 
Small Office 91 4% 16.4 
Large Office 253 12% 19.3 
Restaurant 52 2% 41.8 
Retail 134 6% 13.1 
Grocery 92 4% 46.3 
College 44 2% 13.9 
School 57 3% 8.0 
Health 68 3% 29.9 
Lodging 40 2% 12.7 
Warehouse 49 2% 5.4 
Miscellaneous 147 7% 10.4 
Total 1,027 100% 14.5 

Figure 3-7 (WA) and Figure 3-8 (ID) show the distribution of annual electricity consumption and summer
peak demand by end use across all commercial buildings. Electric usage is dominated by cooling and
lighting, which comprise almost 48% of annual electricity usage. Winter peak demand is dominated by
heating and lighting.
Figure 3-9 (WA) and Figure 3-10 (ID) presents the electricity usage in GWh by end use and segment. Small
offices, retail, and miscellaneous buildings use the most electricity in the service territory. As far as end
uses, cooling and lighting are the major uses across all segments. Office equipment is concentrated more
in the larger customers.
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Washington

Cooling
15%
Heating
11%
Ventilation
10%
Water Heating
5%
Interior Lighting
25%
Exterior 
Lighting
8%
Refrigeration
7%
Food 
Preparation
3%
Office 
Equipment
8%
Miscellaneous
8%Annual Use by End Use
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Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Idaho

Cooling
4%
Heating
24%
Ventilation
9%
Water Heating
7%
Interior Lighting
28%
Exterior Lighting
3%
Refrigeration
6%
Food Preparation
3%
Office Equipment
8%
Miscellaneous
8%
Winter Peak Demand
Cooling
15%
Heating
11%
Ventilation
10%
Water Heating
5%
Interior Lighting
25%
Exterior 
Lighting
8%
Refrigeration
7%
Food Preparation
3%
Office Equipment
8%
Miscellaneous
8%Annual Use by End Use
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Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2017), Washington

Cooling
4%
Heating
24%
Ventilation
9%
Water Heating
7%
Interior Lighting
28%
Exterior Lighting
3%
Refrigeration
6%
Food Preparation
3%
Office Equipment
8%
Miscellaneous
8%
Winter Peak Demand
0
100
200
300
400
500
600
An
n
u
a
l

E
n
e
r
g
y

U
s
e

(
G
W
h
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2017), Idaho

Table 3-9 (WA) and Table 3-10 (ID) show the average market profile for electricity of the commercial sector
as a whole, representing a composite of all segments and buildings. Market profiles for each segment are
presented in the appendix to this volume.

0
50
100
150
200
250
300
An
n
u
a
l

E
n
e
r
g
y

U
s
e

(
G
W
h
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 3-9 Average Electric Market Profile for the Commercial Sector, 2017, Washington
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 8.6% 2.77 0.24  36.3 
Cooling Water‐Cooled Chiller 5.0% 4.48 0.23 34.4 
Cooling RTU 46.4% 2.59 1.20  182.8 
Cooling PTAC 4.3% 2.37 0.10 15.5 
Cooling PTHP 1.7% 1.98 0.03  5.3 
Cooling Evaporative AC 0.1% 1.42 0.00 0.3 
Cooling Air‐Source Heat Pump 8.6% 2.71 0.23  35.6 
Cooling Geothermal Heat Pump 4.3% 1.66 0.07 10.8 
Heating Electric Furnace 3.8% 5.54 0.21  32.2 
Heating Electric Room Heat 15.1% 5.38 0.81 123.9 
Heating PTHP 1.7% 3.60 0.06  9.6 
Heating Air‐Source Heat Pump 8.6% 4.78 0.41 62.9 
Heating Geothermal Heat Pump 4.3% 3.66 0.16  23.8 
Ventilation Ventilation 100.0% 1.42 1.42 216.1 
Water Heating  Water Heater 52.4% 1.29 0.68  103.0 
Interior Lighting General Service Lighting 100.0% 0.31 0.31 47.4 
Interior Lighting  Exempted Lighting 100.0% 0.20 0.20  30.8 
Interior Lighting High‐Bay Lighting 100.0% 1.44 1.44 219.0 
Interior Lighting  Linear Lighting 100.0% 1.67 1.67  253.7 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 16.0 
Exterior Lighting  Area Lighting 100.0% 0.87 0.87  131.6 
Exterior Lighting Linear Lighting 100.0% 0.19 0.19 29.4 
Refrigeration   Walk‐in Refrigerator/Freezer  7.8%  1.66  0.13  19.6 
Refrigeration  Reach‐in Refrigerator/Freezer 15.5% 0.14 0.02 3.4 
Refrigeration   Glass Door Display 33.2% 0.33 0.11  16.8 
Refrigeration  Open Display Case 33.2% 1.98 0.66 99.7 
Refrigeration   Icemaker 32.8% 0.27 0.09  13.6 
Refrigeration  Vending Machine 32.8% 0.16 0.05 8.2 
Food Preparation  Oven 36.1% 0.18 0.06  9.7 
Food Preparation Fryer 35.5% 0.48 0.17 26.1 
Food Preparation  Dishwasher 23.9% 0.51 0.12  18.6 
Food Preparation Hot Food Container 24.9% 0.08 0.02 3.1 
Food Preparation  Steamer 22.3% 0.28 0.06  9.5 
Office Equipment Desktop Computer 100.0% 0.69 0.69 104.8 
Office Equipment  Laptop 99.0% 0.10 0.10  15.1 
Office Equipment Server 88.4% 0.16 0.14 21.6 
Office Equipment  Monitor 100.0% 0.12 0.12  18.5 
Office Equipment Printer/Copier/Fax 100.0% 0.07 0.07 10.8 
Office Equipment  POS Terminal 57.1% 0.04 0.02  3.4 
Miscellaneous Non‐HVAC Motors 58.4% 0.24 0.14 21.0 
Miscellaneous  Pool Pump 8.8% 0.01 0.00  0.2 
Miscellaneous Pool Heater 3.1% 0.02 0.00 0.1 
Miscellaneous  Clothes Washer 11.2% 0.02 0.00  0.3 
Miscellaneous Clothes Dryer 7.2% 0.05 0.00 0.6 
Miscellaneous  Other Miscellaneous  100.0%  1.02  1.02  154.6 
Total       14.46 2,199.5 

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Table 3-10 Average Electric Market Profile for the Commercial Sector, 2017, Idaho
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 8.6% 2.77 0.24  16.9 
Cooling Water‐Cooled Chiller 5.0% 4.48 0.23 16.0 
Cooling RTU 46.4% 2.59 1.20  85.3 
Cooling PTAC 4.3% 2.37 0.10 7.2 
Cooling PTHP 1.7% 1.98 0.03  2.5 
Cooling Evaporative AC 0.1% 1.42 0.00 0.1 
Cooling Air‐Source Heat Pump 8.6% 2.71 0.23  16.6 
Cooling Geothermal Heat Pump 4.3% 1.66 0.07 5.0 
Heating Electric Furnace 3.8% 5.54 0.21  15.0 
Heating Electric Room Heat 15.1% 5.38 0.81 57.8 
Heating PTHP 1.7% 3.60 0.06  4.5 
Heating Air‐Source Heat Pump 8.6% 4.78 0.41 29.4 
Heating Geothermal Heat Pump 4.3% 3.66 0.16  11.1 
Ventilation Ventilation 100.0% 1.42 1.42 100.9 
Water Heating  Water Heater 52.4% 1.29 0.68  48.1 
Interior Lighting General Service Lighting 100.0% 0.31 0.31 22.1 
Interior Lighting  Exempted Lighting 100.0% 0.20 0.20  14.4 
Interior Lighting High‐Bay Lighting 100.0% 1.44 1.44 102.2 
Interior Lighting  Linear Lighting 100.0% 1.67 1.67  118.4 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 7.4 
Exterior Lighting  Area Lighting 100.0% 0.87 0.87  61.4 
Exterior Lighting Linear Lighting 100.0% 0.19 0.19 13.7 
Refrigeration   Walk‐in Refrigerator/Freezer  7.8%  1.66  0.13  9.2 
Refrigeration  Reach‐in Refrigerator/Freezer 15.5% 0.14 0.02 1.6 
Refrigeration   Glass Door Display 33.2% 0.33 0.11  7.9 
Refrigeration  Open Display Case 33.2% 1.98 0.66 46.5 
Refrigeration   Icemaker 32.8% 0.27 0.09  6.3 
Refrigeration  Vending Machine 32.8% 0.16 0.05 3.8 
Food Preparation  Oven 36.1% 0.18 0.06  4.5 
Food Preparation Fryer 35.5% 0.48 0.17 12.2 
Food Preparation  Dishwasher 23.9% 0.51 0.12  8.7 
Food Preparation Hot Food Container 24.9% 0.08 0.02 1.5 
Food Preparation  Steamer 22.3% 0.28 0.06  4.4 
Office Equipment Desktop Computer 100.0% 0.69 0.69 48.9 
Office Equipment  Laptop 99.0% 0.10 0.10  7.0 
Office Equipment Server 88.4% 0.16 0.14 10.1 
Office Equipment  Monitor 100.0% 0.12 0.12  8.6 
Office Equipment Printer/Copier/Fax 100.0% 0.07 0.07 5.1 
Office Equipment  POS Terminal 57.1% 0.04 0.02  1.6 
Miscellaneous Non‐HVAC Motors 58.4% 0.24 0.14 9.8 
Miscellaneous  Pool Pump 8.8% 0.01 0.00  0.1 
Miscellaneous Pool Heater 3.1% 0.02 0.00 0.0 
Miscellaneous  Clothes Washer 11.2% 0.02 0.00  0.1 
Miscellaneous Clothes Dryer 7.2% 0.05 0.00 0.3 
Miscellaneous  Other Miscellaneous  100.0%  1.02  1.02  72.2 
Total       14.46 1,026.8 

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Industrial Sector
The total electricity used in 2017 by Avista’s industrial customers was 870 GWh; 504 GWh (WA) and 366
GWh (ID). Avista billing data and load forecast, NEEA’s IFSA, and secondary sources were used to develop
estimates of energy intensity (annual kWh/employee). Using the electricity use and intensity estimates, we
infer the number of employees which is the unit of analysis in LoadMAP for the industrial sector. These
are shown in Table 3-11.
Table 3-11 Industrial Sector Control Totals (2017)
State 
Electricity Sales Intensity Winter Peak 
(GWh) (Annual kWh/employee) (MW) 
Washington 504 29,854 93 
Idaho 366 67,257  76 

Figure 3-12 shows the distribution of annual electricity consumption and summer peak demand by end
use for all industrial customers. Motors are the largest overall end use for the industrial sector, accounting
for 33% of energy use. Note that this end use includes a wide range of industrial equipment, such as air
compressors and refrigeration compressors, pumps, conveyor motors, and fans. The process end use
accounts for 19% of annual energy use, which includes heating, cooling, refrigeration, and electro-
chemical processes. Lighting is the next highest, followed by cooling, miscellaneous, heating and
ventilation.
Table 3-12 and Table 3-13 show the composite market profile for the industrial sector.

Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All Industries, WA

Cooling
4%
Heating
17%
Ventilation
4%
Interior Lighting
13%
Exterior 
Lighting
Motors
33%
Process
19%
Miscellaneous
7%Annual Use by End Use
Page 808 Avista Corp. 2020 Electric IRP Appendices
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Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All Industries, ID

Cooling
0%
Heating
29%
Ventilation
2%
Interior 
Lighting
12%
Exterior Lighting
1%
Motors
32%
Process
18%
Miscellaneous
6%
Winter Peak Demand
Cooling
4%
Heating
17%
Ventilation
4%
Interior Lighting
13%
Exterior Lighting
3%
Motors
33%
Process
19%
Miscellaneous
7%Annual Use by End Use
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Cooling
0%
Heating
29%
Ventilation
2%
Interior 
Lighting
12%
Exterior Lighting
1%
Motors
32%
Process
18%
Miscellaneous
6%Winter Peak Demand
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Table 3-12 Average Electric Market Profile for the Industrial Sector, 2017, Washington
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  6,629.79 165.74  2.8 
Cooling Water‐Cooled Chiller 2.5% 6,983.13 174.58 2.9 
Cooling RTU 11.4%  7,389.72 842.74  14.2 
Cooling Air‐Source Heat Pump 1.7% 7,386.34 124.90 2.1 
Cooling Geothermal Heat Pump 0.0%  4,926.69 0.00  0.0 
Heating Electric Furnace 2.3% 32,574.73 747.28 12.6 
Heating Electric Room Heat 12.4%  31,023.55 3,849.55  65.0 
Heating Air‐Source Heat Pump 1.7% 28,604.84 483.71 8.2 
Heating Geothermal Heat Pump 0.0%  19,079.43 0.00  0.0 
Ventilation Ventilation 100.0% 1,077.71 1,077.71 18.2 
Interior Lighting  General Service Lighting  100.0%  206.68  206.68  3.5 
Interior Lighting High‐Bay Lighting 100.0% 3,233.38 3,233.38 54.6 
Interior Lighting  Linear Lighting 100.0%  537.49 537.49  9.1 
Exterior Lighting General Service Lighting 100.0% 38.05 38.05 0.6 
Exterior Lighting  Area Lighting 100.0%  720.88 720.88  12.2 
Exterior Lighting Linear Lighting 100.0% 147.69 147.69 2.5 
Motors Pumps 100.0%  1,899.28 1,899.28  32.1 
Motors Fans & Blowers 100.0% 2,280.92 2,280.92 38.5 
Motors Compressed Air 100.0%  1,844.32 1,844.32  31.2 
Motors Material Handling 100.0% 3,900.92 3,900.92 65.9 
Motors Other Motors 100.0%  65.46 65.46  1.1 
Process Process Heating 100.0% 3,211.52 3,211.52 54.3 
Process Process Cooling 100.0%  843.19 843.19  14.2 
Process Process Refrigeration 100.0% 843.19 843.19 14.2 
Process Process Electrochemical 100.0%  324.59 324.59  5.5 
Process Process Other 100.0% 352.25 352.25 6.0 
Miscellaneous  Miscellaneous 100.0%  1,937.76 1,937.76  32.7 
Total       29,853.79 504.4 

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Table 3-13 Average Electric Market Profile for the Industrial Sector, 2017, Idaho
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  14,936.14 373.40  2.0 
Cooling Water‐Cooled Chiller 2.5% 15,732.18 393.30 2.1 
Cooling RTU 11.4%  16,648.18 1,898.60  10.3 
Cooling Air‐Source Heat Pump 1.7% 16,640.58 281.39 1.5 
Cooling Geothermal Heat Pump 0.0%  11,099.27 0.00  0.0 
Heating Electric Furnace 2.3% 73,387.09 1,683.53 9.2 
Heating Electric Room Heat 12.4%  69,892.47 8,672.59  47.2 
Heating Air‐Source Heat Pump 1.7% 64,443.40 1,089.73 5.9 
Heating Geothermal Heat Pump 0.0%  42,983.75 0.00  0.0 
Ventilation Ventilation 100.0% 2,427.96 2,427.96 13.2 
Interior Lighting  General Service Lighting  100.0%  465.63  465.63  2.5 
Interior Lighting High‐Bay Lighting 100.0% 7,284.44 7,284.44 39.6 
Interior Lighting  Linear Lighting 100.0%  1,210.90 1,210.90  6.6 
Exterior Lighting General Service Lighting 100.0% 85.72 85.72 0.5 
Exterior Lighting  Area Lighting 100.0%  1,624.05 1,624.05  8.8 
Exterior Lighting Linear Lighting 100.0% 332.72 332.72 1.8 
Motors Pumps 100.0%  4,278.85 4,278.85  23.3 
Motors Fans & Blowers 100.0% 5,138.64 5,138.64 28.0 
Motors Compressed Air 100.0%  4,155.05 4,155.05  22.6 
Motors Material Handling 100.0% 8,788.33 8,788.33 47.8 
Motors Other Motors 100.0%  147.48 147.48  0.8 
Process Process Heating 100.0% 7,235.19 7,235.19 39.4 
Process Process Cooling 100.0%  1,899.62 1,899.62  10.3 
Process Process Refrigeration 100.0% 1,899.62 1,899.62 10.3 
Process Process Electrochemical 100.0%  731.25 731.25  4.0 
Process Process Other 100.0% 793.59 793.59 4.3 
Miscellaneous  Miscellaneous 100.0%  4,365.54 4,365.54  23.8 
Total       67,257.13 366.1 

Page 812 Avista Corp. 2020 Electric IRP Appendices

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BASELINE PROJECTION
Prior to developing estimates of energy-efficiency potential, we developed a baseline end-use projection
to quantify what the consumption is likely to be in the future and 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:
 Customer population and economic growth
 Appliance/equipment standards and building codes already mandated (see Chapter 2)
 Forecasts of future electricity prices and other drivers of consumption
 Trends in fuel shares and appliance saturations and assumptions about miscellaneous electricity
growth
Although it aligns closely with it, the baseline projection is not Avista’s official load forecast. Rather it was
developed to serve as the metric against which EE potentials are measured. This chapter presents the
baseline projections we developed for this study. Below, we present the baseline projections for each
sector and state, which include projections of annual use in GWh and summer peak demand in MW. We
also present a summary across all sectors.
Please note that the base-year for the study is 2017. Annual energy use and summer peak demand values
for 2017 reflect actual weather. In future years, energy use and peak demand reflect normal weather, as
defined by Avista. In the figures below, the shift from actual to normal weather is apparent in the increase
in energy use and peak demand in 2017 for the residential and commercial sectors. This results from the
fact that 2017 was cooler than normal (e.g. more energy was required to heat a home in the Winter of
2017 than in an average year).
Residential Sector
Annual Use
Table 4-1 (WA) and Table 4-2 (ID) present the baseline projection for electricity at the end-use level for
the residential sector as a whole. Overall in Washington, residential use increases from 2,607 GWh in 2017
to 3,254 GWh in 2040, an increase of 25%. Residential use in Idaho increases from 1,250 GWh in 2017 to
1,628 GWh in 2040, an increase of 30%. This reflects a substantial customer growth forecast in both states.
Figure 4-1 (WA) and Figure 4-3 (ID) display the graphical representation of the baseline projection.
Figure 4-2 (WA) and Figure 4-4 (ID) present the baseline projection of annual electricity use per household.
Most noticeable is that lighting use decreases throughout the time period as the lighting standards from
EISA come into effect. Heating usage increases over the forecast due to going from actual weather in 2017
to normal weather in 2018 and for the rest of the forecast.

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Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 
Cooling  138  121  121  122  125  135  ‐2% 
Space Heating 914 816 823 843 882 975 7% 
Water Heating 352  347  345  342  345  366  4% 
Interior Lighting 173 148 137 112 93 88 ‐49% 
Exterior Lighting 48  40  37  31  26  24  ‐51% 
Appliances 525 532 534 541 557 606 16% 
Electronics 156  166  170  180  200  249  59% 
Miscellaneous 301 345 361 411 514 810 169% 
Total 2,607  2,515  2,528  2,581  2,743  3,254  25% 

Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington

0
500
1000
1500
2000
2500
3000
3500
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Figure 4-2 Residential Baseline Projection by End Use – Annual Use per Household, Washington

Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 
Cooling  58  51  52  53  56  64  10% 
Space Heating 427 386 390 404 430 489 14% 
Water Heating 183  182  181  181  184  199  9% 
Interior Lighting 87 75 70 58 50 50 ‐43% 
Exterior Lighting 24  20  19  16  14  13  ‐46% 
Appliances 264 270 272 278 291 326 24% 
Electronics 70  76  78  83  95  123  75% 
Miscellaneous 136 155 162 184 230 365 167% 
Total 1,250  1,215  1,223  1,256  1,348  1,628  30% 

0
2000
4000
6000
8000
10000
12000
14000
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho

Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household, Idaho

Commercial Sector Baseline Projections
Annual Use
In Washington, annual electricity use in the commercial sector grows during the overall forecast horizon,
starting at 2,200 GWh in 2017, and increasing to 2,531 in 2040, an increase of 15%. In Idaho, annual
electricity use grows from 1,027 GWh in 2017 to 1,159 GWh in 2040, an increase of 13%. The tables and
graphs below present the baseline projection at the end-use level for the commercial sector as a whole.
Usage in lighting is declining throughout the forecast, due largely to the phasing in of codes and standards
0
500
1000
1500
2000
2500
3000
3500
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
0
2000
4000
6000
8000
10000
12000
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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such as the EISA 2007 lighting standards. Usage in commercial cooling decreases over the forecast due
to going from actual weather in 2017 to weather-normal in 2018 for the forecast.
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 321  276  275  271  266  267  ‐17% 
Heating 252 245 246 249 256 275 9% 
Ventilation 216  218  219  222  229  248  15% 
Water Heating 103 103 103 104 108 119 15% 
Interior Lighting 551  536  528  515  521  558  1% 
Exterior Lighting 177 176 176 175 177 191 8% 
Refrigeration 161  162  162  164  172  198  23% 
Food Preparation 67 70 71 75 83 101 50% 
Office Equipment 174  179  181  190  208  248  42% 
Miscellaneous 177 193 199 217 251 327 85% 
Total 2,200  2,160  2,162  2,183  2,270  2,531  15% 
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 150  129  129  127  125  127  ‐15% 
Heating 118 115 115 117 120 129 10% 
Ventilation 101  102  102  104  107  116  15% 
Water Heating 48 49 49 50 52 57 19% 
Interior Lighting 257  250  247  241  244  262  2% 
Exterior Lighting 83 82 82 82 83 89 8% 
Refrigeration 75  76  76  77  80  93  23% 
Food Preparation 31 33 33 35 39 47 51% 
Office Equipment 81  84  85  89  97  116  43% 
Miscellaneous 82 90 93 102 109 122 47% 
Total 1,027  1,008  1,010  1,022  1,057  1,159  13% 

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Figure 4-5 Commercial Baseline Projection by End Use, Washington

Figure 4-6 Commercial Baseline Projection by End Use, Idaho

0
500
1000
1500
2000
2500
3000
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
0
200
400
600
800
1000
1200
1400
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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  | 59 Applied Energy Group • www.appliedenergygroup.com
Industrial Sector Baseline Projections
Annual Use
Annual industrial use increases by 25% through the forecast horizon, consistent with trends from Avista’s
industrial load forecast. The tables and graphs below present the projection at the end-use level. Overall
in Washington, industrial annual electricity use increases from 504 GWh in 2017 to 683 GWh in 2040. In
Idaho, annual electricity use increases from 366 GWh in 2017 to 406 GWh in 2040.
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 22  24  24  25  26  28  29% 
Heating 86 93 94 97 102 112 31% 
Ventilation 18  20  20  20  21  23  29% 
Interior Lighting 67 68 67 67 67 71 5% 
Exterior Lighting 15  16  16  16  17  18  19% 
Process 94 103 104 107 112 125 32% 
Motors 169  184  186  191  202  223  32% 
Miscellaneous 33 40 42 48 58 81 148% 
Total 504  548  553  571  605  683  35% 

Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 16  15  15  15  15  15  ‐8% 
Heating 62 65 65 65 65 65 4% 
Ventilation 13  14  14  14  14  14  6% 
Interior Lighting 49 50 49 47 45 43 ‐12% 
Exterior Lighting 11  12  12  12  11  11  ‐1% 
Process 68 75 75 75 75 75 10% 
Motors 123  134  134  134  134  134  10% 
Miscellaneous 24 29 30 34 39 49 108% 
Total 366  395  395  396  398  406  11% 

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  | 60 Applied Energy Group • www.appliedenergygroup.com
Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington

Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho

0
100
200
300
400
500
600
700
800
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
0
50
100
150
200
250
300
350
400
450
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Process
Motors
Miscellaneous
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Summary of Baseline Projections across Sectors and States
Annual Use
Table 4-7 and Figure 4-9 provide a summary of the baseline projection for annual use by sector for the
entire Avista service territory. Overall, the projection shows strong growth in electricity use, driven
primarily by customer growth forecasts.
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Residential 3,857  3,731  3,751  3,838  4,090  4,882  27% 
Commercial 3,226 3,168 3,171 3,205 3,327 3,690 14% 
Industrial 871  942  948  967  1,004  1,089  25% 
Total 7,953 7,841 7,871 8,009 8,421 9,661 21% 

Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined

‐
2,000
4,000
6,000
8,000
10,000
12,000
2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Annual 
Use (GWh)
Industrial
Commercial
Residential
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CONSERVATION POTENTIAL
This section presents the conservation potential for Avista. This includes every measure that is considered
in the measure list, regardless of delivery mechanism (program implementation, NEEA initiatives, or
momentum savings).
We present the annual energy savings in GWh and aMW, as well as the winter peak demand savings in
MW, for selected years. Year-by-year savings for annual energy and peak demand are available in the
LoadMAP model, which was provided to Avista at the conclusion of the study.
This section begins a summary of annual energy savings across all three sectors. Then we provide details
for each sector. Please note that all savings are provided at the customer meter.
Overall Summary of Energy Efficiency Potential
Summary of Annual Energy Savings
Table 5-1 (WA) and Table 5-2 (ID) summarize the EE savings in terms of annual energy use for all measures
for two levels of potential relative to the baseline projection. Figure 5-1(WA) and Figure 5-2 (ID) displays
the two levels of potential by year. Figure 5-3 (WA) and Figure 5-4 (ID) display the EE projections.
 Technical Potential reflects the adoption of all conservation measures regardless of cost-
effectiveness. For Washington, first-year savings are 102 GWh, or 2.0% of the baseline projection.
Cumulative savings in 2040 are 1,607 GWh, or 24.5% of the baseline. For Idaho, first-year savings are
51 GWh, or 1.9% of the baseline projection. Cumulative savings in 2040 are 845 GWh, or 26.1% of
the baseline.
 Technical Achievable Potential modifies Technical Potential by accounting for customer
adoption constraints. In Washington, first-year savings are 47 GWh, or 0.9% of the baseline. In 2040,
cumulative technical achievable savings reach 1,272 GWh, or 19.4% of the baseline projection. This
results in average annual savings of 1.0% of the baseline each year. Technical Achievable Potential
reflects 79% of Technical Potential throughout the forecast horizon. For Idaho, first year savings are
24 GWh or 0.9% of the baseline and by 2040 cumulative technical achievable savings reach 673
GWh, or 20.8% of the baseline. This results in average annual savings of 1% of the baseline each
year. Technical Achievable Potential reflects 80% of Technical Potential throughout the forecast
horizon.

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Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 5,243 5,268 5,300 5,687 6,572 
Cumulative Savings (GWh)           
Technical Achievable Potential 47  100  158  636  1,272 
Technical Potential 102 203 305 979 1,607 
Cumulative Savings (aMW)          
Technical Achievable Potential 5 11 18 73 145 
Technical Potential 12  23  35  112  183 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.9%  1.9%  3.0%  11.2%  19.4% 
Technical Potential 2.0% 3.9% 5.8% 17.2% 24.5% 

Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 2,628 2,640 2,656 2,834 3,241 
Cumulative Savings (GWh)           
Technical Achievable Potential 24  50  80  328  673 
Technical Potential 51 102 153 502 845 
Cumulative Savings (aMW)          
Technical Achievable Potential 3 6 9 37 77 
Technical Potential 6  12  17  57  96 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.9%  1.9%  3.0%  11.6%  20.8% 
Technical Potential 1.9% 3.9% 5.8% 17.7% 26.1% 

Page 823 Avista Corp. 2020 Electric IRP Appendices
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  | 64 Applied Energy Group • www.appliedenergygroup.com
Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy), Washington

Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho

0%
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2021 2022 2023 2030 2040
% 
o
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Technical Achievable Potential Technical Potential
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2021 2022 2023 2030 2040
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Page 824 Avista Corp. 2020 Electric IRP Appendices
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Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Washington

Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho

 ‐
 1,000.0
 2,000.0
 3,000.0
 4,000.0
 5,000.0
 6,000.0
 7,000.0
GWh
Baseline Projection
Technical Achievable Potential
Technical Potential
 ‐
 500.0
 1,000.0
 1,500.0
 2,000.0
 2,500.0
 3,000.0
 3,500.0
GWh
Baseline Projection
Technical Achievable Potential
Technical Potential
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Summary of Conservation Potential by Sector
Table 5-3 and Figure 5-5 summarize the range of electric Technical Achievable Potential by sector, both
states combined. The residential and commercial sectors contribute the most savings, but by 2040 the
commercial sector potential begins to approach that of residential due to large lost opportunity lighting
equipment and controls measures.
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and ID
  2021 2022 2023 2030 2040 
Cumulative Savings (GWh)  
Residential 31 66 106 461 1,000 
Commercial 33 69 109 414 800 
Industrial 7 15 24 89 145 
Total 71 150 238 965 1,945 

Cumulative Savings (aMW)  
Residential 4 8 12 53 114 
Commercial 4 8 12 47 91 
Industrial 1 2 3 10 17 
Total 8 17 27 110 222 

Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)

‐
500
1,000
1,500
2,000
2,500
2021 2022 2023 2030 2040
Ac
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Residential
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Residential Conservation Potential
Table 5-4 (WA) and Table 5-5 (ID) present estimates for measure-level conservation potential for the
residential sector in terms of annual energy savings. Figure 5-6 (WA) and Figure 5-7 (ID) display the two
levels of potential by year. For Washington, Technical Achievable Potential in the first year, 2021 is 21 GWh,
or 0.8 % of the baseline projection. By 2040, cumulative technical achievable savings are 647 GWh, or
19.5% of the baseline projection. At this level, it represents over 82% of technical potential. For Idaho, first
year technical achievable savings are 10 GWh or 0.8% of the baseline and by 2040 cumulative technical
achievable savings reach 353 GWh, or 21.2% of the baseline. Technical Achievable Potential is 82% of
technical potential in 2040.
Table 5-4 Residential Conservation Potential (Annual Energy), Washington
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 2,528  2,543  2,562  2,783  3,319 
Cumulative Savings (GWh)           
Technical Achievable Potential 21  44  71  305  647 
Technical Potential 48 96 144 475 791 
Cumulative Savings (aMW)          
Technical Achievable Potential 2 5 8 35 74 
Technical Potential 5  11  16  54  90 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.8%  1.7%  2.8%  11.0%  19.5% 
Technical Potential 1.9% 3.8% 5.6% 17.1% 23.8% 

Table 5-5 Residential Conservation Potential (Annual Energy), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 1,223  1,233  1,244  1,370  1,663 
Cumulative Savings (GWh)           
Technical Achievable Potential 10  22  35  157  353 
Technical Potential 24 48 72 246 430 
Cumulative Savings (aMW)          
Technical Achievable Potential 1 2 4 18 40 
Technical Potential 3  5  8  28  49 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.8%  1.8%  2.8%  11.4%  21.2% 
Technical Potential 1.9% 3.9% 5.8% 18.0% 25.9% 
Page 827 Avista Corp. 2020 Electric IRP Appendices
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  | 68 Applied Energy Group • www.appliedenergygroup.com
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy),
Washington

Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy), Idaho

Below, we present the top residential measures from the perspective of annual energy use. Table 5-6
identifies the top 20 residential measures from the perspective of annual energy savings in 2022 for
Washington. The top three measures include Ductless Mini Split Heat Pumps (Ducted Forced Air), Water
Heater – Low-Flow Showerheads, and Ductless Mini Split Heat Pump (Zonal). Note that technical
achievable savings do not screen for cost effectiveness and some measures are expected to be screened
out during the IRP process.

0%
5%
10%
15%
20%
25%
30%
2021 2022 2023 2030 2040
% 
o
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Ba
s
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Technical Achievable Potential Technical Potential
0%
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2021 2022 2023 2030 2040
% 
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Page 828 Avista Corp. 2020 Electric IRP Appendices
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Table 5-6 Residential Top Measures in 2019 (Annual Energy, MWh), Washington
Rank Residential Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Ductless Mini Split Heat Pump (Ducted Forced Air)  3,651  8% 
2 Water Heater ‐ Low‐Flow Showerheads 2,834 6% 
3  Ductless Mini Split Heat Pump (Zonal) 2,727  6% 
4 Thermostat ‐ Connected 2,303 5% 
5  Windows ‐ Low‐e Storm Addition 2,011  5% 
6 Building Shell ‐ Infiltration Control 1,976 4% 
7  Ducting ‐ Repair and Sealing 1,832  4% 
8 Windows ‐ Cellular Shades 1,754 4% 
9  Insulation ‐ Floor Installation 1,668  4% 
10 Furnace ‐ Conversion to Air‐Source Heat Pump 1,640 4% 
11  Monitor 1,537  3% 
12 Insulation ‐ Ducting 1,472 3% 
13  Windows ‐ High Efficiency/ENERGY STAR 1,457  3% 
14 General Service Screw‐in 1,374 3% 
15  Insulation ‐ Wall Cavity Installation 1,080  2% 
16 Doors ‐ Storm and Thermal 873 2% 
17  Exterior Lighting ‐ Photosensor Control 802  2% 
18 Insulation ‐ Ceiling Installation 759 2% 
19  Insulation ‐ Radiant Barrier 751  2% 
20 Water Heater ‐ Pipe Insulation 645 1% 
 Total of Top 20 Measures  33,145  75% 
  Total Cumulative Savings 44,428 100% 

Figure 5-8 presents forecasts of cumulative energy savings for Washington. Space heating and water
heating account for a substantial portion of the savings throughout the forecast horizon. Weatherization,
ductless heat pumps, heat pump water heaters, and LED lighting account for a large portion of potential
over the 20-year study period.
Page 829 Avista Corp. 2020 Electric IRP Appendices
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  | 70 Applied Energy Group • www.appliedenergygroup.com
Figure 5-8 Residential Technical Achievable Savings Forecast (Cumulative GWh), Washington

Table 5-7 shows the top residential measures from the perspective of annual energy use in Idaho in 2019.
The top three measures are the same as Washington and include Ductless Mini Split Heat Pumps (Ducted
Forced Air), Water Heater – Low-Flow Showerheads, and Ductless Mini Split Heat Pump (Zonal). Note that
technical achievable savings do not screen for cost effectiveness and some measures are expected to be
screened out during the IRP process.

0
100
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300
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2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Table 5-7 Residential Top Measures in 2019 (Annual Energy, MWh), Idaho
Rank Residential Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Ductless Mini Split Heat Pump (Ducted Forced Air)  1,934  9% 
2 Ductless Mini Split Heat Pump (Zonal) 1,467 7% 
3  Water Heater ‐ Low‐Flow Showerheads 1,440  7% 
4 Thermostat ‐ Connected 1,086 5% 
5  Windows ‐ Low‐e Storm Addition 921  4% 
6 Building Shell ‐ Infiltration Control 914 4% 
7  Insulation ‐ Floor Installation 893  4% 
8 Furnace ‐ Conversion to Air‐Source Heat Pump 860 4% 
9  Windows ‐ Cellular Shades 829  4% 
10 Insulation ‐ Wall Cavity Installation 725 3% 
11  Ducting ‐ Repair and Sealing 716  3% 
12 Monitor 697 3% 
13  General Service Screw‐in ‐ LEDs 650  3% 
14 Insulation ‐ Ducting 597 3% 
15  Insulation ‐ Ceiling Installation  495  2% 
16 Windows ‐ High Efficiency/ENERGY STAR 420 2% 
17  Doors ‐ Storm and Thermal 395  2% 
18 Exterior Lighting ‐ Photosensor Control 386 2% 
19  Insulation ‐ Foundation 364  2% 
20 Insulation ‐ Radiant Barrier 354 2% 
 Total of Top 20 Measures  16,145  74% 
  Total Cumulative Savings 21,726 100% 

Figure 5-9 presents forecasts of cumulative energy savings for Idaho. Results are similar to Washington
where the majority of the savings come from heating and water heating measures.
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Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulative GWh), Idaho

0
50
100
150
200
250
300
350
400
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Commercial Conservation Potential
Table 5-8 (WA) and Table 5-9 (ID) present estimates for the two levels of conservation potential for the
commercial sector from the perspective of annual energy savings and average MW.
Table 5-8 Commercial Conservation Potential (Annual Energy), WA
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 2,162  2,166  2,173  2,292  2,562 
Cumulative Savings (GWh)           
Technical Achievable Potential 22  47  73  278  536 
Technical Potential 47 93 139 430 703 
Cumulative Savings (aMW)          
Technical Achievable Potential 3 5 8 32 61 
Technical Potential 5  11  16  49  80 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 1.0%  2.2%  3.4%  12.1%  20.9% 
Technical Potential 2.2% 4.3% 6.4% 18.7% 27.4% 

Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 1,010  1,012  1,016  1,065  1,171 
Cumulative Savings (GWh)           
Technical Achievable Potential 11  22  35  136  264 
Technical Potential 22 44 66 208 344 
Cumulative Savings (aMW)          
Technical Achievable Potential 1 3 4 16 30 
Technical Potential 3  5  8  24  39 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 1.0%  2.2%  3.5%  12.8%  22.6% 
Technical Potential 2.2% 4.4% 6.5% 19.6% 29.4% 
Figure 5-10 (WA) and Figure 5-11 (ID) display the two levels of potential by year. For Washington, the first
year of the projection, Technical Achievable Potential is 22 GWh, or 1.0% of the baseline projection. By
2040, technical achievable savings are 536 GWh, or 20.9% of the baseline projection. Throughout the
forecast horizon, Technical Achievable Potential represents about 76% of technical potential. For Idaho,
first year technical achievable savings are 11 GWh or 1.0% of the baseline and by 2040 cumulative technical
achievable savings reach 264 GWh, or 22.6% of the baseline. Throughout the forecast horizon, Technical
Achievable Potential represents about 77% of technical potential.
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Figure 5-10 Commercial Conservation Savings (Energy), Washington

Figure 5-11 Commercial Conservation Savings (Energy), Idaho

Below, we present the top commercial measures from the perspective of annual energy use.
Table 5-10 (WA) and Table 5-11 (ID) identify the top 20 commercial-sector measures from the perspective
of annual energy savings in 2019. In both states, lighting applications make up three out of the top five
measures. Although the market has seen significant penetration of LEDs in some applications, newer
systems – particularly those with built-in occupancy sensors or other controls – still represent significant
savings opportunities.
0%
5%
10%
15%
20%
25%
30%
35%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
0%
5%
10%
15%
20%
25%
30%
35%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
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Figure 5-12 (WA) and Figure 5-13 (ID) present forecasts of cumulative energy savings by end use. Lighting
savings from interior and exterior applications account for a substantial portion of the savings throughout
the forecast horizon.
Table 5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Linear Lighting ‐ LEDs 3,852  8% 
2 High‐Bay Lighting ‐ LEDs 2,674 6% 
3  Space Heating ‐ Heat Recovery Ventilator 2,252  5% 
4 Refrigeration ‐ Evaporative Condenser 2,181 5% 
5  Area Lighting ‐ LEDs 1,908  4% 
6 Chiller ‐ Variable Flow Chilled Water Pump 1,714 4% 
7  Refrigeration ‐ Variable Speed Compressor 1,678  4% 
8 Refrigeration ‐ Replace Single‐Compressor with Subcooled Multiplex 1,607 3% 
9  HVAC ‐ Dedicated Outdoor Air System (DOAS) 1,434  3% 
10 Exterior Lighting ‐ Bi‐Level Parking Garage Fixture 1,407 3% 
11  Exterior Lighting ‐ Photovoltaic Installation  1,385  3% 
12 Retrocommissioning 1,322 3% 
13  Destratification Fans (HVLS) 1,207  3% 
14 Refrigeration ‐ High Efficiency Compressor 1,126 2% 
15  Water Heater ‐ Solar System 1,090  2% 
16 Refrigeration ‐ ECM Compressor Head Fan Motor 984 2% 
17  Interior Lighting ‐ Networked Fixture Controls 922  2% 
18 Office Equipment ‐ Advanced Power Strips 903 2% 
19  Exterior Lighting ‐ Enhanced Controls 691  1% 
20 Water Heater ‐ Pipe Insulation 664 1% 
 Total of Top 20 Measures  31,001  66% 
  Total Cumulative Savings 46,666 100% 

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Figure 5-12 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Washington

0
100
200
300
400
500
600
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 5-11 Commercial Top Measures in 2019 (Annual Energy, MWh), Idaho
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Linear Lighting – LEDs 1,809  8% 
2 High‐Bay Lighting ‐ LEDs 1,256 6% 
3  Space Heating ‐ Heat Recovery Ventilator 1,165  5% 
4 Refrigeration ‐ Evaporative Condenser 1,018 5% 
5  Area Lighting ‐ LEDs 896  4% 
6 Chiller ‐ Variable Flow Chilled Water Pump 812 4% 
7  Refrigeration ‐ Variable Speed Compressor 791  4% 
8 Refrigeration ‐ Replace Single‐Compressor with Subcooled Multiplex 750 3% 
9  HVAC ‐ Dedicated Outdoor Air System (DOAS) 668  3% 
10 Retrocommissioning 659 3% 
11  Exterior Lighting ‐ Bi‐Level Parking Garage Fixture  658  3% 
12 Exterior Lighting ‐ Photovoltaic Installation 647 3% 
13  Destratification Fans (HVLS) 563  3% 
14 Refrigeration ‐ High Efficiency Compressor 530 2% 
15  Water Heater ‐ Solar System 517  2% 
16 Refrigeration ‐ ECM Compressor Head Fan Motor 456 2% 
17  Interior Lighting ‐ Networked Fixture Controls 432  2% 
18 Office Equipment ‐ Advanced Power Strips 421 2% 
19  Exterior Lighting ‐ Enhanced Controls 323  1% 
20 Water Heater ‐ Pipe Insulation 315 1% 
 Total of Top 20 Measures 14,686  66% 
  Total Cumulative Savings 22,325 100% 

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Figure 5-13 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Idaho

Industrial Conservation Potential
Table 5-12 (WA) and Table 5-13 (ID) present potential estimates at the measure level for the industrial
sector, from the perspective of annual energy savings. Figure 5-14 (WA) and Figure 5-15 (ID) display the
two levels of potential by year. For Washington, technical achievable savings in the first year, 2021, are 4
GWh, or 0.8% of the baseline projection. In 2040, savings reach 89 GWh, or 12.9% of the baseline
projection. For Idaho, technical achievable savings in the first year, 2021, are 3 GWh, or 0.7% of the baseline
projection. In 2040, savings reach 56 GWh, or 13.7% of the baseline projection.
Table 5-12 Industrial Conservation Potential (Annual Energy), WA
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 553  559  565  612  691 
Cumulative Savings (GWh)           
Technical Achievable Potential 4  9  14  54  89 
Technical Potential 7 15 22 74 114 
Cumulative Savings (aMW)          
Technical Achievable Potential 0 1 2 6 10 
Technical Potential 1  2  3  8  13 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.8%  1.6%  2.5%  8.8%  12.9% 
Technical Potential 1.3% 2.6% 3.9% 12.2% 16.4% 
0
50
100
150
200
250
300
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 395  395  395  399  407 
Cumulative Savings (GWh)           
Technical Achievable Potential 3  6  10  35  56 
Technical Potential 5 10 15 48 71 
Cumulative Savings (aMW)          
Technical Achievable Potential 0 1 1 4 6 
Technical Potential 1  1  2  5  8 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.7%  1.6%  2.4%  8.9%  13.7% 
Technical Potential 1.2% 2.4% 3.7% 12.0% 17.4% 

Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy),
Washington

0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
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Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy), Idaho

Below, we present the top industrial measures from the perspective of annual energy use.
Table 5-14 and Table 5-15 identify the top 20 industrial measures from the perspective of annual energy
savings in 2020. For both states, the top measure is the instillation of destratification fans (HVLS). The
measure with the second highest savings is the upgrade of compressed air equipment. Compressed air
leak management program rounds out the top three in both states.
Figure 5-16 (WA) and Figure 5-17 (ID) present forecasts of energy savings by end use as a percent of total
annual savings and cumulative savings. Various motor savings and lighting make up the majority of savings
potential in the study horizon.
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
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Table 5-14 Industrial Top Measures in 2019 (Annual Energy, GWh), Washington
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Destratification Fans (HVLS) 1,263  14% 
2 Compressed Air ‐ Equipment Upgrade 746 8% 
3  Compressed Air ‐ Leak Management Program 728  8% 
4 High‐Bay Lighting ‐ LEDs 673 8% 
5  Pumping System ‐ Equipment Upgrade 372  4% 
6 Fan System ‐ Equipment Upgrade 246 3% 
7  Paper: Premium Control Large Material  221  2% 
8 Material Handling ‐ Variable Speed Drive 216 2% 
9  Retrocommissioning 213  2% 
10 Kraft: Efficient Agitator 203 2% 
11  Fan System ‐ Variable Speed Drive 192  2% 
12 Area Lighting 184 2% 
13  Compressed Air ‐ Outside Air Intake 181  2% 
14 Paper: Efficient Pulp Screen  178 2% 
15  Exterior Lighting ‐ Enhanced Controls 178  2% 
16 Interior Lighting ‐ Networked Fixture Controls 173 2% 
17  Linear Lighting ‐ LEDs 169  2% 
18 Compressed Air ‐ End Use Optimization 145 2% 
19  Thermostat ‐ Wi‐Fi/Interactive  140  2% 
20 Motors ‐ Synchronous Belts 137 2% 
 Total of Top 20 Measures  6,560  74% 
  Total Cumulative Savings 8,883 100% 

Figure 5-16 Industrial Technical Achievable Savings Forecast (Cumulative GWh), Washington

0
10
20
30
40
50
60
70
80
90
100
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
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Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Destratification Fans (HVLS) 863  14% 
2 Compressed Air ‐ Equipment Upgrade 537 9% 
3  Compressed Air ‐ Leak Management Program 524  9% 
4 High‐Bay Lighting 413 7% 
5  Pumping System ‐ Equipment Upgrade 268  4% 
6 Fan System ‐ Equipment Upgrade 177 3% 
7  Paper: Premium Control Large Material  159  3% 
8 Material Handling ‐ Variable Speed Drive 155 3% 
9  Retrocommissioning 155  3% 
10 Kraft: Efficient Agitator 146 2% 
11  Fan System ‐ Variable Speed Drive 138  2% 
12 Compressed Air ‐ Outside Air Intake 130 2% 
13  Exterior Lighting ‐ Enhanced Controls 128  2% 
14 Paper: Efficient Pulp Screen  128 2% 
15  Area Lighting 113  2% 
16 Interior Lighting ‐ Networked Fixture Controls 112 2% 
17  Linear Lighting 104  2% 
18 Compressed Air ‐ End Use Optimization 104 2% 
19  Motors ‐ Synchronous Belts 98  2% 
20 Thermostat ‐ Wi‐Fi/Interactive 95 2% 
 Total of Top 20 Measures  4,547  74% 
  Total Cumulative Savings 6,149 100% 
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho

0
10
20
30
40
50
60
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
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DEMAND RESPONSE POTENTIAL
In 2014, AEG and The Brattle Group performed an assessment of winter demand response potential for
Avista’s commercial and industrial (C&I) sectors. As part of this conservation potential assessment, Avista
asked AEG to update the DR analysis for C&I sectors in Washington and Idaho. In 2016, AEG provided an
update to the 2014 assessment. This year, Avista asked that AEG include the demand response potential
for their residential sector. In addition, since Avista is a dual-peaking utility, AEG was also asked to provide
summer demand response potential.
The updated analysis provides demand response potential and cost estimates for the 20-year planning
horizon of 2021-2040 to inform the development of Avista’s 2019 Integrated Resource Plan (IRP). It
primarily seeks to develop reliable estimates of the magnitude, timing, and costs of DR resources likely
available to Avista over the 20-year planning horizon. The analysis focuses on resources assumed
achievable during the planning horizon, recognizing known market dynamics that may hinder resource
acquisition. DR analysis results will also be incorporated into subsequent DR planning and program
development efforts.
This section describes our analysis approach and the data sources used to develop potential and cost
estimates. The following three steps broadly outline our analysis approach:
1. Segment residential service, general service, large general service, and extra-large general service
customers for DR analysis and develop market characteristics (customer count and coincident
peak demand values) by segment for the base year and planning period.
2. Identify and describe the relevant DR programs and develop assumptions on key program
parameters for potential and cost analysis.
3. Assess achievable potential by DR program for the 2021-2040 planning period and estimate
program budgets and levelized costs.
Market Characterization
The first step in the DR analysis was to segment customers by service class and develop characteristics for
each segment. The two relevant characteristics for DR potential analysis are the number of eligible
customers in each market segment and their coincident peak demand.
Market segmentation
Like the 2014 and 2016 studies, we used Avista’s rate schedules as the basis for customer segmentation
by state and customer class. Table 6-1 summarizes the market segmentation we developed for this study.

