20180831Avista 2018 Natural Gas IRP.pdf

AlEvtsra
Avista Corp.
141 1 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
August 31,2018 Avu- G- tx'05
Diane Hanian, Secretary
Idaho Public Utilities Commission
Statehouse Mail
472 W. Washington Street
Boise, Idaho 83702
Dear Ms. Hanian:
RE: Avista Utilities 2018 Natural Gas Integrated Resource Plan (IRP)
Per the Idaho Commission's Integrated Resource Plan Requirements, outlined in Case No.U- I 500-
165, OrderNo.22299, Case No.GNR-E-93-1, OrderNo.24729 and Case No.GNR-E-93-3, Order
No. 25260, Avista Corporation dlblal Avista Utilities hereby submits for filing an original and
seven (7) copies of its 2018 Natural Gas Integrated Resource Plan. An electronic copy of the IRP
and appendices are also enclosed.
The Company submits the IRP to Public Utility Commissions in Idaho, Washington and Oregon
every two years as required by state regulation. A copy of the IRP and Appendices are being
provided electronically with each hard copy of the IRP (inside the front cover). Paper use and
printing costs have been reduced by putting supporting documents on our web site at
https://www.myavista.com/about-us/our-company/integrated-resource-planning.
Please direct any questions regarding the IRP to Tom Pardee at [phone] or myself at 509-
497-4975.
t/x
Gervais
' Manager, Regulatory Policy
Regulatory Affairs
Avista Utilities
linda. gervais@avistacorp. com
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\\201 I
Natural Gas
lntegrated Resource Plan
August 31, 2018
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Safe Harbor Statement
This document contains fonvard-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the Company's
control, and many of which could have a significant impact on the Company's operations,
results of operations and financial condition, and could cause actual results to differ
materially from those anticipated.
For a further discussion of these factors and other important factors, please refer to the
Company's reports filed with the Securities and Exchange Commission. The fonvard-
looking statements contained in this document speak only as of the date hereof. The
Company undertakes no obligation to update any foruard-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New risks,
uncertainties and other factors emerge from time to time, and it is not possible for
management to predict all of such factors, nor can it assess the impact of each such factor
on the Company's business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those contained in any fonruard-
looking statement.
TReLe or CoTTENTS
0
1
2
3
4
5
6
7
8
I
Executive Summary
lntroduction...........
Demand Forecasts
Demand Side Resources
Supply Side Resources..
...Page 1
...Page 15
...Page 27
...Page 47
..Page 87
Policy Considerations..Page 113
Page 121lntegrated Resource Portfolio... .. .
Alternate Scenarios, Portfolios, and Stochastic Analysis........Page 151
Distribution Planning Page 169
Action Plan. ...Page 179
Executive Summary
Executive Summary
Avista's 2O1B Natural Gas lntegrated Resource
Plan (lRP) identifies a strategic natural gas
resource portfolio to meet customer demand
requirements over the next 20 years. While the
primary focus of the IRP is meeting customers'
needs under peak weather conditions, this process
also evaluates customer needs under normal or
average conditions. The formal exercise of
bringing together customer demand forecasts with
comprehensive analyses of resource options,
including supply-side resources and demand-side
measures, is valuable to Avista, its customers,
regulatory agencies, and other stakeholders for
long-range planning.
IRP Process and Stakeholder
lnvolvement
The IRP is a coordinated effort by several Avista departments with input from our
Technical Advisory Committee (TAC), which includes Commission Staff, peer utilities,
customers, and other stakeholders. The TAC is a vital component of our IRP process that
provides a forum for discussing multiple perspectives, identifies issues and risks, and
improves analytical planning methods. TAC topics include natural gas demand forecasts,
price forecasts, demand-side management (DSt\4), supply-side resources, modeling
tools, distribution planning, and policy issues. The IRP process produces a resource
portfolio designed to serve our customers' natural gas needs while balancing cost and
risk.
Planning Environment
A longterm resource plan addresses the uncertainties inherent in any planning exercise.
Natural gas is an abundant No(h American resource with expectations for sufficient
supplies for many decades because of continuing technological advancements in
extraction. The use of natural gas in liquefied natural gas (LNG) exports, natural gas
vehicles, power generation and exports to Jt/exico will add demand for natural gas. We
model various sensitivities and scenarios to account for the uncertainties surrounding
supply and demand.
Avista Corp 2018 Natural Gas IRP
Chapter
Highlights
An increase in customer
forecast over 20 years
versus the 2016 IRP
Lower use per customer
Higher DSM potential
RNG and Hydrogen
considered in the
available resource stack
for the first time
Landfill RNG is a chosen
resource in the High
Growth & Low Prices
scenario
a
a
a
o
a
Executive Summary
Demand Forecasts
Avista defines eleven distinct demand areas in this IRP structured around the pipeline
transportation and storage resources that serve them. Demand areas include Avista's
service territories (Washington; ldaho; Medford/Roseburg, Oregon; Klamath Falls,
Oregon and La Grande, Oregon) and then disaggregated by the pipelines serving them.
The Washington and ldaho service territories include areas served only by Northwest
Pipeline (NWP), only by Gas Transmission Northwest (GTN), and by both pipelines. The
tMedford service territory includes an area served by NWP and GTN.
Weather, customer groMh and use-per-customer are the most significant demand
influencing factors. Other demand influencing factors include population, employment,
age and income demographics, construction levels, conservation technology, new uses
(e.9. natural gas vehicles), and use-per-customer trends.
Customers may adjust consumption in response to price, so Avista analyzed factors that
could influence natural gas prices and demand through price elasticity. These factors
include:
. Supply: shale gas, industrial use, and exports to lMexico and of LNG.
. lnfrastructure: regional pipeline projects, national pipeline projects, and
storage.
. Regulatory: subsidies, market transparency/speculation, and carbon
regulation.
. Other: drilling innovations, thermal generation and energy correlations (i.e.
oil/gas, coal/gas, and liquids/gas).
Avista developed a historical-based reference case and conducted sensitivity analysis on
key demand drivers by varying assumptions to understand how demand changes. Using
this information, and incorporating input from the TAC, Avista created alternate demand
scenarios for detailed analysis. Table 1 summarizes these demand scenarios, which
represent a broad range of potential scenarios for planning purposes. The Average Case
represents Avista's demand forecast for normal planning purposes. The Expected Case
is the most likely scenario for peak day planning purposes.
Avista Corp 2018 Natural Gas IRP 2
Executive Summary
Table 1: Demand Scenarios
The IRP process defines the methodology for the development of two primary types of
demand forecasts - annual average daily and peak day. The annual average daily
demand forecast is useful for preparing revenue budgets, developing natural gas
procurement plans, and preparing purchased gas adjustment filings. Forecasts of peak
day demand are critical for determining the adequacy of existing resources or the timing
for new resource acquisitions to meet our customers' natural gas needs in extreme
weather conditions. Table 2 shows the Average and Expected Case demand forecasts:
Table 2: Annual and Peak Demand Gases Dth/d
Annual Average Daily Demand - Expected average day, system-wide core demand
increases from an average of 93,900 dekatherms per day (Dth/day) in 2018 to 94,205
Dth/day in 2037. This is an annual average growth rate of 0.02 percent and is net of
projected conservation savings from DSM programs. Appendix 3.1 shows gross demand,
conservation savings and net demand.
Peak Day Demand - The peak day demand for the Washington, ldaho and La Grande
service territories is modeled on and around February 15 of each year. For the
southwestern Oregon service territories (Medford, Roseburg, Klamath Falls), the model
assumes this event on and around December 20 each year. Expected coincidental peak
day, or the sum of demand from each territories modeled peak, the system-wide core
demand increases from a peak of 377,206 Dth/day in 2018 to 427,852 Dth/day in 2037.
Forecasted non-coincidental peak day demand, or the sum of demand from the highest
single day including all forecasted territories, peaks at 347,228 Dth/day in 2018 and
3
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Alternate Weather Standard
80% below 1990 emissions
2018 IRP Demand Scenarios
2018 93,900 377,206 347,228
2037 94,205 427,852 392,601
Annual Average Daily
Demand
Peak Day Demand Non-coincidental
Peak Day DemandYear
Avista Corp 2018 Natural Gas IRP
Executive Summary
increases to 392,601 Dth/day in2037, a0.71percent average annualgroMh rate in peak
day requirements. This is also net of projected conservation savings from DSIM programs.
Figure '1 shows forecasted average daily demand for the six demand scenarios modeled
over the IRP planning horizon.
Figure 'l: Average Daily Demand (Net of DSM Savings)
110
100
90
80
70
60
50
40
*Expected Case
-lsry
Growth & High Prices
+80 % Below 1990 Emissions
-cold
Day 20yr weather std
High Growth & Low Prices
Average Case
Figure 2 shows forecasted system-wide peak day demand for the six demand scenarios
modeled over the IRP planning horizon.