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Table 6-1 Market Segmentation
Market Dimensions Segmentation Variable Description 
1 State Idaho 
Washington 
2 Customer Class 
By rate schedule: 
Residential Service 
General Service: Rate Schedule 11 
Large General Service: Rate Schedule 21 
Extra Large General Service: Rate Schedule 2511 
We excluded Avista’s two largest industrial customers from our analysis because they are so large and
unique that a segment-based modeling approach is not appropriate. To accurately estimate demand
reduction potential for these customers, we would need to develop a detailed understanding of their
industrial processes and associated possibilities for load reduction. We would also need to develop specific
DR potential estimates for each customer. Avista may wish to engage with these large customers directly
to gauge interest in participating in DR programs.
Customer Counts by Segment
Once the customer segments were defined, we developed customer counts and coincident peak demand
values for the three C&I segments. We developed these estimates separately by state for Washington and
Idaho. We considered 2017 as the base year for the study, since this is the most recent year with a full 12
months of available customer data. This also coincides with the base year used for the CPA study. The
forecast years are 2018 to 2040.
Avista provided the number of customers by rate schedule for Washington and Idaho over the 2017-2023
timeframe. We used this data to calculate the average annual growth rate. We then applied these same
average annual growth rates to develop customer projections over the rest of the study timeframe, 2024-
2040. The average annual growth rate for all sectors is 1.1%. Table 6-2 below shows the number of
customers by state and customer class for the base year and selected future years.

Table 6-2 Baseline C&I Customer Forecast by State and Customer Class
Customer Class 2017 2018 2019 2020 2027 2037 
Washington 
Residential Service 222,837 225,529 227,521 229,618 243,398 245,335 
General Service 22,415  22,716  22,945  23,202  25,002  27,783 
Large General Service 1,835 1,845 1,844 1,844 1,844 1,844 
Extra Large General Service  20  20  20  20  20  20 

11 Excluding the two largest Schedule 25 and Schedule 25P customers.
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Customer Class 2017 2018 2019 2020 2027 2037 
Idaho            
Residential Service 112,001 113,733 115,077 116,390 126,029 127,452 
General Service 15,979  16,176  16,366  16,559  17,980  18,193 
Large General Service 1,114 1,115 1,115 1,115 1,115 1,115 
Extra Large General Service  11  11  11  11  11  11 

Forecasts of Winter and Summer Peak Demand
System Peak Demand
Avista provided the 2017 system winter and summer peak values as well as annual energy forecasts
through 2024. AEG used the annual energy growth rate by state and sector to forecast annual peak
demands through 2040, Table 6-3 shows the winter and summer system peaks for the base year and
selected futures years. These peaks exclude the demand for Avista’s largest industrial customers. The
winter and summer system peaks are each expected to increase by 4.1% by 2037, an average annual
increase of 0.21%.
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) 12
Peak Demand 2017 2018 2019 2020 2030 2037 
Winter System Peak  1496  1468  1434  1440  1509  1559 
Summer System Peak 1417 1389 1355 1362 1428 1477 

Coincident Peak Demand by Segment
To develop the coincident peak forecast for each segment, we started with electricity sales by customer
class. Avista provided electricity sales by rate schedule for the years 2017 through 2024. For the remaining
years of the forecast, 2025 through 2040, we projected electricity sales using the average annual growth
rate over the 2017 through 2021 timeframe.
Next, we relied on electricity sales and coincident peak demand values for 2010 provided in the 2010 load
research study conducted by Avista to calculate the load factors for Residential Service, General Service,
Large General Service, and Extra Large General Service customers for Washington and Idaho. We then
applied the load factors to the 2017 electricity sales data to derive coincident peak demand estimates for
the four segments. Table 6-4 and Table 6-5 below show the load factors and coincident peak values for
the base year and selected future years.

12 The system peak forecast shown here is the net native load forecast from data provided by Avista, excluding the two largest industrial
loads.
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Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load 
Factor 2017 2018 2019 2020 2027 2037 
Washington 
Residential 0.63 575 551 527 529 548 550 
General Service 0.60 82  80  81  82  88  89 
Large General Service 0.60 187 187 188 188 188 188 
Extra Large General Service 0.69 83  87  86  86  85  85 
Total  928 905 882 885 910 913 
Idaho 
Residential 0.65 264 256 248 251 267 270 
General Service 0.66 63  62  63  63  68  69 
Large General Service 0.66 99 99 98 98 98 98 
Extra Large General Service 0.60 52  56  56  55  54  54 
Total  477 473 464 467 487 490 

Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load 
Factor 2017 2018 2019 2020 2027 2037 
Washington 
Residential 0.50 568 544 520 523 525 528 
General Service 0.51 76  74  74  75  81  82 
Large General Service 0.51 173 173 173 173 174 174 
Extra Large General Service 0.57 68  71  71  71  70  70 
Total  885 862 839 842 845 849 
Idaho 
Residential 0.53 254 246 239 241 243 246 
General Service 0.57 57  57  57  57  58  59 
Large General Service 0.57 89 90 89 89 88 89 
Extra Large General Service 0.53 46  50  49  49  49  49 
Total  446 442 434 436 439 442 

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System and Coincident Peak Forecasts by State
The next step in market characterization is to define the estimated peak load forecast for the study
timeframe. This is done at the Avista system level, and also by state. We used Avista’s peak demand data
to develop the individual state contribution to the estimated coincident peak values. These represent a
state’s projected demand at the time of the system peak for both summer and winter.
Figure 6-1 shows the statewide contribution to the estimated system coincident summer peak, developed
based on load forecast data provided by Avista. In the base year of analysis, 2017, system peak load for
the summer is 1,374 MW at the grid or generator level. Washington contributes 66% of summer system
peak while Idaho contributes 34%. Over the study period, summer coincident peak load is expected to
grow by an average of 0.48% annually from 2021-2040.
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)

Figure 6-2 shows the jurisdictional contribution to the estimated system coincident winter peak forecast,
developed based on load forecast data provided by PacifiCorp. In the base year of analysis, 2016, system
peak load for the winter (a typical December weekday at 6:00 pm) is 8,170 MW at the grid or generator
level. The winter system peak is about 18% lower than the summer peak. Utah contributes 38% of winter
system peak, followed by Oregon at 32%, Wyoming at 15%, Washington 10%, and Idaho 3%, with California
at 2%. Over the study period, winter coincident peak load is expected to grow by an average of 0.59%
annually.
 ‐
 200
 400
 600
 800
 1,000
 1,200
 1,400
 1,600
MW
Washington Idaho
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Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter)

Equipment End Use Saturation
Another key component of market characterization for DR analysis is end use saturation data. This is
required to further segment the market and identify eligible customers for direct control of different
equipment options. The relevant space heating equipment for DR analysis are electric furnaces and air-
source heat pumps. We obtained C&I saturation data from the CPA study, which had updated figures from
the 2014 NEEA Commercial Building Stock Assessment (CBSA). We obtained Residential saturation data
from the 2016 NEEA Residential Building Stock Assessment (RBSA). Table 6-6 and Table 6-7 below show
saturation estimates by state and customer class for Washington and Idaho respectively. We assume slight
growth trends in Central AC, Space Heating, and Electric Vehicle saturations through 2040. AMI Saturations
are new to the analysis this year. We assume 100% AMI Saturation in the residential sector from the start
of the forecast horizon. Avista plans to have 100% AMI Saturation in the commercial sector by 2022 in
Washington and by 2024 in Idaho. They plan to roll out each over the course of two years starting in 2020
in Washington and 2022 in Idaho.
 ‐
 200
 400
 600
 800
 1,000
 1,200
 1,400
 1,600
 1,800
MW
Washington Idaho
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Table 6-6 2017 End Use Saturations by Customer Class, Washington
End Use Saturation by Equipment Type Residential C&I 
Space Heating Saturation  
Electric Furnace 7.4% 1.2% 
Air‐Source Heat Pump 19.4% 14.2% 
Total (Applicable for DR Analysis) 26.8% 15.5% 
Water Heating Saturation  
All equipment 42.2% 45.2% 
Electric Vehicle Saturation     
All equipment 0.2% ‐ 
Central AC Saturation    
All Equipment  38.4% 38.4% 
AMI Saturation    
All Equipment 100.0% 0.0% 
Appliance Saturation    
All Equipment 100.0% ‐ 

Table 6-7 2017 End Use Saturation by Customer Class, Idaho
End Use Saturation by Equipment Type Residential C&I 
Space Heating Saturation  
Electric Furnace 7.4% 1.2% 
Air‐Source Heat Pump 9.9% 14.2% 
Total (Applicable for DR Analysis) 17.3% 15.5% 
Water Heating Saturation  
All equipment 43.0% 45.2% 
Electric Vehicle Saturation     
All equipment 0.2% ‐ 
Central AC Saturation    
All Equipment  36.0% 36.0% 
AMI Saturation    
All Equipment 100.0% 0.0% 
Appliance Saturation    
All Equipment 100.0% ‐ 

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DSM Program Options
The next step in the analysis is to characterize the available DSM options for the Avista territory. We
considered the characteristics and applicability of a comprehensive list of options available in the DSM
marketplace today as well as those projected into the 20-year study time horizon. We included for
quantitative analysis those options which have been deployed at scale such that reliable estimates exist
for cost, lifetime, and performance. Each selected option is described briefly below.
Program Descriptions
Direct Load Control of Central Air Conditioners
The DLC Central AC program targets Avista’s Residential and General Service customers in Washington
and Idaho. This program directly controls Central AC load in summer through a load control switch placed
on a customer’s AC unit. During events, the AC units will be cycled on and off. Participation in the program
is expected to be shared with the Smart Thermostat- Cooling Program in the integrated scenario since
the programs are similar. However, if only one program is rolled out of the two, then participation would
be expected to double for the program implemented. In the fully integrated case, we assume it would
take three full time employees to manage all the DLC programs (five total).
Direct Load Control of Domestic Hot Water Heaters
The DLC Domestic Hot Water Heater program targets Avista’s Residential and General Service customers
in Washington and Idaho. This program directly controls water heating load throughout the year for these
customers through a load control switch. Water heaters would be completely turned off during the DR
event period. The event period is assumed to be 50 hours during the summer months and another 50
hours during winter months. Water heaters of all sizes are eligible for control. We assume a $160 cost to
Avista for each switch, a $200 installation fee, and a permit and license cost of $100 for residential
participants ($125 for general service participants).
Smart Thermostats DLC Heating/Cooling
This program uses the two-way communicating ability of smart thermostats to cycle them on and off
during events. The Smart Thermostat program targets Avista’s Residential and General Service customers
in Washington and Idaho. We assume this will be a Bring your own Thermostat program (BYOT) and
therefore assume no installation costs to Avista. Since the cooling and heating programs are quite different
as far as impact assumptions and participation rates, we modeled them separately. As mentioned in the
DLC Central AC program description, participation in the DLC Smart Thermostat Cooling program is
expected to be split between the two programs in the integrated scenario.
Smart Appliances DLC
The Smart Appliances DLC program uses a Wi-Fi hub to connect smart Wi-Fi enabled appliances such as
washers, dryers, refrigerators, and water heaters. During events throughout the year, the smart appliances
will be cycled on and off. The Smart Appliances DLC program targets Avista’s Residential and General
Service customers in Washington and Idaho. We assume a low steady-state participation rate of 5% for
this program.
Third Party Contracts
Third Party Contracts are assumed to be available for General Service, Large General Service, and Extra
Large General Service customers year-round. For the Large and Extra Large General Service customers,
we assume they will engage in firm curtailment. Under this program option, it is assumed that participating
customers will agree to reduce demand by a specific amount or curtail their consumption to a predefined
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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 $/kW-month or $/kW-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 energy 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 maximum
demand greater than 200 kW 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.
For the general service customers, we simulate a demand buyback program. In a demand buyback
program, customers volunteer to reduce what they can on a day-ahead or day-of basis during a
predefined event window. Customers then receive an energy payment based on their performance during
the events.
Electric Vehicle DLC Smart Chargers
DLC Smart Chargers for Electric Vehicles can be switched off during on-peak hours throughout the year
to offset demand to off-peak hours. Avista currently has an Electric Vehicle Supply Equipment (EVSE) pilot
program in place for residential, commercial electric vehicle fleets, and workplace charging locations. We
also assume the DR program would only be available for residential service customers. The EVSE pilot
called daily demand response events from 4-8 PM. The events yielded impacts of 0.41 kW per charger
however the notifications only reached 82.5% of participants. Therefore, we assume a smaller impact per
charger of 0.34 kW per charger for this study.
Time-of-Use Pricing
The Time-of-Use (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. We
assume two scenarios for the TOU rate. An opt-in rate where participants will have to choose to go on the
rate and an opt-out rate where participants will automatically be placed on the TOU rate and will need to
request a rate change if required. We assume this rate will 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. We assume that this rate will be
offered to all service classes.

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Real Time Pricing
The Real Time Pricing rate is a dynamic rate that fluctuates throughout the day based on energy market
prices. Since it is a dynamic rate that will involve shifting energy use depending on the different prices
throughout the day, we assume only Large and Extra Large General Service customers will be able to
utilize this rate.
Ancillary Services
Ancillary Services refer to functions that help grid operators maintain a reliable electricity system. Ancillary
services maintain the proper flow and direction of electricity, address imbalances between supply and
demand, and help the system recover after a power system event. In systems with significant variable
renewable energy penetration, additional ancillary services may be required to manage increased
variability and uncertainty. We assume ancillary services demand response capabilities can be available in
all sectors.
Thermal Energy Storage
Ice Energy Storage, a type of thermal energy storage, is an emerging technology that is being explored in
many peak-shifting applications across the country. This technology involves cooling and freezing water
in a storage container so that the energy can be used at a later time for space cooling. More specifically,
the freezing water takes advantage of the large amount of latent energy associated with the phase change
between ice and liquid water, which will absorb or release a large amount of thermal energy while
maintaining a constant temperature at the freezing (or melting) point. An ice energy storage unit turns
water into ice during off-peak times when price and demand for electricity is low, typically night time.
During the day, at peak times, the stored ice is melted to meet all or some of the building’s cooling
requirements, allowing air conditioners to operate at reduced loads.
Ice energy storage is primarily being used in non-residential buildings and applications, as modeled in
this analysis, but may see expansion in the future to encompass smaller, residential systems as well as
emerging grid services for peak shaving and renewable integration. Since the ice energy storage is used
for space cooling, we assume this program would be available during the summer months only.
Battery Energy Storage
This program provides the ability to shift peak loads using stored electrochemical energy. Currently the
main battery storage equipment uses Lithium-Ion Batteries. They are the most cost-effective battery type
on the market today. We assume the battery energy storage option will be available for all service classes
with the size and cost of the battery varying depending upon the level of demand of the building.
Behavioral
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.
For this analysis, we assumed the Behavioral DR program would be offered as part of a Home Energy
Reports program in a typical opt-out scenario. As such, we assume this program would be offered to
residential customers only.
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Program Assumptions and Characteristics
Table 6-8 lists the DSM options considered in the study, including the eligible sectors, the mechanism for
deployment and the expected annual event hours (summer and winter hours combined if both seasons
are considered). As shown below, this study update includes a multitude of options that were not
considered in the previous study. Space Heating was considered as an additional option, however Avista
ultimately decided the Smart Thermostat DLC Heating program would be sufficient for DLC space heating
options. For cooling, both Central AC DLC and Smart Thermostats DLC were considered as options.
Table 6-8 Class 1 DSM Products Assessed in the Study
DSM Option Eligible Sectors Mechanism 
Annual 
Event 
Hours 
DLC of central air 
conditioners   
Residential, General 
Service  
Direct load control switch installed on customer’s 
equipment 100 
DLC of domestic hot 
water heaters 
(DHW) 
Residential, General 
Service 
Direct load control switch installed on customer’s 
equipment 100 
Smart Thermostats 
DLC Heating 
Residential, General 
Service Internet‐enabled control of thermostat set points  36 
Smart Thermostats 
DLC Cooling 
Residential, General 
Service Internet‐enabled control of thermostat set points 36 
Smart Appliances 
DLC 
Residential, General 
Service  
Internet‐enabled control of operational cycles of 
white goods appliances 1056 
Thermal Energy 
Storage 
General Service, Large 
General Service, Extra 
Large General Service 
Peak shifting of space cooling loads using stored 
ice 72 
Third Party 
Contracts 
General Service, Large 
General Service, Extra 
Large General Service 
Customers enact their customized, mandatory 
curtailment plan. Penalties apply for non‐
performance.  
60 
Electric Vehicle DLC 
Smart Chargers Residential Automated, level 2 EV chargers that postpone or 
curtail charging during peak hours.  1056 
Time‐of‐Use Pricing  All Sectors 
Higher rate for a particular block of hours that 
occurs every day. Requires either on/off peak 
meters or AMI technology. 
1056 
Variable Peak Pricing All Sectors 
Much higher rate for a particular block of hours 
that occurs only on event days. Requires AMI 
technology.  
80 
Real Time Pricing Large General Service, 
Extra Large General Service 
Dynamic rate that fluctuates throughout the day 
based on energy market prices. Requires AMI 
technology.  
72 
Ancillary Services All Sectors 
Automated control of various building 
management systems or end‐uses through one of 
the mechanisms already described 
160 
Thermal Energy 
Storage 
General Service, Large 
General Service, Extra 
Large General Service 
Peak shifting of primarily space cooling or heating 
loads using a thermal storage medium such as 
water or ice 
72 
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DSM Option Eligible Sectors Mechanism 
Annual 
Event 
Hours 
Battery Energy 
Storage All Sectors 
Peak shifting of loads using stored 
electrochemical energy 

72 
Behavioral Residential 
Voluntary DR reductions in response to behavioral 
messaging. Example programs exist in CA and 
other states. Requires AMI technology. 
80 
The description of options below includes the key assumptions used for potential and levelized cost
calculations. The development of these assumptions is based on findings from research and review of
available information on the topic, including national program survey databases, evaluation studies,
program reports, regulatory filings. The key parameters required to estimate potential for a DSM program
are participation rate, per participant load reduction and program costs. We have described below our
assumptions of these parameters.
Participation Rate Assumptions
Table 6-9 below shows the steady-state participation rate assumptions for each DSM option as well as the
basis for the assumptions. As previously mentioned, the participation for space cooling is split between
DLC Central AC and Smart Thermostat options.
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Table 6-9 DSM Steady-State Participation Rates (% of eligible customers)
DSM Option Residential 
Service 
General 
Service 
Large General 
Service 
Extra Large 
General 
Service 
Basis for 
Assumption 
Direct Load Control 
(DLC) of central air 
conditioners   
7% 7% ‐ ‐ 
50/50 split 
between DLC 
Central AC and 
Smart Thermostats 
DLC of domestic 
hot water heaters 
(DHW) 
15% 5% ‐ ‐ 
Industry 
Experience‐ Brattle 
Study 
Smart Thermostats 
DLC Heating 12.5% 10% ‐ ‐ 
Agreed Upon 
Estimate with 
Avista 
Smart Thermostats 
DLC Cooling 7% 7% ‐ ‐ 
Agreed Upon 
Estimate with 
Avista (See DLC 
Central AC) 
Smart Appliances 
DLC 5% 5% ‐ ‐ 
2017 ISACA IT Risk 
Reward Barometer 
– US Consumer 
Results, October 
2017 
Third Party 
Contracts ‐ 15% 22.1% 20.9% Industry Experience 
Electric Vehicle DLC 
Smart Chargers 25%  ‐  ‐  ‐  Industry Experience 
Time‐of‐Use Pricing 
Opt‐in 13% 13% 13% 13% Best estimate 
based on industry 
experience; Winter 
impacts ½ of 
summer impacts 
Time‐of‐Use Pricing 
Opt‐out 74%  74%  74%  74% 
Variable Peak 
Pricing 25% 25% 25% 25% OG&E 2017 Smart 
Hours Study 
Real Time Pricing ‐ ‐ 3% 3%  Industry Experience 
Ancillary Services 15% 7.5% 7.5% 7.5% 
Industry 
Experience; C&I ½ 
of Residential 
Thermal Energy 
Storage ‐ 0.5% 1.5% 1.5%  Industry Experience 
Battery Energy 
Storage 0.5% 0.5% 0.5% 0.5% Industry Experience 
Behavioral 20% ‐ ‐ ‐ PG&E rollout with 
six waves (2017) 

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Load Reduction Assumptions
Table 6-10 presents the per participant load reductions for each DSM option and explains the basis for
these assumptions. The load reductions are shown on a kW basis for technology-based options and a
percent load reduction otherwise.
Table 6-10 DSM Per Participant Impact Assumptions
DSM Option Residential General 
Service 
Large 
General 
Service 
Extra 
Large 
General 
Service 
Basis for Assumption 
Direct Load 
Control (DLC) 
of central air 
conditioners   
0.5 kW  1.22 kW  ‐  ‐ Average CAC Impacts across WA and ID in Avista 
territory 
DLC of 
domestic hot 
water heaters 
(DHW) 
0.58 kW 1.46 kW ‐ ‐ 
7th Plan, pg. 25 from Cadmus Report, Commercial: 
Res value multiplied by the CAC DLC ratio (small 
C&I impact /Res impact) 
Smart 
Thermostats 
DLC Heating 
1.5 kW  4 kW  ‐  ‐ 
Developed using the average of the 7th plan and 
the PSE 2010 DLC Pilot (WA), multiplied by ratio 
of HDD for the area 
Smart 
Thermostats 
DLC Cooling 
0.5 kW 1.22 kW ‐ ‐ Average CAC Impacts across WA and ID in Avista 
territory 
Smart 
Appliances DLC 0.14 kW  0.14 kW  ‐  ‐ 
Ghatikar, Rish. Demand Response Automation in 
Appliance and Equipment. Lawrence Berkley 
National Laboratory, 2017. 
Third Party 
Contracts ‐ 10% 21% 21% 
Impact Estimates from Aggregator Programs in 
California (Source: 2012 Statewide Load Impact 
Evaluation of California Aggregator Demand 
Response Programs Volume 1: Ex post and Ex 
ante Load Impacts; Christensen Associates Energy 
Consulting; April 1, 2013). 
Electric Vehicle 
DLC Smart 
Chargers 
0.34 kW  ‐  ‐  ‐ 
Avista EVSE DR Pilot Program for Residential‐ 
impact was 0.41 kW. 82.5% of customers received 
the DR notification so reducing to 0.34 kW. 
Time‐of‐Use 
Pricing Opt‐in 5.7% 0.2% 2.6% 3.1% 
Best estimate based on industry experience; 
Winter impacts ½ of summer impacts Time‐of‐Use 
Pricing Opt‐out 3.4%  0.2%  2.6%  3.1% 
Variable Peak 
Pricing 10% 4% 4% 4% OG&E 2017 Smart Hours Study; Summer Impacts 
Shown (Winter impacts ¾ summer) 
Real Time 
Pricing ‐  ‐  4%  4% Industry Experience; Same as VPP Large and Extra 
Large General Service 
Ancillary 
Services 4.8% 4.8% 4.8% 4.8% Industry Experience 
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DSM Option Residential General 
Service 
Large 
General 
Service 
Extra 
Large 
General 
Service 
Basis for Assumption 
Thermal Energy 
Storage   1.68 kW  8.4 kW  8.4 kW 
Ice Bear Tech Specifications, https://www.ice‐
energy.com/wp‐content/uploads/2016/03/ICE‐
BEAR‐30‐Product‐Sheet.pdf 
Battery Energy 
Storage 2 kW 2 kW 15 kW 15 kW Typical Battery size per segment 
Behavioral  2%  ‐  ‐  ‐ Opower documentation for BDR with Consumers 
and Detroit Energy 
Program Costs
Table 6-11 shows the annual marketing, recruitment, incentives, and program development costs
associated with each DSM option.
Table 6-12 presents itemized cost assumptions for the DSM Options and the basis for the assumptions for
the state of Washington. Table 6-11 shows the annual O&M costs per participant and per MW (Third Party
Contracts only) and the Cost of Equipment and installation per participant and per kW (Thermal Energy
Storage only).
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington)
DSM Option Annual O&M Cost Per Participant 
Annual 
O&M Cost 
per MW 
Cost of 
Equip + 
Install Per 
Participant 
Cost of 
Equip + 
Install per 
kW 
DLC Central AC $13.00    $260.00  $0.00 
DLC Water Heating $23.63  $472.50 $0.00 
DLC Smart Thermostats – Heating $44.00    $0.00  $0.00 
DLC Smart Thermostats ‐ Cooling $44.00  $0.00 $0.00 
DLC Smart Appliances $0.00    $300.00  $0.00 
Third Party Contracts $0.00 $80,000.00 $0.00 $0.00 
DLC Electric Vehicle Charging $11.00    $1,200.00  $0.00 
Time‐of‐Use Opt‐in $0.00  $0.00 $0.00 
Time‐of‐Use Opt‐out $0.00    $0.00  $0.00 
Variable Peak Pricing Rates $0.00  $0.00 $0.00 
Real Time Pricing $0.00    $0.00  $0.00 
Ancillary Services $0.00  $300.00 $0.00 
Thermal Energy Storage $308.00    $0.00  $6,160.00 
Battery Energy Storage $0.00  $27,897.60 $0.00 
Behavioral $3.25   $0.00  $0.00 
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Table 6-12 shows the annual marketing, recruitment, incentives, and program development costs
associated with each DSM option.
Table 6-12 Marketing, Recruitment, Incentive, and Development Costs (Washington)
DSM Option Annual Marketing/Recruitment  
Cost Per Participant 
Annual 
Incentive Per 
Participant 
Program 
Development 
Cost 
DLC Central AC $67.50  $29.00  $23,863.32 
DLC Water Heating $0.00 $24.00 $24,128.89 
DLC Smart Thermostats ‐ Heating $67.50  $20.00  $23,963.15 
DLC Smart Thermostats ‐ Cooling $67.50 $20.00 $23,863.32 
DLC Smart Appliances $50.00  $0.00  $24,084.70 
Third Party Contracts $0.00 $0.00 $0.00 
DLC Electric Vehicle Charging $50.00  $24.00  $49,135.60 
Time‐of‐Use Opt‐in $57.50 $0.00 $12,315.14 
Time‐of‐Use Opt‐out $57.50  $0.00  $12,281.26 
Variable Peak Pricing Rates $175.00 $0.00 $12,222.26 
Real Time Pricing $300.00  $0.00  $24,194.41 
Ancillary Services $0.00 $0.00 $11,700.67 
Thermal Energy Storage $100.00  $0.00  $14,994.78 
Battery Energy Storage $25.00 $0.00 $8,017.36 
Behavioral $0.00 $0.00  $66,055.68 
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Table 6-13 and Table 6-14 present the equivalent cost tables for the state of Idaho.
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho)
DSM Option Annual O&M Cost Per Participant 
Annual 
O&M Cost 
per MW 
Cost of 
Equip + 
Install Per 
Participant 
Cost of 
Equip + 
Install per 
kW 
DLC Central AC $13.00    $260.00  $0.00 
DLC Water Heating $23.63  $472.50 $0.00 
DLC Smart Thermostats – Heating $44.00    $0.00  $0.00 
DLC Smart Thermostats ‐ Cooling $44.00  $0.00 $0.00 
DLC Smart Appliances $0.00    $300.00  $0.00 
Third Party Contracts $0.00 $80,000.00 $0.00 $0.00 
DLC Electric Vehicle Charging $11.00    $1,200.00  $0.00 
Time‐of‐Use Opt‐in $0.00  $0.00 $0.00 
Time‐of‐Use Opt‐out $0.00    $0.00  $0.00 
Variable Peak Pricing Rates $0.00  $0.00 $0.00 
Real Time Pricing $0.00    $0.00  $0.00 
Ancillary Services $0.00  $300.00 $0.00 
Thermal Energy Storage $308.00    $0.00  $6,160.00 
Battery Energy Storage $0.00  $27,897.60 $0.00 
Behavioral $3.25   $0.00  $0.00 

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Table 6-14 Marketing, Recruitment, Incentive, and Development Costs (Idaho)
DSM Option 
Annual 
Marketing/Recruitment 
Cost Per Participant 
Annual 
Incentive Per 
Participant 
Program 
Development 
Cost 
DLC Central AC $67.50  $29.00  $13,636.68 
DLC Water Heating $0.00 $24.00 $13,371.11 
DLC Smart Thermostats ‐ 
Heating $67.50 $20.00  $13,536.85 
DLC Smart Thermostats ‐ 
Cooling $67.50 $20.00 $13,636.68 
DLC Smart Appliances $50.00  $0.00  $13,415.30 
Third Party Contracts $0.00 $0.00 $0.00 
DLC Electric Vehicle Charging $50.00  $24.00  $25,864.40 
Time‐of‐Use Opt‐in $69.00 $0.00 $6,434.86 
Time‐of‐Use Opt‐out $69.00  $0.00  $6,468.74 
Variable Peak Pricing Rates $175.00 $0.00 $6,527.74 
Real Time Pricing $300.00  $0.00  $13,305.59 
Ancillary Services $0.00 $0.00 $7,049.33 
Thermal Energy Storage $100.00  $0.00  $10,005.22 
Battery Energy Storage $25.00 $0.00 $4,482.64 
Behavioral $0.00 $0.00  $33,944.32 

Other Cross-cutting Assumptions
In addition to the above program-specific assumptions, there are three that affect all programs:
 Discount rate. We used a nominal discount rate of 5.21% to calculate the net present value (NPV)
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 6.5% to convert estimated demand savings at the
customer meter level to demand savings at the generator level. In the next section, we report our
analysis results at the generator level.
 Snapback. In this context, snapback refers to the amount of energy savings that result from DR
programs. We have assumed in this analysis that the amount of kWh savings from DR programs is
negligible since most of the reduction during events is typically shifted to other times of day, either
before or after the event.

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DR Potential and Cost Estimates
This section presents analysis results on demand savings and cost estimates for DR programs. We
developed savings estimates in two ways:
 First, we present the integrated results. If Avista offers more than one program, then the potential for
double counting exists. To address this possibility, we created a participation hierarchy to define the
order in which the programs are taken by customers. Then we computed the savings and costs under
this scenario. For this study, we assumed a customer would not be on both a Central AC program and
a Smart Thermostat program and would only be on a thermal energy storage program or battery
energy storage program. The hierarchy of pricing rates is as follows: Time-of-Use, Variable Peak
Pricing, and Real Time Pricing.
 At the very end of this section, we present high-level standalone results in 2040 without considering
the integrated effects that occur if more than one DR option is offered to Avista customers. Standalone
results represent an upper bound for each program individually and should not be added together as
that would overstate the overall system level potential.
All potential results presented in this section represent capacity savings in terms of equivalent generation
capacity.
Integrated Potential Results
The following sections separate out the integrated potential results for winter and summer for the Time-
of-Use Opt-in and Time-of-Use Opt-out scenarios.
Winter TOU Opt-in Scenario
Figure 6-3 and Table 6-15 show the total winter demand savings from individual DR options for selected
years of the analysis. These savings represent integrated savings from all available DR options in Avista’s
Washington and Idaho service territories.
Key findings include:
 In the TOU opt-in scenario, participants are split more evenly across the available pricing options,
leading to larger participation in the variable peak pricing rate and consequently a large VPP savings
potential.
 The highest potential option is Third Party Contracts which is expected to reach a savings potential of
23.2 MW by 2040.
 Since most of the participants are likely to be on the VPP pricing rate in the TOU Opt-in scenario, the
TOU potential is significantly lower than in the Opt-out case.
 After Third Party Contracts, the next three biggest potential options in winter include VPP, DLC Smart
Thermostats- Heating, and DLC Water Heating all of which are projected to contribute over 19 MW by
2040.
 The total potential savings in the winter TOU Opt-in scenario are expected to increase from 13 MW in
2021 to nearly 107 MW by 2040. The respective increase in the percentage of system peak goes from
0.9% in 2021 to 6.7% by 2040.
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Figure 6-3 Summary of Potential Analysis for Avista (TOU Opt-In Winter Peak MW @Generator)

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Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 13.0 33.2 91.9 97.0 106.9 
Market Potential (% of baseline) 0.9% 2.3% 6.2% 6.4% 6.7% 
Potential Forecast 1,440 1,427 1,389 1,418 1,482 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.5  4.7  16.2  17.1 19.3 
DLC Smart Thermostats ‐ Heating 1.5 4.6 16.0 17.2 19.7 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.3 0.9 3.0 3.1 3.4 
Third Party Contracts 3.4  9.5  23.0  23.0 23.2 
DLC Electric Vehicle Charging 0.0 0.0 0.3 0.6 1.1 
Time‐of‐Use Opt‐in 0.7  2.2  6.7  6.9 7.2 
Time‐of‐Use Opt‐out 0.0 0.0 0.0 0.0 0.0 
Variable Peak Pricing Rates 2.3  7.0  20.0  20.5 21.5 
Real Time Pricing 0.1 0.3 0.6 0.6 0.6 
Ancillary Services 2.2  2.2  2.2  2.3 2.5 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.1  0.3  1.0  2.8 5.2 
Behavioral 0.8 1.6 2.9 3.0 3.2 
Achievable Potential (% of Baseline)      
DLC Central AC 0.00% 0.00% 0.00% 0.00% 0.00% 
DLC Water Heating 0.11%  0.32%  1.09%  1.13%  1.21% 
DLC Smart Thermostats ‐ Heating 0.10% 0.32% 1.08% 1.13% 1.24% 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.02% 0.06% 0.20% 0.21% 0.22% 
Third Party Contracts 0.23%  0.65%  1.55%  1.52%  1.46% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.07% 
Time‐of‐Use Opt‐in 0.05%  0.15%  0.46%  0.45%  0.45% 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 0.16%  0.48%  1.35%  1.35%  1.35% 
Real Time Pricing 0.01% 0.02% 0.04% 0.04% 0.04% 
Ancillary Services 0.15%  0.15%  0.15%  0.15%  0.16% 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.01%  0.02%  0.07%  0.18%  0.33% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

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Table 6-16 and Table 6-17 show demand savings by individual DR option for the states of Washington and
Idaho separately. Using the available DSM options, Washington is projected to save 68.78 MW (4.3% of
winter system peak demand) by 2040 while Idaho is projected to save 38.16 MW (2.4% of winter system
peak demand) by 2040.
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 9.09 23.06 59.79 62.92 68.78 
Market Potential (% of System Peak) 0.6% 1.6% 4.0% 4.2% 4.3% 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating  0.99  3.00  10.38  11.07  12.60 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.19  0.57  1.96  2.04 2.21 
Third Party Contracts 2.76 7.28 14.58 14.64 14.78 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37 0.74 
Time‐of‐Use Opt‐in 0.49 1.49 4.50 4.57 4.72 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 1.62 4.85 13.25 13.49 14.00 
Real Time Pricing 0.07  0.17  0.38  0.38 0.38 
Ancillary Services 1.35 1.36 1.39 1.44 1.55 
Thermal Energy Storage  ‐  ‐  ‐  ‐  ‐ 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.55  1.07  1.96  2.00 2.08 

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Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (Winter MW) 3.87 10.15 32.07 34.11 38.16 
Market Potential (% of System Peak) 0.3% 0.7% 2.2% 2.3% 2.4% 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 0.53 1.61 5.60 6.00 6.88 
DLC Smart Thermostats ‐ Heating  0.53  1.61  5.64  6.10 7.14 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.10  0.30  1.04  1.10 1.24 
Third Party Contracts 0.64 2.25 8.37 8.40 8.47 
DLC Electric Vehicle Charging 0.00  0.02  0.09  0.19 0.39 
Time‐of‐Use Opt‐in 0.22 0.67 2.24 2.32 2.47 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 0.70 2.16 6.73 6.97 7.48 
Real Time Pricing 0.04  0.11  0.21  0.21 0.21 
Ancillary Services 0.82 0.82 0.84 0.87 0.93 
Thermal Energy Storage  ‐  ‐  ‐  ‐  ‐ 
Battery Energy Storage 0.03 0.08 0.35 0.98 1.87 
Behavioral 0.26  0.51  0.95  0.99 1.07 
Cost Results
Table 6-18 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Third Party Contracts option delivers the highest savings at approximately $74.8/kW-year cost.
Capacity-based and energy-based payments to the third-party constitutes the major cost component
for this option. All O&M and administrative costs are expected to be incurred by the representative
third party contractor.
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 21.8
MW of savings in 2040 at $21.01/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of CPP deployment costs.