4Avista Corp 2018 Natural Gas IRP
Figure 2: Peak Day Demand Scenarios (Net of DSM Savings)
-80
% Below 1990 Emissions
-Cold
Day 20yr Weather Std
Executive Summary
High Growth & Low Prices
Average Case
400
350
300
2so
200
150
100
d
*Expected Case
-[6ry
Growth & High prices
Natural Gas Price Forecasts
Natural gas prices are a fundamental component of integrated resource planning as the
commodity price is a significant element to the total cost of a resource option. Price
forecasts affect the avoided cost threshold for determining cost-effectiveness of
conservation measures. The price of natural gas also influences the consumption of
natural gas by customers. A price elasticity adjustment to use-per-customer reflects
customer responses to changing natural gas prices.
As more information surfaces about the costs and volumes produced by shale gas there
appears to be market consensus that production costs will remain lowfor quite some time.
Avista expects continued low prices even with increased incremental demand for LNG,
exports to [\4exico, transportation fuels, and increased industrial consumption.
Avista expects carbon legislation at the state level through a cap and trade (Oregon) or a
tax mechanism (Washington). Current IRP price forecasts include a considerably higher
carbon adder in Oregon and Washington, but no carbon cost in ldaho. Avista analyzed
Avista Corp 2018 Natural Gas IRP 5
Executive Summary
three carbon sensitivities and their impact on demand forecasts to address the uncertainty
about carbon legislation.
Avista combined forward prices with two fundamental price forecasts from credible
industry sources for an expected price strip at the Henry Hub. A high and low price were
developed to vary the price in a symmetrical fashion based off of the expected price curve.
These three price curves represent a reasonable range of pricing possibilities for this IRP
analysis. The array of prices provides necessary variation for addressing uncertainty of
future prices. Figure 3 depicts the price forecasts used in this lRP.
Figure 3: LodMedium/High Henry Hub Forecasts (Nominal $/Dth)
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Low Price ofxps6ted Price
Historical statistical analysis shows a long run consumption response to price changes.
ln order to model consumption response to these price curves, Avista utilized an expected
elasticity response factor of -0.10, for every 10% of price movement, as found in our
tVedford/Roseburg service territory, and applied it under various scenarios and
sensitivities.
Existing and Potential Resources
Avista has a diversified portfolio of natural gas supply resources, including access to and
contracts for the purchase of natural gas from several supply basins; owned and
Avista Corp 2018 Natural Gas IRP 6
-fligh
prigs
Executive Summary
contracted storage providing supply source flexibility; and firm capacity rights on six
pipelines. For potential resource additions, Avista considers incremental pipeline
transportation, storage options, distribution enhancements, and various forms of LNG
storage or service. Beginning in Avista's 2020 IRP and all future planning documents and
analysis thereafter, Avista intends to include conservation as a potential resource
addition.
Avista models aggregated conservation potentialthat reduces demand if the conservation
programs are cost-effective over the planning horizon. The identification and
incorporation of conservation savings into the SENDOUT@ model utilizes projected
natural gas prices and the estimated cost of alternative supply resources. The operational
business planning process starts with IRP identified savings and ultimately determines
the near-term program offerings. Avista actively promotes cost-effective DSM measures
to our customers as one component of a comprehensive strategy to arrive at a mix of best
cosUrisk adjusted resources.
Resource Needs
ln all cases, except for the High Growth and Low price scenario, the analysis showed no
resource deficiencies in the 2l-year planning horizon given Avista's existing supply
resources. Avista is not resource deficient in the Expected Case in the 2}-year planning
horizon.
Figures 5 through 8 illustrate Avista's peak day demand by service territory for both this
and the prior lRP. These charts compare existing peak day resources to expected peak
day demand by year and show the timing and extent of resource deficiencies, if any, for
the Expected Case. Based on this information, and more specifically where a resource
deficiency is nearly present as shown in Figure 6 & 8, Avista has time to carefully monitor,
plan and take action on potential resource additions as described in the Ongoing Activities
section of Chapter 9 - Action Plan. Any underutilized resources will be optimized to
mitigate the costs incurred by customers until the resource is required to meet demand.
This management of long- and short-term resources provides the flexibility to meet firm
customer demand in a reliable and cost-effective manner as described in Supply Side
Resources - Chapter 4.
7Avista Corp 2018 Natural Gas IRP
Executive Summary
Figure 5: Expected Case - WA & lD Existing Resources vs. Peak Day Demand
(Net of DSM)
Figure 6: Expected Case - Medford/Roseburg Existing Resources vs. Peak Day Demand
(Net of DSM)
Dth
120,000
100,000
80,000
60,000
40,000
20,000
0
"$ .ti" "d "et "d} "dP "dP "$ "S "&" "S "&" "d "&" "S "dp "dP "&" "d "e"IExistingGTN IExistingNWP r-----TJPTF-2 -G-PeakDayDemand PriorlRP PeakDayDemand
8
Dth
400,000
350,000
300,000
250,000
200,000
150,000
r.00,000
50,000
0
,o" "d "$et "d) "dP "dP "S "^d "..r" "$ "..p" "d "e" "d) "-f dP
"&" "d "e" "dIExisting GTN
ISpokane Supply
IExisting NWP
-+Peak Day Demand
I-IJP TF-2
Prior IRP Peak Day Demand
Avista Corp 2018 Natural Gas IRP
Executive Summary
Figure 7: Expected Case - Klamath Falls Existing Resources vs. Peak Day Demand
(Net of DSM)
Dth
22,OOO
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
"$ "dP "d 4}"
"d> "dP "of "of "d "s," "$ "dt. "d "&" "d) "dP "dP "-p" "d "e"
I Klamath Lateral +Peak Day Demand Prior IRP Peak Day Demand
Figure 8: Expected Case - La Grande Existing Resources vs. Peak Day Demand
(Net of DSM)
Dth
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
"tI. "dP "..gt "dP "dP "dP "dF "of dr" "S "tpt "d "&t "dl "dry "dP "&" "-d "&" "dIExisting NWP r---lJP TF-2 --rFPeak Day Demand Prior IRP Peak Day Demand
I
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IAvista Corp 2018 Natural Gas IRP
Executive Summary
A critical risk remains in the slope of forecasted demand growth, which although
increasing continues to be almost flat in Avista's current projections. This outlook implies
that existing resources will be sufficient within the planning horizon to meet demand.
However, if demand groMh accelerates, the steeper demand curve could quickly
accelerate resource shortages by several years. Figure 9 conceptually illustrates this risk.
ln this hypothetical example, a resource shortage does not occur until year eight in the
initial demand case. However, the shortage accelerates by five years under the revised
demand case to year three. This "flat demand risk" requires close monitoring of
accelerating demand, as well as careful evaluation of lead times to acquire the preferred
incremental resource.
Figure 9: Hypothetical Flat Demand Risk Example
Alternate Demand Scenarios
Avista performed the same analysis for five other demand scenarios: Average, High
Growth/Low Price,80 Percent Below 1990 Emissions, Low Growth/High Price, and
Coldest in 20 Years. As expected, the High Growth/Low Price scenario has the most rapid
growth and is the only scenario with unserved demand. This "steeper" demand lessens
the "flat demand risk" discussed above, yet resource deficiencies occur late in the
planning horizon. Figure 10 shows first year resource deficiencies under each scenario.
Avista Corp 2018 Natural Gas IRP 10
Demand
7
6
5
4
3
2
1
0
Years 1 2 4 5 6 7 9 10
Resources *lnitial Demand +Revised Demand
T'o
othtrf
T'g(!
Eoo
l!I
]h
Executive Summary
Figure 10: Scenario Comparisons of First Year Peak Demand Not Met with Existing
Resources
WA/ID Medford/Roseburg Klamath La Grande
2018
20L9
2020
202L
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
I Expected CaseI Low Growth & High Prices
.80% Below L990 EmissionsI Cold Day 20yr Weather Std
High Growth & Low Prices
Average Case
lssues and Challenges
Even with the planning, analysis, and conclusions reached in this lRP, there is still
uncertainty requiring diligent monitoring of the following issues.
Demand lssues
Although the future customer growth trajectory in Avista's service territory has slightly
increased compared to the 2016 lRP, the need in considering a range of demand
scenarios provides insight into how quickly resource needs can change if demand varies
from the Expected Case.
With a rise in natural gas supply and subsequent low costs, there is increasing interest in
using natural gas. Avista does not anticipate traditional residential and commercial
customers will provide increased growth in demand. Power generation from natural gas
is increasingly being used to back up solar and wind technology as well as replacing
retired coal plants. Exports of LNG and to lMexico currently have a demand of over 7
Bcf/day. With additional LNG plants forecasted to come online in the next few years
combined with additional pipeline infrastructure build into [/exico increases demand from
these areas to nearly 13.5 Bcf. There is already a higher demand for exports to [\4exico
and more LNG plants have come online and are now lookingfor 4 Bcf per day on average.
Avista Corp 2018 Natural Gas IRP 11
Executive Summary
[Most of these emerging markets will not be core customers of the LDC, but could affect
regional natural gas infrastructure and natural gas pricing if an LNG export facility is built
in the area.