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Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter)
DR Option 
Washington 
2021‐2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Winter 
Potential MW in 2040 
DLC Central AC ‐ ‐ ‐ ‐ 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating  $46.17 $45.21 $45.83 19.74 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ 
DLC Smart Appliances $237.04  $240.63 $238.30 3.45 
Third Party Contracts $74.80 $74.80 $74.80 23.25 
DLC Electric Vehicle Charging  $688.90  $698.35 $692.17 1.14 
Time‐of‐Use Opt‐in $45.56 $54.73 $48.68 7.20 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates $21.60 $22.81 $22.01 21.48 
Real Time Pricing $194.77  $191.22 $193.51 0.58 
Ancillary Services $90.19 $94.80 $91.74 2.48 
Thermal Energy Storage ‐ ‐ ‐ ‐ 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $128.58  $134.97 $130.75 3.15 

Winter TOU Opt-out Scenario
Figure 6-4 and Table 6-19 show the total winter demand savings from individual DR options for selected
years of the analysis. These savings represent integrated savings from all available DR options in Avista’s
Washington and Idaho service territories.
Key findings include:
 In the TOU opt-out scenario, customers are placed on the Time-of-Use rate by default and will need
to go through an added step to switch rates. Therefore, the majority of savings among the rates are
concentrated in TOU which is expected to reach 27.4 MW by 2040.
 In the Opt-out scenario, most of the participants are likely to be on the TOU pricing rate and we see
a much lower savings potential for the VPP rate (6.6 MW by 2040).
 After TOU, the next three biggest potential options in winter include Third Party Contracts, DLC Smart
Thermostats- Heating, and DLC Water Heating all of which are projected to contribute over 19 MW by
2040.
 The total potential savings in the winter TOU Opt-out scenario are expected to increase from 45.6 MW
in 2021 to nearly 112 MW by 2040. The respective increase in the percentage of system peak goes
from 3.1% in 2021 to 7.0% by 2040. In this scenario, the potential savings starts at a much faster rate
than in the opt-in case as the participation in TOU will represent a much bigger portion initially.
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Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)

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Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,453  1,460  1,481  1,515  1,589 
Market Potential (Winter MW) 45.6 56.7 96.8 101.9 111.9 
Market Potential (% of baseline) 3.1% 3.9% 6.5% 6.7% 7.0% 
Potential Forecast 1,407 1,403 1,384 1,413 1,477 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.5  4.7  16.2  17.1 19.3 
DLC Smart Thermostats ‐ Heating 1.5 4.6 16.0 17.2 19.7 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.3 0.9 3.0 3.1 3.4 
Third Party Contracts 3.4  9.5  23.0  23.0 23.2 
DLC Electric Vehicle Charging 0.0 0.0 0.3 0.6 1.1 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 35.7 31.7 25.9 26.4 27.4 
Variable Peak Pricing Rates 0.1  1.2  6.1  6.3 6.6 
Real Time Pricing 0.0 0.1 0.2 0.2 0.2 
Ancillary Services 2.2  2.2  2.2  2.3 2.5 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.1  0.3  1.0  2.8 5.2 
Behavioral 0.8 1.6 2.9 3.0 3.2 
Achievable Potential (% of Baseline)       
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 0.11%  0.32%  1.09%  1.13%  1.21% 
DLC Smart Thermostats ‐ Heating 0.10% 0.32% 1.08% 1.13% 1.24% 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.02% 0.06% 0.20% 0.21% 0.22% 
Third Party Contracts 0.23%  0.65%  1.55%  1.52%  1.46% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.07% 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 2.46% 2.17% 1.75% 1.74% 1.73% 
Variable Peak Pricing Rates 0.01%  0.08%  0.41%  0.41%  0.41% 
Real Time Pricing 0.00% 0.01% 0.01% 0.01% 0.01% 
Ancillary Services 0.15%  0.15%  0.15%  0.15%  0.16% 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.01%  0.02%  0.07%  0.18%  0.33% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

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Table 6-20 and Table 6-21 show demand savings by individual DR option for the states of Washington and
Idaho separately.
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (Winter MW) 8.39 21.45 55.77 58.77 64.34 
Market Potential (% of System Peak) 0.6% 1.6% 4.0% 4.1% 4.3% 
Achievable Potential (MW)      
DLC Central AC 0.39  1.19  4.04  4.32 4.92 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.39 1.20 4.15 4.44 5.06 
DLC Smart Appliances 0.19  0.57  1.96  2.04 2.21 
Third Party Contracts 2.44 6.50 13.04 13.10 13.23 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37 0.74 
Time‐of‐Use Opt‐in 0.48 1.44 4.36 4.43 4.58 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 1.58 4.70 12.85 13.09 13.59 
Real Time Pricing 0.06  0.16  0.34  0.34 0.33 
Ancillary Services 1.21 1.22 1.25 1.30 1.40 
Thermal Energy Storage 0.03  0.14  0.45  0.46 0.48 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.54  1.06  1.93  1.97 2.05 

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Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (Winter MW) 3.56 9.40 30.20 31.80 35.64 
Market Potential (% of System Peak) 0.3% 0.7% 2.2% 2.2% 2.4% 
Achievable Potential (MW)      
DLC Central AC 0.22  0.65  2.28  2.43  2.85 
DLC Water Heating 0.53 1.61 5.68 6.00 6.88 
DLC Smart Thermostats ‐ Heating ‐  ‐  ‐  ‐  ‐ 
DLC Smart Thermostats ‐ Cooling 0.22 0.66 2.34 2.50 2.94 
DLC Smart Appliances 0.10  0.30  1.06  1.10  1.24 
Third Party Contracts 0.57 2.01 7.55 7.57 7.64 
DLC Electric Vehicle Charging 0.00  0.02  0.11  0.19  0.39 
Time‐of‐Use Opt‐in 0.21 0.64 2.14 2.20 2.35 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 0.67 2.06 6.42 6.61 7.10 
Real Time Pricing 0.04  0.10  0.19  0.19  0.19 
Ancillary Services 0.74 0.74 0.77 0.79 0.85 
Thermal Energy Storage 0.00  0.03  0.29  0.30  0.32 
Battery Energy Storage 0.03 0.08 0.45 0.98 1.87 
Behavioral 0.25  0.49  0.92  0.95  1.03 
Cost Results
Table 6-22 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The TOU Opt-out option delivers the highest savings at approximately $62.87/kW-year cost and has
the potential to contribute 27.42 MW of savings in 2040.
 The Third Party Contracts option delivers the second highest savings at approximately $74.8/kW-year
cost. Capacity-based and energy-based payments to the third-party constitutes the major cost
component for this option. All O&M and administrative costs are expected to be incurred by the
representative third party contractor.
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 21.8
MW of savings in 2040 at $35.76/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of CPP deployment costs.

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Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter
DR Option 
Washington 
2021‐2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Winter 
Potential MW in 2040 
DLC Central AC ‐ ‐ ‐ ‐ 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating  $46.17 $45.21 $45.83 19.74 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ 
DLC Smart Appliances $237.04  $240.63 $238.30 3.45 
Third Party Contracts $74.80 $74.80 $74.80 23.25 
DLC Electric Vehicle Charging  $688.90  $698.35 $692.17 1.14 
Time‐of‐Use Opt‐in ‐ ‐ ‐ ‐ 
Time‐of‐Use Opt‐out $58.06 $72.18 $62.87 27.42 
Variable Peak Pricing Rates $35.30 $36.64 $35.76 6.59 
Real Time Pricing $659.87  $578.41 $193.51 0.18 
Ancillary Services $90.19 $94.80 $91.74 2.48 
Thermal Energy Storage ‐ ‐ ‐ ‐ 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $128.58  $134.97 $130.75 3.15 

Summer TOU Opt-in Scenario
Figure 6-5 and Table 6-23 show the total summer demand savings from individual DR options for selected
years of the analysis. These savings represent integrated savings from all available DR options in Avista’s
Washington and Idaho service territories.
Key findings include:
 Similar to the winter case, in the TOU opt-in scenario, many customers will choose to go on the
variable peak pricing rate leading to a large VPP savings potential.
 The highest potential option is Third Party Contracts which is expected to reach a savings potential of
20.87 MW by 2040.
 Since most of the participants are likely to be on the VPP pricing rate in the TOU Opt-in scenario, the
TOU potential is significantly lower than in the Opt-out case.
 After Third Party Contracts, the next two biggest potential options in summer include VPP, and DLC
Water Heating each of which are projected to contribute over 19 MW by 2040. Space cooling options
are split across DLC Smart Thermostat and DLC Central AC options. Together they contribute 15.78
MW by 2040.
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 The total potential savings in the summer TOU Opt-in scenario are expected to increase from 11.9 MW
in 2021 to 100 MW by 2040. The respective increase in the percentage of system peak goes from 0.9%
in 2021 to 6.6% by 2040 (very similar to the winter percentages).

Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator)

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Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 11.9 30.8 85.6 90.6 100.0 
Market Potential (% of baseline) 0.9% 2.2% 6.1% 6.3% 6.6% 
Potential Forecast 1,362 1,350 1,315 1,343 1,405 
Achievable Potential (MW)           
DLC Central AC 0.61 1.84 6.32 6.75 7.78 
DLC Water Heating 1.54  4.68  16.23  17.13  19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.61  1.85  6.49  6.93  8.00 
DLC Smart Appliances 0.29 0.88 3.01 3.14 3.45 
Third Party Contracts 3.01  8.52  20.60  20.67  20.87 
DLC Electric Vehicle Charging 0.01 0.05 0.30 0.55 1.14 
Time‐of‐Use Opt‐in 0.68  2.09  6.50  6.63  6.93 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 2.25  6.76  19.27  19.70  20.69 
Real Time Pricing 0.10 0.25 0.52 0.52 0.52 
Ancillary Services 1.95  1.96  2.02  2.09  2.25 
Thermal Energy Storage 0.03 0.17 0.74 0.76 0.80 
Battery Energy Storage 0.08  0.26  1.10  2.77  5.21 
Behavioral 0.79 1.55 2.85 2.92 3.08 
Achievable Potential (% of Baseline)           
DLC Central AC 0.04% 0.13% 0.45% 0.47% 0.52% 
DLC Water Heating 0.11%  0.34%  1.16%  1.19%  1.28% 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.04%  0.13%  0.46%  0.48%  0.53% 
DLC Smart Appliances 0.02% 0.06% 0.22% 0.22% 0.23% 
Third Party Contracts 0.22%  0.62%  1.47%  1.44%  1.39% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.08% 
Time‐of‐Use Opt‐in 0.05%  0.15%  0.46%  0.46%  0.46% 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 0.16%  0.49%  1.38%  1.37%  1.37% 
Real Time Pricing 0.01% 0.02% 0.04% 0.04% 0.03% 
Ancillary Services 0.14%  0.14%  0.14%  0.15%  0.15% 
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.05% 
Battery Energy Storage 0.01%  0.02%  0.08%  0.19%  0.35% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

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Table 6-24 and Table 6-25 show demand savings by individual DR option for the states of Washington
and Idaho separately.
Table 6-24 Achievable DR Potential by Option for WashingtonTOU Opt-In (Summer MW
@Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 8.39 21.45 55.77 58.77 64.34 
Market Potential (% of System Peak) 0.6% 1.6% 4.0% 4.1% 4.3% 
Achievable Potential (MW)      
DLC Central AC 0.39  1.19  4.04  4.32  4.92 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.39 1.20 4.15 4.44 5.06 
DLC Smart Appliances 0.19  0.57  1.96  2.04  2.21 
Third Party Contracts 2.44 6.50 13.04 13.10 13.23 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37  0.74 
Time‐of‐Use Opt‐in 0.48 1.44 4.36 4.43 4.58 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 1.58 4.70 12.85 13.09 13.59 
Real Time Pricing 0.06  0.16  0.34  0.34  0.33 
Ancillary Services 1.21 1.22 1.25 1.30 1.40 
Thermal Energy Storage 0.03  0.14  0.45  0.46  0.48 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.54  1.06  1.93  1.97  2.05 

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Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 3.56 9.40 30.20 31.80 35.64 
Market Potential (% of System Peak) 0.3% 0.7% 2.2% 2.2% 2.4% 
Achievable Potential (MW)      
DLC Central AC 0.22  0.65  2.28  2.43  2.85 
DLC Water Heating 0.53 1.61 5.68 6.00 6.88 
DLC Smart Thermostats ‐ Heating  0.00  0.00  0.00  0.00  0.00 
DLC Smart Thermostats ‐ Cooling 0.22 0.66 2.34 2.50 2.94 
DLC Smart Appliances 0.10  0.30  1.06  1.10  1.24 
Third Party Contracts 0.57 2.01 7.55 7.57 7.64 
DLC Electric Vehicle Charging 0.00  0.02  0.11  0.19  0.39 
Time‐of‐Use Opt‐in 0.21 0.64 2.14 2.20 2.35 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 0.67 2.06 6.42 6.61 7.10 
Real Time Pricing 0.04  0.10  0.19  0.19  0.19 
Ancillary Services 0.74 0.74 0.77 0.79 0.85 
Thermal Energy Storage 0.00  0.03  0.29  0.30  0.32 
Battery Energy Storage 0.03 0.08 0.45 0.98 1.87 
Behavioral 0.25  0.49  0.92  0.95  1.03 
Cost Results
Table 6-26 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Third Party Contracts option delivers the highest savings at approximately $83.39/kW-year cost.
Capacity-based and energy-based payments to the third-party constitutes the major cost component
for this option. All O&M and administrative costs are expected to be incurred by the representative
third party contractor.
 The Variable Peak Pricing option has the lowest levelized cost among all the DR options. It delivers
21.36 MW of savings in 2040 at $22.85/kW-year system wide. Enabling technology purchase and
installation costs for enhancing customer response is a large part of CPP deployment costs.
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Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In
DR Option 
Washington 2021‐
2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Summer 
Potential MW in 
2040 
DLC Central AC $120.70 $118.55 $119.95 7.78 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling $131.00 $127.06 $129.62 8.00 
DLC Smart Appliances $237.04 $240.63 $238.30 3.45 
Third Party Contracts $83.62 $82.98 $83.39 20.69 
DLC Electric Vehicle Charging $688.90 $698.35 $692.16 1.14 
Time‐of‐Use Opt‐in $46.99 $57.66 $50.55 6.93 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates $22.26 $24.05 $22.85 20.36 
Real Time Pricing $218.89 $212.35 $193.51 0.33 
Ancillary Services $99.98 $104.78 $101.56 2.25 
Thermal Energy Storage $610.99 $591.88 $603.36 0.80 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $130.16 $140.39 $133.57 2.05 

Summer TOU Opt-out Scenario
Figure 6-6 and Table 6-27 show the total summer demand savings from individual DR options for selected
years of the analysis. These savings represent integrated savings from all available DR options in Avista’s
Washington and Idaho service territories.
Key findings include:
 In the TOU opt-out scenario, customers are placed on the Time-of-Use rate by default and will need
to go through an added step to switch rates. Therefore, the majority of savings among the rates are
concentrated in TOU which is expected to reach 26.2 MW by 2040.
 In the Opt-out scenario, most of the participants are likely to be on the TOU pricing rate and we see
a much lower savings potential for the VPP rate (6.35 MW by 2040).
 After TOU Opt-out, the next two biggest potential options in summer include Third Party Contracts,
and DLC Water Heating each of which are projected to contribute over 19 MW by 2040. Space cooling
options are split across DLC Smart Thermostat and DLC Central AC options. Together they contribute
15.78 MW by 2040.
 The total potential savings in the summer TOU Opt-in scenario are expected to increase from 43.2
MW in 2021 to 104.5 MW by 2040. The respective increase in the percentage of system peak goes
from 3.1% in 2021 to 6.9% by 2040 (very similar to the winter percentages for the TOU Opt-in case).
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Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator)

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Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 43.2 53.3 90.1 95.1 104.5 
Market Potential (% of baseline) 3.1% 3.9% 6.4% 6.6% 6.9% 
Potential Forecast 1,330 1,327 1,310 1,339 1,400 
Achievable Potential (MW)           
DLC Central AC 0.61 1.84 6.29 6.75 7.78 
DLC Water Heating 1.54  4.68  16.15  17.13  19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.61  1.85  6.45  6.93  8.00 
DLC Smart Appliances 0.29 0.88 3.00 3.14 3.45 
Third Party Contracts 3.01  8.52  20.59  20.67  20.87 
DLC Electric Vehicle Charging 0.01 0.05 0.28 0.55 1.14 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 34.18 30.26 24.70 25.18 26.20 
Variable Peak Pricing Rates 0.08  1.17  5.90  6.05  6.35 
Real Time Pricing 0.04 0.08 0.16 0.16 0.16 
Ancillary Services 1.95  1.96  2.02  2.09  2.25 
Thermal Energy Storage 0.03 0.17 0.74 0.76 0.80 
Battery Energy Storage 0.08  0.26  1.00  2.77  5.21 
Behavioral 0.79 1.55 2.84 2.92 3.08 
Achievable Potential (% of Baseline)           
DLC Central AC 0.04% 0.13% 0.45% 0.47% 0.52% 
DLC Water Heating 0.11%  0.34%  1.15%  1.19%  1.28% 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.04%  0.13%  0.46%  0.48%  0.53% 
DLC Smart Appliances 0.02% 0.06% 0.21% 0.22% 0.23% 
Third Party Contracts 0.22%  0.62%  1.47%  1.44%  1.39% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.08% 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 2.49% 2.19% 1.76% 1.76% 1.74% 
Variable Peak Pricing Rates 0.01%  0.08%  0.42%  0.42%  0.42% 
Real Time Pricing 0.00% 0.01% 0.01% 0.01% 0.01% 
Ancillary Services 0.14%  0.14%  0.14%  0.15%  0.15% 
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.05% 
Battery Energy Storage 0.01%  0.02%  0.07%  0.18%  0.33% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

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Table 6-28 and Table 6-29 show demand savings by individual DR option for the states of Washington
and Idaho separately.
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW
@Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 30.37 37.02 58.77 61.78 67.36 
Market Potential (% of System Peak) 2.2% 2.7% 4.2% 4.3% 4.5% 
Achievable Potential (MW)      
DLC Central AC 0.39  1.19  4.04  4.32  4.92 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating  0.00  0.00  0.00  0.00  0.00 
DLC Smart Thermostats ‐ Cooling 0.39 1.20 4.15 4.44 5.06 
DLC Smart Appliances 0.19  0.57  1.96  2.04  2.21 
Third Party Contracts 2.44 6.50 13.04 13.10 13.23 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37  0.74 
Time‐of‐Use Opt‐in      
Time‐of‐Use Opt‐out 24.02  21.09  16.50  16.75  17.26 
Variable Peak Pricing Rates 0.07 0.76 3.94 4.02 4.17 
Real Time Pricing 0.02  0.03  0.10  0.10  0.10 
Ancillary Services 1.21 1.22 1.25 1.30 1.40 
Thermal Energy Storage 0.03  0.14  0.45  0.46  0.48 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.54  1.06  1.93  1.97  2.05 

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Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 12.85 16.24 31.37 33.32 37.19 
Market Potential (% of System Peak) 0.9% 1.2% 2.2% 2.3% 2.5% 
Achievable Potential (MW)      
DLC Central AC 0.22  0.65  2.24  2.43  2.85 
DLC Water Heating 0.53 1.61 5.60 6.00 6.88 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.22 0.66 2.30 2.50 2.94 
DLC Smart Appliances 0.10  0.30  1.04  1.10  1.24 
Third Party Contracts 0.57 2.01 7.55 7.57 7.64 
DLC Electric Vehicle Charging 0.00  0.02  0.09  0.19  0.39 
Time‐of‐Use Opt‐in ‐ ‐ ‐ ‐ ‐ 
Time‐of‐Use Opt‐out 10.17  9.17  8.20  8.43  8.94 
Variable Peak Pricing Rates 0.01 0.41 1.96 2.03 2.18 
Real Time Pricing 0.02  0.05  0.06  0.06  0.06 
Ancillary Services 0.74 0.74 0.76 0.79 0.85 
Thermal Energy Storage 0.00  0.03  0.29  0.30  0.32 
Battery Energy Storage 0.03 0.08 0.35 0.98 1.87 
Behavioral 0.25  0.49  0.91  0.95  1.03 
Cost Results
Table 6-30 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Third Party Contracts option delivers the highest savings at approximately $83.39/kW-year cost.
Capacity-based and energy-based payments to the third-party constitutes the major cost component
for this option. All O&M and administrative costs are expected to be incurred by the representative
third party contractor.
 The Variable Peak Pricing option has the lowest levelized cost among all the DR options. It delivers
6.25 MW of savings in 2040 at $37.14/kW-year system wide. Enabling technology purchase and
installation costs for enhancing customer response is a large part of CPP deployment costs.

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Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out
DR Option 
Washington 2021‐
2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Summer 
Potential MW in 
2040 
DLC Central AC $120.70 $118.55 $119.95 7.78 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling $131.00 $127.06 $129.62 8.00 
DLC Smart Appliances $237.04 $240.63 $238.30 3.45 
Third Party Contracts $83.62 $82.98 $83.39 20.87 
DLC Electric Vehicle Charging $688.90 $698.35 $692.16 1.14 
Time‐of‐Use Opt‐in ‐ ‐ ‐ ‐ 
Time‐of‐Use Opt‐out $60.46 $76.46 $65.81 26.20 
Variable Peak Pricing Rates $36.38 $38.66 $37.14 6.25 
Real Time Pricing $741.22 $641.72 $193.51 0.10 
Ancillary Services $99.98 $104.78 $101.56 2.25 
Thermal Energy Storage $610.99 $591.88 $603.36 0.80 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $130.16 $140.39 $133.57 2.05 

Stand-alone Potential Results
The above results assume that the programs are offered on an integrated basis where participation across
similar options do not overlap. However, it is also important to see the potential by option where each
program is unaffected by participation in other options. This way, Avista can gauge the impact from
implementing an individual program. For this scenario we do not combine the potential savings and only
show individual potential contributions by program for each scenario.
Winter Results
Figure 6-7 and Table 6-31 show the winter demand savings from individual DR options for selected years
of the analysis. These savings represent stand-alone savings from all available DR options in Avista’s
Washington and Idaho service territories.
Key findings include:
 When each TOU option is examined as an individual program, the Time-of-Use Opt-out option has a
much larger potential savings then if participants could opt-in to the rate. The TOU Opt-out option
makes up the largest savings potential in the stand-alone case and is expected to reach 32.9 MW by
2040.
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 Since the different rate options are not allowed to influence other rates in the stand-alone scenario,
each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
 After TOU Opt-in, the next two biggest potential options in winter include VPP and Third Party
Contracts all of which are projected to contribute over 23 MW by 2040.
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator)

‐
20
40
60
80
100
120
140
160
2021 2022 2025 2030 2040
Achievable Potential 
(MW)
Time‐of‐Use Opt‐out
Time‐of‐Use Opt‐in
DLC Electric Vehicle Charging
Third Party Contracts
DLC Smart Thermostats ‐ Heating
DLC Smart Thermostats ‐ Cooling
Battery Energy Storage
Thermal Energy Storage
Behavioral
Real Time Pricing
Variable Peak Pricing Rates
DLC Smart Appliances
DLC Water Heating
DLC Central AC
Ancillary Services
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Table 6-32 Achievable DR Potential by Option (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,453  1,460  1,481  1,515  1,589 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.5 4.7 16.2 17.1 19.3 
DLC Smart Thermostats ‐ Heating 1.5 4.6 16.0 17.2 19.7 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.3  0.9  3.0  3.1 3.4 
Third Party Contracts 3.4 9.5 23.0 23.0 23.2 
DLC Electric Vehicle Charging 0.0  0.0  0.3  0.6 1.1 
Time‐of‐Use Opt‐in 0.7 2.3 8.0 8.2 8.6 
Time‐of‐Use Opt‐out 36.5  33.6  30.9  31.6 32.9 
Variable Peak Pricing Rates 2.4 7.7 27.2 27.9 29.5 
Real Time Pricing 0.1  0.3  1.1  1.1 1.1 
Ancillary Services 2.2 2.2 2.2 2.3 2.5 
Thermal Energy Storage  ‐  ‐  ‐  ‐  ‐ 
Battery Energy Storage 0.1 0.3 1.0 2.8 5.2 
Behavioral 0.8  1.7  3.4  3.5 3.7 
Achievable Potential (% of Baseline)      
DLC Central AC ‐  ‐  ‐  ‐  ‐ 
DLC Water Heating 0.11% 0.32% 1.09% 1.13% 1.21% 
DLC Smart Thermostats ‐ Heating 0.10% 0.32% 1.08% 1.13% 1.24% 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.02%  0.06%  0.20%  0.21%  0.22% 
Third Party Contracts 0.23% 0.65% 1.55% 1.52% 1.46% 
DLC Electric Vehicle Charging 0.00%  0.00%  0.02%  0.04%  0.07% 
Time‐of‐Use Opt‐in 0.05% 0.16% 0.54% 0.54% 0.54% 
Time‐of‐Use Opt‐out 2.51%  2.30%  2.09%  2.08%  2.07% 
Variable Peak Pricing Rates 0.16% 0.53% 1.84% 1.84% 1.86% 
Real Time Pricing 0.01%  0.02%  0.08%  0.08%  0.07% 
Ancillary Services 0.15% 0.15% 0.15% 0.15% 0.16% 
Thermal Energy Storage 0.00%  0.00%  0.00%  0.00%  0.00% 
Battery Energy Storage 0.01% 0.02% 0.07% 0.18% 0.33% 
Behavioral 0.06%  0.11%  0.23%  0.23%  0.23% 

Table 6-33 and Table 6-34 show demand savings by individual DR option for the states of Washington
and Idaho separately. As mentioned above, the programs with the largest potential savings are TOU Opt-
out, VPP, and Third Party Contracts each individually contributing over 14.5 MW of savings in the
Washington Territory alone.
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Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.01  3.06  10.55  11.13  12.38 
DLC Smart Thermostats ‐ Heating 0.99 3.00 10.38 11.07 12.60 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.19 0.57 1.96 2.04 2.21 
Third Party Contracts 2.76  7.28  14.58  14.64  14.78 
DLC Electric Vehicle Charging 0.01 0.03 0.19 0.37 0.74 
Time‐of‐Use Opt‐in 0.50  1.58  5.32  5.42 5.63 
Time‐of‐Use Opt‐out 25.54 23.42 20.51 20.85 21.55 
Variable Peak Pricing Rates 1.67  5.34  18.02  18.41  19.20 
Real Time Pricing 0.07 0.22 0.73 0.73 0.73 
Ancillary Services 1.35  1.36  1.39  1.44 1.55 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.05  0.17  0.65  1.79 3.34 
Behavioral 0.56 1.12 2.28 2.33 2.44 

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Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 0.53  1.61  5.60  6.00 6.88 
DLC Smart Thermostats ‐ Heating 0.53 1.61 5.64 6.10 7.14 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.10 0.30 1.04 1.10 1.24 
Third Party Contracts 0.64  2.25  8.37  8.40 8.47 
DLC Electric Vehicle Charging 0.00 0.02 0.09 0.19 0.39 
Time‐of‐Use Opt‐in 0.22  0.71  2.66  2.75 2.95 
Time‐of‐Use Opt‐out 10.93 10.20 10.41 10.72 11.38 
Variable Peak Pricing Rates 0.72  2.35  9.19  9.54  10.29 
Real Time Pricing 0.04 0.12 0.41 0.40 0.40 
Ancillary Services 0.82  0.82  0.84  0.87 0.93 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.03  0.08  0.35  0.98 1.87 
Behavioral 0.27 0.54 1.10 1.15 1.26 
Cost Results
Table 6-35 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 29.49
MW of savings in 2040 at $20.67/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of VPP deployment costs.
 The second lowest levelized cost among all the DR options is DLC Smart Thermostats-Heating. It
delivers 29.49 MW of savings in 2040 at $20.67/kW-year system wide. Enabling technology purchase
and installation costs for enhancing customer response is a large part of VPP deployment costs.

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Table 6-35 DR Program Costs and Potential (Winter)
DR Option 
Washington 
2021‐2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Winter 
Potential MW in 2040 
DLC Central AC     
DLC Water Heating $139.94 $138.67 $139.40 19.27 
DLC Smart Thermostats ‐ Heating  $46.17 $45.21 $45.83 19.74 
DLC Smart Thermostats ‐ Cooling     
DLC Smart Appliances $237.04  $240.63 $238.56 3.45 
Third Party Contracts $74.80 $74.80 $74.80 23.25 
DLC Electric Vehicle Charging  $688.90  $698.35 $692.17 1.14 
Time‐of‐Use Opt‐in $43.07 $52.26 $46.40 8.58 
Time‐of‐Use Opt‐out $51.59 $65.02 $56.45 32.93 
Variable Peak Pricing Rates $20.23 $21.38 $20.67 29.49 
Real Time Pricing $104.67  $104.18 $104.49 1.13 
Ancillary Services $90.19 $94.80 $91.95 2.48 
Thermal Energy Storage     
Battery Energy Storage $389.24 $393.20 $390.86 5.22 
Behavioral $120.61  $126.65 $122.66 3.70 

Summer Results
Figure 6-9 and Table 6-36 show the summer demand savings from individual DR options for selected
years of the analysis. These savings represent the individual stand-alone savings from all available DR
options in Avista’s Washington and Idaho service territories.
Key findings include:
 When each TOU option is examined as an individual program, the Time-of-Use Opt-out option has a
much larger potential savings then if participants could opt-in to the rate. The TOU Opt-out option
makes up the largest savings potential in the stand-alone case and is expected to reach 31.4 MW by
2040.
 Since the different rate options are not allowed to influence other rates in the stand-alone scenario,
each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
 After TOU Opt-in, the next two biggest potential options in winter include VPP and Third Party
Contracts all of which are projected to contribute over 20 MW by 2040. DLC Water Heating also has
a high savings potential projected to reach 19.3 MW by 2040.
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Figure 6-9 Summary of Summer Potential by Option (MW @Generator)

‐
20
40
60
80
100
120
140
160
2021 2022 2025 2030 2040
Achievable Potential 
(MW)
Time‐of‐Use Opt‐out
Time‐of‐Use Opt‐in
DLC Electric Vehicle Charging
Third Party Contracts
DLC Smart Thermostats ‐ Heating
DLC Smart Thermostats ‐ Cooling
Battery Energy Storage
Thermal Energy Storage
Behavioral
Real Time Pricing
Variable Peak Pricing Rates
DLC Smart Appliances
DLC Water Heating
DLC Central AC
Ancillary Services
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Table 6-36 Achievable DR Potential by Option (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,374  1,380  1,400  1,434  1,505 
Achievable Potential (MW)      
DLC Central AC 0.6  1.9  6.5  6.9  8.0 
DLC Water Heating 1.5 4.7 16.2 17.1 19.3 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.6 1.9 6.5 6.9 8.0 
DLC Smart Appliances 0.3  0.9  3.0  3.1  3.4 
Third Party Contracts 3.0 8.5 20.6 20.7 20.9 
DLC Electric Vehicle Charging 0.0  0.0  0.3  0.6  1.1 
Time‐of‐Use Opt‐in 0.7 2.2 7.7 7.9 8.3 
Time‐of‐Use Opt‐out 34.9  32.1  29.4  30.1  31.4 
Variable Peak Pricing Rates 2.3 7.3 25.7 26.4 27.9 
Real Time Pricing 0.1  0.2  0.7  0.7  0.7 
Ancillary Services 1.9 2.0 2.0 2.1 2.2 
Thermal Energy Storage 0.6  1.1  2.2  2.3  2.4 
Battery Energy Storage 0.0 0.2 0.8 0.8 0.8 
Behavioral 0.1  0.3  1.0  2.8  5.2 
Achievable Potential (% of Baseline)      
DLC Central AC 0.04%  0.13%  0.46%  0.48%  0.53% 
DLC Water Heating 0.11% 0.34% 1.15% 1.19% 1.28% 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.04% 0.13% 0.46% 0.48% 0.53% 
DLC Smart Appliances 0.02%  0.06%  0.21%  0.22%  0.23% 
Third Party Contracts 0.22% 0.62% 1.47% 1.44% 1.39% 
DLC Electric Vehicle Charging 0.00%  0.00%  0.02%  0.04%  0.08% 
Time‐of‐Use Opt‐in 0.05% 0.16% 0.55% 0.55% 0.55% 
Time‐of‐Use Opt‐out 2.54%  2.32%  2.10%  2.10%  2.09% 
Variable Peak Pricing Rates 0.16% 0.53% 1.83% 1.84% 1.85% 
Real Time Pricing 0.00%  0.01%  0.05%  0.05%  0.04% 
Ancillary Services 0.14% 0.14% 0.14% 0.15% 0.15% 
Thermal Energy Storage 0.04%  0.08%  0.16%  0.16%  0.16% 
Battery Energy Storage 0.00% 0.01% 0.06% 0.06% 0.06% 
Behavioral 0.01%  0.02%  0.07%  0.19%  0.35% 

Table 6-37 and Table 6-38 show summer demand savings by individual DR option for the states of
Washington and Idaho separately. As mentioned above, the programs with the largest potential savings
are TOU Opt-out, VPP, and Third Party Contracts each individually contributing over 13 MW of savings in
the Washington Territory alone.
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Table 6-37 Achievable DR Potential by Option for Washington (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)           
DLC Central AC 0.39 1.20 4.15 4.44 5.06 
DLC Water Heating 1.01  3.06  10.55  11.13  12.38 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.39  1.20  4.15  4.44  5.06 
DLC Smart Appliances 0.19 0.57 1.96 2.04 2.21 
Third Party Contracts 2.44  6.50  13.04  13.10  13.23 
DLC Electric Vehicle Charging 0.01 0.03 0.19 0.37 0.74 
Time‐of‐Use Opt‐in 0.48  1.53  5.15  5.25  5.45 
Time‐of‐Use Opt‐out 24.52 22.43 19.65 19.98 20.68 
Variable Peak Pricing Rates 1.63  5.17  17.46  17.84  18.62 
Real Time Pricing 0.07 0.20 0.65 0.65 0.65 
Ancillary Services 1.21  1.22  1.25  1.30  1.40 
Thermal Energy Storage 0.03 0.14 0.47 0.48 0.50 
Battery Energy Storage 0.05  0.17  0.65  1.79  3.34 
Behavioral 0.55 1.11 2.25 2.30 2.41 

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Table 6-38 Achievable DR Potential by Option for Idaho (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)           
DLC Central AC 0.22 0.66 2.30 2.50 2.94 
DLC Water Heating 0.53  1.61  5.60  6.00  6.88 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.22  0.66  2.30  2.50  2.94 
DLC Smart Appliances 0.10 0.30 1.04 1.10 1.24 
Third Party Contracts 0.57  2.01  7.55  7.57  7.64 
DLC Electric Vehicle Charging 0.00 0.02 0.09 0.19 0.39 
Time‐of‐Use Opt‐in 0.21  0.67  2.52  2.61  2.80 
Time‐of‐Use Opt‐out 10.37 9.65 9.80 10.09 10.74 
Variable Peak Pricing Rates 0.69  2.24  8.70  9.04  9.75 
Real Time Pricing 0.04 0.11 0.37 0.36 0.36 
Ancillary Services 0.74  0.74  0.76  0.79  0.85 
Thermal Energy Storage 0.00 0.03 0.31 0.32 0.34 
Battery Energy Storage 0.03  0.08  0.35  0.98  1.87 
Behavioral 0.26 0.52 1.06 1.11 1.21 
Cost Results
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 27.89
MW of savings in 2040 at $21.44/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of VPP deployment costs.
 The second lowest levelized cost option is the TOU Opt-in rate. It delivers 8.25 MW of savings in 2040
at $44.49/kW-year system wide.
Table 6-39 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 27.89
MW of savings in 2040 at $21.44/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of VPP deployment costs.
 The second lowest levelized cost option is the TOU Opt-in rate. It delivers 8.25 MW of savings in 2040
at $44.49/kW-year system wide.
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Table 6-39 DR Program Costs and Potential – Summer
DR Option 
Washington 2021‐
2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Summer 
Potential MW in 
2040 
DLC Central AC $120.31 $118.14 $119.55 8.00 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling $131.00 $127.06 $129.62 8.00 
DLC Smart Appliances $237.04 $240.63 $238.30 3.45 
Third Party Contracts $83.62 $82.98 $83.39 20.87 
DLC Electric Vehicle Charging $688.90 $698.35 $692.16 1.14 
Time‐of‐Use Opt‐in $44.49 $55.11 $48.03 8.25 
Time‐of‐Use Opt‐out $53.81 $68.96 $58.88 31.42 
Variable Peak Pricing Rates $20.87 $22.57 $21.44 27.89 
Real Time Pricing $117.58 $115.69 $116.90 0.65 
Ancillary Services $99.98 $104.78 $101.56 2.25 
Thermal Energy Storage $122.10 $131.73 $125.31 2.41 
Battery Energy Storage $593.83 $573.63 $585.74 0.84 
Behavioral $389.24 $393.20 $390.63 5.22 
Page 891 Avista Corp. 2020 Electric IRP Appendices
Page 892 Avista Corp. 2020 Electric IRP Appendices

| A‐1 Applied Energy Group • www.appliedenergygroup.com

MARKET PROFILES
This appendix presents the market profiles for each sector and segment for Washington, followed by
Idaho.
Begins on Next page.
Page 893 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐2 Applied Energy Group • www.appliedenergygroup.com
Table A-1 Washington Residential Single Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 38.4%  1,271 488  66.1 
Cooling Room AC 12.3% 691 85 11.5 
Cooling Air‐Source Heat Pump 19.4%  1,332 258  34.9 
Cooling Geothermal Heat Pump 1.0% 1,176 12 1.6 
Cooling Evaporative AC 1.3%  647 8  1.1 
Space Heating Electric Room Heat 6.3% 14,299 904 122.4 
Space Heating  Electric Furnace 7.4%  16,116  1,195  162.0 
Space Heating Air‐Source Heat Pump 19.4% 12,257 2,373 321.5 
Space Heating  Geothermal Heat Pump 1.0%  5,402 55  7.5 
Space Heating Secondary Heating 66.5% 372 248 33.6 
Water Heating  Water Heater <= 55 Gal  42.2%  3,362  1,419  192.3 
Water Heating Water Heater > 55 Gal 5.8% 3,554 205 27.8 
Interior Lighting  General Service Screw‐in  100.0%  761  761  103.1 
Interior Lighting Linear Lighting 100.0% 124 124 16.8 
Interior Lighting  Exempted Screw‐In 100.0%  58 58  7.8 
Exterior Lighting Screw‐in 100.0% 284 284 38.5 
Appliances Clothes Washer 96.4%  77 74  10.1 
Appliances Clothes Dryer 38.6% 741 286 38.8 
Appliances Dishwasher 80.9%  377 305  41.3 
Appliances Refrigerator 94.6% 705 667 90.4 
Appliances Freezer 59.1%  564 333  45.2 
Appliances Second Refrigerator 39.7% 829 329 44.6 
Appliances Stove/Oven 66.9%  443 296  40.2 
Appliances Microwave 95.6% 124 119 16.1 
Electronics Personal Computers 80.5%  161 130  17.5 
Electronics Monitor 161.4% 61 99 13.4 
Electronics Laptops 94.4%  42 40  5.4 
Electronics TVs 205.8% 114 234 31.7 
Electronics Printer/Fax/Copier 85.5%  42 36  4.9 
Electronics Set‐top Boxes/DVRs 175.4% 99 173 23.4 
Electronics Devices and Gadgets 100.0%  108 108  14.6 
Miscellaneous Electric Vehicles 0.2% 4,324 9 1.2 
Miscellaneous  Pool Pump 0.5%  3,500 19  2.5 
Miscellaneous Pool Heater 0.1% 3,517 5 0.7 
Miscellaneous  Hot Tub / Spa 0.7%  2,032 13  1.8 
Miscellaneous Furnace Fan 75.8% 205 156 21.1 
Miscellaneous  Well pump 2.0%  561 11  1.5 
Miscellaneous Miscellaneous 100.0% 1,554 1,554 210.5 
 Total       13,473  1,825.3 

Page 894 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐3 Applied Energy Group • www.appliedenergygroup.com
Table A-2 Washington Residential Multi Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 16.3%  426 70  0.9 
Cooling Room AC 49.0% 258 127 1.6 
Cooling Air‐Source Heat Pump 2.9%  426 12  0.2 
Cooling Geothermal Heat Pump 0.0% 376 0 0.0 
Cooling Evaporative AC 0.9%  320 3  0.0 
Space Heating Electric Room Heat 72.8% 2,937 2,139 26.7 
Space Heating  Electric Furnace 7.6%  3,143 239  3.0 
Space Heating Air‐Source Heat Pump 2.9% 1,831 53 0.7 
Space Heating  Geothermal Heat Pump 0.0%  807 0  0.0 
Space Heating Secondary Heating 44.8% 443 199 2.5 
Water Heating  Water Heater <= 55 Gal  74.2%  2,100  1,558  19.4 
Water Heating Water Heater > 55 Gal 0.5% 2,220 10 0.1 
Interior Lighting  General Service Screw‐in  100.0%  405  405  5.1 
Interior Lighting Linear Lighting 100.0% 33 33 0.4 
Interior Lighting  Exempted Screw‐In 100.0%  33 33  0.4 
Exterior Lighting Screw‐in 100.0% 130 130 1.6 
Appliances Clothes Washer 82.7%  75 62  0.8 
Appliances Clothes Dryer 69.1% 586 405 5.1 
Appliances Dishwasher 70.9%  375 266  3.3 
Appliances Refrigerator 92.7% 701 650 8.1 
Appliances Freezer 46.4%  562 261  3.3 
Appliances Second Refrigerator 3.9% 660 25 0.3 
Appliances Stove/Oven 74.5%  357 266  3.3 
Appliances Microwave 93.6% 124 117 1.5 
Electronics Personal Computers 35.5%  161 57  0.7 
Electronics Monitor 72.8% 61 45 0.6 
Electronics Laptops 41.9%  42 18  0.2 
Electronics TVs 124.7% 114 142 1.8 
Electronics Printer/Fax/Copier 49.5%  42 21  0.3 
Electronics Set‐top Boxes/DVRs 91.4% 99 90 1.1 
Electronics Devices and Gadgets 100.0%  108 108  1.3 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  2,032 0  0.0 
Miscellaneous Furnace Fan 18.9% 73 14 0.2 
Miscellaneous  Well pump 0.0%  556 0  0.0 
Miscellaneous Miscellaneous 100.0% 529 529 6.6 
 Total       8,084  100.9 

Page 895 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐4 Applied Energy Group • www.appliedenergygroup.com
Table A-3 Washington Residential Mobile Home Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 19.6%  1,001 196  1.6 
Cooling Room AC 18.5% 531 98 0.8 
Cooling Air‐Source Heat Pump 26.9%  1,001 269  2.2 
Cooling Geothermal Heat Pump 0.0% 881 0 0.0 
Cooling Evaporative AC 1.7%  499 9  0.1 
Space Heating Electric Room Heat 0.0% 7,208 0 0.0 
Space Heating  Electric Furnace 32.1%  7,715  2,478  19.9 
Space Heating Air‐Source Heat Pump 26.9% 6,752 1,813 14.5 
Space Heating  Geothermal Heat Pump 0.0%  3,094 0  0.0 
Space Heating Secondary Heating 54.2% 493 267 2.1 
Water Heating  Water Heater <= 55 Gal  67.3%  3,288  2,214  17.8 
Water Heating Water Heater > 55 Gal 0.0% 3,476 0 0.0 
Interior Lighting  General Service Screw‐in  100.0%  441  441  3.5 
Interior Lighting Linear Lighting 100.0% 62 62 0.5 
Interior Lighting  Exempted Screw‐In 100.0%  19 19  0.2 
Exterior Lighting Screw‐in 100.0% 109 109 0.9 
Appliances Clothes Washer 91.2%  77 70  0.6 
Appliances Clothes Dryer 66.7% 924 616 4.9 
Appliances Dishwasher 70.2%  377 265  2.1 
Appliances Refrigerator 93.0% 700 651 5.2 
Appliances Freezer 61.4%  565 347  2.8 
Appliances Second Refrigerator 18.2% 742 135 1.1 
Appliances Stove/Oven 82.5%  537 443  3.6 
Appliances Microwave 93.0% 124 116 0.9 
Electronics Personal Computers 45.8%  161 74  0.6 
Electronics Monitor 77.1% 61 47 0.4 
Electronics Laptops 66.7%  42 28  0.2 
Electronics TVs 156.3% 114 177 1.4 
Electronics Printer/Fax/Copier 58.3%  42 25  0.2 
Electronics Set‐top Boxes/DVRs 91.7% 99 90 0.7 
Electronics Devices and Gadgets 100.0%  108 108  0.9 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  2,032 0  0.0 
Miscellaneous Furnace Fan 84.6% 157 132 1.1 
Miscellaneous  Well pump 3.4%  451 15  0.1 
Miscellaneous Miscellaneous 100.0% 811 811 6.5 
 Total       12,125  97.3 