Price lssues
Shale oil and gas drilling technology is adding an abundant amount of supply at low cost.
This is primarily due to increasingly efficient drilling technology and the rapid
advancement in understanding of drilling shale wells. ln areas such as the eastern United
States, shale production is so prolific the entire flow of gas on the pipeline infrastructure
has changed and is now flowing out of the highest demand areas in the US. This supply
also flows into Canada and across the U.S. ln western Canada there are some large and
very capital intensive oil sands projects where production will continue regardless of the
price of natural gas. ln the past, this natural gas would commonly find its home in the U.S.
Canadian natural gas has become somewhat stranded within the western half of North
America and is creating a very low price environment. This new paradigm, benefits
Northwest consumers as the prices for Canadian gas have deep discounts as compared
to the Henry Hub.
LNG Exports
Liquefied natural gas is a process of chilling natural gas to -260 degrees Fahrenheit to
create a condensed version, 1/600 the volume, of natural gas. This process acts as a
virtual pipeline taking domestic production to nearly any location in the world. For years
the U.S. was expected to be an importer of LNG. This is a stark contrast to reality as in
2017 the export of LNG from the U.S. has quadrupled led by two projects, Sabine Pass
in Louisiana and Cove Point in Maryland. ln recent history, this market dynamic has
changed from fixed price gas contracts to more spot purchases of LNG. The three largest
countries for U.S. LNG exports are Mexico, South Korea and China. Waiting in the wings
to provide more LNG supply are four additional export facilities located mostly in the gulf
coast region of the U.S. and will bring the total export capacity to nearly 10 Bcf per day
by 2019. ln 2020, the U.S. is expected to become the third largest exporter of LNG in the
world. Canadian LNG is on a slower construction pace, but has a new ray of light in the
LNG Canada project. Though as a whole and when compared to the U.S., environmental
concerns and policies are having a larger impact on investment decisions in these
projects. lf and when LNG plants are constructed, exporting LNG can alter the price,
constrain existing pipeline networks, stimulate development of new pipeline resources,
and change flows of natural gas across North America.
Action Plan
Avista's 2019-2020 Action Plan outlines activities for study, development and preparation
for the 2020 lRP. The purpose of the Action Plan is to position Avista to provide the best
Avista Corp 2018 Natural Gas IRP 12
Executive Summary
cosUrisk resource portfolio and to support and improve IRP planning. The Action Plan
identifies needed supply and demand side resources and highlights key analytical needs
in the near term. lt also highlights essential ongoing planning initiatives and natural gas
industry trends Avista will monitor as a part of its ongoing planning processes (Chapter 9
- Action Plan).
Key ongoing components of the Action Plan include:
1. Avista's 2020 IRP will contain an individual measure level for dynamic DStt/
program structure in its analytics. ln prior IRP's, it was a deterministic method
based on based on Expected Case assumptions. ln the 2020 lRP, each porlfolio
will have the ability to select conservation to meet unserved customer demand.
Avista will explore methods to enable a dynamic analytical process for the
evaluation of conservation potential within individual portfolios.
2. Work with Staff to get clarification on types of natural gas distribution system
analyses for possible inclusion in the 2020 lRP.
3. Work with Staff to clarify types of distribution system costs for possible inclusion in
our avoided cost calculation.
4. Revisit coldest on record planning standard and discuss with TAC for prudency.
5. Provide additional information on resource optimization benefits and analyze risk
exposure
6. DSIV-lntegration of ETO and AEG/CPA data. Discuss the integration of ETO and
AEG/CPA data as well as past program(s) experience, knowledge of current and
developing markets, and future codes and standards.
7. Carbon Costs - consult Washington State Commission's Acknowledgement Letter
Attachmenf in its 2017 Electric IRP (Docket UE-161036), where emissions price
modelling is discussed, including the cost of risk of future greenhouse gas
regulation, in addition to known regulations.
8. Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.
9. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
Avista Corp 2018 Natural Gas IRP 13
a
Executive Summary
Natural gas infrastructure investment not included as discrete projects in IRP
Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
of system associated with reliability
. lncluding, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
Anticipated PHil/SA guidance or rules related to 49 CFR Part 5192
that will likely requires additional capital to comply
. Officials from both PHtt/SA and the AGA have indicated it is not
prudent for operators to wait for the federal rules to become final
before improving their systems to address these expected rules.