Page 896 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐5 Applied Energy Group • www.appliedenergygroup.com
Table A-4 Washington Residential Low-Income Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 18.9%  444 84  5.6 
Cooling Room AC 42.3% 255 108 7.2 
Cooling Air‐Source Heat Pump 6.9%  449 31  2.1 
Cooling Geothermal Heat Pump 0.1% 396 0 0.0 
Cooling Evaporative AC 1.0%  284 3  0.2 
Space Heating Electric Room Heat 58.9% 3,709 2,185 146.1 
Space Heating  Electric Furnace 10.0%  4,043 406  27.1 
Space Heating Air‐Source Heat Pump 6.9% 2,851 197 13.2 
Space Heating  Geothermal Heat Pump 0.1%  1,269 1  0.1 
Space Heating Secondary Heating 47.9% 337 162 10.8 
Water Heating  Water Heater <= 55 Gal  70.3%  1,993  1,401  93.7 
Water Heating Water Heater > 55 Gal 1.0% 2,107 20 1.3 
Interior Lighting  General Service Screw‐in  100.0%  441  441  29.5 
Interior Lighting Linear Lighting 100.0% 62 62 4.1 
Interior Lighting  Exempted Screw‐In 100.0% 19 19  1.3 
Exterior Lighting Screw‐in 100.0% 109 109 7.3 
Appliances Clothes Washer 84.9% 83 70  4.7 
Appliances Clothes Dryer 65.8% 734 483 32.3 
Appliances Dishwasher 71.8%  382 275  18.4 
Appliances Refrigerator 92.9% 707 658 44.0 
Appliances Freezer 49.1%  566 278  18.6 
Appliances Second Refrigerator 8.9% 685 61 4.1 
Appliances Stove/Oven 74.6%  438 327  21.8 
Appliances Microwave 93.8% 126 118 7.9 
Electronics Personal Computers 41.0%  163 67  4.5 
Electronics Monitor 82.1% 62 51 3.4 
Electronics Laptops 49.7% 43 21  1.4 
Electronics TVs 136.0% 115 156 10.4 
Electronics Printer/Fax/Copier 54.0% 43 23  1.5 
Electronics Set‐top Boxes/DVRs 99.8% 100 100 6.7 
Electronics Devices and Gadgets 100.0%  108 108  7.2 
Miscellaneous Electric Vehicles 0.0% 4,324 1 0.1 
Miscellaneous  Pool Pump 0.1%  3,500 2  0.1 
Miscellaneous Pool Heater 0.0% 3,517 1 0.0 
Miscellaneous  Hot Tub / Spa 0.1%  2,032 1  0.1 
Miscellaneous Furnace Fan 31.2% 95 30 2.0 
Miscellaneous  Well pump 0.5%  546 3  0.2 
Miscellaneous Miscellaneous 100.0% 668 668 44.6 
 Total       8,728  583.5 

Page 897 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐6 Applied Energy Group • www.appliedenergygroup.com
Table A-5 Washington Commercial Large Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 13.7% 3.08 0.42  11.9 
Cooling Water‐Cooled Chiller 8.5% 3.37 0.28 8.0 
Cooling RTU 44.5% 3.22 1.43  40.4 
Cooling PTAC 2.4% 3.80 0.09 2.5 
Cooling PTHP 0.7% 3.22 0.02  0.7 
Cooling Evaporative AC 0.0% 1.29 0.00 0.0 
Cooling Air‐Source Heat Pump 14.2% 3.22 0.46  12.9 
Cooling Geothermal Heat Pump 7.6% 1.96 0.15 4.2 
Heating Electric Furnace 1.2% 5.64 0.07  2.0 
Heating Electric Room Heat 23.8% 5.37 1.28 36.0 
Heating PTHP 0.7% 4.29 0.03  0.9 
Heating Air‐Source Heat Pump 14.2% 4.77 0.68 19.1 
Heating Geothermal Heat Pump 7.6% 3.85 0.29  8.3 
Ventilation Ventilation 100.0% 3.11 3.11 87.7 
Water Heating  Water Heater 45.2% 1.04 0.47  13.2 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 7.0 
Interior Lighting  Exempted Lighting 100.0% 0.10 0.10  2.9 
Interior Lighting High‐Bay Lighting 100.0% 1.01 1.01 28.4 
Interior Lighting  Linear Lighting 100.0% 1.72 1.72  48.6 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 2.7 
Exterior Lighting  Area Lighting 100.0% 1.28 1.28  36.0 
Exterior Lighting Linear Lighting 100.0% 0.18 0.18 5.1 
Refrigeration  Walk‐in Refrigerator/Freezer 2.0% 0.14 0.00  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 14.0% 0.03 0.00 0.1 
Refrigeration  Glass Door Display 77.4% 0.03 0.03  0.7 
Refrigeration  Open Display Case 77.4% 0.19 0.15 4.2 
Refrigeration  Icemaker 44.9% 0.05 0.02  0.7 
Refrigeration  Vending Machine 44.9% 0.05 0.02 0.6 
Food Preparation  Oven 66.0% 0.09 0.06  1.6 
Food Preparation Fryer 76.4% 0.13 0.10 2.7 
Food Preparation  Dishwasher 43.1% 0.18 0.08  2.1 
Food Preparation Hot Food Container 43.1% 0.02 0.01 0.3 
Food Preparation  Steamer 43.1% 0.13 0.06  1.6 
Office Equipment Desktop Computer 100.0% 2.35 2.35 66.1 
Office Equipment  Laptop 100.0% 0.36 0.36  10.2 
Office Equipment Server 100.0% 0.23 0.23 6.5 
Office Equipment  Monitor 100.0% 0.41 0.41  11.7 
Office Equipment Printer/Copier/Fax 100.0% 0.21 0.21 6.0 
Office Equipment  POS Terminal 40.0% 0.03 0.01  0.3 
Miscellaneous Non‐HVAC Motors 89.6% 0.35 0.31 8.8 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.42  1.42  39.9 
Total       19.27 542.8 

Page 898 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐7 Applied Energy Group • www.appliedenergygroup.com
Table A-6 Washington Commercial Small Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.17 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.45 0.00 0.0 
Cooling RTU 65.6% 3.61 2.37  28.0 
Cooling PTAC 2.3% 4.25 0.10 1.2 
Cooling PTHP 0.7% 3.61 0.03  0.3 
Cooling Evaporative AC 0.0% 1.44 0.00 0.0 
Cooling Air‐Source Heat Pump 14.0% 3.61 0.50  6.0 
Cooling Geothermal Heat Pump 7.5% 2.20 0.16 1.9 
Heating Electric Furnace 1.1% 6.82 0.08  0.9 
Heating Electric Room Heat 21.9% 6.49 1.42 16.8 
Heating PTHP 0.7% 5.16 0.04  0.4 
Heating Air‐Source Heat Pump 14.0% 5.73 0.80 9.5 
Heating Geothermal Heat Pump 7.5% 4.44 0.33  3.9 
Ventilation Ventilation 100.0% 1.25 1.25 14.7 
Water Heating  Water Heater 60.0% 0.94 0.56  6.6 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 2.9 
Interior Lighting  Exempted Lighting 100.0% 0.13 0.13  1.6 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 17.8 
Interior Lighting  Linear Lighting 100.0% 1.54 1.54  18.2 
Exterior Lighting General Service Lighting 100.0% 0.16 0.16 1.9 
Exterior Lighting  Area Lighting 100.0% 1.58 1.58  18.6 
Exterior Lighting Linear Lighting 100.0% 0.07 0.07 0.9 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.66  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 8.8% 0.15 0.01 0.2 
Refrigeration   Glass Door Display 0.0% 0.15 0.00  0.0 
Refrigeration  Open Display Case 0.0% 0.90 0.00 0.0 
Refrigeration   Icemaker 5.1% 0.25 0.01  0.2 
Refrigeration  Vending Machine 5.1% 0.12 0.01 0.1 
Food Preparation  Oven 3.6% 0.19 0.01  0.1 
Food Preparation Fryer 3.6% 0.27 0.01 0.1 
Food Preparation  Dishwasher 3.6% 0.37 0.01  0.2 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.27 0.01  0.1 
Office Equipment Desktop Computer 100.0% 1.24 1.24 14.7 
Office Equipment  Laptop 100.0% 0.19 0.19  2.3 
Office Equipment Server 100.0% 0.36 0.36 4.3 
Office Equipment  Monitor 100.0% 0.22 0.22  2.6 
Office Equipment Printer/Copier/Fax 100.0% 0.17 0.17 2.0 
Office Equipment  POS Terminal 20.0% 0.10 0.02  0.2 
Miscellaneous Non‐HVAC Motors 22.0% 0.28 0.06 0.7 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.19  1.19  14.0 
Total       16.41 193.9 

Page 899 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐8 Applied Energy Group • www.appliedenergygroup.com
Table A-7 Washington Commercial Retail Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 2.19 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 2.39 0.00 0.0 
Cooling RTU 67.0% 2.50 1.67  36.6 
Cooling PTAC 2.4% 2.62 0.06 1.4 
Cooling PTHP 0.8% 2.49 0.02  0.4 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 14.3% 2.49 0.36  7.8 
Cooling Geothermal Heat Pump 7.7% 1.52 0.12 2.5 
Heating Electric Furnace 0.5% 6.04 0.03  0.7 
Heating Electric Room Heat 9.6% 5.75 0.55 12.1 
Heating PTHP 0.8% 4.03 0.03  0.7 
Heating Air‐Source Heat Pump 14.3% 4.47 0.64 14.0 
Heating Geothermal Heat Pump 7.7% 3.04 0.23  5.1 
Ventilation Ventilation 100.0% 1.01 1.01 22.1 
Water Heating  Water Heater 61.8% 0.82 0.50  11.0 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 8.3 
Interior Lighting  Exempted Lighting 100.0% 0.36 0.36  7.9 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 33.1 
Interior Lighting  Linear Lighting 100.0% 2.28 2.28  49.9 
Exterior Lighting General Service Lighting 100.0% 0.24 0.24 5.2 
Exterior Lighting  Area Lighting 100.0% 0.84 0.84  18.5 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 1.7 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.42  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 5.4% 0.09 0.01 0.1 
Refrigeration   Glass Door Display 5.4% 0.10 0.01  0.1 
Refrigeration  Open Display Case 5.4% 0.57 0.03 0.7 
Refrigeration   Icemaker 5.1% 0.32 0.02  0.4 
Refrigeration  Vending Machine 5.1% 0.15 0.01 0.2 
Food Preparation  Oven 3.6% 0.17 0.01  0.1 
Food Preparation Fryer 3.6% 0.25 0.01 0.2 
Food Preparation  Dishwasher 3.6% 0.35 0.01  0.3 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.25 0.01  0.2 
Office Equipment Desktop Computer 100.0% 0.18 0.18 3.9 
Office Equipment  Laptop 100.0% 0.03 0.03  0.6 
Office Equipment Server 82.0% 0.21 0.17 3.8 
Office Equipment  Monitor 100.0% 0.03 0.03  0.7 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.4 
Office Equipment  POS Terminal 100.0% 0.06 0.06  1.2 
Miscellaneous Non‐HVAC Motors 40.2% 0.34 0.13 3.0 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 7.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 4.0% 0.03 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.43  1.43  31.4 
Total       13.09 286.3 

Page 900 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐9 Applied Energy Group • www.appliedenergygroup.com
Table A-8 Washington Commercial Restaurant Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.49 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.52 0.00 0.0 
Cooling RTU 72.9% 3.99 2.91  7.7 
Cooling PTAC 2.7% 4.69 0.13 0.3 
Cooling PTHP 1.9% 3.98 0.08  0.2 
Cooling Evaporative AC 3.3% 1.59 0.05 0.1 
Cooling Air‐Source Heat Pump 8.2% 3.98 0.33  0.9 
Cooling Geothermal Heat Pump 0.0% 2.43 0.00 0.0 
Heating Electric Furnace 19.1% 4.81 0.92  2.4 
Heating Electric Room Heat 1.7% 4.58 0.08 0.2 
Heating PTHP 1.9% 3.01 0.06  0.2 
Heating Air‐Source Heat Pump 8.2% 3.35 0.28 0.7 
Heating Geothermal Heat Pump 0.0% 2.37 0.00  0.0 
Ventilation Ventilation 100.0% 1.98 1.98 5.2 
Water Heating  Water Heater 57.9% 7.75 4.49  11.9 
Interior Lighting General Service Lighting 100.0% 1.34 1.34 3.5 
Interior Lighting  Exempted Lighting 100.0% 0.94 0.94  2.5 
Interior Lighting High‐Bay Lighting 100.0% 2.92 2.92 7.7 
Interior Lighting  Linear Lighting 100.0% 1.87 1.87  4.9 
Exterior Lighting General Service Lighting 100.0% 0.28 0.28 0.7 
Exterior Lighting  Area Lighting 100.0% 2.14 2.14  5.7 
Exterior Lighting Linear Lighting 100.0% 0.40 0.40 1.1 
Refrigeration   Walk‐in Refrigerator/Freezer  74.0%  6.59  4.88  12.9 
Refrigeration  Reach‐in Refrigerator/Freezer 7.0% 2.96 0.21 0.5 
Refrigeration   Glass Door Display 5.2% 1.52 0.08  0.2 
Refrigeration  Open Display Case 5.2% 9.00 0.47 1.2 
Refrigeration   Icemaker 97.3% 2.49 2.42  6.4 
Refrigeration  Vending Machine 97.3% 1.17 1.14 3.0 
Food Preparation  Oven 21.0% 3.95 0.83  2.2 
Food Preparation Fryer 82.0% 5.71 4.68 12.4 
Food Preparation  Dishwasher 52.5% 3.93 2.06  5.5 
Food Preparation Hot Food Container 84.0% 0.54 0.45 1.2 
Food Preparation  Steamer 16.0% 2.88 0.46  1.2 
Office Equipment Desktop Computer 100.0% 0.29 0.29 0.8 
Office Equipment  Laptop 100.0% 0.04 0.04  0.1 
Office Equipment Server 50.0% 0.34 0.17 0.5 
Office Equipment  Monitor 100.0% 0.05 0.05  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.2 
Office Equipment  POS Terminal 100.0% 0.09 0.09  0.2 
Miscellaneous Non‐HVAC Motors 20.0% 0.54 0.11 0.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  2.15  2.15  5.7 
Total       41.80 110.5 

Page 901 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐10 Applied Energy Group • www.appliedenergygroup.com
Table A-9 Washington Commercial Grocery Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.5% 3.98 0.02  0.1 
Cooling Water‐Cooled Chiller 0.3% 4.33 0.01 0.1 
Cooling RTU 71.3% 4.53 3.23  13.8 
Cooling PTAC 2.1% 5.33 0.11 0.5 
Cooling PTHP 0.6% 4.15 0.03  0.1 
Cooling Evaporative AC 1.2% 1.81 0.02 0.1 
Cooling Air‐Source Heat Pump 7.2% 4.15 0.30  1.3 
Cooling Geothermal Heat Pump 0.0% 1.41 0.00 0.0 
Heating Electric Furnace 6.4% 7.41 0.47  2.0 
Heating Electric Room Heat 1.2% 7.06 0.08 0.4 
Heating PTHP 0.6% 3.42 0.02  0.1 
Heating Air‐Source Heat Pump 7.2% 3.80 0.27 1.2 
Heating Geothermal Heat Pump 0.0% 2.65 0.00  0.0 
Ventilation Ventilation 100.0% 2.18 2.18 9.3 
Water Heating  Water Heater 62.5% 2.29 1.43  6.1 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 1.6 
Interior Lighting  Exempted Lighting 100.0% 0.30 0.30  1.3 
Interior Lighting High‐Bay Lighting 100.0% 2.02 2.02 8.6 
Interior Lighting  Linear Lighting 100.0% 5.01 5.01  21.4 
Exterior Lighting General Service Lighting 100.0% 0.36 0.36 1.5 
Exterior Lighting  Area Lighting 100.0% 1.78 1.78  7.6 
Exterior Lighting Linear Lighting 100.0% 0.38 0.38 1.6 
Refrigeration   Walk‐in Refrigerator/Freezer  16.0%  5.38  0.86  3.7 
Refrigeration  Reach‐in Refrigerator/Freezer 83.1% 0.34 0.29 1.2 
Refrigeration   Glass Door Display 94.9% 3.54 3.36  14.3 
Refrigeration  Open Display Case 94.9% 20.97 19.90 84.9 
Refrigeration   Icemaker 98.9% 0.29 0.29  1.2 
Refrigeration  Vending Machine 98.9% 0.27 0.27 1.1 
Food Preparation  Oven 11.0% 0.64 0.07  0.3 
Food Preparation Fryer 87.0% 0.92 0.80 3.4 
Food Preparation  Dishwasher 54.9% 1.27 0.70  3.0 
Food Preparation Hot Food Container 73.0% 0.17 0.13 0.5 
Food Preparation  Steamer 20.0% 0.93 0.19  0.8 
Office Equipment Desktop Computer 100.0% 0.16 0.16 0.7 
Office Equipment  Laptop 64.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.09 0.09 0.4 
Office Equipment  Monitor 100.0% 0.03 0.03  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.1 
Office Equipment  POS Terminal 100.0% 0.06 0.06  0.3 
Miscellaneous Non‐HVAC Motors 34.6% 0.20 0.07 0.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  2.7 
Total       46.35 197.8 

Page 902 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐11 Applied Energy Group • www.appliedenergygroup.com
Table A-10 Washington Commercial Health Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 16.7% 5.60 0.93  4.6 
Cooling Water‐Cooled Chiller 66.7% 7.13 4.76 23.3 
Cooling RTU 11.0% 5.57 0.61  3.0 
Cooling PTAC 0.4% 6.56 0.03 0.1 
Cooling PTHP 0.0% 5.56 0.00  0.0 
Cooling Evaporative AC 0.0% 2.23 0.00 0.0 
Cooling Air‐Source Heat Pump 0.6% 5.56 0.03  0.2 
Cooling Geothermal Heat Pump 0.9% 3.38 0.03 0.1 
Heating Electric Furnace 3.0%  17.22 0.51  2.5 
Heating Electric Room Heat 0.1% 16.40 0.01 0.0 
Heating PTHP 0.0%  10.10 0.00  0.0 
Heating Air‐Source Heat Pump 0.6% 11.22 0.06 0.3 
Heating Geothermal Heat Pump 0.9% 7.92 0.07  0.3 
Ventilation Ventilation 100.0% 4.56 4.56 22.3 
Water Heating  Water Heater 12.6% 4.56 0.57  2.8 
Interior Lighting General Service Lighting 100.0% 0.55 0.55 2.7 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  1.1 
Interior Lighting High‐Bay Lighting 100.0% 2.59 2.59 12.7 
Interior Lighting  Linear Lighting 100.0% 4.04 4.04  19.8 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.2 
Exterior Lighting  Area Lighting 100.0% 0.66 0.66  3.3 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.4 
Refrigeration   Walk‐in Refrigerator/Freezer  33.0%  0.27  0.09  0.4 
Refrigeration  Reach‐in Refrigerator/Freezer 50.0% 0.06 0.03 0.2 
Refrigeration   Glass Door Display 90.4% 0.06 0.06  0.3 
Refrigeration  Open Display Case 90.4% 0.38 0.34 1.7 
Refrigeration   Icemaker 90.4% 0.21 0.19  0.9 
Refrigeration  Vending Machine 90.4% 0.10 0.09 0.4 
Food Preparation  Oven 69.7% 0.64 0.45  2.2 
Food Preparation Fryer 80.7% 0.93 0.75 3.7 
Food Preparation  Dishwasher 53.5% 1.28 0.68  3.3 
Food Preparation Hot Food Container 53.5% 0.17 0.09 0.5 
Food Preparation  Steamer 53.5% 0.93 0.50  2.4 
Office Equipment Desktop Computer 100.0% 0.56 0.56 2.7 
Office Equipment  Laptop 100.0% 0.03 0.03  0.2 
Office Equipment Server 100.0% 0.07 0.07 0.3 
Office Equipment  Monitor 100.0% 0.10 0.10  0.5 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.3 
Office Equipment  POS Terminal 100.0% 0.04 0.04  0.2 
Miscellaneous Non‐HVAC Motors 74.1% 0.63 0.47 2.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 63.0% 0.04 0.02  0.1 
Miscellaneous Clothes Dryer 58.0% 0.12 0.07 0.3 
Miscellaneous  Other Miscellaneous  100.0%  4.89  4.89  23.9 
Total       29.95 146.7 

Page 903 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐12 Applied Energy Group • www.appliedenergygroup.com
Table A-11 Washington Commercial College Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 28.5% 4.25 1.21  8.2 
Cooling Water‐Cooled Chiller 0.0% 5.34 0.00 0.0 
Cooling RTU 46.8% 2.49 1.16  7.9 
Cooling PTAC 3.0% 2.93 0.09 0.6 
Cooling PTHP 2.1% 2.48 0.05  0.4 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 7.9% 2.48 0.20  1.3 
Cooling Geothermal Heat Pump 5.7% 1.51 0.09 0.6 
Heating Electric Furnace 0.0%  11.87 0.00  0.0 
Heating Electric Room Heat 8.1% 11.31 0.91 6.2 
Heating PTHP 2.1% 7.12 0.15  1.0 
Heating Air‐Source Heat Pump 7.9% 7.92 0.63 4.2 
Heating Geothermal Heat Pump 5.7% 5.95 0.34  2.3 
Ventilation Ventilation 100.0% 1.52 1.52 10.3 
Water Heating  Water Heater 55.3% 2.08 1.15  7.8 
Interior Lighting General Service Lighting 100.0% 0.09 0.09 0.6 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.3 
Interior Lighting High‐Bay Lighting 100.0% 1.42 1.42 9.6 
Interior Lighting  Linear Lighting 100.0% 2.19 2.19  14.8 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.1 
Exterior Lighting  Area Lighting 100.0% 0.29 0.29  1.9 
Exterior Lighting Linear Lighting 100.0% 0.75 0.75 5.1 
Refrigeration   Walk‐in Refrigerator/Freezer  7.7%  0.16  0.01  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 13.4% 0.07 0.01 0.1 
Refrigeration   Glass Door Display 26.6% 0.04 0.01  0.1 
Refrigeration  Open Display Case 26.6% 0.22 0.06 0.4 
Refrigeration   Icemaker 26.6% 0.12 0.03  0.2 
Refrigeration  Vending Machine 26.6% 0.06 0.02 0.1 
Food Preparation  Oven 21.0% 0.24 0.05  0.3 
Food Preparation Fryer 21.0% 0.34 0.07 0.5 
Food Preparation  Dishwasher 21.0% 0.47 0.10  0.7 
Food Preparation Hot Food Container 21.0% 0.06 0.01 0.1 
Food Preparation  Steamer 21.0% 0.35 0.07  0.5 
Office Equipment Desktop Computer 100.0% 0.47 0.47 3.2 
Office Equipment  Laptop 100.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.06 0.06 0.4 
Office Equipment  Monitor 100.0% 0.08 0.08  0.6 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.4 
Office Equipment  POS Terminal 100.0% 0.02 0.02  0.1 
Miscellaneous Non‐HVAC Motors 88.8% 0.08 0.07 0.5 
Miscellaneous  Pool Pump 90.3% 0.01 0.01  0.1 
Miscellaneous Pool Heater 36.2% 0.02 0.01 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.01 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.35  0.35  2.4 
Total       13.91 93.9 

Page 904 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐13 Applied Energy Group • www.appliedenergygroup.com
Table A-12 Washington Commercial School Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 22.1% 1.97 0.43  6.7 
Cooling Water‐Cooled Chiller 0.0% 2.47 0.00 0.0 
Cooling RTU 36.2% 1.15 0.42  6.4 
Cooling PTAC 2.4% 1.35 0.03 0.5 
Cooling PTHP 1.6% 1.15 0.02  0.3 
Cooling Evaporative AC 0.0% 0.46 0.00 0.0 
Cooling Air‐Source Heat Pump 6.1% 1.15 0.07  1.1 
Cooling Geothermal Heat Pump 4.4% 0.70 0.03 0.5 
Heating Electric Furnace 0.0% 6.44 0.00  0.0 
Heating Electric Room Heat 4.4% 6.13 0.27 4.2 
Heating PTHP 1.6% 3.86 0.06  1.0 
Heating Air‐Source Heat Pump 6.1% 4.29 0.26 4.1 
Heating Geothermal Heat Pump 4.4% 3.23 0.14  2.2 
Ventilation Ventilation 100.0% 0.71 0.71 11.0 
Water Heating  Water Heater 50.0% 0.99 0.50  7.6 
Interior Lighting General Service Lighting 100.0% 0.16 0.16 2.5 
Interior Lighting  Exempted Lighting 100.0% 0.18 0.18  2.8 
Interior Lighting High‐Bay Lighting 100.0% 0.81 0.81 12.5 
Interior Lighting  Linear Lighting 100.0% 1.51 1.51  23.3 
Exterior Lighting General Service Lighting 100.0% 0.00 0.00 0.1 
Exterior Lighting  Area Lighting 100.0% 0.12 0.12  1.8 
Exterior Lighting Linear Lighting 100.0% 0.66 0.66 10.1 
Refrigeration   Walk‐in Refrigerator/Freezer  19.0%  0.17  0.03  0.5 
Refrigeration  Reach‐in Refrigerator/Freezer 33.0% 0.08 0.02 0.4 
Refrigeration   Glass Door Display 65.7% 0.04 0.03  0.4 
Refrigeration  Open Display Case 65.7% 0.23 0.15 2.3 
Refrigeration   Icemaker 65.7% 0.13 0.08  1.3 
Refrigeration  Vending Machine 65.7% 0.06 0.04 0.6 
Food Preparation  Oven 64.8% 0.11 0.07  1.1 
Food Preparation Fryer 58.6% 0.16 0.09 1.5 
Food Preparation  Dishwasher 52.3% 0.22 0.12  1.8 
Food Preparation Hot Food Container 52.3% 0.03 0.02 0.2 
Food Preparation  Steamer 52.3% 0.16 0.08  1.3 
Office Equipment Desktop Computer 100.0% 0.29 0.29 4.5 
Office Equipment  Laptop 100.0% 0.02 0.02  0.3 
Office Equipment Server 100.0% 0.07 0.07 1.1 
Office Equipment  Monitor 100.0% 0.05 0.05  0.8 
Office Equipment Printer/Copier/Fax 100.0% 0.03 0.03 0.5 
Office Equipment  POS Terminal 36.0% 0.01 0.00  0.1 
Miscellaneous Non‐HVAC Motors 43.7% 0.07 0.03 0.5 
Miscellaneous  Pool Pump 6.0% 0.02 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.02 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.33  0.33  5.0 
Total       7.96 122.7 

Page 905 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐14 Applied Energy Group • www.appliedenergygroup.com
Table A-13 Washington Commercial Lodging Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 2.0% 0.49 0.01  0.1 
Cooling Water‐Cooled Chiller 7.3% 0.62 0.05 0.3 
Cooling RTU 15.8% 1.52 0.24  1.6 
Cooling PTAC 38.8% 1.79 0.70 4.7 
Cooling PTHP 13.0% 1.52 0.20  1.3 
Cooling Evaporative AC 0.5% 0.61 0.00 0.0 
Cooling Air‐Source Heat Pump 5.1% 1.52 0.08  0.5 
Cooling Geothermal Heat Pump 5.5% 1.44 0.08 0.5 
Heating Electric Furnace 1.4% 3.02 0.04  0.3 
Heating Electric Room Heat 51.1% 2.88 1.47 9.9 
Heating PTHP 13.0% 2.42 0.32  2.1 
Heating Air‐Source Heat Pump 5.1% 2.69 0.14 0.9 
Heating Geothermal Heat Pump 5.5% 1.90 0.10  0.7 
Ventilation Ventilation 100.0% 0.94 0.94 6.4 
Water Heating  Water Heater 50.0% 3.20 1.60  10.8 
Interior Lighting General Service Lighting 100.0% 0.81 0.81 5.4 
Interior Lighting  Exempted Lighting 100.0% 0.43 0.43  2.9 
Interior Lighting High‐Bay Lighting 100.0% 1.29 1.29 8.7 
Interior Lighting  Linear Lighting 100.0% 0.46 0.46  3.1 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.3 
Exterior Lighting  Area Lighting 100.0% 1.73 1.73  11.6 
Exterior Lighting Linear Lighting 100.0% 0.03 0.03 0.2 
Refrigeration   Walk‐in Refrigerator/Freezer  3.0%  0.39  0.01  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 19.0% 0.09 0.02 0.1 
Refrigeration   Glass Door Display 58.9% 0.09 0.05  0.4 
Refrigeration  Open Display Case 58.9% 0.54 0.32 2.1 
Refrigeration   Icemaker 58.9% 0.15 0.09  0.6 
Refrigeration  Vending Machine 58.9% 0.14 0.08 0.6 
Food Preparation  Oven 13.8% 0.26 0.04  0.2 
Food Preparation Fryer 21.0% 0.37 0.08 0.5 
Food Preparation  Dishwasher 30.0% 0.51 0.15  1.0 
Food Preparation Hot Food Container 30.0% 0.07 0.02 0.1 
Food Preparation  Steamer 30.0% 0.38 0.11  0.8 
Office Equipment Desktop Computer 100.0% 0.08 0.08 0.6 
Office Equipment  Laptop 100.0% 0.01 0.01  0.1 
Office Equipment Server 100.0% 0.05 0.05 0.3 
Office Equipment  Monitor 100.0% 0.01 0.01  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.1 
Office Equipment  POS Terminal 58.0% 0.01 0.01  0.1 
Miscellaneous Non‐HVAC Motors 91.3% 0.14 0.12 0.8 
Miscellaneous  Pool Pump 76.0% 0.01 0.01  0.1 
Miscellaneous Pool Heater 27.0% 0.02 0.00 0.0 
Miscellaneous  Clothes Washer 67.0% 0.02 0.01  0.1 
Miscellaneous Clothes Dryer 26.0% 0.07 0.02 0.1 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  4.2 
Total       12.69 85.3 

Page 906 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐15 Applied Energy Group • www.appliedenergygroup.com
Table A-14 Washington Commercial Warehouse Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 1.59 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 1.68 0.00 0.0 
Cooling RTU 16.0% 1.78 0.28  5.5 
Cooling PTAC 1.1% 2.09 0.02 0.4 
Cooling PTHP 0.3% 1.78 0.01  0.1 
Cooling Evaporative AC 0.0% 0.71 0.00 0.0 
Cooling Air‐Source Heat Pump 1.7% 1.78 0.03  0.6 
Cooling Geothermal Heat Pump 0.0% 1.08 0.00 0.0 
Heating Electric Furnace 2.3% 7.84 0.18  3.5 
Heating Electric Room Heat 12.4% 7.46 0.93 17.8 
Heating PTHP 0.3% 6.19 0.02  0.4 
Heating Air‐Source Heat Pump 1.7% 6.88 0.12 2.2 
Heating Geothermal Heat Pump 0.0% 5.93 0.00  0.0 
Ventilation Ventilation 100.0% 0.26 0.26 5.0 
Water Heating  Water Heater 55.3% 0.26 0.15  2.8 
Interior Lighting General Service Lighting 100.0% 0.07 0.07 1.4 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.7 
Interior Lighting High‐Bay Lighting 100.0% 1.69 1.69 32.6 
Interior Lighting  Linear Lighting 100.0% 0.28 0.28  5.4 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.4 
Exterior Lighting  Area Lighting 100.0% 0.38 0.38  7.3 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 1.5 
Refrigeration   Walk‐in Refrigerator/Freezer  1.1%  0.49  0.01  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 2.0% 0.11 0.00 0.0 
Refrigeration   Glass Door Display 10.1% 0.11 0.01  0.2 
Refrigeration  Open Display Case 10.1% 0.67 0.07 1.3 
Refrigeration   Icemaker 10.1% 0.19 0.02  0.4 
Refrigeration  Vending Machine 10.1% 0.09 0.01 0.2 
Food Preparation  Oven 2.3% 0.03 0.00  0.0 
Food Preparation Fryer 2.3% 0.05 0.00 0.0 
Food Preparation  Dishwasher 2.3% 0.07 0.00  0.0 
Food Preparation Hot Food Container 2.3% 0.01 0.00 0.0 
Food Preparation  Steamer 2.3% 0.05 0.00  0.0 
Office Equipment Desktop Computer 100.0% 0.09 0.09 1.7 
Office Equipment  Laptop 100.0% 0.01 0.01  0.2 
Office Equipment Server 89.0% 0.10 0.09 1.8 
Office Equipment  Monitor 100.0% 0.02 0.02  0.3 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.2 
Office Equipment  POS Terminal 77.0% 0.03 0.02  0.4 
Miscellaneous Non‐HVAC Motors 49.9% 0.12 0.06 1.2 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.43  0.43  8.3 
Total       5.40 104.0 

Page 907 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐16 Applied Energy Group • www.appliedenergygroup.com
Table A-15 Washington Commercial Miscellaneous Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 9.7% 1.64 0.16  4.8 
Cooling Water‐Cooled Chiller 5.0% 1.78 0.09 2.7 
Cooling RTU 56.8% 1.86 1.06  32.0 
Cooling PTAC 5.1% 2.19 0.11 3.4 
Cooling PTHP 2.6% 1.86 0.05  1.5 
Cooling Evaporative AC 0.0% 0.74 0.00 0.0 
Cooling Air‐Source Heat Pump 5.5% 1.86 0.10  3.1 
Cooling Geothermal Heat Pump 1.0% 1.13 0.01 0.4 
Heating Electric Furnace 12.5% 4.77 0.59  18.0 
Heating Electric Room Heat 14.8% 4.55 0.67 20.3 
Heating PTHP 2.6% 3.61 0.09  2.8 
Heating Air‐Source Heat Pump 5.5% 4.01 0.22 6.7 
Heating Geothermal Heat Pump 1.0% 3.13 0.03  1.0 
Ventilation Ventilation 100.0% 0.73 0.73 22.1 
Water Heating  Water Heater 53.0% 1.39 0.74  22.3 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 11.4 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  6.9 
Interior Lighting High‐Bay Lighting 100.0% 1.56 1.56 47.2 
Interior Lighting  Linear Lighting 100.0% 1.46 1.46  44.3 
Exterior Lighting General Service Lighting 100.0% 0.09 0.09 2.8 
Exterior Lighting  Area Lighting 100.0% 0.64 0.64  19.3 
Exterior Lighting Linear Lighting 100.0% 0.06 0.06 1.8 
Refrigeration   Walk‐in Refrigerator/Freezer  10.3%  0.58  0.06  1.8 
Refrigeration  Reach‐in Refrigerator/Freezer 12.1% 0.13 0.02 0.5 
Refrigeration   Glass Door Display 3.4% 0.13 0.00  0.1 
Refrigeration  Open Display Case 3.4% 0.79 0.03 0.8 
Refrigeration   Icemaker 21.6% 0.22 0.05  1.4 
Refrigeration  Vending Machine 21.6% 0.20 0.04 1.3 
Food Preparation  Oven 58.9% 0.08 0.05  1.5 
Food Preparation Fryer 29.9% 0.12 0.04 1.1 
Food Preparation  Dishwasher 15.4% 0.17 0.03  0.8 
Food Preparation Hot Food Container 15.4% 0.02 0.00 0.1 
Food Preparation  Steamer 15.4% 0.12 0.02  0.6 
Office Equipment Desktop Computer 100.0% 0.20 0.20 6.0 
Office Equipment  Laptop 100.0% 0.03 0.03  0.9 
Office Equipment Server 66.0% 0.12 0.08 2.3 
Office Equipment  Monitor 100.0% 0.03 0.03  1.1 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.7 
Office Equipment  POS Terminal 28.0% 0.03 0.01  0.3 
Miscellaneous Non‐HVAC Motors 59.9% 0.15 0.09 2.6 
Miscellaneous  Pool Pump 4.0% 0.01 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 10.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.57  0.57  17.1 
Total       10.43 315.8 

Page 908 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐17 Applied Energy Group • www.appliedenergygroup.com
Table A-16 Washington Industrial Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  6,629.79 165.74  2.8 
Cooling Water‐Cooled Chiller 2.5% 6,983.13 174.58 2.9 
Cooling RTU 11.4%  7,389.72 842.74  14.2 
Cooling Air‐Source Heat Pump 1.7% 7,386.34 124.90 2.1 
Cooling Geothermal Heat Pump 0.0%  4,926.69 0.00  0.0 
Heating Electric Furnace 2.3% 32,574.73 747.28 12.6 
Heating Electric Room Heat 12.4%  31,023.55 3,849.55  65.0 
Heating Air‐Source Heat Pump 1.7% 28,604.84 483.71 8.2 
Heating Geothermal Heat Pump 0.0%  19,079.43 0.00  0.0 
Ventilation Ventilation 100.0% 1,077.71 1,077.71 18.2 
Interior Lighting  General Service Lighting  100.0%  206.68  206.68  3.5 
Interior Lighting High‐Bay Lighting 100.0% 3,233.38 3,233.38 54.6 
Interior Lighting  Linear Lighting 100.0%  537.49 537.49  9.1 
Exterior Lighting General Service Lighting 100.0% 38.05 38.05 0.6 
Exterior Lighting  Area Lighting 100.0%  720.88 720.88  12.2 
Exterior Lighting Linear Lighting 100.0% 147.69 147.69 2.5 
Motors Pumps 100.0%  1,899.28 1,899.28  32.1 
Motors Fans & Blowers 100.0% 2,280.92 2,280.92 38.5 
Motors Compressed Air 100.0%  1,844.32 1,844.32  31.2 
Motors Material Handling 100.0% 3,900.92 3,900.92 65.9 
Motors Other Motors 100.0%  65.46 65.46  1.1 
Process Process Heating 100.0% 3,211.52 3,211.52 54.3 
Process Process Cooling 100.0%  843.19 843.19  14.2 
Process Process Refrigeration 100.0% 843.19 843.19 14.2 
Process Process Electrochemical 100.0%  324.59 324.59  5.5 
Process Process Other 100.0% 352.25 352.25 6.0 
Miscellaneous  Miscellaneous 100.0%  1,937.76 1,937.76  32.7 
Total       29,853.79 504.4 

Page 909 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐18 Applied Energy Group • www.appliedenergygroup.com
Table A-17 Idaho Residential Single Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 36.0%  1,271 458  31.2 
Cooling Room AC 11.6% 691 80 5.5 
Cooling Air‐Source Heat Pump 9.9%  1,332 132  9.0 
Cooling Geothermal Heat Pump 0.8% 1,176 10 0.7 
Cooling Evaporative AC 1.6%  647 10  0.7 
Space Heating Electric Room Heat 9.8% 15,052 1,470 100.1 
Space Heating  Electric Furnace 7.4%  16,964  1,262  86.0 
Space Heating Air‐Source Heat Pump 9.9% 12,902 1,277 87.0 
Space Heating  Geothermal Heat Pump 0.8%  5,686 47  3.2 
Space Heating Secondary Heating 57.2% 392 224 15.3 
Water Heating  Water Heater <= 55 Gal  43.0%  3,362  1,445  98.4 
Water Heating Water Heater > 55 Gal 5.9% 3,554 209 14.2 
Interior Lighting  General Service Screw‐in  100.0%  761  761  51.8 
Interior Lighting Linear Lighting 100.0% 124 124 8.4 
Interior Lighting  Exempted Screw‐In 100.0% 58 58  3.9 
Exterior Lighting Screw‐in 100.0% 284 284 19.4 
Appliances Clothes Washer 95.5% 83 79  5.4 
Appliances Clothes Dryer 65.6% 734 482 32.8 
Appliances Dishwasher 80.1%  382 306  20.8 
Appliances Refrigerator 95.5% 707 676 46.0 
Appliances Freezer 66.3%  566 376  25.6 
Appliances Second Refrigerator 39.7% 829 329 22.4 
Appliances Stove/Oven 58.4%  438 256  17.4 
Appliances Microwave 93.1% 126 117 8.0 
Electronics Personal Computers 63.3%  163 103  7.0 
Electronics Monitor 126.9% 62 79 5.4 
Electronics Laptops 85.7% 43 36  2.5 
Electronics TVs 199.0% 115 228 15.5 
Electronics Printer/Fax/Copier 76.9% 43 33  2.2 
Electronics Set‐top Boxes/DVRs 105.8% 100 105 7.2 
Electronics Devices and Gadgets 100.0%  108 108  7.3 
Miscellaneous Electric Vehicles 0.2% 4,324 9 0.6 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.8%  950 8  0.5 
Miscellaneous Furnace Fan 70.2% 541 380 25.9 
Miscellaneous  Well pump 0.0%  561 0  0.0 
Miscellaneous Miscellaneous 100.0% 1,254 1,254 85.4 
 Total       12,815  872.7 

Page 910 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐19 Applied Energy Group • www.appliedenergygroup.com
Table A-18 Idaho Residential Multi Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 22.6%  426 96  0.5 
Cooling Room AC 32.0% 258 83 0.5 
Cooling Air‐Source Heat Pump 1.3%  426 6  0.0 
Cooling Geothermal Heat Pump 0.0% 376 0 0.0 
Cooling Evaporative AC 1.9%  320 6  0.0 
Space Heating Electric Room Heat 58.5% 2,937 1,718 9.4 
Space Heating  Electric Furnace 16.4%  3,143 515  2.8 
Space Heating Air‐Source Heat Pump 1.3% 1,831 24 0.1 
Space Heating  Geothermal Heat Pump 0.0%  807 0  0.0 
Space Heating Secondary Heating 30.0% 443 133 0.7 
Water Heating  Water Heater <= 55 Gal 60.4%  2,100  1,269  7.0 
Water Heating Water Heater > 55 Gal 4.6% 2,220 101 0.6 
Interior Lighting  General Service Screw‐in  100.0%  405  405  2.2 
Interior Lighting Linear Lighting 100.0% 33 33 0.2 
Interior Lighting  Exempted Screw‐In 100.0% 33 33  0.2 
Exterior Lighting Screw‐in 100.0% 130 130 0.7 
Appliances Clothes Washer 59.6% 78 47  0.3 
Appliances Clothes Dryer 42.3% 785 332 1.8 
Appliances Dishwasher 73.1%  379 277  1.5 
Appliances Refrigerator 90.4% 691 624 3.4 
Appliances Freezer 23.1%  548 127  0.7 
Appliances Second Refrigerator 3.9% 660 25 0.1 
Appliances Stove/Oven 69.2%  317 219  1.2 
Appliances Microwave 86.5% 126 109 0.6 
Electronics Personal Computers 46.3%  163 75  0.4 
Electronics Monitor 94.9% 62 59 0.3 
Electronics Laptops 74.1% 43 32  0.2 
Electronics TVs 140.7% 115 162 0.9 
Electronics Printer/Fax/Copier 51.9% 43 22  0.1 
Electronics Set‐top Boxes/DVRs 64.8% 100 65 0.4 
Electronics Devices and Gadgets 100.0%  108 108  0.6 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  950 0  0.0 
Miscellaneous Furnace Fan 33.3% 196 65 0.4 
Miscellaneous  Well pump 0.0%  556 0  0.0 
Miscellaneous Miscellaneous 100.0% 783 783 4.3 
 Total       7,681  42.2 

Page 911 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐20 Applied Energy Group • www.appliedenergygroup.com
Table A-19 Idaho Residential Mobile Home Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 22.5%  890 201  1.0 
Cooling Room AC 12.9% 472 61 0.3 
Cooling Air‐Source Heat Pump 26.1%  890 232  1.2 
Cooling Geothermal Heat Pump 0.0% 783 0 0.0 
Cooling Evaporative AC 0.0%  443 0  0.0 
Space Heating Electric Room Heat 6.2% 7,208 447 2.3 
Space Heating  Electric Furnace 24.8%  7,715  1,915  9.7 
Space Heating Air‐Source Heat Pump 26.1% 6,752 1,763 8.9 
Space Heating  Geothermal Heat Pump 0.0%  3,094 0  0.0 
Space Heating Secondary Heating 38.5% 493 190 1.0 
Water Heating  Water Heater <= 55 Gal  75.0%  3,288  2,466  12.4 
Water Heating Water Heater > 55 Gal 0.0% 3,476 0 0.0 
Interior Lighting  General Service Screw‐in  100.0%  441  441  2.2 
Interior Lighting Linear Lighting 100.0% 62 62 0.3 
Interior Lighting  Exempted Screw‐In 100.0% 19 19  0.1 
Exterior Lighting Screw‐in 100.0% 109 109 0.5 
Appliances Clothes Washer 94.9% 82 78  0.4 
Appliances Clothes Dryer 82.1% 830 681 3.4 
Appliances Dishwasher 74.4%  384 286  1.4 
Appliances Refrigerator 84.6% 705 597 3.0 
Appliances Freezer 48.7%  567 276  1.4 
Appliances Second Refrigerator 18.2% 742 135 0.7 
Appliances Stove/Oven 82.1%  312 256  1.3 
Appliances Microwave 92.3% 126 116 0.6 
Electronics Personal Computers 46.4%  163 76  0.4 
Electronics Monitor 78.1% 62 48 0.2 
Electronics Laptops 50.0% 43 21  0.1 
Electronics TVs 110.7% 115 127 0.6 
Electronics Printer/Fax/Copier 42.9% 43 18  0.1 
Electronics Set‐top Boxes/DVRs 89.3% 100 89 0.4 
Electronics Devices and Gadgets 100.0%  108 108  0.5 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 1.8%  3,500 65  0.3 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  950 0  0.0 
Miscellaneous Furnace Fan 71.4% 310 222 1.1 
Miscellaneous  Well pump 0.0%  451 0  0.0 
Miscellaneous Miscellaneous 100.0% 418 418 2.1 
 Total       11,522  58.1 

Page 912 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐21 Applied Energy Group • www.appliedenergygroup.com
Table A-20 Idaho Residential Low-Income Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 23.9%  470 112  3.8 
Cooling Room AC 28.0% 270 76 2.5 
Cooling Air‐Source Heat Pump 4.7%  476 22  0.7 
Cooling Geothermal Heat Pump 0.1% 420 0 0.0 
Cooling Evaporative AC 1.6%  300 5  0.2 
Space Heating Electric Room Heat 48.4% 4,146 2,006 67.0 
Space Heating  Electric Furnace 16.3%  4,519 738  24.6 
Space Heating Air‐Source Heat Pump 4.7% 3,187 148 4.9 
Space Heating  Geothermal Heat Pump 0.1%  1,419 1  0.0 
Space Heating Secondary Heating 33.5% 377 126 4.2 
Water Heating  Water Heater <= 55 Gal  60.2%  2,345  1,411  47.1 
Water Heating Water Heater > 55 Gal 4.2% 2,479 105 3.5 
Interior Lighting  General Service Screw‐in  100.0%  441  441  14.7 
Interior Lighting Linear Lighting 100.0% 62 62 2.1 
Interior Lighting  Exempted Screw‐In 100.0% 19 19  0.6 
Exterior Lighting Screw‐in 100.0% 109 109 3.6 
Appliances Clothes Washer 66.7% 79 53  1.8 
Appliances Clothes Dryer 48.6% 784 381 12.7 
Appliances Dishwasher 73.9%  379 280  9.4 
Appliances Refrigerator 90.3% 694 627 20.9 
Appliances Freezer 30.0%  552 165  5.5 
Appliances Second Refrigerator 8.9% 685 61 2.0 
Appliances Stove/Oven 69.4%  328 228  7.6 
Appliances Microwave 87.8% 126 111 3.7 
Electronics Personal Computers 48.0%  163 78  2.6 
Electronics Monitor 96.4% 62 60 2.0 
Electronics Laptops 72.8% 43 31  1.0 
Electronics TVs 143.6% 115 165 5.5 
Electronics Printer/Fax/Copier 53.5% 43 23  0.8 
Electronics Set‐top Boxes/DVRs 71.4% 100 71 2.4 
Electronics Devices and Gadgets 100.0%  108 108  3.6 
Miscellaneous Electric Vehicles 0.0% 4,324 1 0.0 
Miscellaneous  Pool Pump 0.2%  3,500 6  0.2 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.1%  950 1  0.0 
Miscellaneous Furnace Fan 40.8% 242 99 3.3 
Miscellaneous  Well pump 0.0%  546 0  0.0 
Miscellaneous Miscellaneous 100.0% 364 364 12.1 
 Total       8,293  276.8 

Page 913 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐22 Applied Energy Group • www.appliedenergygroup.com
Table A-21 Idaho Commercial Large Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 13.7% 3.08 0.42  5.6 
Cooling Water‐Cooled Chiller 8.5% 3.37 0.28 3.7 
Cooling RTU 44.5% 3.22 1.43  18.9 
Cooling PTAC 2.4% 3.80 0.09 1.2 
Cooling PTHP 0.7% 3.22 0.02  0.3 
Cooling Evaporative AC 0.0% 1.29 0.00 0.0 
Cooling Air‐Source Heat Pump 14.2% 3.22 0.46  6.0 
Cooling Geothermal Heat Pump 7.6% 1.96 0.15 2.0 
Heating Electric Furnace 1.2% 5.64 0.07  0.9 
Heating Electric Room Heat 23.8% 5.37 1.28 16.8 
Heating PTHP 0.7% 4.29 0.03  0.4 
Heating Air‐Source Heat Pump 14.2% 4.77 0.68 8.9 
Heating Geothermal Heat Pump 7.6% 3.85 0.29  3.9 
Ventilation Ventilation 100.0% 3.11 3.11 40.9 
Water Heating  Water Heater 45.2% 1.04 0.47  6.2 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 3.3 
Interior Lighting  Exempted Lighting 100.0% 0.10 0.10  1.4 
Interior Lighting High‐Bay Lighting 100.0% 1.01 1.01 13.3 
Interior Lighting  Linear Lighting 100.0% 1.72 1.72  22.7 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 1.3 
Exterior Lighting  Area Lighting 100.0% 1.28 1.28  16.8 
Exterior Lighting Linear Lighting 100.0% 0.18 0.18 2.4 
Refrigeration  Walk‐in Refrigerator/Freezer 2.0% 0.14 0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 14.0% 0.03 0.00 0.1 
Refrigeration  Glass Door Display 77.4% 0.03 0.03  0.3 
Refrigeration  Open Display Case 77.4% 0.19 0.15 2.0 
Refrigeration  Icemaker 44.9% 0.05 0.02  0.3 
Refrigeration  Vending Machine 44.9% 0.05 0.02 0.3 
Food Preparation  Oven 66.0% 0.09 0.06  0.8 
Food Preparation Fryer 76.4% 0.13 0.10 1.3 
Food Preparation  Dishwasher 43.1% 0.18 0.08  1.0 
Food Preparation Hot Food Container 43.1% 0.02 0.01 0.1 
Food Preparation  Steamer 43.1% 0.13 0.06  0.7 
Office Equipment Desktop Computer 100.0% 2.35 2.35 30.9 
Office Equipment  Laptop 100.0% 0.36 0.36  4.8 
Office Equipment Server 100.0% 0.23 0.23 3.0 
Office Equipment  Monitor 100.0% 0.41 0.41  5.4 
Office Equipment Printer/Copier/Fax 100.0% 0.21 0.21 2.8 
Office Equipment  POS Terminal 40.0% 0.03 0.01  0.2 
Miscellaneous Non‐HVAC Motors 89.6% 0.35 0.31 4.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.42  1.42  18.6 
Total       19.27 253.4 

Page 914 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐23 Applied Energy Group • www.appliedenergygroup.com
Table A-22 Idaho Commercial Small Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.17 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.45 0.00 0.0 
Cooling RTU 65.6% 3.61 2.37  13.0 
Cooling PTAC 2.3% 4.25 0.10 0.5 
Cooling PTHP 0.7% 3.61 0.03  0.1 
Cooling Evaporative AC 0.0% 1.44 0.00 0.0 
Cooling Air‐Source Heat Pump 14.0% 3.61 0.50  2.8 
Cooling Geothermal Heat Pump 7.5% 2.20 0.16 0.9 
Heating Electric Furnace 1.1% 6.82 0.08  0.4 
Heating Electric Room Heat 21.9% 6.49 1.42 7.8 
Heating PTHP 0.7% 5.16 0.04  0.2 
Heating Air‐Source Heat Pump 14.0% 5.73 0.80 4.4 
Heating Geothermal Heat Pump 7.5% 4.44 0.33  1.8 
Ventilation Ventilation 100.0% 1.25 1.25 6.9 
Water Heating  Water Heater 60.0% 0.94 0.56  3.1 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 1.4 
Interior Lighting  Exempted Lighting 100.0% 0.13 0.13  0.7 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 8.3 
Interior Lighting  Linear Lighting 100.0% 1.54 1.54  8.5 
Exterior Lighting General Service Lighting 100.0% 0.16 0.16 0.9 
Exterior Lighting  Area Lighting 100.0% 1.58 1.58  8.7 
Exterior Lighting Linear Lighting 100.0% 0.07 0.07 0.4 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.66  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 8.8% 0.15 0.01 0.1 
Refrigeration   Glass Door Display 0.0% 0.15 0.00  0.0 
Refrigeration  Open Display Case 0.0% 0.90 0.00 0.0 
Refrigeration   Icemaker 5.1% 0.25 0.01  0.1 
Refrigeration  Vending Machine 5.1% 0.12 0.01 0.0 
Food Preparation  Oven 3.6% 0.19 0.01  0.0 
Food Preparation Fryer 3.6% 0.27 0.01 0.1 
Food Preparation  Dishwasher 3.6% 0.37 0.01  0.1 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.27 0.01  0.1 
Office Equipment Desktop Computer 100.0% 1.24 1.24 6.8 
Office Equipment  Laptop 100.0% 0.19 0.19  1.1 
Office Equipment Server 100.0% 0.36 0.36 2.0 
Office Equipment  Monitor 100.0% 0.22 0.22  1.2 
Office Equipment Printer/Copier/Fax 100.0% 0.17 0.17 0.9 
Office Equipment  POS Terminal 20.0% 0.10 0.02  0.1 
Miscellaneous Non‐HVAC Motors 22.0% 0.28 0.06 0.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.19  1.19  6.5 
Total       16.41 90.5 

Page 915 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐24 Applied Energy Group • www.appliedenergygroup.com
Table A-23 Idaho Commercial Retail Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 2.19 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 2.39 0.00 0.0 
Cooling RTU 67.0% 2.50 1.67  17.1 
Cooling PTAC 2.4% 2.62 0.06 0.6 
Cooling PTHP 0.8% 2.49 0.02  0.2 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 14.3% 2.49 0.36  3.6 
Cooling Geothermal Heat Pump 7.7% 1.52 0.12 1.2 
Heating Electric Furnace 0.5% 6.04 0.03  0.3 
Heating Electric Room Heat 9.6% 5.75 0.55 5.6 
Heating PTHP 0.8% 4.03 0.03  0.3 
Heating Air‐Source Heat Pump 14.3% 4.47 0.64 6.5 
Heating Geothermal Heat Pump 7.7% 3.04 0.23  2.4 
Ventilation Ventilation 100.0% 1.01 1.01 10.3 
Water Heating  Water Heater 61.8% 0.82 0.50  5.1 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 3.9 
Interior Lighting  Exempted Lighting 100.0% 0.36 0.36  3.7 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 15.4 
Interior Lighting  Linear Lighting 100.0% 2.28 2.28  23.3 
Exterior Lighting General Service Lighting 100.0% 0.24 0.24 2.4 
Exterior Lighting  Area Lighting 100.0% 0.84 0.84  8.6 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.8 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.42  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 5.4% 0.09 0.01 0.1 
Refrigeration   Glass Door Display 5.4% 0.10 0.01  0.1 
Refrigeration  Open Display Case 5.4% 0.57 0.03 0.3 
Refrigeration   Icemaker 5.1% 0.32 0.02  0.2 
Refrigeration  Vending Machine 5.1% 0.15 0.01 0.1 
Food Preparation  Oven 3.6% 0.17 0.01  0.1 
Food Preparation Fryer 3.6% 0.25 0.01 0.1 
Food Preparation  Dishwasher 3.6% 0.35 0.01  0.1 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.25 0.01  0.1 
Office Equipment Desktop Computer 100.0% 0.18 0.18 1.8 
Office Equipment  Laptop 100.0% 0.03 0.03  0.3 
Office Equipment Server 82.0% 0.21 0.17 1.8 
Office Equipment  Monitor 100.0% 0.03 0.03  0.3 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.2 
Office Equipment  POS Terminal 100.0% 0.06 0.06  0.6 
Miscellaneous Non‐HVAC Motors 40.2% 0.34 0.13 1.4 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 7.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 4.0% 0.03 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.43  1.43  14.6 
Total       13.09 133.6 

Page 916 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐25 Applied Energy Group • www.appliedenergygroup.com
Table A-24 Idaho Commercial Restaurant Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.49 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.52 0.00 0.0 
Cooling RTU 72.9% 3.99 2.91  3.6 
Cooling PTAC 2.7% 4.69 0.13 0.2 
Cooling PTHP 1.9% 3.98 0.08  0.1 
Cooling Evaporative AC 3.3% 1.59 0.05 0.1 
Cooling Air‐Source Heat Pump 8.2% 3.98 0.33  0.4 
Cooling Geothermal Heat Pump 0.0% 2.43 0.00 0.0 
Heating Electric Furnace 19.1% 4.81 0.92  1.1 
Heating Electric Room Heat 1.7% 4.58 0.08 0.1 
Heating PTHP 1.9% 3.01 0.06  0.1 
Heating Air‐Source Heat Pump 8.2% 3.35 0.28 0.3 
Heating Geothermal Heat Pump 0.0% 2.37 0.00  0.0 
Ventilation Ventilation 100.0% 1.98 1.98 2.4 
Water Heating  Water Heater 57.9% 7.75 4.49  5.5 
Interior Lighting General Service Lighting 100.0% 1.34 1.34 1.7 
Interior Lighting  Exempted Lighting 100.0% 0.94 0.94  1.2 
Interior Lighting High‐Bay Lighting 100.0% 2.92 2.92 3.6 
Interior Lighting  Linear Lighting 100.0% 1.87 1.87  2.3 
Exterior Lighting General Service Lighting 100.0% 0.28 0.28 0.3 
Exterior Lighting  Area Lighting 100.0% 2.14 2.14  2.6 
Exterior Lighting Linear Lighting 100.0% 0.40 0.40 0.5 
Refrigeration   Walk‐in Refrigerator/Freezer  74.0%  6.59  4.88  6.0 
Refrigeration  Reach‐in Refrigerator/Freezer 7.0% 2.96 0.21 0.3 
Refrigeration   Glass Door Display 5.2% 1.52 0.08  0.1 
Refrigeration  Open Display Case 5.2% 9.00 0.47 0.6 
Refrigeration   Icemaker 97.3% 2.49 2.42  3.0 
Refrigeration  Vending Machine 97.3% 1.17 1.14 1.4 
Food Preparation  Oven 21.0% 3.95 0.83  1.0 
Food Preparation Fryer 82.0% 5.71 4.68 5.8 
Food Preparation  Dishwasher 52.5% 3.93 2.06  2.5 
Food Preparation Hot Food Container 84.0% 0.54 0.45 0.6 
Food Preparation  Steamer 16.0% 2.88 0.46  0.6 
Office Equipment Desktop Computer 100.0% 0.29 0.29 0.4 
Office Equipment  Laptop 100.0% 0.04 0.04  0.0 
Office Equipment Server 50.0% 0.34 0.17 0.2 
Office Equipment  Monitor 100.0% 0.05 0.05  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.1 
Office Equipment  POS Terminal 100.0% 0.09 0.09  0.1 
Miscellaneous Non‐HVAC Motors 20.0% 0.54 0.11 0.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  2.15  2.15  2.7 
Total       41.80 51.6 

Page 917 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐26 Applied Energy Group • www.appliedenergygroup.com
Table A-25 Idaho Commercial Grocery Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.5% 3.98 0.02  0.0 
Cooling Water‐Cooled Chiller 0.3% 4.33 0.01 0.0 
Cooling RTU 71.3% 4.53 3.23  6.4 
Cooling PTAC 2.1% 5.33 0.11 0.2 
Cooling PTHP 0.6% 4.15 0.03  0.1 
Cooling Evaporative AC 1.2% 1.81 0.02 0.0 
Cooling Air‐Source Heat Pump 7.2% 4.15 0.30  0.6 
Cooling Geothermal Heat Pump 0.0% 1.41 0.00 0.0 
Heating Electric Furnace 6.4% 7.41 0.47  0.9 
Heating Electric Room Heat 1.2% 7.06 0.08 0.2 
Heating PTHP 0.6% 3.42 0.02  0.0 
Heating Air‐Source Heat Pump 7.2% 3.80 0.27 0.5 
Heating Geothermal Heat Pump 0.0% 2.65 0.00  0.0 
Ventilation Ventilation 100.0% 2.18 2.18 4.3 
Water Heating  Water Heater 62.5% 2.29 1.43  2.9 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 0.8 
Interior Lighting  Exempted Lighting 100.0% 0.30 0.30  0.6 
Interior Lighting High‐Bay Lighting 100.0% 2.02 2.02 4.0 
Interior Lighting  Linear Lighting 100.0% 5.01 5.01  10.0 
Exterior Lighting General Service Lighting 100.0% 0.36 0.36 0.7 
Exterior Lighting  Area Lighting 100.0% 1.78 1.78  3.6 
Exterior Lighting Linear Lighting 100.0% 0.38 0.38 0.8 
Refrigeration   Walk‐in Refrigerator/Freezer  16.0%  5.38  0.86  1.7 
Refrigeration  Reach‐in Refrigerator/Freezer 83.1% 0.34 0.29 0.6 
Refrigeration   Glass Door Display 94.9% 3.54 3.36  6.7 
Refrigeration  Open Display Case 94.9% 20.97 19.90 39.6 
Refrigeration   Icemaker 98.9% 0.29 0.29  0.6 
Refrigeration  Vending Machine 98.9% 0.27 0.27 0.5 
Food Preparation  Oven 11.0% 0.64 0.07  0.1 
Food Preparation Fryer 87.0% 0.92 0.80 1.6 
Food Preparation  Dishwasher 54.9% 1.27 0.70  1.4 
Food Preparation Hot Food Container 73.0% 0.17 0.13 0.3 
Food Preparation  Steamer 20.0% 0.93 0.19  0.4 
Office Equipment Desktop Computer 100.0% 0.16 0.16 0.3 
Office Equipment  Laptop 64.0% 0.02 0.02  0.0 
Office Equipment Server 100.0% 0.09 0.09 0.2 
Office Equipment  Monitor 100.0% 0.03 0.03  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.0 
Office Equipment  POS Terminal 100.0% 0.06 0.06  0.1 
Miscellaneous Non‐HVAC Motors 34.6% 0.20 0.07 0.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  1.3 
Total       46.35 92.3 

Page 918 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐27 Applied Energy Group • www.appliedenergygroup.com
Table A-26 Idaho Commercial Health Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 16.7% 5.60 0.93  2.1 
Cooling Water‐Cooled Chiller 66.7% 7.13 4.76 10.9 
Cooling RTU 11.0% 5.57 0.61  1.4 
Cooling PTAC 0.4% 6.56 0.03 0.1 
Cooling PTHP 0.0% 5.56 0.00  0.0 
Cooling Evaporative AC 0.0% 2.23 0.00 0.0 
Cooling Air‐Source Heat Pump 0.6% 5.56 0.03  0.1 
Cooling Geothermal Heat Pump 0.9% 3.38 0.03 0.1 
Heating Electric Furnace 3.0%  17.22 0.51  1.2 
Heating Electric Room Heat 0.1% 16.40 0.01 0.0 
Heating PTHP 0.0%  10.10 0.00  0.0 
Heating Air‐Source Heat Pump 0.6% 11.22 0.06 0.1 
Heating Geothermal Heat Pump 0.9% 7.92 0.07  0.2 
Ventilation Ventilation 100.0% 4.56 4.56 10.4 
Water Heating  Water Heater 12.6% 4.56 0.57  1.3 
Interior Lighting General Service Lighting 100.0% 0.55 0.55 1.3 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  0.5 
Interior Lighting High‐Bay Lighting 100.0% 2.59 2.59 5.9 
Interior Lighting  Linear Lighting 100.0% 4.04 4.04  9.2 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.1 
Exterior Lighting  Area Lighting 100.0% 0.66 0.66  1.5 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.2 
Refrigeration   Walk‐in Refrigerator/Freezer  33.0%  0.27  0.09  0.2 
Refrigeration  Reach‐in Refrigerator/Freezer 50.0% 0.06 0.03 0.1 
Refrigeration   Glass Door Display 90.4% 0.06 0.06  0.1 
Refrigeration  Open Display Case 90.4% 0.38 0.34 0.8 
Refrigeration   Icemaker 90.4% 0.21 0.19  0.4 
Refrigeration  Vending Machine 90.4% 0.10 0.09 0.2 
Food Preparation  Oven 69.7% 0.64 0.45  1.0 
Food Preparation Fryer 80.7% 0.93 0.75 1.7 
Food Preparation  Dishwasher 53.5% 1.28 0.68  1.6 
Food Preparation Hot Food Container 53.5% 0.17 0.09 0.2 
Food Preparation  Steamer 53.5% 0.93 0.50  1.1 
Office Equipment Desktop Computer 100.0% 0.56 0.56 1.3 
Office Equipment  Laptop 100.0% 0.03 0.03  0.1 
Office Equipment Server 100.0% 0.07 0.07 0.1 
Office Equipment  Monitor 100.0% 0.10 0.10  0.2 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.1 
Office Equipment  POS Terminal 100.0% 0.04 0.04  0.1 
Miscellaneous Non‐HVAC Motors 74.1% 0.63 0.47 1.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 63.0% 0.04 0.02  0.1 
Miscellaneous Clothes Dryer 58.0% 0.12 0.07 0.2 
Miscellaneous  Other Miscellaneous  100.0%  4.89  4.89  11.2 
Total       29.95 68.5 

Page 919 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐28 Applied Energy Group • www.appliedenergygroup.com
Table A-27 Idaho Commercial College Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 28.5% 4.25 1.21  3.8 
Cooling Water‐Cooled Chiller 0.0% 5.34 0.00 0.0 
Cooling RTU 46.8% 2.49 1.16  3.7 
Cooling PTAC 3.0% 2.93 0.09 0.3 
Cooling PTHP 2.1% 2.48 0.05  0.2 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 7.9% 2.48 0.20  0.6 
Cooling Geothermal Heat Pump 5.7% 1.51 0.09 0.3 
Heating Electric Furnace 0.0%  11.87 0.00  0.0 
Heating Electric Room Heat 8.1% 11.31 0.91 2.9 
Heating PTHP 2.1% 7.12 0.15  0.5 
Heating Air‐Source Heat Pump 7.9% 7.92 0.63 2.0 
Heating Geothermal Heat Pump 5.7% 5.95 0.34  1.1 
Ventilation Ventilation 100.0% 1.52 1.52 4.8 
Water Heating  Water Heater 55.3% 2.08 1.15  3.6 
Interior Lighting General Service Lighting 100.0% 0.09 0.09 0.3 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.1 
Interior Lighting High‐Bay Lighting 100.0% 1.42 1.42 4.5 
Interior Lighting  Linear Lighting 100.0% 2.19 2.19  6.9 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.1 
Exterior Lighting  Area Lighting 100.0% 0.29 0.29  0.9 
Exterior Lighting Linear Lighting 100.0% 0.75 0.75 2.4 
Refrigeration   Walk‐in Refrigerator/Freezer  7.7%  0.16  0.01  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 13.4% 0.07 0.01 0.0 
Refrigeration   Glass Door Display 26.6% 0.04 0.01  0.0 
Refrigeration  Open Display Case 26.6% 0.22 0.06 0.2 
Refrigeration   Icemaker 26.6% 0.12 0.03  0.1 
Refrigeration  Vending Machine 26.6% 0.06 0.02 0.0 
Food Preparation  Oven 21.0% 0.24 0.05  0.2 
Food Preparation Fryer 21.0% 0.34 0.07 0.2 
Food Preparation  Dishwasher 21.0% 0.47 0.10  0.3 
Food Preparation Hot Food Container 21.0% 0.06 0.01 0.0 
Food Preparation  Steamer 21.0% 0.35 0.07  0.2 
Office Equipment Desktop Computer 100.0% 0.47 0.47 1.5 
Office Equipment  Laptop 100.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.06 0.06 0.2 
Office Equipment  Monitor 100.0% 0.08 0.08  0.3 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.2 
Office Equipment  POS Terminal 100.0% 0.02 0.02  0.1 
Miscellaneous Non‐HVAC Motors 88.8% 0.08 0.07 0.2 
Miscellaneous  Pool Pump 90.3% 0.01 0.01  0.0 
Miscellaneous Pool Heater 36.2% 0.02 0.01 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.01 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.35  0.35  1.1 
Total       13.91 43.8 

Page 920 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐29 Applied Energy Group • www.appliedenergygroup.com
Table A-28 Idaho Commercial School Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 22.1% 1.97 0.43  3.1 
Cooling Water‐Cooled Chiller 0.0% 2.47 0.00 0.0 
Cooling RTU 36.2% 1.15 0.42  3.0 
Cooling PTAC 2.4% 1.35 0.03 0.2 
Cooling PTHP 1.6% 1.15 0.02  0.1 
Cooling Evaporative AC 0.0% 0.46 0.00 0.0 
Cooling Air‐Source Heat Pump 6.1% 1.15 0.07  0.5 
Cooling Geothermal Heat Pump 4.4% 0.70 0.03 0.2 
Heating Electric Furnace 0.0% 6.44 0.00  0.0 
Heating Electric Room Heat 4.4% 6.13 0.27 2.0 
Heating PTHP 1.6% 3.86 0.06  0.5 
Heating Air‐Source Heat Pump 6.1% 4.29 0.26 1.9 
Heating Geothermal Heat Pump 4.4% 3.23 0.14  1.0 
Ventilation Ventilation 100.0% 0.71 0.71 5.1 
Water Heating  Water Heater 50.0% 0.99 0.50  3.6 
Interior Lighting General Service Lighting 100.0% 0.16 0.16 1.2 
Interior Lighting  Exempted Lighting 100.0% 0.18 0.18  1.3 
Interior Lighting High‐Bay Lighting 100.0% 0.81 0.81 5.8 
Interior Lighting  Linear Lighting 100.0% 1.51 1.51  10.9 
Exterior Lighting General Service Lighting 100.0% 0.00 0.00 0.0 
Exterior Lighting  Area Lighting 100.0% 0.12 0.12  0.9 
Exterior Lighting Linear Lighting 100.0% 0.66 0.66 4.7 
Refrigeration   Walk‐in Refrigerator/Freezer  19.0%  0.17  0.03  0.2 
Refrigeration  Reach‐in Refrigerator/Freezer 33.0% 0.08 0.02 0.2 
Refrigeration   Glass Door Display 65.7% 0.04 0.03  0.2 
Refrigeration  Open Display Case 65.7% 0.23 0.15 1.1 
Refrigeration   Icemaker 65.7% 0.13 0.08  0.6 
Refrigeration  Vending Machine 65.7% 0.06 0.04 0.3 
Food Preparation  Oven 64.8% 0.11 0.07  0.5 
Food Preparation Fryer 58.6% 0.16 0.09 0.7 
Food Preparation  Dishwasher 52.3% 0.22 0.12  0.8 
Food Preparation Hot Food Container 52.3% 0.03 0.02 0.1 
Food Preparation  Steamer 52.3% 0.16 0.08  0.6 
Office Equipment Desktop Computer 100.0% 0.29 0.29 2.1 
Office Equipment  Laptop 100.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.07 0.07 0.5 
Office Equipment  Monitor 100.0% 0.05 0.05  0.4 
Office Equipment Printer/Copier/Fax 100.0% 0.03 0.03 0.2 
Office Equipment  POS Terminal 36.0% 0.01 0.00  0.0 
Miscellaneous Non‐HVAC Motors 43.7% 0.07 0.03 0.2 
Miscellaneous  Pool Pump 6.0% 0.02 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.02 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.33  0.33  2.4 
Total       7.96 57.3 

Page 921 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐30 Applied Energy Group • www.appliedenergygroup.com
Table A-29 Idaho Commercial Lodging Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 2.0% 0.49 0.01  0.0 
Cooling Water‐Cooled Chiller 7.3% 0.62 0.05 0.1 
Cooling RTU 15.8% 1.52 0.24  0.8 
Cooling PTAC 38.8% 1.79 0.70 2.2 
Cooling PTHP 13.0% 1.52 0.20  0.6 
Cooling Evaporative AC 0.5% 0.61 0.00 0.0 
Cooling Air‐Source Heat Pump 5.1% 1.52 0.08  0.2 
Cooling Geothermal Heat Pump 5.5% 1.44 0.08 0.2 
Heating Electric Furnace 1.4% 3.02 0.04  0.1 
Heating Electric Room Heat 51.1% 2.88 1.47 4.6 
Heating PTHP 13.0% 2.42 0.32  1.0 
Heating Air‐Source Heat Pump 5.1% 2.69 0.14 0.4 
Heating Geothermal Heat Pump 5.5% 1.90 0.10  0.3 
Ventilation Ventilation 100.0% 0.94 0.94 3.0 
Water Heating  Water Heater 50.0% 3.20 1.60  5.0 
Interior Lighting General Service Lighting 100.0% 0.81 0.81 2.5 
Interior Lighting  Exempted Lighting 100.0% 0.43 0.43  1.3 
Interior Lighting High‐Bay Lighting 100.0% 1.29 1.29 4.0 
Interior Lighting  Linear Lighting 100.0% 0.46 0.46  1.4 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.1 
Exterior Lighting  Area Lighting 100.0% 1.73 1.73  5.4 
Exterior Lighting Linear Lighting 100.0% 0.03 0.03 0.1 
Refrigeration   Walk‐in Refrigerator/Freezer  3.0%  0.39  0.01  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 19.0% 0.09 0.02 0.1 
Refrigeration   Glass Door Display 58.9% 0.09 0.05  0.2 
Refrigeration  Open Display Case 58.9% 0.54 0.32 1.0 
Refrigeration   Icemaker 58.9% 0.15 0.09  0.3 
Refrigeration  Vending Machine 58.9% 0.14 0.08 0.3 
Food Preparation  Oven 13.8% 0.26 0.04  0.1 
Food Preparation Fryer 21.0% 0.37 0.08 0.2 
Food Preparation  Dishwasher 30.0% 0.51 0.15  0.5 
Food Preparation Hot Food Container 30.0% 0.07 0.02 0.1 
Food Preparation  Steamer 30.0% 0.38 0.11  0.4 
Office Equipment Desktop Computer 100.0% 0.08 0.08 0.3 
Office Equipment  Laptop 100.0% 0.01 0.01  0.0 
Office Equipment Server 100.0% 0.05 0.05 0.2 
Office Equipment  Monitor 100.0% 0.01 0.01  0.0 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.0 
Office Equipment  POS Terminal 58.0% 0.01 0.01  0.0 
Miscellaneous Non‐HVAC Motors 91.3% 0.14 0.12 0.4 
Miscellaneous  Pool Pump 76.0% 0.01 0.01  0.0 
Miscellaneous Pool Heater 27.0% 0.02 0.00 0.0 
Miscellaneous  Clothes Washer 67.0% 0.02 0.01  0.0 
Miscellaneous Clothes Dryer 26.0% 0.07 0.02 0.1 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  2.0 
Total       12.69 39.8 

Page 922 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐31 Applied Energy Group • www.appliedenergygroup.com
Table A-30 Idaho Commercial Warehouse Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 1.59 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 1.68 0.00 0.0 
Cooling RTU 16.0% 1.78 0.28  2.6 
Cooling PTAC 1.1% 2.09 0.02 0.2 
Cooling PTHP 0.3% 1.78 0.01  0.0 
Cooling Evaporative AC 0.0% 0.71 0.00 0.0 
Cooling Air‐Source Heat Pump 1.7% 1.78 0.03  0.3 
Cooling Geothermal Heat Pump 0.0% 1.08 0.00 0.0 
Heating Electric Furnace 2.3% 7.84 0.18  1.6 
Heating Electric Room Heat 12.4% 7.46 0.93 8.3 
Heating PTHP 0.3% 6.19 0.02  0.2 
Heating Air‐Source Heat Pump 1.7% 6.88 0.12 1.0 
Heating Geothermal Heat Pump 0.0% 5.93 0.00  0.0 
Ventilation Ventilation 100.0% 0.26 0.26 2.3 
Water Heating  Water Heater 55.3% 0.26 0.15  1.3 
Interior Lighting General Service Lighting 100.0% 0.07 0.07 0.7 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.3 
Interior Lighting High‐Bay Lighting 100.0% 1.69 1.69 15.2 
Interior Lighting  Linear Lighting 100.0% 0.28 0.28  2.5 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.2 
Exterior Lighting  Area Lighting 100.0% 0.38 0.38  3.4 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.7 
Refrigeration   Walk‐in Refrigerator/Freezer  1.1%  0.49  0.01  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 2.0% 0.11 0.00 0.0 
Refrigeration   Glass Door Display 10.1% 0.11 0.01  0.1 
Refrigeration  Open Display Case 10.1% 0.67 0.07 0.6 
Refrigeration   Icemaker 10.1% 0.19 0.02  0.2 
Refrigeration  Vending Machine 10.1% 0.09 0.01 0.1 
Food Preparation  Oven 2.3% 0.03 0.00  0.0 
Food Preparation Fryer 2.3% 0.05 0.00 0.0 
Food Preparation  Dishwasher 2.3% 0.07 0.00  0.0 
Food Preparation Hot Food Container 2.3% 0.01 0.00 0.0 
Food Preparation  Steamer 2.3% 0.05 0.00  0.0 
Office Equipment Desktop Computer 100.0% 0.09 0.09 0.8 
Office Equipment  Laptop 100.0% 0.01 0.01  0.1 
Office Equipment Server 89.0% 0.10 0.09 0.8 
Office Equipment  Monitor 100.0% 0.02 0.02  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.1 
Office Equipment  POS Terminal 77.0% 0.03 0.02  0.2 
Miscellaneous Non‐HVAC Motors 49.9% 0.12 0.06 0.6 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.43  0.43  3.9 
Total       5.40 48.5 

Page 923 Avista Corp. 2020 Electric IRP Appendices
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐32 Applied Energy Group • www.appliedenergygroup.com
Table A-31 Idaho Commercial Miscellaneous Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 9.7% 1.64 0.16  2.2 
Cooling Water‐Cooled Chiller 5.0% 1.78 0.09 1.3 
Cooling RTU 56.8% 1.86 1.06  14.9 
Cooling PTAC 5.1% 2.19 0.11 1.6 
Cooling PTHP 2.6% 1.86 0.05  0.7 
Cooling Evaporative AC 0.0% 0.74 0.00 0.0 
Cooling Air‐Source Heat Pump 5.5% 1.86 0.10  1.4 
Cooling Geothermal Heat Pump 1.0% 1.13 0.01 0.2 
Heating Electric Furnace 12.5% 4.77 0.59  8.4 
Heating Electric Room Heat 14.8% 4.55 0.67 9.5 
Heating PTHP 2.6% 3.61 0.09  1.3 
Heating Air‐Source Heat Pump 5.5% 4.01 0.22 3.1 
Heating Geothermal Heat Pump 1.0% 3.13 0.03  0.5 
Ventilation Ventilation 100.0% 0.73 0.73 10.3 
Water Heating  Water Heater 53.0% 1.39 0.74  10.4 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 5.3 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  3.2 
Interior Lighting High‐Bay Lighting 100.0% 1.56 1.56 22.0 
Interior Lighting  Linear Lighting 100.0% 1.46 1.46  20.7 
Exterior Lighting General Service Lighting 100.0% 0.09 0.09 1.3 
Exterior Lighting  Area Lighting 100.0% 0.64 0.64  9.0 
Exterior Lighting Linear Lighting 100.0% 0.06 0.06 0.8 
Refrigeration   Walk‐in Refrigerator/Freezer  10.3%  0.58  0.06  0.8 
Refrigeration  Reach‐in Refrigerator/Freezer 12.1% 0.13 0.02 0.2 
Refrigeration   Glass Door Display 3.4% 0.13 0.00  0.1 
Refrigeration  Open Display Case 3.4% 0.79 0.03 0.4 
Refrigeration   Icemaker 21.6% 0.22 0.05  0.7 
Refrigeration  Vending Machine 21.6% 0.20 0.04 0.6 
Food Preparation  Oven 58.9% 0.08 0.05  0.7 
Food Preparation Fryer 29.9% 0.12 0.04 0.5 
Food Preparation  Dishwasher 15.4% 0.17 0.03  0.4 
Food Preparation Hot Food Container 15.4% 0.02 0.00 0.0 
Food Preparation  Steamer 15.4% 0.12 0.02  0.3 
Office Equipment Desktop Computer 100.0% 0.20 0.20 2.8 
Office Equipment  Laptop 100.0% 0.03 0.03  0.4 
Office Equipment Server 66.0% 0.12 0.08 1.1 
Office Equipment  Monitor 100.0% 0.03 0.03  0.5 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.3 
Office Equipment  POS Terminal 28.0% 0.03 0.01  0.1 
Miscellaneous Non‐HVAC Motors 59.9% 0.15 0.09 1.2 
Miscellaneous  Pool Pump 4.0% 0.01 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 10.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.57  0.57  8.0 
Total       10.43 147.4 

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Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐33 Applied Energy Group • www.appliedenergygroup.com
Table A-32 Idaho Industrial Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  14,936.14 373.40  2.0 
Cooling Water‐Cooled Chiller 2.5% 15,732.18 393.30 2.1 
Cooling RTU 11.4%  16,648.18 1,898.60  10.3 
Cooling Air‐Source Heat Pump 1.7% 16,640.58 281.39 1.5 
Cooling Geothermal Heat Pump 0.0%  11,099.27 0.00  0.0 
Heating Electric Furnace 2.3% 73,387.09 1,683.53 9.2 
Heating Electric Room Heat 12.4%  69,892.47 8,672.59  47.2 
Heating Air‐Source Heat Pump 1.7% 64,443.40 1,089.73 5.9 
Heating Geothermal Heat Pump 0.0%  42,983.75 0.00  0.0 
Ventilation Ventilation 100.0% 2,427.96 2,427.96 13.2 
Interior Lighting  General Service Lighting  100.0%  465.63  465.63  2.5 
Interior Lighting High‐Bay Lighting 100.0% 7,284.44 7,284.44 39.6 
Interior Lighting  Linear Lighting 100.0%  1,210.90 1,210.90  6.6 
Exterior Lighting General Service Lighting 100.0% 85.72 85.72 0.5 
Exterior Lighting  Area Lighting 100.0%  1,624.05 1,624.05  8.8 
Exterior Lighting Linear Lighting 100.0% 332.72 332.72 1.8 
Motors Pumps 100.0%  4,278.85 4,278.85  23.3 
Motors Fans & Blowers 100.0% 5,138.64 5,138.64 28.0 
Motors Compressed Air 100.0%  4,155.05 4,155.05  22.6 
Motors Material Handling 100.0% 8,788.33 8,788.33 47.8 
Motors Other Motors 100.0%  147.48 147.48  0.8 
Process Process Heating 100.0% 7,235.19 7,235.19 39.4 
Process Process Cooling 100.0%  1,899.62 1,899.62  10.3 
Process Process Refrigeration 100.0% 1,899.62 1,899.62 10.3 
Process Process Electrochemical 100.0%  731.25 731.25  4.0 
Process Process Other 100.0% 793.59 793.59 4.3 
Miscellaneous  Miscellaneous 100.0%  4,365.54 4,365.54  23.8 
Total       67,257.13 366.1 
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| B‐1 
Applied Energy Group • www.appliedenergygroup.com

MARKET ADOPTION (RAMP) RATES
This appendix presents the Power Council’s 7th Plan ramp rates we applied to technical potential to estimate Technical Achievable Potential.
Table B-1 Measure Ramp Rates Used in CPA
Key 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 
LO12Med  9%  19%  28%  37%  47%  55%  62%  67%  71%  75%  78%  80%  82%  83% 84%  85%  85%  85%  85%  85% 
LO5Med 4% 8% 13% 20% 27% 35% 45% 54% 63% 71% 76% 81% 83% 84% 85% 85% 85% 85% 85% 85% 
LO1Slow  0%  1%  1%  3%  5%  7%  11%  16%  22%  29%  37%  46%  54%  62%  69%  75%  79%  82%  84%  85% 
LO50Fast 38% 56% 68% 76% 81% 83% 84% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 
LO20Fast  19%  32%  42%  49%  55%  61%  65%  69%  72%  75%  78%  79%  81%  82%  83%  84%  84%  84%  85%  85% 
LOEven20 4% 9% 13% 17% 21% 26% 30% 34% 38% 43% 47% 51% 55% 60% 64% 68% 72% 77% 81% 85% 
LOMax60  1%  3%  5%  8%  12%  16%  20%  24%  28%  31%  34%  37%  40%  42%  45%  47%  49%  51%  53%  55% 
LO3Slow 0% 1% 3% 5% 9% 15% 22% 31% 40% 49% 57% 65% 71% 75% 79% 81% 83% 84% 85% 85% 
Retro12Med  11%  11%  11%  11%  11%  10%  8%  6%  5%  4%  3%  3%  2%  2%  1%  1%  0%  0%  0%  0% 
Retro5Med 4% 5% 6% 7% 8% 10% 11% 11% 10% 9% 7% 5% 3% 1% 1% 0% 0% 0% 0% 0% 
Retro1Slow  0%  1%  1%  1%  2%  3%  4%  6%  7%  8%  9%  10%  10%  9%  8%  7%  5%  3%  2%  1% 
Retro50Fast 45% 21% 14% 9% 6% 3% 1% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 
Retro20Fast  22%  16%  11%  8%  7%  6%  5%  5%  4%  3%  3%  2%  2%  1%  1%  1% 1%  0%  0%  0% 
RetroEven20 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 
RetroMax60  1%  2%  3%  4%  5%  5%  5%  4%  4%  4%  4%  3%  3%  3%  3%  3%  3%  2%  2%  2% 
Retro3Slow 1% 1% 2% 3% 5% 7% 8% 10% 11% 11% 10% 9% 7% 6% 4% 3% 2% 1% 1% 0% 

* Assumption of 55% maximum achievability from Council’s 7th Power Plan

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  | C‐1 Applied Energy Group • www.appliedenergygroup.com

MEASURE DATA
Measure level assumptions and data are available in the “Avista 2019 DSM Potential Study Measure
Assumptions” workbook provided to Avista alongside this file.
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  | D‐1 Applied Energy Group • www.appliedenergygroup.com

HB 1444 IMPACT ANALYSIS
In April 2019, the Washington State Legislature passed HB 1444, which established new energy efficiency
requirements for some consumer technologies sold in Washington, particularly water-using equipment,
commercial kitchen equipment, and desktop computing equipment. These devices have associated
savings potential within the CPA which would be affected by this legislation, in that the savings would
become part of the baseline, or “naturally occurring” efficiency.
AEG did not reconfigure and rerun the CPA to include the impacts of this legislation, as the standards
were not yet in place at the time the study was designed and developed, however, an estimate of the likely
impacts is provided in Table D-1 below. AEG estimates that 5% - 7% of Avista’s Washington Technical
Achievable Potential for the biennium period could be moved into the baseline by HB 1444.
Table D-1 Impacts of HB 1444 on EE Potential13
Technical Achievable Potential MWh ‐ CPA Total 2022 2030 2040 
Idaho 50,201  328,073  673,115 
Washington 99,977 636,490 1,271,968 
Total 150,178  964,564  1,945,083 

HB 1444 Affected Measures ‐ TAP MWh 2022 2030 2040 
Residential         
Monitor 1,537 7,994 8,552 
Personal Computers 634  2,846  2,913 
Water Heater ‐ Faucet Aerators 19 693 821 
Water Heater ‐ Low‐Flow Showerheads 2,834  10,144  7,814 
Commercial       
Desktop Computer 418  2,285  2,600 
Dishwasher 24 756 2,461 
ENERGY STAR Water Cooler 80  433  879 
Fryer 40 1,256 2,937 
Hot Food Container 18  537  2,005 
Monitor 67 300 319 
Steamer 44  2,010  8,070 
Water Heater ‐ Faucet Aerators/Low Flow Nozzles 442 990 1,044 
Water Heater ‐ Low‐Flow Showerheads 242  536  562 
Total 6,400  30,779  40,977 
% of WA 6.4%  4.8%  3.2% 
% of Total 4.3%  3.2%  2.1% 

13 Note: HB 1444 also requires direct load control switches to be present on storage water heaters, which would affect the cost of the
Residential Water Heating DLC program described in Chapter 6, but AEG did not assume a change in participation or potential as a result
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Avista Conservation Potential Assessment for 2021-2040 

Applied Energy Group, Inc. 500 Ygnacio Valley Rd, Suite 250 Walnut Creek, CA 94596 P: 510.982.3525
Page 932 Avista Corp. 2020 Electric IRP Appendices

2020 Electric Integrated
Resource Plan

Appendix E – Conservation
Potential Assessment Measure
Assumptions

Please see attached spreadsheet

Page 933 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated
Resource Plan
Appendix F – Resource
Adequacy in the Pacific
Northwest by E3
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Resource Adequacy in the
Pacific Northwest

March 2019
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© 2019 Energy and Environmental Economics, Inc.