Construction of gas infrastructure associated with groMh
Other special contract projects not known at the time the IRP was
published
Other non-lRP investments common to all jurisdictions that are ongoing, for
example:
Enterprise technology projects & programs
Corporate facilities capital maintenance and improvements
a
Ongoing Activities
Meet regularly with Commission Staff to provide information on market activities and
significant changes in assumptions and/or status of Avista activities related to the IRP or
natural gas procurement practices.
Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.
Conclusion
Slightly higher customer groMh continues to be offset by lower use-per-customer and an
increased amount of DSM. This has eliminated the need for Avista to acquire additional
supply-side resources, therefore appropriate management of underutilized resources to
reduce costs until resources are needed is essential. The combination of low priced
natural gas in addition to carbon taxes or other programs has led to a higher potential for
DSM measures as compared to the previous three IRP's. The IRP has many objectives,
but foremost is to ensure that proper planning enables Avista to continue delivering safe,
reliable, and economic natural gas service to our customers.
Avista Corp 2018 Natural Gas IRP 14
Chapter 1 : lntroduction
1: lntroduction
Avista is involved in the production, transmission
and distribution of natural gas and electricity, as
well as other energy-related businesses. Avista,
founded in 1889 as Washington Water Power,
has been providing reliable, efficient and
reasonably priced energy to customers for over
130 years.
Avista entered the natural gas business with the
purchase of Spokane Natural Gas Company in
1958. ln 1970, it expanded into natural gas
storage with Washington Natural Gas (now Puget
Sound Energy) and El Paso Natural Gas (its
interest subsequently purchased by NWP) to
develop the Jackson Prairie natural gas
underground storage facility in Chehalis,
Washington. ln 1991 , Avista added 63,000 customers with the acquisition of CP
National Corporation's Oregon and California properties. Avista sold the California
properties and its 18,000 South Lake Tahoe customers to Southwest Gas in 2005.
Figure 1 .1 shows where Avista currently provides natural gas service to approximately
348,000 customers in eastern Washington, northern ldaho and several communities in
northeast and southwest Oregon. Figure 1.2 shows the number of natural gas
customers by state.
Chapter
Highlights
. High amount of
uncertainty in long-term
forecasting
. Sensitivities help to
understand risk of
uncertainty
. Seasonal demand
r 348,000 natural gas
customers
I
I
Avista Corp 2018 Natural Gas IRP 15
Chapter 1 : lntroduction
Figure 1.1 : Avista's Natural Gas Service Territory
TYE8TERTU
CA]TAOIAII
AEOITIEilTANV
g..rtl.
golr.
Orffi ROCXTES AASTN
Figure 1.2: Avista's Natural Gas Customer Counts
r Washington r Oregon ldaho
Total 348,000
Washington
163,000
Oregon
102,000
Avista Corp 2018 Natural Gas IRP 16
Avista Natural Gas Service Areas, Gas Fields,
Trading Flubs and Major Pipelines
r(tt
a AFrla SrrYiaa ll.ritary
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83.000
Chapter 1 : lntroduction
Avista's natural gas operations covers 30,000 square miles in eastern Washington,
northern ldaho and portions of southern and eastern Oregon, with a population of 1.6
million. The company manages its natural gas operation through the North and South
operating divisions:
. The North Division includes Avista's eastern Washington and northern ldaho
service area which is home to over 800,000 people. lt includes urban areas, farms,
timberlands, and the Coeur d'Alene mining district. Spokane is the largest
metropolitan area with a regional population of approximately 490,000 followed
by the Lewiston, ldaho/Clarkston, Washington, and Coeur d'Alene, ldaho, areas.
The North Division has about 75 miles of natural gas transmission pipeline and
5,400 miles in the distribution system. The North Division receives natural gas at
more than 40 points along interstate pipelines for distribution to over 246,000
customers.
The South Division serves four counties in southern Oregon and one county in
eastern Oregon. The combined population of these areas is over 500,000
residents. The South Division includes urban areas, farms and timberlands. The
Medford, Ashland and Grants Pass areas, located in Jackson and Josephine
Counties, is the largest single area served by Avista in this division with a regional
population of approximately 297,000. The South Division consists of about 15
miles of natural gas transmission main and 2,400 miles of distribution pipelines.
Avista receives natural gas at more than 20 points along interstate pipelines and
distributes it to more than 102,000 customers.
a
Gustomers
Avista provides natural gas services to both core and transportation-only customer
classes. Core or retail customers purchase natural gas directly from Avista with delivery
to their home or business under a bundled rate. Core customers on firm rate schedules
are entitled to receive any volume of natural gas they require. Some core customers are
on interruptible rate schedules. These customers pay a lower rate than firm customers
because their service can be interrupted. lnterruptible customers are not considered in
peak day IRP planning.
Transportation-only customers purchase natural gas from third parties who deliver the
purchased gas to our distribution system. Avista delivers this natural gas to their
business charging a distribution rate only. Avista can interrupt the delivery service when
following the priority of service tariff. The long-term resource planning exercise excludes
transportation-only customers because they purchase their own natural gas and utilize
their own interstate pipeline transportation contracts. However, distribution planning
includes these customers.
Avista Corp 2018 Natural Gas IRP 17
Chapter 1 : lntroduction
Avista's core or retail customers include residential, commercial and industrial
categories. [\4ost of Avista's customers are residential, followed by commercial and
relatively few industrial accounts (Figure 1.3).
Figure 1.3: Firm Customer Mix
wA/rD
Customer
Make up
Oregon
Customer
Make up
Com
9.68%
Res
90.23%
Com
LL.67%
Res
88.307o
Avista Corp 2018 Natural Gas IRP 18
Chapter 1 : lntroduction
The customer mix is more balanced between residential and commercial accounts on
an annual volume basis (Figure 1.4). Volume consumed by core industrial customers is
not significant to the total, partly because most industrial customers in Avista's service
territories a re tran sportatio n-on ly customers.
Figure 1.4 Therms by Class
wA/rD
Customer
Demand
Oregon
Customer
Demand
Res
s4.40%
Com
35.47%
Res
6L5L%
Com
42.97%
lnd
2.63"/,
Avista Corp 2018 Natural Gas IRP 19
Chapter 1 : lntroduction
Core customer demand is seasonal, especially residential accounts in Avista's service
territories with colder winters (Figure 1.5). lndustrial demand, which is typically not
weather sensitive, has very little seasonality. However, the La Grande service territory
has several industrially classified agricultural processing facilities that produce a late
summer seasonal demand spike.
Figure 1.5: Customer Demand by Service Territory
1.cfi,tm
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hn ,b& |.r al' t( .ln tU lq LF t& fil 6c trn Ftb rttrr AIr $r.* lm |.1 art La' $fi t,r Dr(
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Industrial
lntegrated Resource Planning
Avista's IRP involves a comprehensive analytical process to ensure that core firm
customers receive long{erm reliable natural gas service at a reasonable price. The IRP
evaluates, identifies, and plans for the acquisition of an optimal combination of existing
and future resources using expected costs and associated risks to meet average daily
and peak-day demand delivery requirements over a 2O-year planning horizon.
Purpose of the IRP
Avista's 2018 Natural Gas IRP:
. Provides a comprehensive long-range planning tool;
. Fully integrates forecasted requirements with existing and potential resources;
utm
Avista Corp 2018 Natural Gas IRP 20
Werhln6otr/ldeho lrtrdfiord/Roceburg
tm.m
,rom
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iqd
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ET
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tu irn
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III
E
Chapter 1 : lntroduction
Determines the most cost-effective, risk-adjusted means for meeting future
demand requirements; and
[Veets Washington, ldaho and Oregon regulations, commission orders, and other
applicable guidelines.
Avista's IRP Process
The natural gas IRP process considers:
. Customer growth and usage;
. Weather planning standard;
. Conservation opportunities;
. Existing and potential supply-side resource options;
. Current and potential legislation/regulation;
. Risk; and
. Least cost mix of supply and conservation.
Public Participation
Avista's TAC members play a key role and have a significant impact in developing the
lRP. TAC members included Commission Staff, peer utilities, government agencies,
and other interested parties. TAC members provide input on modeling, planning
assumptions, and the general direction of the planning process.
Avista sponsored four TAC meetings to facilitate stakeholder involvement in the 2018
lRP. The first meeting convened on January 25,2018 and the last meeting occurred on
I\Aay 10,2018. t\4eetings are at a variety of locations convenient for stakeholders and
are electronically available for those unable to attend in person. Each meeting included
a broad spectrum of stakeholders. The meetings focused on specific planning topics,
reviewing the progress of planning activities, and soliciting input on IRP development
and results. TAC members received a draft of this IRP on July 2,2018 for their review.
Avista appreciates all of the time and effort TAC members contributed to the IRP
process; they provided valuable input through their participation in the TAC process. A
list of these organizations can be found below (Table 1.1).
a
a
Avista Corp 2018 Natural Gas IRP 21
Cascade Natural Gas Northwest lndustrial Gas
Users
Oregon Public Utility
Commission
Fortis Northwest Natural Gas Puget Sound Energy
ldaho Public Utilities
Commission
Williams - Northwest
Pipeline
TransCanada
Northwest Gas Association Washington Utilities and
Transportation Commission
Chapter 1 : lntroduction
Table 1.1: TAC Member Participation
Preparation of the IRP is a coordinated endeavor by several departments within Avista
with involvement and guidance from management. We are gratefulfor their efforts and
contributions.