© 2019 Copyright. All Rights Reserved.
Energy and Environmental Economics, Inc.
44 Montgomery Street, Suite 1500
San Francisco, CA 94104
415.391.5100
www.ethree.com

Project Team:
Zach Ming
Arne Olson
Huai Jiang
Manohar Mogadali
Nick Schlag

Resource Adequacy in the
Pacific Northwest

March 2019
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© 2019 Energy and Environmental Economics, Inc.

Table of Contents
Executive Summary ................................................................................................... i
Background and Approach .......................................................................................... ii
Key Findings ................................................................................................................... ii
1 Introduction ......................................................................................................... 1
1.1 Study Background & Context ........................................................................... 1
1.2 Prior Studies ........................................................................................................ 2
1.3 Purpose of Study ................................................................................................ 2
1.4 Report Contents .................................................................................................. 3
2 Resource Adequacy in the Northwest ............................................................ 4
2.1 What is Resource Adequacy? .......................................................................... 4
2.2 Planning Practices in the Northwest ............................................................... 6
3 Modeling Approach ........................................................................................... 9
3.1 Renewable Energy Capacity Planning (RECAP) Model ............................. 9
3.2 Study Region ..................................................................................................... 14
3.3 Scenarios & Sensitivities ................................................................................. 16
3.4 Key Portfolio Metrics ........................................................................................ 18
3.5 Study Caveats ................................................................................................... 20
4 Key Inputs & Assumptions .............................................................................. 22
4.1 Load Forecast ................................................................................................... 22
4.2 Existing Resources........................................................................................... 24
4.3 Candidate Resources ...................................................................................... 31
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4.4 Estimating Cost and GHG Metrics ................................................................ 35
5 Results ................................................................................................................ 36
5.1 Short-Term Outlook (2018) ............................................................................. 36
5.2 Medium-Term Outlook (2030) ........................................................................ 38
5.3 Long-Term Outlook (2050) ............................................................................. 41
6 Discussion & Implications ............................................................................... 67
6.1 Land Use Implications of High Renewable Scenarios .............................. 67
6.2 Reliability Standards ........................................................................................ 68
6.3 Benefits of Reserve Sharing ........................................................................... 71
7 Conclusions ....................................................................................................... 74
7.1 Key Findings ...................................................................................................... 75
Appendix A. Assumption Development Documentation ........................ A-1
Appendix B. RECAP Model Documentation ............................................. B-1
Appendix C. Renewable Profile Development .......................................... C-8

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© 2019 Energy and Environmental Economics, Inc.

Study Sponsors
This study was sponsored by Puget Sound Energy, Avista, NorthWestern Energy, and the Public Generating
Pool (PGP). PGP is a trade association representing 10 consumer-owned utilities in Oregon and Washington:
Chelan County PUD, Clark Public Utilities, Cowlitz County PUD, Eugene Water and Electric Board, Klickitat
PUD, Grant County PUD, Lewis County PUD, Tacoma Power, Snohomish County PUD, and Benton PUD.
Acknowledgements
E3 thanks the staff of the Northwest Power and Conservation Council (NWPCC) for providing data and
technical review.
Conventions
The following conventions are used throughout this report:
 All costs are reported in 2016 dollars.
 All levelized costs are assumed to be levelized in real terms (i.e., a stream of payments over the
lifetime of the contract that is constant in real dollars).

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Acronyms
CONE Cost of New Entry
DR Demand Response
EE Energy Efficiency
ELCC Effective Load Carrying Capability
EUE Expected Unserved Energy
FOR Forced Outage Rate
GENESYS NWPCC’s Generation Evaluation System Model
GHG Greenhouse Gas
ISO Independent System Operator
LOLE Loss-of-Load Expectation
LOLF Loss-of-Load Frequency
LOLP Loss-of-Load Probability
MISO Midwest Independent System Operator
MMT Million Metric Ton
MTTR Mean Time to Repair
NERC North American Electric Reliability Corporation
NREL National Renewable Energy Laboratory
NWPCC Northwest Power and Conservation Council
NWPP Northwest Power Pool
PNUCC Pacific Northwest Utilities Conference Committee
PRM Planning Reserve Margin
RA Resource Adequacy
RECAP E3’s Renewable Energy Capacity Planning Model
RPS Renewables Portfolio Standard
RTO Regional Transmission Operator
SPP Southwest Power Pool
WECC Western Electricity Coordinating Council
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© 2018 Energy and Environmental Economics, Inc.
Executive Summary
Executive Summary
The Pacific Northwest is expected to undergo significant changes to its electricity generation resource mix
over the next 30 years due to changing economics of resources and more stringent environmental policy
goals. In particular, the costs of wind, solar, and battery storage have experienced significant declines in
recent years, a trend that is expected to continue. Greenhouse gas and other environmental policy goals
combined with changing economics have put pressure on existing coal resources, and many coal power
plants have announced plans to retire within the next decade.
As utilities become more reliant on intermittent renewable energy resources (wind and solar) and energy-
limited resources (hydro and battery storage) and less reliant on dispatchable firm resources (coal),
questions arise about how the region will serve future load reliably. In particular, policymakers across the
region are considering many different policies – such as carbon taxes, carbon caps, renewable portfolio
standards, limitations on new fossil fuel infrastructure, and others – to reduce greenhouse gas emissions
in the electricity sector and across the broader economy. The environmental, cost, and reliability
implications of these various policy proposals will inform electricity sector planning and policymaking in
the Pacific Northwest.
This study finds that deep decarbonization of the Northwest grid is feasible without sacrificing reliable
electric load service. But this study also finds that, absent technological breakthroughs, achieving 100%
GHG reductions using only wind, solar, hydro, and energy storage is both impractical and prohibitively
expensive. Firm capacity – capacity that can be relied upon to produce energy when it is needed the most,
even during the most adverse weather conditions – is an important component of a deeply-decarbonized
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Resource Adequacy in the Pacific Northwest
grid. Increased regional coordination is also a key to ensuring reliable electric service at reasonable cost
under deep decarbonization.
Background and Approach
This study builds on the previous Northwest Low-Carbon Scenario Analysis conducted by E3 for PGP in
2017-2018 by focusing on long-run reliability and Resource Adequacy. This study uses E3’s Renewable
Energy Capacity Planning (RECAP) model, a loss-of-load-probability model designed specifically to test the
Resource Adequacy of high-renewable electricity systems under a wide variety of weather conditions,
renewable generation, and forced outages of electric generating resources. Specifically, this study
examines four key questions:
 How to maintain Resource Adequacy in the 2020-2030 timeframe under growing loads and
increasing coal retirements?
 How to maintain Resource Adequacy in the 2050 timeframe under different levels of carbon
abatement goals, including zero carbon?
 How much effective capacity can be provided by wind, solar, electric energy storage, and demand
response?
 How much firm capacity is needed to maintain reliable electric service at various levels of carbon
reductions?
Key Findings
1. It is possible to maintain Resource Adequacy for a deeply decarbonized Northwest electricity grid,
as long as sufficient firm capacity is available during periods of low wind, solar, and hydro
production;
o Natural gas generation is the most economic source of firm capacity today;
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© 2018 Energy and Environmental Economics, Inc.
Executive Summary
o Adding new gas generation capacity is not inconsistent with deep reductions in carbon
emissions because the significant quantities of zero-marginal-cost renewables will ensure
that gas is only used during reliability events;
o Wind, solar, demand response, and short-duration energy storage can contribute but
have important limitations in their ability to meet Northwest Resource Adequacy needs;
o Other potential low-carbon firm capacity solutions include (1) new nuclear generation,
(2) fossil generation with carbon capture and sequestration, (3) ultra-long duration
electricity storage, and (4) replacing conventional natural gas with carbon-neutral gas
such as hydrogen or biogas.
2. It would be extremely costly and impractical to replace all carbon-emitting firm generation
capacity with solar, wind, and storage, due to the very large quantities of these resources that
would be required;
o Firm capacity is needed to meet the new paradigm of reliability planning under deep
decarbonization, in which the electricity system must be designed to withstand prolonged
periods of low renewable production once storage has depleted; renewable overbuild is
the most economic solution to completely replace carbon-emitting resources but requires
a 2x buildout that results in curtailment of almost half of all wind and solar production.
3. The Northwest is expected to need new capacity in the near term in order to maintain an
acceptable level of Resource Adequacy after planned coal retirements.
4. Current planning practices risk underinvestment in the new capacity needed to ensure Resource
Adequacy at acceptable levels;
o Reliance on market purchases or front-office transactions (FOTs) reduces the cost of
meeting Resource Adequacy needs on a regional basis by taking advantage of load and
resource diversity among utilities in the region;
o Capacity resources are not firm without a firm fuel supply; investment in fuel delivery
infrastructure may be required to ensure Resource Adequacy even under a deep
decarbonization trajectory;
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Resource Adequacy in the Pacific Northwest
o Because the region lacks a formal mechanism for ensuring adequate physical firm
capacity, there is a risk that reliance on market transactions may result in double-counting
of available surplus generation capacity;
o The region might benefit from and should investigate a formal mechanism to share
planning reserves on a regional basis, which may help ensure sufficient physical firm
capacity and reduce the quantity of capacity required to maintain Resource Adequacy.

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Introduction
© 2018 Energy and Environmental Economics, Inc.
1 Introduction
1.1 Study Background & Context
The Pacific Northwest is expected to undergo significant changes to its electricity generation resource mix
over the next 30 years due to changing economics of resources and more stringent environmental policy
goals. In particular, the costs of wind, solar, and battery storage have experienced significant declines in
recent years, a trend that is expected to continue. Greenhouse gas and other environmental policy goals
combined with changing economics have put pressure on existing coal resources, and many coal power
plants have announced plans to retire within the next decade.
As utilities become more reliant on intermittent renewable energy resources (wind and solar) and energy-
limited resources (hydro and battery storage) and less reliant on dispatchable firm resources (coal),
questions arise about how the region will serve future load reliably. In particular, policymakers across the
region are considering many different policies – such as carbon taxes, carbon caps, renewable portfolio
standards, limitations on new fossil fuel infrastructure, and others – to reduce greenhouse gas emissions
in the electricity sector and across the broader economy. The environmental, cost, and reliability
implications of these various policy proposals will inform electricity sector planning and policymaking in
the Pacific Northwest.
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Resource Adequacy in the Pacific Northwest
1.2 Prior Studies
In 2017-2018, E3 completed a series of studies1 for PGP and Climate Solutions to evaluate the costs of
alternative electricity decarbonization strategies in Washington and Oregon. These studies were
conducted using E3’s RESOLVE model, which is a dispatch and investment model that identifies optimal
long-term generation and transmission investments in the electric system to meet various
decarbonization and renewable energy targets. The studies found that the least-cost pathway to reduce
greenhouse gases from electricity generation is to replace coal generation with a mix of energy efficiency,
renewables, and natural gas generation. While these studies examined in great detail the economics of
new resources needed to achieve decarbonization, including the type, quantity, and location of these
resources, they did not look in-depth at reliability and Resource Adequacy.
1.3 Purpose of Study
This study builds on the previous Northwest Low-Carbon Scenario Analysis conducted by E3 for PGP in
2017-2018 by focusing on long-run reliability and Resource Adequacy. This study uses E3’s Renewable
Energy Capacity Planning (RECAP) model, a loss-of-load-probability model designed specifically to test the
Resource Adequacy of high-renewable electricity systems under a wide variety of weather conditions,
renewable generation, and forced outages of electric generating resources. Specifically, this study
examines four key questions:
 How to maintain Resource Adequacy in the 2020-2030 timeframe under growing loads and
increasing coal retirements?
 How to maintain Resource Adequacy in the 2050 timeframe under different levels of carbon
abatement goals, including zero carbon?

1 https://www.ethree.com/projects/study-policies-decarbonize-electric-sector-northwest-public-generating-pool-2017-present/
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Introduction
© 2018 Energy and Environmental Economics, Inc.
 How much effective capacity can be provided by wind, solar, electric energy storage, and demand
response?
 How much firm capacity is needed to maintain reliable electric service at various levels of carbon
reductions?
1.4 Report Contents
The remainder of this report is organized as follows:
 Section 2 introduces Resource Adequacy and current practices in the Northwest
 Section 3 describes the study’s modeling approach
 Section 4 highlights key inputs and assumptions used in the modeling
 Section 5 presents results across a variety of time horizons and resource portfolios
 Section 6 discusses implications of the results
 Section 7 summarizes the study’s conclusions and lessons learned

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Resource Adequacy in the Pacific Northwest
2 Resource Adequacy in the Northwest
2.1 What is Resource Adequacy?
Resource adequacy is the ability of an electric power system to serve load across a broad range of weather
and system operating conditions, subject to a long-run standard on the maximum frequency of reliability
events where generation is insufficient to serve all load. The resource adequacy of a system thus depends
on the characteristics of its load—seasonal patterns, weather sensitivity, hourly patterns—as well as its
resources—size, dispatchability, outage rates, and other limitations on availability. Ensuring resource
adequacy is an important goal for utilities seeking to provide reliable service to their customers.
While utility portfolios are typically designed to meet specified resource adequacy targets, there is no
single mandatory or voluntary national standard for resource adequacy. Across North America, resource
adequacy standards are established by utilities, regulatory commissions, and regional transmission
operators, and each uses its own conventions to do so. The North American Electric Reliability Council
(NERC) and the Western Electric Coordinating Council (WECC) publish information about resource
adequacy but have no formal governing role.
While a variety of approaches are used, the industry best practice is to establish a standard for resource
adequacy using a two-step process:
 Loss-of-load-probability (LOLP) modeling: LOLP modeling uses statistical techniques and/or
Monte Carlo approaches to simulate the capability of a generation portfolio to produce sufficient
generation to meet loads across a wide range of different conditions. Utilities plan the system to
meet a specific reliability standard that is measured through LOLP modeling such as the expected
frequency and/or size of reliability events; a relatively common standard used in LOLP modeling
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Resource Adequacy in the Northwest
© 2018 Energy and Environmental Economics, Inc.
is “one day in ten years,” which is often translated to an expectation of 24 hours of lost load every
ten years, or 2.4 hours per year.2
 Planning reserve margin (PRM) requirements: Utilities then determine the required PRM
necessary to ensure that the system will meet the specific the reliability standard from the LOLP
modeling. A PRM establishes a total requirement for capacity based on the peak demand of an
electric system plus some reserve margin to account for unexpected outages and extreme
conditions; reserve margin requirements typically vary among utilities between 12-19% above
peak demand. To meet this need, capacity from resources that can produce their full power on
demand (e.g., nuclear, gas, coal) are typically counted at or near 100%, whereas resources that
are constrained in their availability or ability to dispatch (e.g., hydro, storage, wind, solar) are
typically de-rated below full capacity.
While LOLP modeling is more technically rigorous, most utilities perform LOLP modeling relatively
infrequently and use a PRM requirement to heuristically ensure compliance with a specific reliability
standard due to its relative simplicity and ease of implementation. The concept and application of a PRM
to measure resource adequacy has historically worked well in a paradigm in which most generation
capacity is “firm”; that is, the resource will be available to dispatch to full capacity, except in the event of
unexpected forced outages. Under this paradigm, as long as the system has sufficient capacity to meet its
peak demand (plus some reserve margin for extreme weather and unexpected forced outages), it will be
capable of serving load throughout the rest of the year as well.
However, growing penetrations of variable (e.g., wind and solar) and energy-limited (e.g., hydro, electric
energy storage, and demand response) resources require the application of increasingly sophisticated
modeling tools to determine the appropriate PRM and to measure the contribution of each resource
towards resource adequacy. Because wind and solar do not always generate during the system peak and
because storage may run out of charge while it is serving the system peak, these resources are often de-

2 Other common interpretations of the “one day in ten year” standard include 1 “event” (of unspecified duration) in ten years or “one hour in ten
years” i.e., 0.1 hrs/yr
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Resource Adequacy in the Pacific Northwest
rated below the capability of a fully dispatchable thermal generator when counted toward meeting the
PRM.
2.2 Planning Practices in the Northwest
A number of entities within the Northwest conduct analysis and planning for resource adequacy within
the region. Under its charter to ensure prudent management of the region’s federal hydro system while
balancing environmental and energy needs, the Northwest Power and Conservation Council (NWPCC)
conducts regular assessments of the resource adequacy position for the portion of the Northwest region
served by the Bonneville Power Administration. The NWPCC has established an informal reliability target
for the region of 5% annual loss of load probability3—a metric that ensures that the region will experience
reliability events in fewer than one in twenty years—and uses GENESYS, a stochastic LOLP model with a
robust treatment of the resource’s variable hydroelectric conditions and capabilities, to examine whether
regional resources are sufficient to meet this target on a five-year ahead basis.4 These studies provide
valuable information referenced by regulators and utilities throughout the region.
While the work of the Council is widely regarded as the most complete regional assessment of resource
adequacy for the smaller region, the Council itself holds no formal decision-making authority to prescribe
new capacity procurement or to enforce its reliability standards. Instead, the ultimate administration of
resource adequacy lies in the hands of individual utilities, often subject to the oversight of state
commissions. Most resource adequacy planning occurs within the planning and procurement processes

3 This Council’s standard, which focuses only on whether a reliability event occurred within a year, is unique to the Northwest and is not widely used
throughout the rest of the North America
4 The most recent of these reports, the Pacific Northwest Power Supply Adequacy Assessment for 2023, is available at:
https://www.nwcouncil.org/sites/default/files/2018-7.pdf (accessed January 18, 2019).
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of utilities: individual utilities submit integrated resource plans (IRPs) that consider long-term resource
adequacy needs and conduct resource solicitations to satisfy those needs.
Utilities rely on a combination of self-owned generation, bilateral contracts, and front-office transactions
(FOTs) to satisfy their resource adequacy requirements. FOTs represent short-term firm market purchases
for physical power delivery. FOTs are contracted on both a month-ahead, day-ahead and hour-ahead
basis. A survey of the utility IRPs in the Northwest reveals that most of the utilities expect to meet a
significant portion of their peak capacity requirements in using FOTs.
FOTs may be available to utilities for several potential reasons including 1) the region as a whole has a
capacity surplus and some generators are uncontracted to a specific utility or 2) natural load diversity
between utilities such that one utility may have excess generation during another’s peak load conditions
and vice versa. The use of FOTs in place of designated firm resources can result in lower costs of providing
electric service, as the cost of contracting with existing resources is generally lower than the cost of
constructing new resources.
However, as loads grow in the region and coal generation retires, the region’s capacity surplus is shrinking,
and questions are emerging about whether sufficient resources will be available for utilities to contract
with for month-ahead and day-ahead capacity products. In a market with tight load-resource balance,
extensive reliance on FOTs risks under-investment in the firm capacity resources needed for reliable load
service.

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Table 1: Contribution of FOTs Toward Peak Capacity Requirements in 2018 in the Northwest
Utility Capacity
Requirement (MW)
Front Office
Transactions (MW)
% of Capacity
Requirement from FOTs
Puget Sound5 6,100

1,800 30%
Avista6 2,150

- 0%
Idaho Power7 3,078

313 10%
PacifiCorp8 11,645

462 4%
BPA9 11,506

- 0%
PGE10 4,209

106 3%
NorthWestern11 1,205

503 42%

5 Figure 6-7: Available Mid C Tx plus Additional Mid-C Tx w/ renewals in PSE 2017 IRP: https://www.pse.com/-/media/PDFs/001-Energy-Supply/001-
Resource-Planning/8a_2017_PSE_IRP_Chapter_book_compressed_110717.pdf?la=en&revision=bb9e004c-9da0-4f75-a594-
6c30dd6223f4&hash=75800198E4E8517954C63B3D01E498F2C5AC10C2
6 Figure 6.1 (for peak load), Chapter 4 Tables for resources in Avista 2017 IRP: https://www.myavista.com/-/media/myavista/content-
documents/about-us/our-company/irp-documents/2017-electric-irp-final.pdf?la=en
7 Table 9.11 in Idaho Power 2017 IRP: https://docs.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/IRP.pdf
8 Table 5.2 in PacifiCorp 2017 IRP (Interruptible Contracts + Purchases):
https://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2017_IRP/2017_IRP_VolumeI_IRP_Final.pdf
9 Bottom of the page in BPA fact sheet: https://www.bpa.gov/news/pubs/GeneralPublications/gi-BPA-Facts.pdf
10 PGE 2016 IRP Table P-1 Spot Market Purchases (rounded from 106), Capacity Need : https://www.portlandgeneral.com/our-company/energy-
strategy/resource-planning/integrated-resource-planning/2016-irp
11 Table 2-2 for peak load and netted out existing resources (Ch. 8) @ 12%PRM from NorthWestern Energy 2015 IRP:
https://www.northwesternenergy.com/our-company/regulatory-environment/2015-electricity-supply-resource-procurement-plan
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3 Modeling Approach
3.1 Renewable Energy Capacity Planning (RECAP) Model
3.1.1 MODEL OVERVIEW
This study assesses the resource adequacy of electric generating resource portfolios for different
decarbonization scenarios in the Northwest region using E3’s Renewable Energy Capacity Planning
(RECAP) model. RECAP is a loss-of-load-probability model developed by E3 that has been used extensively
to test the resource adequacy of electric systems across the North American continent, including
California, Hawaii, Canada, the Pacific Northwest, the Upper Midwest, Texas, and Florida.
RECAP calculates a number of reliability metrics which are used to assess the resource adequacy for an
electricity system with a given set of loads and generating resources.
 Loss of Load Expectation (hrs/yr) – LOLE
o The total number of hours in a year where load + reserves exceeds generation
 Expected Unserved Energy (MWh/yr) – EUE
o The total quantity of unserved energy in a year when load + reserves exceeds generation
 Loss of Load Probability (%/yr) – LOLP
o The probability in a year that load + reserves exceeds generation at any time
 Effective Load Carrying Capability (%) – ELCC
o The additional load met by an incremental generator while maintaining the same level of
system reliability (used for dispatch-limited resources such as wind, solar, storage, hydro,
and demand response). Equivalently, this is the quantity of perfectly dispatchable
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generation that could be removed from the system by an incremental dispatch-limited
generator
 Planning Reserve Margin (%) – PRM
o The resource margin above a 1-in-2 peak load, in %, that is required in order to meet a
specific reliability standard (such as 2.4 hrs./yr. LOLE)
This study uses 2.4 hrs./yr. LOLE reliability standard which is based on a commonly accepted 1-day-in-10-
year standard. All portfolios that are developed by RECAP in this analysis for resource adequacy are
designed to meet a 2.4 hrs./yr. LOLE standard.
RECAP calculates reliability statistics by simulating the electric system with a specific set of generating
resources and loads under a wide variety of weather years, renewable generation years, and stochastic
forced outages of electric generation resources and imports on transmission. By simulating the system
thousands of times with different combinations of these factors, RECAP provides robust, stochastic
estimation of LOLE and other reliability statistics.
RECAP was specifically designed to calculate the reliability of electric systems operating under high
penetrations of renewable energy and storage. Correlations enforced within the model capture linkage
among load, weather, and renewable generation conditions. Time-sequential simulation tracks the state
of charge and energy availability for dispatch-limited resources such as hydro, energy storage, and
demand response.
3.1.2 MODEL METHODOLOGY
The steps of the RECAP modeling process are shown below in Figure 1. RECAP calculates long-run resource
availability through Monte Carlo simulation of electricity system resource availability using weather
conditions from 1948-2017. Each simulation begins on January 1, 1948 and runs hourly through December
31, 2017. Hourly electric loads for 1948-2017 are synthesized using statistical analysis of actual load
shapes and weather conditions for 2014-2017 combined with recorded historical weather conditions.
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Then, hourly wind and solar generation profiles are drawn from simulations created by the National
Renewable Energy Laboratory (NREL) and paired with historical weather days through an E3-created day-
matching algorithm. Next, nameplate capacity and forced outage rates (FOR) for thermal generation are
drawn from various sources including the GENESYS database and the Western Electric Coordinating
Council’s Anchor Data Set. Hydro is dispatched based on the load net of renewable and thermal
generation. Annual hydro generation values are drawn randomly from 1929-2008 water years and shaped
to calendar months and weeks based on the Northwest Power and Conservation Council’s GENESYS
model. For each hydro year, we identify all the hydro dispatch constraints including maximum and
minimum power capacity, 2-hour to 10-hour sustained peaking limits, and hydro budget, specific to the
randomly-drawn hydro condition. For each x-hour sustained peaking limit (where x = 2, 4, and 10), RECAP
dispatches hydro so that the average capacity over consecutive x hours does not exceed the sustained
peaking capability. Overall, hydro is dispatched to minimize the post-hydro net load subject to the above
constraints. In other words, hydro is used within assumed constraints to meet peak load needs while
minimizing loss-of-load. Finally, RECAP uses storage and demand response to tackle the loss-of-load hours
and storage is only discharged during loss-of-load hours. A more detailed description of the RECAP model
is in Appendix B.2.
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Figure 1: Overview of RECAP Model

3.1.3 PORTFOLIO DEVELOPMENT
RECAP is used in this study to both test the reliability of the existing 2018 Greater Northwest electricity
system as well as to determine a total capacity need in 2030 and to develop portfolios in 2050 under
various levels of decarbonization that meet a 1-day-in-10-year reliability standard of 2.4 hrs./yr.
To develop each 2050 decarbonization portfolio, RECAP calculates the reliability of the system in 2050
after forecasted load growth and the removal of all fossil generation but the maintenance of all existing
carbon-free resources. Unsurprisingly, these portfolios are significantly less reliable than the required 2.4
hrs./yr. nor do they deliver enough carbon-free generation to meet the various decarbonization targets.
To improve the reliability and increase GHG-free generation of these portfolios, RECAP tests the
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contribution of small, equal-cost increments of candidate GHG-free resources. The seven candidate
resources in this study are:
 Northwest Wind (WA/OR)
 Montana Wind
 Wyoming Wind
 Solar (based on an assumed diverse mix of resources from each state)
 4-Hour Storage
 8-Hour Storage
 16-Hour Storage
The resource that improves reliability the most (as measured in loss-of-load-expectation) is then added
to the system. This process is repeated until the delivered GHG-free generation is sufficient to meet the
GHG target (e.g., 80% reduction) for each particular scenario. Once a portfolio has achieved the objective
GHG target, RECAP calculates the residual quantity of perfect firm capacity that is needed to bring the
portfolio in compliance with a reliability standard of 2.4 hrs./yr. This perfect firm MW capacity is converted
to MW of natural gas capacity by grossing up by 5% to account for forced outages. Natural gas capacity is
used because it is the most economic source of firm capacity. To the extent that other carbon-free
resources can substitute for natural gas capacity, this is reflected in deeper decarbonization portfolios
that have higher quantities of wind, solar, and storage along with a smaller residual requirement for firm
natural gas capacity.
Figure 2 illustrates a simple example of this portfolio development process where RECAP has 3 candidate
resources: wind, solar, and storage. The model evaluates the contribution to reliability of equal-cost
increments of the three candidate resources and selects the resource that improves reliability the most.
From that new portfolio, the process is repeated until either the system reaches a reliability standard of
2.4 or a particular GHG target is achieved.
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Figure 2: RECAP Portfolio Development Process

3.2 Study Region
The geographic region for this study consists of the U.S. portion of the Northwest Power Pool (NWPP),
excluding Nevada, which this study refers to as the “Greater Northwest”. This region includes the states
of Washington, Oregon, Idaho, Utah, and parts of Montana and Wyoming.
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Figure 3: The study region - The Greater Northwest

It is important to note that this is a larger region than was analyzed in the prior E3 decarbonization work
in the Northwest which only analyzed a “Core Northwest” region consisting of Oregon, Washington,
northern Idaho and Western Montana. The larger footprint encompasses the utilities that have
traditionally coordinated operational efficiencies through programs under the Northwest Power Pool and
includes utilities that typically transact with each other to maintain resource adequacy and optimize
resource portfolios. The larger region also incorporates a footprint that allows for diversity of both load
and resources which minimizes the need for firm capacity. The Balancing Authority Areas (BAAs) that were
included in this Greater Northwest study region are listed in Table 2.
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Table 2: List of Balancing Authorities Included in Study
Balancing Authority Areas Included in Greater Northwest Study Region
Avista Bonneville Power
Administration
Chelan County PUD
Douglas County PUD Grant County PUD Idaho Power
NorthWestern PacifiCorp East PacifiCorp West
Portland General
Electric
Puget Sound Energy Seattle City Light
Tacoma Power Western Area Power
Administration Upper
Great Plains

3.3 Scenarios & Sensitivities
This study examines the resource adequacy requirements of the Greater Northwest region across multiple
timeframes and decarbonization scenarios.
 Near-term (2018) reliability statistics are calculated for today’s system based on 2018 existing
loads and resources. These results are presented to give the reader a sense of existing challenges
and as a reference for other scenario results.
 Medium-term (2030) reliability statistics are calculated in 2030 for two scenarios: a Reference
scenario and a No Coal scenario. The Reference scenario includes the impact of expected load
growth and announced generation retirements, notably the Boardman, Centralia, and Colstrip
coal plants. The No Coal scenario assumes that all coal is retired.
 Long-term (2050) reliability statistics are calculated in 2050 for multiple scenarios including a
Reference scenario and for a range of decarbonization targets. The Reference scenario includes
the impact of load growth, growth in renewable capacity to meet current RPS policy goals, and
the retirement of all coal. Decarbonization scenarios assume GHG emissions are reduced to 60%,
80%, 90%, 98% and 100% below 1990 GHG levels through the addition of wind, solar, and electric
energy storage.
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These scenarios are summarized in Table 3.
Table 3: List of Scenarios and Descriptions
Analysis Period Scenario Description
Near-term (2018) Reference 2018 Existing Loads and Resources
Medium-Term
(2030)
Reference Includes load growth through 2030 and announced
generation retirements, notably the Boardman,
Centralia, and Colstrip coal plants
No Coal Same as 2030 reference but all coal generation in
the region is retired (11 GW)
Long-Term (2050) Reference Includes load growth through 2050, renewable
capacity additions to meet RPS targets, and
retirement of all coal generation (11 GW)
60% GHG Reduction
Scenarios achieve specified greenhouse gas
reduction (relative to 1990 levels) through addition
of solar, wind, and energy storage; sufficient gas
generating capacity is maintained to ensure
reliability (except in 100% GHG Reduction)
80% GHG Reduction
90% GHG Reduction
98% GHG Reduction
100% GHG Reduction
This study further explores the potential resource adequacy needs of a 100% carbon free electricity
system in 2050 recognizing that emerging technologies beyond wind, solar, and electric energy storage
that are not yet available today may come to play a significant role in the region’s energy future. To better
understand how those technologies might impact the viability of achieving this ambitious goal, the study
includes several sensitivity analyses of the 100% GHG Reduction scenario that assume the wide-scale
availability of several such emerging technology options. These sensitivities are described in Table 4.
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Table 4: 100% GHG Reduction in 2050 Sensitivities
Sensitivity Name Description
Clean Baseload Assesses the impact of technology that generates reliable baseload
power with zero GHG emissions. This scenario might require a
technology such as a small modular nuclear reactor (SMR), fossil
generation with 100% carbon capture and sequestration, or other
undeveloped or commercially unproven technology.
Ultra-Long Duration Storage Assesses the impact of an ultra-long duration electric energy storage
technology (e.g., 100’s of hours) that can be used to integrate wind
and solar. This technology is not commercially available today at
reasonable cost.
Biogas Assesses the impact of a GHG free fuel (e.g., biogas, renewable natural
gas, etc.) that could be used with existing dispatchable generation
capacity.
3.4 Key Portfolio Metrics
Each of the scenarios is evaluated using several different metrics which are defined below:
3.4.1 CLEAN ENERGY METRICS
A number of metrics are used to characterize the greenhouse gas content of generation within the region
in each of the scenarios. These are:
 Greenhouse Gas Emissions (MMT CO2): the annual quantity of greenhouse gas emissions
attributed to ratepayers of the Greater Northwest region, measured in million metric tons.
 Greenhouse Gas Reduction (%): the reduction below 1990 emission levels (approximately 60
million metric tons) for the Greater Northwest region.
 Clean Portfolio Standard (%): the total quantity of GHG-free generation (including renewable,
hydro, and nuclear) divided by retail electricity sales. Because this metric allows the region to
retain the clean attribute for exported electricity and offset in-region or imported natural gas
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generation, this metric can achieve or exceed 100% without reducing GHGs to zero. This metric is
presented because it is a common policy target metric across many jurisdictions to measure clean
energy progress and is the near-universal metric used for state-level Renewables Portfolio
Standards. This metric is consistent with California’s SB 100 which mandates 100% clean energy
by 2045.
 GHG-Free Generation (%): the total quantity of GHG-free generation, minus exported GHG-free
generation, divided by total wholesale load. For this metric, exported clean energy cannot be
netted against in-region or imported natural gas generation. When this metric reaches 100%, GHG
emissions have been reduced to zero.
3.4.2 COST METRICS
 Renewable Curtailment (%): the total quantity of wind and solar generation that cannot be
delivered to loads in the region or exported, expressed as a share of total available potential
generation from wind and solar resources.
 Annual Cost Delta ($B) is the annual cost in 2050 of decarbonization scenarios relative to the 2050
Reference scenario. While the 2050 Reference scenario will require significant costs to meet load
growth, this metric only evaluates the change in costs for each decarbonization scenario relative
to the Reference scenario. By definition, the 2050 Reference scenario has an annual cost delta of
zero. The annual cost delta is calculated by comparing the incremental cost of new wind, solar,
and storage resources to the avoided cost of natural gas capital and operational costs.
 Additional Cost ($/MWh) is the total annual cost delta ($B) divided by total wholesale load, which
provides an average measure of the incremental rate impact borne by ratepayers within the
region. While this metric helps to contextualize the annual cost delta, it is important to note that
the incremental cost will not be borne equally by all load within the Greater Northwest region
and some utilities may experience higher additional costs.
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3.5 Study Caveats
3.5.1 COST RESULTS
The study reports the incremental costs of achieving various GHG targets relative to the cost of the
reference scenario. While the method used to estimate capital and dispatch costs is robust, it does not
entail optimization and the results should be regarded as high-level estimates. For this reason, a range of
potential incremental costs are reported rather than a point estimate. The range is determined by varying
the cost of wind, solar, energy storage and natural gas.
3.5.2 HYDRO DISPATCH
For this study, RECAP utilizes a range of hydro conditions based on NWPCC data covering the time period
1929 – 2008. Within each hydro year, hydroelectric energy “budgets” for each month are allocated to
individual weeks and then dispatched to minimize net load, subject to sustained peaking limit constraints
that are appropriate for the water conditions. Hydro resources are dispatched optimally within each week
with perfect foresight. There are many real-life issues such as biological conditions, flood control,
coordination between different project operators, and others that may constrain hydro operations further
than what is assumed for this study.
3.5.3 TRANSMISSION CONSTRAINTS
This analysis treats the Greater Northwest region as one zone with no internal transmission constraints
or transactional friction. In reality, there are constraints in the region that may prevent a resource in one
corner of the region from being able to serve load in another corner. To the extent that constraints exist,
the Greater Northwest region may be less resource adequate than is calculated in this study and additional
effective capacity would be required to achieve the calculated level of resource adequacy. It is assumed
that new transmission can be developed to deliver energy from new renewable resources to wherever it
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is needed, for a cost that is represented by the generic transmission cost adder applied to resources in
different locations.
3.5.4 INDIVIDUAL UTILITY RESULTS
Cost and resource results in this study are presented from the system perspective and represent an
aggregation of the entire Greater Northwest region. These societal costs include all capital investment
costs (i.e., “steel in the ground”) and operational costs (i.e., fuel and operation and maintenance) that are
incurred in the region. The question of how these societal costs are allocated between individual utilities
is not addressed in this study, but costs for individual utilities may be higher or lower compared to the
region as a whole. Utilities with a relatively higher composition of fossil resources today are likely to bear
a higher cost than utilities with a higher composition of fossil-free resources.
Resource adequacy needs will also be different for each utility as individual systems will need a higher
planning reserve margin than the Greater Northwest region as a whole due to smaller size and less
diversity. The capacity contribution of renewables will be different for individual utilities due to
differences in the timing of peak loads and renewable generation production.
3.5.5 RENEWABLE RESOURCE AVALIBILITY AND LAND USE
The renewable resource availability assumed for this study is based on technical potential as assessed by
NREL. It is assumed wind and solar generation can be developed in each location modeled in this study up
to the technical potential. However, the land consumption is significant for some scenarios and it is not
clear whether enough suitable sites can be found to develop the large quantities of resources needed for
some scenarios. Land use is also a significant concern for the new transmission corridors that would be
required.

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4 Key Inputs & Assumptions
4.1 Load Forecast
The Greater Northwest region had an annual load of 247 TWh and peak load of 43 GW in 2017. This data
was obtained by aggregating hourly load data from the Western Electric Coordinating Council (WECC) for
each of the selected balancing authority areas in the Greater Northwest region.
This study assumes annual load growth of 1.3% pre-energy efficiency and 0.7% post-energy efficiency.
This assumption is consistent with the previous E3 decarbonization work for Oregon and Washington and
is benchmarked to multiple long-term publicly available projections listed in Table 5. The post-energy
efficiency growth rate includes the impact of all cost-effective energy efficiency identified by the NWPCC,
scaled up to the full Greater Northwest region and assumed to continue beyond the end of the Council’s
time horizon. Electrification of vehicles and buildings is only included to the extent that it is reflected in
these load growth forecasts. For example, the NWPCC forecast includes the impact of 1.1 million electric
vehicles by 2030.
In general, E3 believes these load growth forecasts are conservatively low because they exclude the effect
of vehicle and building electrification that would be expected in a deeply decarbonized economy. To the
extent that electrification is higher than forecasted in this study, resource adequacy requirements would
also increase. In this study, total loads increase 25% by 2050, whereas other studies 12 that have
comprehensively examined cost-effective strategies for economy-wide decarbonization include

12 https://www.ethree.com/wp-content/uploads/2018/06/Deep_Decarbonization_in_a_High_Renewables_Future_CEC-500-2018-012-1.pdf
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significant quantities of building, vehicle, and industry electrification that cause electricity-sector loads to
grow by upwards of 60% by 2050 even with significant investments in energy efficiency.
Table 5. Annual load growth forecasts for the Northwest
Source Pre EE Post EE
PNUCC Load Forecast 1.7% 0.9%
BPA White Book 1.1% -
NWPCC 7th Plan 0.9% 0.0%
WECC TEPPC 2026 Common Case - 1.3%
E3 Assumption 1.3% 0.7%
Hourly load profiles are assumed to be constant through the analysis period and do not account for any
potential impact due to electrification of loads or climate change. The Greater Northwest system is a
winter peaking system with loads that are highest during cold snaps on December and January mornings
and evenings. An illustration of the average month/hour load profile for the Greater Northwest is shown
in Figure 4.
Figure 4: Month/Hour Average Hourly Load in the Greater Northwest (GW)

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Projecting these hourly loads using the post-energy efficiency load growth forecasts yields the following
load projections in 2030 and 2050.
Table 6. Load projections in 2030 and 2050 for the Greater NW Region
Load 2018 2030 2050
Median Peak Load (GW) 43 47 54
Annual Energy Load (TWh) 247 269 309

To evaluate the reliability of the Greater Northwest system under a range of weather conditions, hourly
load forecasts for 2030 and 2050 are developed over seventy years of weather conditions (1948-2017).
Historical weather data was obtained from the National Oceanic and Atmospheric Administration (NOAA)
for the following sites in the Greater Northwest region.
Table 7: List of NOAA Sites for Historical Temperature Data
City Site ID
Billings, MT USW00024033
Boise, ID USW00024131
Portland, OR USW00024229
Salt Lake City, UT USW00024127
Seattle, WA USW00024233
Spokane, WA USW00024157
4.2 Existing Resources
A dataset of existing generating resources in the Greater Northwest was derived from two sources: 1) the
NWPCC’s GENESYS model, used to characterize all plants within the Council’s planning footprint; and 2)
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the WECC’s Anchor Data Set, used to gather input data for all existing plants in areas outside of the
NWPCC’s footprint. For each resource, the dataset contains:
 Dependable capacity (MW)
 Location
 Commission and announced retirement date
 Forced outage rate (FOR) and mean time to repair (MTTR)
A breakdown of existing resources by type is shown in Figure 5.
Figure 5: Existing 2018 Installed Capacity (MW) by Resource Type

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Several power plants have announced plans to retire one or more units. The table below lists the notable
coal and natural gas planned retirements through 2030.
Table 8: Planned Coal and Natural Gas Retirements
Power Plant Resource Type Capacity (MW)
Boardman Coal 522
Centralia Coal 1,340
Colstrip 1 & 2 Coal 614
North Valmy Coal 261
Naughton Natural Gas 330
4.2.1 WIND AND SOLAR PROFILES
Hourly wind and solar data were collected for each existing resource in the combined dataset at the
location of the resource. For wind, NREL’s Wind Integration National Dataset Toolkit was used which
includes historical hourly wind speed data from 2007-2012. For solar, NREL’s Solar Prospector Database
was used which includes historical hourly solar insolation data from 1998-2012. These hourly wind speeds
and solar insolation values were then converted into power generation values using the NREL System
Advisor Model (SAM) under assumptions for wind turbine characteristics (turbine power curve and hub
height) and solar panel characteristics (solar inverter ratio). RECAP simulates future electricity generation
from existing wind and solar resources using the historical wind speed data and solar insolation data
respectively.
Simulated wind generation from existing wind plants within BPA territory was benchmarked to historical
wind production data13. To simulate wind generation from existing plants accurately, wind turbine

13 BPA publishes production from wind plants within its Balancing Authority Area in 5-min increments:
https://transmission.bpa.gov/Business/Operations/Wind/default.aspx
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technology (power curve and hub height) varies for each existing wind farm, based on the year of
installation. Figure 6 shows how the simulated wind production compares to historical wind production
in BPA territory in January 2012.
Figure 6: Comparison of historical wind generation to simulated wind production for January 2012

A detailed description of the renewable profile simulation process is described in Appendix C.
4.2.2 HYDRO
Hydro availability is based on a random distribution of the historical hydro record using the water years
from 1929-2008. This data was obtained from the NWPCC’s GENESYS model. Future electricity generation
from existing hydro resources is simulated using the historical hydro availability. Available hydro energy
is dispatched in RECAP subject to sustained peaking limits (1-hr, 2-hr, 4-hr, 10-hr) and minimum output
levels. The sustained peaking limits are based on detailed hydrological models developed by NWPCC.
Available hydro budgets, sustained peaking limits, and minimum output levels are shown for three hydro
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years – 1937 (critical hydro year), 1996 (high hydro year), and 2007 (typical hydro year). The 10-hour
sustained peaking limits for each month represent the maximum average generation for any continuous
10-hour period within the month.
Figure 7: Monthly budgets, sustained peaking limits and minimum outputs levels for 1937 (critical hydro)

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Figure 8: Monthly budgets, sustained peaking limits and minimum outputs levels for 1996 (high hydro)

Figure 9: Monthly budgets, sustained peaking limits and minimum outputs levels for 2007 (typical hydro)

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4.2.3 IMPORTS/EXPORTS
The Greater Northwest region is treated as one zone within the model, but it does have the ability to
import and export energy with neighboring regions, notably California, Canada, Rocky Mountains, and the
Southwest. Import and export assumptions used in this model are consistent with the NWPCC’s GENESYS
model and are listed in Table 9. Monthly and hourly import availabilities are additive but in no hour can
exceed the simultaneous import limit of 3,400 MW. In the 100% GHG Reduction scenarios, import
availability is set to zero to prevent the region from relying on fossil fuel imports.
Table 9: Import Limits
Import Type Availability MW
Monthly Imports
Nov – Mar 2,500
Oct 1,250
Apr – Sep -
Hourly Imports HE 22 – HE 5 3,000
HE 5 – HE 22 -
Simultaneous Import Limit All Hours 3,400
For the purposes of calculating the CPS % metric i.e., “clean portfolio standard”, the model assumes an
instantaneous exports limit of 7,200 MW in all hours.
Table 10: Export Limit
Export Type Availability MW
Simultaneous Export Limit All Hours 7,200
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4.3 Candidate Resources
Candidate resources are used to develop portfolios of resources in 2050 to both achieve GHG reduction
targets or ensure acceptable reliability of 2.4 hrs./yr. LOLE. For a more detailed description of the portfolio
development process, see Section 3.1.3. The 7 candidate resources are:
 Solar (geographically diverse across Greater Northwest)
 Northwest Wind (WA/OR)
 Montana Wind
 Wyoming Wind
 4-Hour Storage
 8-Hour Storage
 16-Hour Storage
Natural gas generation is also added as needed to meet any remaining reliability gaps after the GHG
reduction target is met. The new renewable candidate resources (solar, NW wind, MT wind, WY wind)
are assumed to be added proportionally across a geographically diverse footprint which has a strong
impact on the ability of variable renewable resources to provide reliable power that can substitute for
firm generation. Figure 10 illustrates the location of new candidate renewable resources. When a resource
is added, it is added proportionally at each of the locations shown in the figure below.
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Figure 10: New Renewable Candidate Resources

The generation output profile for each location was simulated by gathering hourly wind speed and solar
insolation data from NREL’s Wind Integration National Dataset Toolkit and Solar Prospector Database and
converting to power output using NREL’s System Advisor Model. The wind profiles used in this study are
based on 135 GW of underlying wind production data from hundreds of sites. The solar profiles used in
this study are based on 80 GW of underlying solar production data across four states. This process is
described in more detail in Appendix C.
New storage resources are available to the model in different increments of duration at different costs
which provide different value in terms of both reliability and renewable integration for GHG reduction.
Note that the model can choose different quantities of each storage duration which results in a fleet-wide
storage duration that is different than any individual storage candidate resource. Because storage is
modeled in terms of capacity charge/discharge and duration, many different storage technologies could
provide this capability. The cost forecast trajectory for Li-Ion battery storage was used to estimate costs,
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but any storage technology that could provide equivalent capacity and duration, such as pumped hydro
or flow batteries, could substitute for the storage included in the portfolio results of this study.
New renewable portfolios are within the bounds of current technical potential estimates published in
NREL.
Table 11. NREL Technical Potential (GW)
State Wind Technical Potential (GW)
Washington 18
Oregon 27
Idaho 18
Montana 944
Wyoming 552
Utah 13
Total 1,588
4.3.1.1 Resource Costs
All costs in this study are presented in 2016 dollars. The average cost of each resource over the 2018-2050
timeframe is shown in Table 12 while the annual cost trajectories from 2018-2050 are shown in Figure 11.
Table 12. Resource Cost Assumptions (2016 $)
Technology Unit High14 Low15 Transmission Notes
Solar PV $/MWh $59 $32 $8 Capacity factor = 27%
NW Wind $/MWh $55 $43 $6 Capacity factor = 37%
MT/WY Wind $/MWh $48 $37 $19 Capacity factor = 43%
4-hr Battery $/kW-yr $194 $97

14 Source for high prices: 2017 E3 PGP Decarbonization Study
15 Source for low prices: NREL 2018 ATB Mid case for wind and solar; Lazard LCOS Mid case 4.0 for batteries
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Technology Unit High14 Low15 Transmission Notes
8-hr Battery $/kW-yr $358 $189
16-hr Battery $/kW-yr $686 $373
Natural Gas Capacity $/kW-yr $150 $150 7,000 Btu/kWh heat rate; $5/MWh variable O&M
Gas Price $/MMBtu $4 $2
Biogas Price $/MMBtu $39 $39

Figure 11: Cost trajectories over the 2018-2050 timeframe (2016 $)

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4.4 Estimating Cost and GHG Metrics
The cost of the future electricity portfolios consists of (1) fixed capital costs for building new resources,
and (2) operating costs for running both existing and new resources. For new wind and new solar
resources, the cost of generation is calculated using their respective levelized costs (see Table 12). Cost of
electricity generation from natural gas plants includes both the capital cost for new natural gas plants and
the operating costs (fuel costs and variable operating costs). All the natural gas plants are assumed to
operate at a heat rate of 7,000 Btu/kWh, with the price of natural gas varying from $2 to $4 per MMBtu
(see Table 12). Storage resources are assumed to have only fixed cost, but no operating cost. All exports
are assumed to yield revenues of $30 per MWh.
In this study, annual GHG emissions are compared against 1990 emission levels, when the emissions for
the Greater Northwest region was 60 million metric tons. GHG emissions are calculated for each thermal
resource depending on the fuel type. For natural gas plants, an emission rate of 117 lb. of CO2 per MMBtu
of natural gas is assumed, yielding 0.371 metric tons of CO2 per MWh of electricity generated from natural
gas (assumed 7,000 Btu/kWh heat rate). For coal plants, an emission rate of 1.0 ton of CO2 per MWh of
electricity generated from coal is assumed.
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5 Results
5.1 Short-Term Outlook (2018)
The 2018 system (today’s system) in the study region is supplied by a mix of various resources, as
described in Section 4.2. The annual electricity load for the study region is 247 TWh with a winter peak
demand of 43 GW. Hydro energy provides the plurality of generation capacity with significant
contributions from natural gas, coal and wind generation.
Resource adequacy conclusions vary depending on what metric is used for evaluation. The region has
sufficient capacity to meet the current standard used by the NWPCC of 5% annual loss of load probability
(LOLP). The region does not have sufficient capacity to meet the 2.4 hrs./yr. LOLE standard used in this
study. In other words, most loss of load is concentrated in a few number of years which matches intuition
for a system that is dependent upon the annual hydro cycle and susceptible to drought conditions. Full
reliability statistics for the Greater Northwest region are shown in Table 13.
Table 13. 2018 Reliability Statistics
Metric Units Value
Annual LOLP (%) % 3.7%
Loss of Load Expectation (LOLE) hrs/yr 6.5
Expected Unserved Energy (EUE) MWh/yr 5,777
Normalized EUE % 0.003%
1-in-2 Peak Load GW 43
PRM Requirement % of peak 12%
Total Effective Capacity Requirement GW 48

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Table 14. 2018 Load and Resource Balance

In order to meet an LOLE target of 2.4 hrs./yr., a planning reserve margin (PRM) of 12% is required. The
PRM is calculated by dividing the quantity of effective capacity needed to meet the LOLE target by the
median peak load, then subtracting one. This result is lower than many individual utilities currently hold
within the region (typical PRM ~15%) due to the load and resource diversity across the geographically
large Greater Northwest region. As shown in Table 14, the total effective capacity (47 GW) available is
slightly lower than the total capacity requirement (48 GW) which is consistent with the finding that the
Load Load GW
Peak Load 42.1
Firm Exports 1.1
PRM (12%) 5.2
Total Requirement 48.4
Resources Nameplate GW Effective % Effective GW
Coal 10.9 100% 10.9
Gas 12.2 100% 12.2
Biomass & Geothermal 0.6 100% 0.6
Nuclear 1.2 100% 1.2
Demand Response 0.6 50% 0.3
Hydro 35.2 53% 18.7
Wind 7.1 7% 0.5
Solar 1.6 12% 0.2
Storage 0 — 0
Total Internal Generation 69.1 44.7
Firm Imports 3.4 74% 2.5
Total Supply 72.5 47.2
Surplus/Deficit
Capacity Surplus/Deficit -1.2
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system is not sufficiently reliable to meet a 2.4 hrs./yr. LOLE target. The effective capacity percent
contributions from wind and solar are shown to be 7% and 12%, respectively. These relatively low values
stem primarily from the non-coincidence of wind and solar production during high load events in the
Greater Northwest region, notably very cold winter mornings and evenings.
It should be noted that the effectiveness of firm capacity is set to 100% by convention in calculating a
PRM. The contribution of variable resources is then measured relative to firm capacity, incorporating the
effect of forced outage rates for firm resources.
5.2 Medium-Term Outlook (2030)
The Greater Northwest system in 2030 is examined under two scenarios:
 Reference
• Planned coal retirements; new gas gen for reliability
 No Coal
• All coal retired; new gas gen for reliability
The resulting generation portfolios in both scenarios (both of which meet the 2.4 hrs./yr. LOLE reliability
standard) are shown in Figure 12 alongside the 2018 system for context. To account for the load growth
by 2030, 5 GW of net new capacity is required to maintain reliability. In the Reference Scenario where 3
GW of coal is retired, 8 GW of new firm capacity is needed by 2030 for reliability. Similarly, the No Coal
Scenario (where all 11 GW of coal is retired) results in 16 GW of new firm capacity need by 2030. The
study assumes all the new capacity in the 2030 timeframe need is met through additional natural gas
build. It should be noted that regardless of what resource mix is built to replace the retirement of coal,
the siting, permitting, and construction of these new resources will take significant time so planning for
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these resources needs to begin well before actual need. The portfolio tables for each scenario are
summarized in Appendix A.2.
Figure 12: Generation Portfolios in 2030

Table 15. 2030 Generation Portfolio: Key Metrics
Metric 2030 Reference 2030 No Coal
GHG-Free Generation (%) 61% 61%
GHG Emissions (MMT CO2 / year) 67 42
% GHG Reduction from 1990 Level -12%16 31%

16 Negative value for %GHG reduction from 1990 level indicates that emissions are above 1990 level
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As these metrics show, without either natural gas replacement of coal capacity or significant increase in
renewable energy, GHG emissions are forecasted to rise in the 2030 timeframe. However, repowering
coal with natural gas has the potential to reduce GHG emissions by 31% below 1990 levels.
In order to meet an LOLE target of 2.4 hrs/yr, the region requires a planning reserve margin (PRM) in 2030
of 12%.
Table 16. 2030 Load and Resource Balance, Reference Scenario
Load Load MW
Peak Load 45.9
Firm Exports 1.1
PRM (12%) 5.8
Total Requirement 52.9
Resources Nameplate MW Effective % Effective MW
Coal 8.2 100% 8.2
Gas 19.9 100% 19.9
Bio/Geo 0.6 100% 0.6
Nuclear 1.2 100% 1.2
DR 2.2 45% 1.0
Hydro 35.2 53% 18.7
Wind 7.1 9% 0.6
Solar 1.6 14% 0.2
Storage 0 — 0
Total Internal Generation 76.1 50.5
Firm Imports 3.4 74% 2.5
Total Supply 79.5 52.9
Surplus/Deficit
Capacity Surplus/Deficit 0.0
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5.3 Long-Term Outlook (2050)
The Greater Northwest system in 2050 is examined under a range of decarbonization scenarios, relative
to 1990 emissions.
 60% GHG Reduction
 80% GHG Reduction
 90% GHG Reduction
 98% GHG Reduction
 100% GHG Reduction
The portfolio for each decarbonization scenario was developed using the methodology described in
Section 3.1.3. To summarize this process, RECAP iteratively adds carbon-free resources (wind, solar
storage) to reduce GHG in a manner that maximizes the effective capacity of these carbon-free resources,
thus minimizing the residual need for firm natural gas capacity. Once a cost-effective portfolio of carbon-
free resources has been added to ensure requisite GHG reductions, the residual need for natural gas
generation capacity is calculated to ensure the entire portfolio meets a 2.4 hrs./yr. LOLE standard.
5.3.1 ELECTRICITY GENERATION PORTFOLIOS
All the 2050 decarbonization portfolios are shown together in Figure 13. Higher quantities of renewable
and energy storage are required to achieve deeper levels of decarbonization, which in turn provide
effective capacity to the system and allow for a reduction in residual firm natural gas capacity need,
relative to the reference case. Detailed portfolio results tables for each scenario are provided in Appendix
A.2.
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Figure 13: Generation Portfolios for 2050 Scenarios

Table 17. 2050 Decarbonization Scenarios: Key Generation Metrics
Metric

Reference
Scenario
GHG Reduction Scenarios
Units 60% Red. 80% Red. 90% Red. 98% Red.
100%
Red.
GHG Emissions MMT/yr 50 25 12 6 1 0
GHG Reductions % below
1990 16% 60% 80% 90% 98% 100%
GHG-Free
Generation % of load 60% 80% 90% 95% 99% 100%
Clean Portfolio
Standard % of sales 63% 86% 100% 108% 117% 123%
Annual Renewable
Curtailment
% of
potential Low Low 4% 10% 21% 47%
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Table 17 evaluates the performance of each decarbonization portfolio along several key generation
metrics that were described in detail in Section 3.4.
Analyzing the portfolio of each decarbonization scenario and resulting performance metrics yields several
interesting observations.
 On retiring all 11 GW of coal by 2050 in the Reference scenario, the Greater Northwest system
requires 20 GW of new capacity in order to meet the 2.4 hrs./yr. LOLE standard used in the study.
This suggests that 9 GW of net new firm capacity is needed to account for load growth through
2050.
 The integration of more renewables and conservation policies provides the energy needed to
serve loads in a deeply decarbonized future, but new gas-fired generation capacity is needed for
relatively short, multi-day events with low renewable generation, high loads, and low hydro
availability.
 To reduce GHG emissions to 80% below 1990 levels, RECAP chooses to build 38 GW of wind, 11
GW of solar, and 2 GW of 4-hour storage. In addition to this renewable build, 12 GW of new firm
capacity is required for reliability (after retaining all the existing natural gas plants) which is
assumed to be met through natural gas build. The generation portfolio under 80% Reduction
Scenario results in a 100% clean portfolio standard and 90% GHG-free generation.
 RECAP achieves deeper levels of decarbonization (GHG emissions 98% below 1990 level down to
1.0 MMT GHG/yr) by overbuilding renewables with 54 GW of wind, 29 GW of solar, and 7 GW of
4-hour storage. Annual renewable oversupply becomes significant (at 21%). Nevertheless, the
system still requires an additional gas build of 2 GW after retaining all existing natural gas plants,
to ensure reliability during periods of low renewable generation. The capacity factor for these gas
plants is extremely low (3%), underlining their importance for reliability.
 The 100% GHG Reduction Scenario (Zero Carbon Scenario) results in no GHG emissions from the
electricity sector. The generation portfolio consists only of renewables (97 GW of wind and 46
GW of solar) and energy storage (29 GW of 6-hour storage). Ensuring a reliable system using only
renewables and energy storage requires a significant amount of renewable overbuild – resulting
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in nearly half of all the generated renewable energy to be curtailed. Compared to the 98% GHG
Reduction Scenario (which results in 99% GHG-free generation), the Zero Carbon Scenario
requires almost double the quantity of renewables and even greater quantity of energy storage.
With increases in renewable generation, generation from natural gas plants decreases. Due to negligible
operating costs associated with renewable production, it is cost optimal to use as much renewable
generation as the system can. During periods of prolonged low renewable generation when energy
storage is depleted, natural gas plants can ramp up to provide the required firm capacity to avoid loss-of-
load events. In the deep decarbonization scenarios, gas is utilized sparingly and even results in very low
capacity factors (such as 9% and 3%). However, RECAP chooses to retain (and even build) natural gas as
the most cost-effective resource to provide reliable firm capacity. Renewable overbuild also results in
significant amounts of curtailment.
Figure 14: Annual generation mix across the scenarios

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A planning reserve margin of 7% to 9% is required to meet the 1-in-10 reliability standard in 2050
depending on the scenario. Accounting for a planning reserve margin, the total capacity requirement (load
plus planning reserve margin) in 2050 is 57-59 GW. As shown in Table 18, this capacity requirement is met
through a diverse mix of resources. Variable or energy-limited resources such as hydro, wind, solar and
storage contribute only a portion of their entire nameplate capacity (ELCC) towards resource adequacy.
Load and resource tables for the 80% and 100% Reduction scenarios are shown below.
Table 18. 2050 Load and Resource Balance, 80% Reduction scenario
Load Load MW
Peak Load 52.8
Firm Exports 1.1
PRM (9%) 4.9
Total Requirement 58.8
Resources Nameplate MW Effective % Effective MW
Coal 0 — 0
Gas 23.5 100% 23.5
Bio/Geo 0.6 100% 0.6
Nuclear 1.2 100% 1.2
DR 5.5 29% 1.6
Hydro 35.2 53% 18.7
Wind 38.0 19% 7.2
Solar 10.6 19% 2.0
Storage 2.2 73% 1.6
Total Internal Generation 116.8 56.3
Firm Imports 3.4 74% 2.5
Total Supply 120.2 58.8
Surplus/Deficit
Capacity Surplus/Deficit 0.0
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Table 19. 2050 Load and Resource Balance, 100% Reduction scenario
Load Load MW
Peak Load 52.8
Firm Exports 1.1
PRM (7%) 4.0
Total Requirement 58.0
Resources Nameplate MW Effective % Effective MW
Coal 0 — 0
Gas 0 — 0
Bio/Geo 0.6 100% 0.6
Nuclear 1.2 100% 1.2
DR 5.5 29% 1.6
Hydro 35.2 57% 20.1
Wind 97.4 22% 21.5
Solar 45.6 16% 7.3
Storage 28.7 20% 5.7
Total Internal Generation 214.2 58.0
Firm Imports 0 — 0
Total Supply 214.2 58.0
Surplus/Deficit
Capacity Surplus/Deficit 0.0

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5.3.2 ELECTRIC SYSTEM COSTS
System costs are estimated using the methodology and cost assumptions described in Section 4.3.1.1 and
Section 4.4. Electric system costs represent the cost of decarbonization relative to the 2050 Reference
scenario, and so by definition all annual and unit cost increases in this scenario are zero. The 2050
Reference scenario does require significant investment in new resources in order to reliably meet load
growth and existing RPS policy targets, so the zero incremental cost is not meant to make any assessment
on the absolute change (or lack thereof) in total electric system costs or rates by 2050.
Table 20 evaluates the performance of 2050 decarbonization scenarios along two cost metrics for both a
low and high set of cost assumptions.
Table 20: 2050 Decarbonization Scenarios: Key Cost Metrics
Metric

Reference
Scenario
GHG Reduction Scenarios
Units 60% Red. 80% Red. 90% Red. 98% Red.
100%
Red.
Annual Cost
Increase
Lo $BB/yr
(vs. Ref) —
$0 $1 $2 $3 $16
Hi $2 $4 $5 $9 $28
Unit Cost
Increase
Lo $/MWh
(vs. Ref) —
$0 $3 $5 $10 $52
Hi $7 $14 $18 $28 $89
Analyzing the cost results for each decarbonization scenario yields several interesting observations
 To reduce GHG emissions to 80% below 1990 levels, a portfolio of wind/solar/storage can be
obtained at an additional annual cost of $1 to $4 billion ($3 to $14/MWh) after accounting for the
avoided costs of new gas build and utilization. Assuming an existing average retail rate of
$0.10/kWh, this implies an increase of 3%-14% in real terms relative to the Reference Scenario.
Because the 80% reduction scenario achieves a 100% clean portfolio standard (as shown in
Section 5.3.1), this scenario is compelling from both a policy perspective and a cost perspective in
balancing multiple objectives across the Greater Northwest region.
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 Deep decarbonization (GHG emissions 98% below 1990 level down to 1.0 MMT GHG/yr) of the
Greater Northwest system can be obtained at an additional annual cost of $3 to $9 billion ($10 to
$28/MWh), i.e., the average retail rates increase 10%-28% in real terms relative to the Reference
Scenario. This suggests that deep decarbonization of the Greater Northwest system can be
achieved at moderate additional costs, assuming that natural gas capacity is available as a
resource option to maintain reliability during prolonged periods of low renewable production.
 The 100% GHG Reduction Scenario requires a significant increase in wind, solar and storage to
eliminate the final 1% of GHG-emitting generation. An additional upfront investment of $100
billion to $170 billion is required, relative to the 98% GHG Reduction scenario. Compared to the
Reference Scenario, the Zero Carbon Scenario requires an additional annual cost of $16 to $28
billion ($52 to $89/MWh), i.e., the average retail rates nearly double.
Costs for individual utilities will vary and may be higher or lower than the region as a whole. This report
does not address allocation of cost between utilities.
As shown in Figure 15, the cost increases of achieving deeper levels of decarbonization become
increasingly large as GHG emissions approach zero. This is primarily due to the level of renewable
overbuild that is required to ensure reliability and the increasing quantities of energy storage required to
integrate the renewable energy.
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Figure 15: Cost of GHG reduction

The marginal cost of GHG reduction represents the incremental cost of additional GHG reductions at
various levels of decarbonization. Figure 16 and Figure 17 both show the increasing marginal cost of GHG
abatement at each level of decarbonization. At very deep levels of GHG reductions, the marginal cost of
carbon abatement greatly exceeds the societal cost of carbon emissions, which generally ranges from
$50/ton to $250/ton17, although some academic estimates range up to $800/ton18.

17 https://19january2017snapshot.epa.gov/climatechange/social-cost-carbon_.html
18 https://www.nature.com/articles/s41558-018-0282-y
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Figure 16: Marginal Cost of GHG Reduction: 60% Reduction To 98% Reduction

Figure 17: Marginal Cost of GHG Reduction: 60% Reduction to 100% Reduction

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5.3.3 DRIVERS OF RELIABILITY CHALLENGES
The major drivers of loss of load in the Greater Northwest system include high load events, prolonged low
renewable generation events, and drought hydro conditions. In today’s system where most generation is
dispatchable, prolonged low renewable generation events do not constitute a large cause of loss-of-load
events. Rather, the largest cause of loss-of-load events stem from the combination of high load events
and drought hydro conditions. This relationship between contribution to LOLE and hydro conditions is
highlighted in Figure 18 which shows nearly all loss of load events concentrated in the worst 25% of hydro
years.
Figure 18. 2018 System Loss-of-Load Under Various Hydro Conditions

At very high renewable penetrations, in contrast, prolonged low renewable generation events usurp
drought hydro conditions as the primary driver of reliability challenges. Figure 19 shows that at high levels
of GHG reductions, loss-of-load is much less concentrated in the worst hydro years as prolonged low
renewable generation events can create loss-of-load conditions in any year.
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Figure 19. 2018 System GHG Reduction Scenarios Loss-of-Load Under Various Hydro Conditions

In practice, these prolonged periods of low renewable output manifest via multi-day winter storms that
inhibit solar production over very wide geographic areas or large-scale high-pressure systems associated
with low wind output. Figure 20 presents an example of multiday loss-of-load in a sample week in 2050
in the 100% GHG Reduction scenario. In a system without available dispatchable resources to call during
such events, low solar radiation and wind speed can often give rise to severe loss-of-load events, especially
when renewable generation may be insufficient to serve all load and storage quickly depletes. As shown
in the example, over 100 GW of total installed renewables can only produce less than 10 GW of output in
some hours. It is the confluence of events like these that drive the need for renewable overbuild to
mitigate these events, which in turn leads to the very high costs associated with ultra-deep
decarbonization.
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Figure 20: Loss-of-load Example in a Sample Week

5.3.4 ROLE OF NATURAL GAS GENERATION CAPACITY
The significant buildout of renewables and storage to meet decarbonization targets contributes to the
resource adequacy needs of the system and reduces the need for thermal generation. However, despite
the very large quantities of storage and renewables in all the high GHG reduction scenarios, a significant
amount of natural gas capacity is still needed for reliability (except for the 100% GHG Reduction scenario
where natural gas combustion is prohibited). Even though the system retains significant quantities of gas
generation capacity for reliability, the capacity factor utilization of the gas fleet decreases substantially at
higher levels of GHG reductions as illustrated in Figure 21. It is noteworthy that all scenarios except 100%
GHG reductions require more gas capacity than exists in 2018, assuming all coal (11 GW) is retired.
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Figure 21: Natural Gas Required Capacity in Different 2050 Scenarios

5.3.5 EFFECTIVE LOAD CARRYING CAPABILITY
Effective Load Carrying Capability (ELCC) is a metric used in the electricity industry to quantify the
additional load that can be met by an incremental generator while maintaining the same level of system
reliability. Equivalently, ELCC is a measure of ‘perfect capacity’ that could be replaced or avoided with
dispatch-limited resources such as wind, solar, storage, or demand response.
5.3.5.1 Wind ELCC
Wind resources in this study are grouped and represented as existing Northwest (Oregon and
Washington) wind, new Northwest wind, and new Wyoming and Montana wind. The ELCC curves of each
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representative wind resource and as well as the combination of all three resources (i.e., “Diverse”) are
shown in Figure 22.
Figure 22: Wind ELCC at Various Penetrations

These results are primarily driven by the coincidence of wind production and high load events. Existing
wind in the Northwest today, primarily in the Columbia River Gorge, has a strong negative correlation with
peak load events that are driven by low pressures and cold temperatures. Conversely, Montana and
Wyoming wind does not exhibit this same correlation and many of the highest load hours are positively
correlated with high wind output as illustrated in Figure 23.
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Figure 23: Load and Wind Correlation (Existing NW Wind and New MT/WY Wind)

Comparing and contrasting the ELCC of different wind resources yields several interesting findings:
 The wide discrepancy between the “worst” wind resource (existing NW) and the “best” wind
resource (new MT/WY) is primarily driven by the correlation of the wind production and peak
load events in Washington and Oregon. Existing NW wind is almost entirely located within the
Columbia River Gorge which tends to have very low wind output during the high-pressure weather
systems associated with the Greater Northwest cold snaps that drive peak load events.
Conversely, MY/WY wind is much less affected by this phenomenon due largely to geographic
distance, and wind output tends to be highest during the winter months when the Northwest is
most likely to experience peak load events.
 All wind resources experience significant diminishing returns at high levels of penetration. While
wind may generate significant energy during the system peak, ultimately the net load peak that
drives ELCC will shift to an hour with low wind production and reduce the effectiveness with which
wind can provide ELCC. Diversity mitigates the rate of decline of ELCC.
 New NW wind has notably higher ELCC values than existing NW wind due to both improvements
in turbine technology but also through larger geographic diversity of wind development within
the Northwest region but outside of the Columbia River Gorge.
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 Diverse wind (combination of all three wind groups) yields the highest ELCC values at high
penetrations. This is because even the best wind resources experience periods of low production
and additional geographic diversity can help to mitigate these events and improve ELCC.
5.3.5.2 Solar ELCC
Solar resources in this study are grouped and represented as existing solar and new solar which is built
across the geographically diverse area of Idaho, Washington, Oregon, and Utah. In general, solar provides
lower capacity value than wind due to the negative correlation between winter peak load events and solar
generation which tends to be highest in the summer. Like wind, solar ELCC also diminishes as more
capacity is added. Figure 24 shows this information for the ELCC of new solar in the Greater Northwest
region.
Figure 24: Solar ELCC at Various Penetrations

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5.3.5.3 Storage ELCC
At small initial penetrations, energy storage can provide nearly 100% ELCC as a substitute for peaking
generation that only needs to discharge for a small number of hours. However, at higher penetrations,
the required duration for storage to continue to provide ELCC to the system diminishes significantly. This
is primarily due to the fact that storage does not generate energy and ELCC is a measure of perfect capacity
which can reliably generate energy. This result holds true for both shorter duration (6-hr) and longer
duration (12-hr) storage which represents the upper end of duration for commercially available storage
technologies. Figure 25 highlights the steep diminishing returns of storage toward ELCC.
Figure 25: Storage ELCC at Various Penetrations

This steeply-declining ELCC value for diurnal energy storage is particularly acute in the Pacific Northwest.
This has to do with the fact that there is a significant quantity of energy storage implicit with the 35-GW
hydro system in the region. The Federal Columbia River Power System is already optimized over multiple
days, weeks and months within the bounds of non-power constraints such as flood control, navigation
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and fish & wildlife protections. Significant quantities of energy are stored in hydroelectric reservoirs today
and dispatched when needed to meet peak loads. Thus, additional energy storage has less value for
providing resource adequacy in the Northwest than it does in regions that have little or no energy storage
today.
5.3.5.4 Demand Response ELCC
Demand response (DR) represents a resource where the system operator can call on certain customers
during times of system stress to reduce their load and prevent system-wide loss-of-load events. However,
DR programs have limitations on how often they can be called and how long participants respond when
they are called. DR in this study is represented as having a maximum of 10 calls per year with each call
lasting a maximum of 4 hours. This is a relatively standard format for DR programs, although practice
varies widely across the country. This study also assumes perfect foresight of the system operator such
that a DR call is never “wasted” when it wasn’t actually needed for system reliability.
Figure 26: Cumulative and Marginal ELCC of DR

Figure 26 shows the cumulative and marginal ELCC of DR at increasing levels of penetration. Due to the
limitations on the number of calls and duration of each call, DR has an initial ELCC of approximately 50%.
Similar to energy storage, conventional 4-hour DR has less value in the Pacific Northwest than in other
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regions due to the flexibility inherent in the hydro system. Also, the capacity value of DR declines as the
need for duration becomes longer and longer.
5.3.5.5 ELCC Portfolio Effects
Grouping different types of renewable resources, energy storage, and DR together often creates synergies
between the different resources such that the combined ELCC of the entire portfolio is more than the sum
of any resource’s individual contribution. For example, solar generation can provide the energy that
storage needs to be effective and storage can provide the on-demand dispatchability that solar needs to
be effective. This resulting increase in ELCC is referred to as the diversity benefit.
Figure 27 shows the average ELCC for each resource type both on a stand-alone basis and also with a
diversity allocation that accrues to each resource when they are added to a portfolio together.

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Figure 27: ELCC of Solar, Wind, and Storage with Diversity Benefits

Figure 28 presents the cumulative portfolio ELCC of wind, solar, and storage up to the penetrations
required to reliably serve load in a 100% GHG Reduction scenario. At high penetrations of renewables and
storage, most of the ELCC is realized through diversity, although it still requires approximately 170 GW of
nameplate renewable and storage resources to provide an equivalent of 37 GW of firm ELCC capacity that
is required to retire all fossil generation. However, unlike adding these resources on a standalone basis, a
combined portfolio continues to provide incremental ELCC value of approximately 20% of nameplate even
at very high levels of penetration.
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Figure 28: ELCC of Different Portfolios in 2050

5.3.6 SENSITIVITY ANALYSIS
This study also explores the potential resource adequacy needs of a 100% GHG free electricity system
recognizing that emerging technologies beyond wind, solar, and electric energy storage that are not yet
available today may come to play a significant role in the region’s energy future. Specifically, the
alternative resources analyzed are: clean baseload, ultra-long duration storage, and biogas which are
further described in Table 21.
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Table 21: Sensitivity Descriptions
Sensitivity Name Description
Clean Baseload Assesses the impact of technology that generates reliable baseload
power with zero GHG emissions. This scenario might require a
technology such as a small modular nuclear reactor (SMR), fossil
generation with 100% carbon capture and sequestration, or other
undeveloped or commercially unproven technology.
Ultra-Long Duration Storage Assesses the impact of an ultra-long duration electric energy storage
technology (e.g., 100’s of hours) that can be used to integrate wind
and solar. This technology is not commercially available today at
reasonable cost.
Biogas Assesses the impact of a GHG free fuel (e.g., biogas, renewable natural
gas, etc.) that could be used with existing dispatchable generation
capacity.
All three of these alternative technology options have the potential to greatly reduce the required
renewable overbuild of the system as shown in Figure 29. This is achieved because each of these
technologies is dispatchable and can generate energy during prolonged periods of low wind and solar
production when short-duration energy storage would become depleted.
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Figure 29: 2050 100% GHG Reduction Sensitivity Portfolio Results

While these alternative technologies clearly highlight the benefits, there are significant technical
feasibility, economic, and political feasibility hurdles that stand in the way of large-scale adoption of these
alternatives at the present time. In particular, clean baseload would require some technology such as
small modular nuclear reactors which is not yet commercially available. Geothermal could provide a clean
baseload resources but is limited in technical potential across the region. Fossil generation with carbon
capture and sequestration (CCS) is another potential candidate, but the technology is not widely deployed,
the cost at scale is uncertain, and current CCS technologies do not achieve a 100% capture rate. Ultra-long
duration storage (926 hours) is not commercially available at reasonable cost assuming the technology is
limited to battery storage or other commercially proven technologies. Biogas potential is also uncertain
and there will be competition from other sectors in the economy to utilize what may be available. A
detailed table of installed nameplate capacity for each portfolio is summarized in Appendix A.2.
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Table 22 shows key cost metrics for the 100% GHG Reduction sensitivity scenarios. For consistency with
the base case scenarios, all costs are relative to the 2050 Reference scenario.
Table 22. 100% GHG Reduction Sensitivity Key Cost Metrics
Metric
100% GHG Reduction Baseline
100% GHG Reduction Clean Baseload
100% GHG Reduction Ultra-Long Duration Storage
100% GHG Reduction Biogas
Carbon Emissions (MMT CO2 / year) 0 0 0 0
Annual Incremental Cost ($B) $12- $28 $11-$22 $370-$920 $2 - $10
Annual Incremental Cost ($/MWh) $39-$91 $36-$70 $1,200-$3,000 $5 - $32
Analyzing the portfolio and key cost metrics for each of the 100% GHG Reduction sensitivity cases yields
several notable observations.
 In the Clean Baseload sensitivity, the availability of a carbon-free source of baseload generation
dramatically reduces the amount of investment in variable renewables and storage needed to
maintain reliability: adding 11 GW of clean baseload resource displaces a portfolio of 15 GW solar,
37 GW wind, and 11 GW of storage. In the context of a highly renewable grid, baseload resources
that produce energy round-the-clock—including during periods when variable resources are not
available—provide significant reliability value to the system. However, at an assumed price of
$91/MWh, the scenario still results in considerable additional costs to ratepayers of between $11-
22 billion per year relative to the Reference Scenario.
 The Ultra-Long Duration Storage sensitivity illustrates a stark direct relationship between the
magnitude of renewable overbuild and the storage capability of the system: limiting renewable
curtailment while simultaneously serving load with zero carbon generation reliability requires
energy storage capability of a duration far beyond today’s commercial applications (this
relationship is further explored in Figure 30 below). Without significant breakthrough in storage
technologies, such a portfolio is beyond both technical and economic limits of feasibility.
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Figure 30: Tradeoff between Renewable Curtailment and Storage Duration

 The Biogas sensitivity demonstrates the relatively high value of the potential option to combust
renewable natural gas in existing gas infrastructure. In this scenario, 14 GW of existing and new
gas generation capacity is retained by 2050, serving as a reliability backstop for the system during
periods of prolonged low renewable output by burning renewable gas. This sensitivity offers the
lowest apparent cost pathway to a zero-carbon electric system because biogas generation does
not require significant additional capital investments. While the biogas fuel is assumed to be quite
expensive on a unit cost basis, the system doesn’t require very much fuel, so the total cost remains
reasonable. Moreover, biogas generation uses the same natural gas delivery and generation
infrastructure as the Reference Case, significantly reducing the capital investments required.
However, the availability of sufficient biomass feedstock to meet the full needs of the electric
sector remains an uncertainty. Moreover, there may be competing uses for biogas in the building
and industrial sectors that inhibit the viability of this approach.

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6 Discussion & Implications
6.1 Land Use Implications of High Renewable Scenarios
Renewables such as wind and solar generation require much greater land area to generate equivalent
energy compared to generation sources such as natural gas and nuclear. In the deep decarbonization
scenarios, significant amount of land area is required for renewable development. In the 100% GHG
Reduction Scenario, estimates of total land use vary from 3 million acres to 14 million acres which is
equivalent to 20 to 100 times the land area of Portland and Seattle combined. This is almost three times
the land use required under the 80% GHG Reduction scenario.
Table 23. Renewable Land Use in 2050
2050 Scenario Units Solar Total Land Use Wind – Direct Land19 Use Wind – Total Land20 Use
80% GHG Reduction Thousand acres 84 94 1,135 – 5,337
100% GHG Reduction Thousand acres 361 241 2,913 – 13,701
Even though such vast expanses of land are available, achieving very high levels of decarbonization would
require extensive land usage for such large renewable development. Additionally, significant quantities of
land would be required to site the necessary transmission to deliver the renewable energy.

19 Direct land use is defined as disturbed land due to physical infrastructure development and includes wind turbine pads, access roads, substations
and other infrastructure
20 Total land use is defined as the project footprint as a whole and is the more commonly cited land-use metric associated with wind plants. They vary
with project and hence as presented as a range
Both direct and total land use for wind is sourced from NREL’s technical report: https://www.nrel.gov/docs/fy09osti/45834.pdf
Land use for solar is sourced from NREL’s technical report: https://www.nrel.gov/docs/fy13osti/56290.pdf
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Figure 31 highlights the scale of renewable development that would be required to achieve 100% GHG
reductions via only wind, solar, and storage. Each dot in the map represents a 200 MW wind or solar farm.
Note that sites are not to scale or indicative of site location.
Figure 31: Map of Renewable Land Use Today and in 80% and 100% GHG Reduction Scenario. Each dot
represents one 200 MW power plant (blue = wind, yellow = solar)

6.2 Reliability Standards
Determining the reliability standard to which each electricity system plans its resource adequacy is the
task of each individual Balancing Authority as there is no mandatory or voluntary national standard. There
are several generally accepted standards used in resource adequacy across North America, with the most
common being the “1-in-10” standard. There is, however, a range of significant interpretations for this
metric. Some interpret it as one loss-of-load day every ten years. Some interpret it as one loss-of-load
event every ten years. And some interpret it as one loss-of-load hour every ten years. The translation of
these interpretations into measurable reliability metrics further compounds inconsistency across
jurisdictions. However, the ultimate interpretation of most jurisdictions ultimately boils down to the use
of one of four reliability metrics:
Today 80% CO2 Reduction 100% CO2 Reduction
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 Annual Loss of Load Probability (aLOLP)
• The probability in a year that load + reserves exceed generation at any time
 Loss of Load Frequency (LOLF)
• The total number of events in a year where load + reserves exceed generation
 Loss of Load Expectation (LOLE)
• The total number of hours in a year where load + reserves exceed generation
 Expected Unserved Energy (EUE)
• The total quantity of unserved energy in a year when load + reserves exceed generation

Each of these metrics provides unique insight into the reliability of the electric system and provides
information that cannot be ascertained by simply using the other metrics. At the same time, each of the
metrics is blind to many of the factors that are ascertained through the other metrics.
The NWPCC sets reliability standards for the Pacific Northwest to have an annual loss of load probability
(aLOLP) to be below 5%. This would mean loss-of-load events occur, on average, less than once in 20
years. However, this metric does not provide any information on the number of events, duration of
events, or magnitude of events that occur during years that experience loss of load. While this metric has
generally served the region well when considering that the biggest reliability drive (hydro) was on an
annual cycle, this metric becomes increasingly precarious when measuring a system that is more and more
dependent upon renewables.
This study uses loss of load expectation (LOLE), because it is a more common metric that is used by utilities
and jurisdictions across the country. Unlike aLOLP, LOLE does yield insight on the duration of events which
can help to provide greater detail whether or not a system is adequately reliable.
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However, LOLE does not capture the magnitude of events when they occur and thus misses a potentially
large measure of reliability as compared to a metric such as EUE. EUE captures the total quantity of energy
that is expected to go unserved each year. While this metric is not perfect, it is likely the most robust
metric in terms of measuring the true reliability of an electric system, particularly in a system that is
energy-constrained. Despite these attributes, EUE is not commonly used as a reliability metric in the
industry today.
RECAP calculates all the aforementioned reliability metrics and can be used to compare and contrast their
performance across different portfolios. Table 24 shows the four reliability metrics across different 2050
decarbonization scenarios.
Table 24: Reliability Statistics Across 2050 Decarbonization Portfolios
Reliability Metric Units
2050
Reference
80%
GHG Red.
100%
GHG Red.
aLOLP %/yr 3.6% 8.1% 10.5%
LOLF #/yr 0.16 0.29 0.13
LOLE hrs/yr 2.4 2.4 2.4
EUE GWh/yr 1.0 2.0 19.0

Because the portfolios were calibrated to meet a 2.4 hrs./yr. LOLE standard, all portfolios yield exactly this
result. However, this does not mean that all portfolios are equally reliable. Notably, the 100% GHG
Reduction scenario has nearly 20 times the quantity of expected unserved energy (EUE) as compared to
the reference scenario. The value of unserved energy varies widely depending on the customer type and
outage duration; studies typically put the value between $5,000 and $50,000/MWh. This means that the
economic cost of unserved energy in the 2050 Reference Scenario is between $5 million and $50 million
per year. However, in the 100% GHG Reduction Scenario, which meets the same target for LOLE, the value
of unserved energy could be nearly $1 billion annually.
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This gives an important insight to some of the qualities of a system that is highly dependent upon dispatch-
limited resources. For a traditional system that is composed mainly of dispatchable generation (coal,
natural gas, nuclear, etc.), the primary reliability challenge is whether there is enough capacity to serve
peak load. Even if the peak is slightly higher than expected or power plants experience forced outages and
are unavailable to serve load, the difference between available generation and total load should be
relatively small. Conversely, for a system that is highly dependent upon variable generation and other
dispatch limited generation, there is a much greater chance that the sum of total generation could be
significantly lower than total load. This phenomenon was highlighted in Section 5.3.3. The reliability
statistics above confirm this intuition by highlighting how aLOLP, LOLF, and LOLE are each uniquely
inadequate to fully capture the reliability of a system that is highly dependent upon variable renewable
energy. For a system that is heavily dependent on variable generation, EUE may be a more useful
reliability metric than the conventional LOLE metrics.
6.3 Benefits of Reserve Sharing
One of the simplifying assumptions made in this study to examine reliability across the Greater Northwest
is the existence of a fully coordinated planning and operating regime within the region. In reality, however,
responsibility for maintaining reliability within the system is distributed among individual utilities and
balancing authorities with oversight from state utility commissions. The current distributed approach to
reliability planning has two interrelated shortcomings:
1) Because the region’s utilities each plan to meet their own needs, they may not rigorously account
for the natural load and resource diversity that exists across the footprint. If each utility built
physical resources to meet its own need, the quantity of resources in the region would greatly
exceed what would be needed to meet industry standards for loss-of-load.
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2) As an informal mechanism for taking advantage of the load and resource diversity that exists in
the region, many utilities rely on front-office transactions (FOTs) or market purchases instead of
physical resources, as was discussed in Section 2. This helps to reduce costs to ratepayers of
maintaining reliability by avoiding the construction of capacity resources. However, as the region
transitions from a period of capacity surplus to one of capacity deficit, and because there is no
uniform standard for capacity accreditation, there is a risk that overreliance on FOTs could lead
to underinvestment in resources needed to meet reliability standards.
Formal regional planning reserve sharing could offer multiple benefits in the Greater Northwest by taking
advantage of load and resource diversity that exists across the region. A system in which each utility builds
physical assets to meet its own needs could result in overcapacity, because not every system peaks at the
same time. Planning to meet regional coincident peak loads requires less capacity than meeting each
individual utility’s peak loads. Further, surplus resources in one area could be utilized to meet a deficit in
a neighboring area. Larger systems require lower reserve margins because they are less vulnerable to
individual, large contingencies. A regional entity could adopt more sophisticated practices and computer
models than individual utilities and manage capacity obligation requirements independent from the
utilities.
Table 25 provides a high-level estimate of the benefits that could accrue if the Northwest employed a
formal planning reserve sharing system. The benefits are divided into (1) benefits due to switching from
individual utility peak to regional peak and (2) benefits due to lower target PRM.
A regional planning reserve sharing system could be established in the Greater Northwest. A regional
entity could be created as a voluntary organization of utilities and states/provinces. The regional entity
would perform loss-of-load studies for the region and calculate the regional PRM and develop accurate
methods for estimating capacity credit of hydro and renewables. The entity would create a forward
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capacity procurement obligation based on studies and allocate responsibility based on their share of the
regional requirement.
Table 25. Possible Benefits from a Regional Planning Reserve Sharing System in the Northwest21
Capacity Requirement BPA + Area NWPP (US)
Individual Utility Peak + 15% PRM (MW) 33,574 46,398
Regional Peak + 15% PRM (MW) 32,833 42,896
Reduction (MW) 741 3,502
Savings ($MM/year) $89 $420
BPA + Area NWPP (US)
Regional Peak + 12% PRM (MW) 31,977 41,777
Reduction (MW) 1,597 4,621
Savings ($MM/year) $192 $555
Rules similar to other markets could be made for standardized capacity accreditation of individual
resources such as dispatchable generation, hydro generation, variable generation, demand response and
energy storage. Tradable capacity products could be defined based on the accredited capacity.
A regional entity could be formed by voluntary association in the Greater Northwest. It could be governed
by independent or stakeholder board. Alternatively, new functionality could be added to the existing
reserve sharing groups such as Northwest Power Pool (NWPP) and Southwest Reserve Sharing Group,
which expand their operating reserve sharing to include planning reserve sharing. It would not require
setting up a regional system operator immediately and PRM sharing could be folded into a regional system
operator if and when it forms.

21 Calculated regional and non-coincident peaks using WECC hourly load data averaged over 2006-2012. Savings value estimated using capacity cost
of $120/kW-yr. Assumes no transmission constraints within the region. Ignores savings already being achieved through bilateral contracts
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7 Conclusions
The Pacific Northwest is expected to undergo significant changes to its electricity generation resource mix
over the next 30 years due to changing economics of resources and more stringent environmental policy
goals. In particular, the costs of wind, solar, and battery storage have experienced significant declines in
recent years, a trend that is expected to continue. Greenhouse gas and other environmental policy goals
combined with changing economics have put pressure on existing coal resources, and many coal power
plants have announced plans to retire within the next decade.
As utilities become more reliant on intermittent renewable energy resources (wind and solar) and energy-
limited resources (hydro and battery storage) and less reliant on dispatchable firm resources (coal),
questions arise about how the region will serve future load reliably. In particular, policymakers across the
region are considering many different policies – such as carbon taxes, carbon caps, renewable portfolio
standards, limitations on new fossil fuel infrastructure, and others – to reduce greenhouse gas emissions
in the electricity sector and across the broader economy. The environmental, cost, and reliability
implications of these various policy proposals will inform electricity sector planning and policymaking in
the Pacific Northwest.
This study finds that deep decarbonization of the Northwest grid is feasible without sacrificing reliable
electric load service. But this study also finds that, absent technological breakthroughs, achieving 100%
GHG reductions using only wind, solar, hydro, and energy storage is both impractical and prohibitively
expensive. Firm capacity – capacity that can be relied upon to produce energy when it is needed the most,
even during the most adverse weather conditions – is an important component of a deeply-decarbonized
grid. Increased regional coordination is also a key to ensuring reliable electric service at reasonable cost
under deep decarbonization.
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7.1 Key Findings
1. It is possible to maintain Resource Adequacy for a deeply decarbonized Northwest electricity grid,
as long as sufficient firm capacity is available during periods of low wind, solar, and hydro
production;
o Natural gas generation is the most economic source of firm capacity today;
o Adding new gas generation capacity is not inconsistent with deep reductions in carbon
emissions because the significant quantities of zero-marginal-cost renewables will ensure
that gas is only used during reliability events;
o Wind, solar, demand response, and short-duration energy storage can contribute but
have important limitations in their ability to meet Northwest Resource Adequacy needs;
o Other potential low-carbon firm capacity solutions include (1) new nuclear generation,
(2) fossil generation with carbon capture and sequestration, (3) ultra-long duration
electricity storage, and (4) replacing conventional natural gas with carbon-neutral gas
such as hydrogen or biogas.
2. It would be extremely costly and impractical to replace all carbon-emitting firm generation
capacity with solar, wind, and storage, due to the very large quantities of these resources that
would be required;
o Firm capacity is needed to meet the new paradigm of reliability planning under deep
decarbonization, in which the electricity system must be designed to withstand prolonged
periods of low renewable production once storage has depleted; renewable overbuild is
the most economic solution to completely replace carbon-emitting resources but requires
a 2x buildout that results in curtailment of almost half of all wind and solar production.
3. The Northwest is expected to need new capacity in the near term in order to maintain an
acceptable level of Resource Adequacy after planned coal retirements.
4. Current planning practices risk underinvestment in the new capacity needed to ensure Resource
Adequacy at acceptable levels;
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o Reliance on market purchases or front-office transactions (FOTs) reduces the cost of
meeting Resource Adequacy needs on a regional basis by taking advantage of load and
resource diversity among utilities in the region;
o Capacity resources are not firm without a firm fuel supply; investment in fuel delivery
infrastructure may be required to ensure Resource Adequacy even under a deep
decarbonization trajectory;
o Because the region lacks a formal mechanism for ensuring adequate physical firm
capacity, there is a risk that reliance on market transactions may result in double-counting
of available surplus generation capacity;
o The region might benefit from and should investigate a formal mechanism to share
planning reserves on a regional basis, which may help ensure sufficient physical firm
capacity and reduce the quantity of capacity required to maintain Resource Adequacy
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Assumption Development Documentation
Appendix A. Assumption Development
Documentation
A.1 Baseline Resources
Table 26. NW Baseline Resources Installed Nameplate Capacity (MW) by Year.
Category Resource Class 2018 2030 2050
Thermal
Natural Gas 12,181 19,850 31,500
Coal 10,895 8,158 0
Nuclear 1,150 1,150 1,150
Total 24,813 29,745 33,237
Firm Renewable Geothermal 79.6 79.6 79.6
Biomass 489.2 489.2 489.2
Variable Renewables Wind 7,079 7,079 9,205
Solar 1,557 1,557 3,593
Hydro Hydro 35,221 35,221 35,221
Storage Storage 0 0 0
DR Shed Demand Response 600 2,200 5,500
Imports Imports* 3,400 3,400 3,400
*Imports consist of market purchases and non-summer firm imports. For more details, please refer to Imports
section.

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A.2 Portfolios of Different Scenarios

Table 27. Portfolios for 2030 scenarios – Installed Nameplate Capacity (GW) by Scenario
Resource Class Reference No Coal
Solar 1.6 1.6
Wind 7.1 7.1
DR 2.2 2.2
Hydro 35.2 35.2
Coal 8.2 -
Natural Gas 19.9 28.0
Nuclear 1.2 1.2
Bio/Geo 0.6 0.6
Storage - -
Imports 3.4 3.4

Table 28. Portfolios for 2050 scenarios – Installed Nameplate Capacity (GW) by Scenario
Resource Class Reference 60% GHG
Reduction
80% GHG
Reduction
90% GHG
Reduction
98% GHG
Reduction
100% GHG
Reduction
Solar 3.6 10.6 10.6 10.6 29.2 45.6
Wind 9.2 22.9 38.0 48.2 53.8 97.4
DR 5.5 5.5 5.5 5.5 5.5 5.5
Hydro 35.2 35.2 35.2 35.2 35.2 35.2
Coal - - - - - -
Natural Gas 31.5 25.5 23.5 19.5 13.5 -
Nuclear 1.2 1.2 1.2 1.2 1.2 1.2
Bio/Geo 0.6 0.6 0.6 0.6 0.6 0.6
Storage - 2.2
(4-hr)
2.2
(4-hr)
4.4
(4-hr)
6.7
(4-hr)
28.7
(6-hr)
Imports 3.4 3.4 3.4 3.4 3.4 -
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Assumption Development Documentation
Table 29. Zero Carbon Sensitivity Portfolios in 2050– Installed Nameplate Capacity (GW) by Scenario
Resource Class 100% GHG Reduction
Renewables
100% GHG Reduction
Baseload Tech
100% GHG Reduction
Long Duration Storage
100% GHG Reduction
Biogas
Solar 45.6 30.7 13.5 29.2
Wind 97.4 60.5 49.2 53.8
DR 5.5 5.5 5.5 5.5
Hydro 35.2 35.2 35.2 35.2
Coal - - - -
Natural Gas - - - 13.5
Nuclear 1.2 1.2 1.2 1.2
Bio/Geo 0.6 0.6 0.6 0.6
Storage 28.7
(6-hr)
18.0
(4-hr)
25.9
(926-hr)
6.7
(4-hr)
Clean Baseload - 11.3 - -
Imports - - - -
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© 2018 Energy and Environmental Economics, Inc.
RECAP Model Documentation
Appendix B. RECAP Model
Documentation
B.1 Background
RECAP is a loss-of-load-probability model developed by E3 to examine the reliability of electricity systems
under high penetrations of renewable energy and storage. In this study, RECAP is used to assess reliability
using the loss-of-load expectation (LOLE) metric. LOLE measures the expected number of hours/yr when
load exceeds generation, leading to a loss-of-load event.
LOLE is one of the most commonly used metrics within the industry across North America to measure the
resource adequacy of the electricity system. LOLE represents the reliability over many years and does not
necessarily imply that a system will experience loss-of-load every single year. For example, if an electricity
system is expected to have two 5-hour loss-of-load events over a ten-year period, the system LOLE would
be 1.0 hr./yr LOLE (10 hours of lost load over 10 years).
There is no formalized standard for LOLE sufficiency promulgated by the North American Electric
Reliability Coordinating Council (NERC), and the issue is state-jurisdictional in most places expect in
organized capacity markets. In order to ensure reliability in the electricity system, the Northwest Power
and Conservation Council (NWPCC) set reliability standards for the Pacific Northwest. The current
reliability standard requires the electricity system to have an annual loss of load probability (annual LOLP)
to be below 5%. This would mean loss-of-load events occur, on average, less than once in 20 years.
However, in a system with high renewables, LOLE is a more robust reliability metric.
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Resource Adequacy in the Pacific Northwest
B.2 Model Overview
RECAP calculates LOLE by simulating the electric system with a specific set of generating resources and
economic conditions under a wide variety of weather years, renewable generation years, hydro years,
and stochastics forced outages of generation and transmission resources, while accounting for the
correlation and relationships between these. By simulating the system thousands of times under different
combinations of these conditions, RECAP is able to provide a statistically significant estimation of LOLE.
B.2.1 LOAD
E3 modeled hourly load for the northwest under current economic conditions using the weather years
1948-2017 using a neural network model. This process develops a relationship between recent daily load
and the following independent variables:
 Max and min daily temperature (including one and two-day lag)
 Month (+/- 15 calendar days)
 Day-type (weekday/weekend/holiday)
 Day index for economic growth or other linear factor over the recent set of load data
The neural network model establishes a relationship between daily load and the independent variables
by determining a set of coefficients to different nodes in hidden layers which represent intermediate steps
in between the independent variables (temp, calendar, day index) and the dependent variable (load). The
model trains itself through a set of iterations until the coefficients converge. Using the relationship
established by the neural network, the model calculates daily load for all days in the weather record (1948-
2017) under current economic conditions. The final step converts these daily load totals into hourly loads.
To do this, the model searches over the actual recent load data (10 years) to find the day that is closest in
total daily load to the day that needs an hourly profile. The model is constrained to search within identical
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© 2018 Energy and Environmental Economics, Inc.
RECAP Model Documentation
day-type (weekday/weekend/holiday) and +/- 15 calendar days when making the selection. The model
then applies this hourly load profile to the daily load MWh.
This hourly load profile for the weather years 1948-2017 under today’s economic conditions is then scaled
to match the load forecast for future years in which RECAP is calculating reliability. This ‘base’ load profile
only captures the loads that are present on the electricity system today and do not very well capture
systematic changes to the load profile due to increased adoption of electric vehicles, building space and
water heating, industrial electrification. Load modification through demand response is captured through
explicit analysis of this resource in Section 0.
Operating reserves of 1,250 MW are also added onto load in all hours with the assumption being that the
system operator will shed load in order to maintain operating reserves of at least 1,250 MW in order to
prevent the potentially more catastrophic consequences that might result due to an unexpected grid
event coupled with insufficient operating reserves.
B.2.2 DISPATCHABLE GENERATION
Available dispatchable generation is calculated stochastically in RECAP using forced outage rates (FOR)
and mean time to repair (MTTR) for each individual generator. These outages are either partial or full
plant outages based on a distribution of possible outage states developed using NWPCC data. Over many
simulated days, the model will generate outages such that the average generating availability of the plant
will yield a value of (1-FOR).
B.2.3 TRANSMISSION
RECAP is a zonal model that models the northwest system as one zone without any internal transmission
constraints. Imports are assumed to be available as mentioned in Imports Section 4.2.3.
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Resource Adequacy in the Pacific Northwest
B.2.4 WIND AND SOLAR PROFILES
Hourly wind and solar profiles were simulated at all wind and solar sites across the northwest. Wind speed
and solar insolation data was obtained from the NREL Western Wind Toolkit22 and the NREL Solar
Prospector Database23, respectively and transformed into hourly production profiles using the NREL
System Advisor Model (SAM). Hourly wind speed data was available from 2007-2012 and hourly solar
insolation data was available from 1998-2014.
A stochastic process was used to match the available renewable profiles with historical weather years
using the observed relationship for years with overlapping data i.e., years with available renewable data.
For each day in the historical load profile (1948-2017), the model stochastically selects a wind profile and
a solar profile using an inverse distance function with the following factors:
 Season (+/- 15 days)
• Probability is 1 inside this range and 0 outside of this range
 Load
• For winter peaking systems like the northwest, high load days tend to have low solar
output
 Previous Day’s Renewable Generation
• High wind or solar days have a higher probability of being followed by a high wind or solar
day, and vice versa. This factor captures the effect of a multi-day low solar or low wind
event that can stress energy-limited systems that are highly dependent on renewable
energy and/or energy storage.
A graphic illustrating this process is shown in Figure 32

22 https://www.nrel.gov/grid/wind-toolkit.html
23 https://nsrdb.nrel.gov/
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© 2018 Energy and Environmental Economics, Inc.
RECAP Model Documentation
Figure 32: Renewable Profile Selection Process

B.2.5 HYDRO DISPATCH
Dispatchable hydro generation is a hybrid resource that is limited by weather (rainfall) but can still be
dispatched for reliability within certain constraints. It is important to differentiate this resource from non-
dispatchable hydro such as many run-of-river systems that produce energy when there is hydro available,
similar to variable wind and solar facilities, especially in a system like northwest which has an abundance
of hydro generation.
To determine hydro availability, the model uses a monthly historical record of hydro production data from
NWPCC’s records from 1929 – 2008. The same data is used to model hydro generation in NWPCC’s
GENESYS model. For every simulated load year, a hydro year is chosen stochastically from the historical
database. The study assumes no significant hydro build in the future and no correlation with temperature,
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000 75,000 80,000 85,000 90,000
Pr
e
v
i
o
u
s

D
a
y

R
e
n
e
w
a
b
l
e

G
e
n
e
r
a
t
i
o
n

(M
W
h
)
Today's Load (MWh)
❑Each blue dot represents a day in the actual renewable generation sample
❑Size of the blue dot represents the probability that the model chooses that day
based on the probability function
Day for which the model is trying to
predict renewable
generation
abs[loadAug 12 –loadi]/stderrload +

abs[renewAug 12 –renewi]/stderrrenew

Probability Function Choices
Inverse distanceSquare inverse distanceGaussian distance
Multivariate normal
Probability of sample i
being selected =Where distancei =
Pr
e
v
i
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s

D
a
y
’
s

D
a
i
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y

Re
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(M
W
h
)
Daily Load (MWh)
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Resource Adequacy in the Pacific Northwest
load or renewable generation. Once the hydro year is selected, the monthly hydro budgets denote the
amount of energy generated from hydro resources in that month. Since RECAP optimizes the hydro
dispatch to minimize loss-of-load, providing only monthly budgets can dispatch hydro extremely flexibly.
For example, some of the hydro can be held back to be dispatched during generator outages. Such high
flexibility in hydro dispatch is not representative of the current northwest hydro system. Therefore, the
monthly budget is further divided into weekly budgets to ensure hydro dispatch is in line with operating
practices in the northwest.
In addition to hydro budgets, hydro dispatch has other upstream and downstream hydrological and
physical constraints that are modeled in a hydrological model by NWPCC. RECAP does not model the
complete hydrological flow but incorporates all the major constraints such as sustained peaking
(maximum generation and minimum generation) limits. Sustained peaking maximum generation
constraint results in the average hydro dispatch over a fixed duration to be under the limit. Similarly,
minimum generation constraints ensure average dispatch over a fixed duration is above the minimum
generation sustainable limits. Sustainable limits are provided over 1-hour, 2-hour, 4-hour and 10-hour
durations.
The weekly budgets and sustained peaking limits together make the hydro generation within RECAP
representative of the actual practices associated with hydro generation in the northwest. Output from
RECAP are benchmarked against hydro outputs from NWPCC’s GENESYS model.
B.2.6 STORAGE
The model dispatches storage if there is insufficient generating capacity to meet load net of renewables
and hydro. Storage is reserved specifically for reliability events where load exceeds available generation.
It is important to note that storage is not dispatched for economics in RECAP which in many cases is how
storage would be dispatched in the real world. However, it is reasonable to assume that the types of
reliability events that storage is being dispatched for (low wind and solar events), are reasonably
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© 2018 Energy and Environmental Economics, Inc.
RECAP Model Documentation
foreseeable such that the system operator would ensure that storage is charged to the extent possible in
advance of these events. (Further, presumably prices would be high during these types of reliability events
so that the dispatch of storage for economics also would satisfy reliability objectives.)
B.2.7 DEMAND RESPONSE
The model dispatches demand response if there is still insufficient generating capacity to meet load even
after storage. Demand response is the resource of last resort since demand response programs often have
a limitation on the number of times they can be called upon over a set period of time. For this study,
demand response was modeled using a maximum of 10 calls per year, with each call lasting for a maximum
of 4 hours.
B.2.8 LOSS-OF-LOAD
The final step in the model calculates loss-of-load if there is insufficient available dispatchable generation,
renewables, hydro, storage, and demand response to serve load + operating reserves.
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Resource Adequacy in the Pacific Northwest
Appendix C. Renewable Profile
Development
The electricity grid in the Greater Northwest consists of significant quantities of existing wind and solar
generation. Significant new renewable build is expected to be built in the future, as explored in this study.
Representing the electricity generation from both existing and future renewable (solar and wind) resources
is fundamental to the analysis in this study. In this appendix section, the process of developing these
renewable profiles for both existing and new renewable resources is elaborated.
C.1 Wind Profiles
C.1.1 SITE SELECTION
Existing wind site locations (latitude and longitude) in the study region are obtained from NWPCC’s
generator database and WECC’s Anchor Data Set. New candidate wind sites are identified based on the
highest average wind speed locations across the Greater Northwest region using data published by NREL24
(see Figure 33).

24 https://maps.nrel.gov/wind-prospector/
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© 2018 Energy and Environmental Economics, Inc.
Renewable Profile Development
Figure 33: Wind speed data in the northwest (Source: NREL)

While striving to place new candidate wind sites in the windiest locations, the new candidate sites are spread
across each state in a way that they span a large geographical area in order to capture diversity in wind
generation (e.g. the likelihood that the wind will be blowing in one location even when it is not in another).
The new candidate sites used in this study are shown in Figure 34. New sites were aggregated geographically
into three single resources that were used in the study modeling: Northwest, Montana, and Wyoming. For
example, Montana wind in the study is represented as a single profile with new wind turbines installed
proportionally across the various “blue squares” shown in Figure 34.
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Resource Adequacy in the Pacific Northwest

Figure 34: New Candidate Solar and Wind Sites

C.1.2 PROFILE SIMULATION
NREL’s Wind Integration National Dataset (WIND) Toolkit25 contains historical hourly wind speed data from
2007-2012 for every 2-km x 2-km grid cell in the continental United States. This data is downloaded for each
selected site location (both existing and new sites).

25 https://www.nrel.gov/grid/wind-toolkit.html
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© 2018 Energy and Environmental Economics, Inc.
Renewable Profile Development
The amount of electricity generated from a wind turbine is a function of wind speed and turbine
characteristics, such as the turbine hub height (height above the ground), and the turbine power curve (the
mapping of the windspeed to the corresponding power output). Wind speeds increase with height above
the ground. Since all NREL WIND data is reported at 100-meters, the wind profile power law is used to scale
wind speeds to different heights, depending on the height of the turbine being modeled. This relationship is
modeled as:
𝑤 𝑑 𝑝 𝑑 ℎ 𝑔ℎ 𝑥
𝑤 𝑑 𝑝 𝑑 ℎ 𝑔ℎ 𝑦=(ℎ 𝑔ℎ 𝑥
ℎ 𝑔ℎ 𝑦)𝑤 𝑑 𝑠ℎ𝑒𝑎𝑟 𝑐𝑜𝑒𝑓𝑓 𝑐 𝑒 𝑡
A wind shear coefficient of 0.143 is used in this study.
A typical power curve is shown in Figure 35. Turbine power curves define the cut-in speed (minimum
windspeed for power generation), rated speed (minimum wind speed to achieve maximum turbine output),
cut-out speed (maximum wind speed for power generation) and power generation between the cut-in
speed and rated speed.
Figure 35: Typical Wind Turbine Power Curve

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Resource Adequacy in the Pacific Northwest
With the advancement of wind turbine technology, hub heights have increased over the years (see Figure
36). For existing wind resources, the hub heights are assumed to be the annual average hub height based
on the install year. For new turbines, hub height is assumed to be 100 meters.
Figure 36: Average turbine nameplate capacity, rotor diameter and hub height for land-based wind
project in the US

For existing turbines, Nordic 1000 54m 1 MW (MT) turbine power curve generates wind profiles that
benchmark well to the historical generation profiles. The validation process of turbine power curve selection
is described in greater detail in Section C.1.3. For new turbines, NREL standard power turbine curves are
used to produce future wind profiles.
The wind generation profiles simulation process can be performed for each 2 km X 2 km grid cell and are
usually limited to maximum power of 8 - 16 MW due to land constraints and the number of turbines that
can fit within that area. However, each wind site that is selected as described in Section C.1.1 (shown in
Figure 34), was modeled as 3 GW of nameplate installed wind capacity and encompasses hundreds of
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© 2018 Energy and Environmental Economics, Inc.
Renewable Profile Development
adjacent grid cells from the NREL WIND Toolkit database. Note that the actual installed wind capacity varies
by scenario in the study and so these 3 GW profiles were scaled up and down to match the installed capacity
of each specific scenario. The adjacent grid cells are chosen such that they are the closest in geographical
distance from the first wind site location (first grid cell). Representing a single wind site using hundreds of
grid cells represents wind production more accurately and irons out any local production spikes that are
limited to only a few grid cells in the NREL WIND Toolkit database.
C.1.3 VALIDATION
BPA publishes historical wind production data26 in its service territory. This data is used to identify a turbine
power curve that best benchmarks wind energy production from existing projects as simulated using
historical wind speed data. Three turbine power curves were tested – GE 1.5SLE 77m 1.5mW (MG), Nordic
1000 54m 1Mw (MT), and NREL standard. Based on annual capacity factors and hourly generation matching,
Nordic 1000 54m 1Mw (MT) turbine was selected to represent existing wind turbines in the study. These
benchmarking results are illustrated in Figure 37 and Figure 38.

26 https://transmission.bpa.gov/business/operations/wind/
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Resource Adequacy in the Pacific Northwest
Figure 37: Comparison of Annual Wind Capacity Factors for Benchmarking

Figure 38: Comparison of Hourly Historical Wind Generation to Simulated Wind Generation for January
2012

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© 2018 Energy and Environmental Economics, Inc.
Renewable Profile Development
C.2 Solar Profiles
C.2.1 SITE SELECTION
Existing solar site locations (latitude, longitude) in the study region are obtained from NWPCC’s generator
database and WECC’s Anchor Data Set. To build new candidate solar resources in the future, the best solar
sites in the region are identified based on the highest insolation from the solar maps published by NREL27
(see Figure 39). While striving to place new candidate wind sites in the sunniest locations, the new candidate
sites are spread across each state in a way that they span a large geographical area in order to capture
diversity in solar generation (e.g. the likelihood that the sun will be shining in one location even when it is
not in another). The future solar sites used in this study are shown in Figure 34.

27 https://maps.nrel.gov/nsrdb-viewer/
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Resource Adequacy in the Pacific Northwest
Figure 39: Solar insolation data in the northwest (Source: NREL)

C.2.2 PROFILE SIMULATION
NREL Solar Prospector Database 28 includes historical hourly solar insolation data: global horizontal
irradiance (GHI), direct normal irradiance (DNI), diffuse horizontal irradiance (DHI), and solar zenith angle
from 1998-2014. This data is downloaded for all each selected site location (both existing and new).

28 https://nsrdb.nrel.gov/
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© 2018 Energy and Environmental Economics, Inc.
Renewable Profile Development
The hourly insolation data is then converted to hourly production profiles using the NREL System Advisor
Model (SAM) simulator. Additional inputs used are tilt, inverter loading ratio and tracking type. All panels
are assumed to have a tilt equal to the latitude of their location. The study assumes an inverter loading ratio
of 1.3 and that all solar systems are assumed to be single-axis tracking. The NREL SAM simulator produces
an hourly time series of generation data that is used to represent the electricity generation from the solar
sites in this study.
Forty sites are aggregated to represent the solar candidate resource used in this study. These sites are evenly
distributed in the four states of Oregon, Washington, Idaho, and Utah as shown in Figure 34.

Page 1043 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated
Resource Plan
Appendix G – New Resource
Table for Transmission
Page 1044 Avista Corp. 2020 Electric IRP Appendices
Resource Capacity YearResourceNoteLocationPORPODStartStopMWTotal
Wind Avista System AVA.SYS AVA.SYS 1/1/2022 Indefinite 100.0
Wind Montana AVAT.NWMT AVA.SYS 1/1/2022 Indefinite 100.0 200.0
Wind Avista System AVA.SYS AVA.SYS 1/1/2023 Indefinite 100.0 100.0
Kettle Falls Kettle Falls, WA AVA.SYS AVA.SYS 1/1/2024 Indefinite 12.0 12.0
Pumped Hydro Mid-C MIDC AVA.SYS 1/1/2026 Indefinite 175.0
Rathdrum Rathdrum, WA AVA.SYS AVA.SYS 1/1/2026 Indefinite 24.0 199.0
Wind Off-System Colstrip/BPA AVA.SYS 1/1/2027 Indefinite 200.0
Post Falls Post Falls AVA.SYS AVA.SYS 1/1/2027 Indefinite 8.0 208.0
Hydro Mid-C MIDC AVA.SYS 1/1/2031 Indefinite 75.0 75.0
Hydro Long Lake AVA.SYS AVA.SYS 1/1/2035 Indefinite 68.0 68.0
Storage TBD AVA.SYS AVA.SYS 1/1/2036 Indefinite 25.0 25.0
Storage TBD AVA.SYS AVA.SYS 1/1/2038 Indefinite 25.0 25.0
Storage TBD AVA.SYS AVA.SYS 1/1/2040 Indefinite 25.0 25.0
Storage TBD AVA.SYS AVA.SYS 1/1/2041 Indefinite 25.0 25.0
Wind TBD AVA.SYS AVA.SYS 1/1/2042 Indefinite 100.0
Storage TBD AVA.SYS AVA.SYS 1/1/2042 Indefinite 25.0 125.0
Wind TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 100.0
Storage TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 100.0
Solar TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 5.0 205.0
Storage TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 75.0
Wind TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 50.0
Solar TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 50.0 175.0
Wind TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 100.0
Storage TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 100.0 200.0
Total 1667.0 1667.0
Appendix G
New Resource Table For Transmission
Page 1045 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated
Resource Plan
Appendix H – New Resource
Cost Assumptions
Please see Appendix H spreadsheet
Page 1046 Avista Corp. 2020 Electric IRP Appendices
2020 Electric Integrated
Resource Plan
Appendix I – Black and Veatch
Renewable Resource and
Storage Study
Page 1047 Avista Corp. 2020 Electric IRP Appendices

www.bv.com
18 James Gall Avista Corporation 1411 E. Mission Ave. Spokane, WA 99202 Subject: 2019 Avista Integrated Resource Plan Renewable Energy Assumptions Dear Mr. Gall: Black & Veatch Corporation (Black & Veatch) is providing this letter to summarize its review of the inputs for renewable energy and energy storage used in the Avista 2019 Integrated Resource Plan (IRP) process.
Background Avista Corporation (Avista) retained Black & Veatch to provide independent third-party services to review assumptions used for renewable energy and energy storage resources in the 2019 IRP process. Black & Veatch reviewed Avista’s supply side resource option inputs workbook, which includes estimates for values such as capital costs, operating costs, performance characteristics, maintenance requirements, emissions, Power Purchase Agreement (PPA) analyses, etc. for both conventional and renewable energy sources. Specifically, Avista asked Black & Veatch to review the workbook assumptions for upfront capital expenditures (CAPEX), operating & maintenance (O&M) costs, performance, and technology improvement curves for solar, wind, and energy storage resource categories. The purpose of the review was for Black & Veatch to opine on the reasonableness and suggest potential changes if necessary. To assist with the analysis, Black & Veatch used internal knowledge from projects with which it is aware in the Northwest, as well as publicly-available information from industry publications.
Supply Side Renewable Energy Resource Categories The list of supply side resources considered for the review are listed in Table 1.
Table 1: Supply Side Renewable Energy Resource Categories
CATEGORY TECHNOLOGY OWNERSHIP NW Wind On System (101.2 MW) Wind PPA NW Wind Off System (101.2 MW) Wind PPA
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| PAGE 2

CATEGORY TECHNOLOGY OWNERSHIP Wind Montana (101.2 MW) Wind PPA Off Shore Wind (100 MW) Wind PPA Solar PV, Fixed Array (5 MW AC) Solar PPA Solar PV, Single Axis Tracking (100 MW AC) Solar PPA Southern NW Solar PV, Single Axis Tracking (100 MW AC) Solar PPA Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) Solar/Storage PPA Distribution Scale 4hr Lithium-Ion Storage Utility Distribution Scale 8hr Lithium-Ion Storage Utility 4hr Lithium-Ion Storage Utility 8hr Lithium-Ion Storage Utility 16hr Lithium-Ion Storage Utility 40hr Lithium-Ion Storage Utility 4 hr Vanadium Flow Battery Storage Utility 4 hr Zinc Bromide Flow Battery Storage Utility
Capex Assumptions The CAPEX assumptions for supply side resources are listed in Table 2. All CAPEX values are 2018 nominal dollars.
Table 2: Supply Side Renewable Energy CAPEX Assumptions
CATEGORY CAPEX* ($/KWACNW Wind On System (101.2 MW) 1,533 NW Wind Off System (101.2 MW) 1,426 Wind Montana (101.2 MW) 1,426 Off Shore Wind (100 MW) 3,500 Solar PV, Fixed Array (5 MW AC) 1,400 Solar PV, Single Axis Tracking (100 MW AC) 1,157 Southern NW Solar PV, Single Axis Tracking (100 MW AC) 1,157
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| PAGE 3

CATEGORY CAPEX* ($/KWACSolar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 1,504 Distribution Scale 4hr Lithium-Ion 1,950 Distribution Scale 8hr Lithium-Ion 3,822 4hr Lithium-Ion 1,438 8hr Lithium-Ion 2,818 16hr Lithium-Ion 5,578 40hr Lithium-Ion 13,858 4 hr Vanadium Flow Battery 1,600 4 hr Zinc Bromide Flow Battery 1,800 * Excludes AFUDC Black & Veatch notes that there has been limited development of offshore wind projects in the United States, so cost estimates are subject to a higher degree of uncertainty. In addition, most energy storage technologies are undergoing significant development and commercialization, for which CAPEX estimates should also be considered with a higher degree of uncertainty. Overall, the CAPEX assumptions appear reasonable.
O&M Assumptions The O&M assumptions for supply side resources are listed in Table 2. All CAPEX values are 2018 nominal dollars.
Table 3: Supply Side Renewable Energy CAPEX Assumptions
CATEGORY
O&M COSTS
($/KW-YR) NW Wind On System (101.2 MW) 35.0 NW Wind Off System (101.2 MW) 35.0 Wind Montana (101.2 MW) 35.0 Off Shore Wind (100 MW) 90.0 Solar PV, Fixed Array (5 MW AC) 10.0 Solar PV, Single Axis Tracking (100 MW AC) 8.0
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CATEGORY
O&M COSTS
($/KW-YR) Southern NW Solar PV, Single Axis Tracking (100 MW AC) 8.0 Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 72.0 Distribution Scale 4hr Lithium-Ion 68.3 Distribution Scale 8hr Lithium-Ion 133.8 4hr Lithium-Ion 50.3 8hr Lithium-Ion 98.6 16hr Lithium-Ion 195.2 40hr Lithium-Ion 485.0 4 hr Vanadium Flow Battery 56.0 4 hr Zinc Bromide Flow Battery 63.0 As noted previously, there has been limited development of offshore wind projects or battery energy storage projects in the United States, so O&M estimates are subject to a higher degree of uncertainty. Overall, the O&M assumptions appear reasonable.
Performance Assumptions The capacity factor and round-trip efficiency values (for energy storage only) assumptions for supply side resources are listed in Table 3.
Table 4: Supply Side Renewable Energy Resource Performance Assumptions
CATEGORY
CAPACITY
FACTOR (%)
ROUND-TRIP
EFFICIENCY (%) NW Wind On System (101.2 MW) 37.0 n/a NW Wind Off System (101.2 MW) 37.0 n/a Wind Montana (101.2 MW) 48.0 n/a Off Shore Wind (100 MW) 50.0 n/a Solar PV, Fixed Array (5 MW AC) 25.0 n/a Solar PV, Single Axis Tracking (100 MW AC) 27.0 n/a
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CATEGORY
CAPACITY
FACTOR (%)
ROUND-TRIP
EFFICIENCY (%) Southern NW Solar PV, Single Axis Tracking (100 MW AC) 30.0 n/a Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 27.0 n/a Distribution Scale 4hr Lithium-Ion n/a 88 Distribution Scale 8hr Lithium-Ion n/a 88 4hr Lithium-Ion n/a 88 8hr Lithium-Ion n/a 88 16hr Lithium-Ion n/a 88 40hr Lithium-Ion n/a 88 4 hr Vanadium Flow Battery n/a 70 4 hr Zinc Bromide Flow Battery n/a 67 Actual capacity factor results for renewable energy resources are highly site-dependent and depend on factors such as weather patterns and site topography. However, the values used by Avista fall within expected ranges. Overall, the performance assumptions appear reasonable.
Technology Improvement Assumptions The technology improvement assumptions for supply side resources are listed in Table 4. These values refer to the aggregate industry learning curve of improving technology efficiency from experience and Research & Development efforts.
Table 5: Supply Side Renewable Energy Resource Technology Improvement Assumptions
CATEGORY
ANNUAL TECHNOLOGY
IMPROVEMENT (%) NW Wind On System (101.2 MW) 0.3 NW Wind Off System (101.2 MW) 0.3 Wind Montana (101.2 MW) 0.3 Off Shore Wind (100 MW) 0.3 Solar PV, Fixed Array (5 MW AC) 0.3
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CATEGORY
ANNUAL TECHNOLOGY
IMPROVEMENT (%) Solar PV, Single Axis Tracking (100 MW AC) 0.3 Southern NW Solar PV, Single Axis Tracking (100 MW AC) 0.3 Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 0.3 Distribution Scale 4hr Lithium-Ion 2.1 to 10.6 Distribution Scale 8hr Lithium-Ion 2.3 to 11.4 4hr Lithium-Ion 2.1 to 10.6 8hr Lithium-Ion 2.3 to 11.4 16hr Lithium-Ion 2.6 to 12.3 40hr Lithium-Ion 3.1 to 14.1 4 hr Vanadium Flow Battery 1.0 to 5.0 4 hr Zinc Bromide Flow Battery 1.0 to 8.0 Black & Veatch notes that solar, wind, and energy storage technologies have all experienced technical improvements over the past decade. While the rate of technology improvement is sometimes uneven, the general industry expectation is that renewable energy and energy storage technologies will continue to advance down the learning curve in future years. In general, the energy storage field is in earlier stages of development and commercialization, and is considered to be more likely to experience faster technological improvements compared to more mature technologies such as wind turbines and PV modules. Overall, the technology improvement assumptions appear reasonable.
Conclusions Black & Veatch reviewed the inputs for renewable energy and energy storage used in the Avista 2019 Integrated Resource Plan (IRP) process. The values used for CAPEX, O&M performance, and technology improvement assumptions appear reasonable and within the range expected for similar facilities.
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2020 Electric Integrated
Resource Plan
Appendix J – Confidential Report
of Portfolio #14
Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160
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