Reg ulatory Requirements
Avista submits a natural gas IRP to the public utility commissions in ldaho, Oregon and
Washington on or before August 31 every two years as required by state regulation. There
is a statutory obligation to provide reliable naturalgas service to customers at rates, terms
and conditions that are fair, just, reasonable and sufficient. Avista regards the IRP as a
means for identifying and evaluating potential resource options and as a process to
establish an Action Plan for resource decisions. Ongoing investigation, analysis and
research may cause Avista to determine that alternative resources are more cost effective
than resources reviewed and selected in this lRP. Avista will continue to review and refine
our understanding of resource options and will act to secure these risk-adjusted, least-
cost options when appropriate.
Planning Model
Consistent with prior lRPs, Avista used the SENDOUT@ planning model to perform
comprehensive natural gas supply planning and analysis for this lRP. SENDOUT@ is a
linear programming-based model that is widely used to solve natural gas supply,
storage and transportation optimization problems. This model uses present value
revenue requirement (PVRR) methodology to perform least-cost optimization based on
daily, monthly, seasonal and annual assumptions related to the following:
. Customer groMh and customer natural gas usage to form demand forecasts;
. Existing and potential transportation and storage options and associated costs;
. Existing and potential natural gas supply availability and pricing;
Avista Corp 2018 Natural Gas IRP 22
Chapter 1 : lntroduction
. Revenue requirements on all new asset additions;
. Weather assumptions; and
. Conservation.
Avista incorporated stochastic modeling by utilizing a SENDOUT@ module to simulate
weather and price uncertainty. The module generates Monte Carlo weather and price
simulations, running concurrently to account for events and to provide a probability
distribution of results that aid resource decisions. Some examples of the types of
stochastic analysis provided include:
. Price and weather probability distributions;
. Probability distributions of costs (i.e. system costs, storage costs, commodity
costs); and
. Resource mix (optimally sizing a contract or asset level of competing resources)
These computer-based planning tools were used to develop the 2O-year best cosUrisk
resource portfolio plan to serve customers.
Planning Environment
Even though Avista publishes an IRP every two years, the process is ongoing with new
information and industry related developments. ln normal circumstances, the process can
become complex as underlying assumptions evolve, impacting previously completed
analyses. Widespread agreement on the availability of shale gas and the ability to
produce it at lower prices has increased interest in the use of natural gas for LNG and
[\4exico exports and industrial uses. One of the most prominent risks in the IRP involves
policies meant to decrease the use of natural gas as outlined in Chapter 5. These policies
are becoming more frequent in Oregon and Washington with of goal of reducing the
amount of direct use natural gas. However, there is uncertainty about the timing and size
of those policy decisions.
Avista Corp 2018 Natural Gas IRP 23
Chapter 1 : lntroduction
IRP Planning Strategy
Planning for an uncertain future requires robust analysis encompassing a wide range of
possibilities. Avista has determined that the planning approach needs to:
o Recognize historical trends may be fundamentally altered;
. Critically review all modeling assumptions;
. Stress test assumptions via sensitivity analysis;
o Pursue a spectrum of scenarios;
. Develop a flexible analytical framework to accommodate changes; and
. [vlaintain a longterm perspective.
With these objectives in mind, Avista developed a strategy encompassing all required
planning criteria. This produced an IRP that effectively analyzes risks and resource
options, which sufficiently ensures customers will receive safe and reliable energy
delivery services with the best-risk, lease-cost, long-term solutions. The following chart
summarizes significant changes from the 2016 IRP (Table 1 .2).
Avista Corp 2018 Natural Gas IRP 24
Chapter
Demand
DSM
Environmental
lssues
lssue
Expected
Customer Growth
CPA potential
Carbon Dioxide
Emission (Carbon)
2018 NaturalGas IRP
Expected Case - system wide
- growth is slightly higher at
1.2%.
Higher price curve and
conservation potential as a
system.
Cumulative Savings over 20
years:
lD:21.1 Million Therms
OR: 17.2 Million Therms
WA: 41.4 Million Therms
Carbon costs are now broken
out by state allowing for
different policy considerations
across jurisdictions.
lD: No federal or State
initiatives ($0)
OR: HB 4001 & SB 1507
($1z.ao - $51.58)
wA - ssB 6203 ($10 - $30)
*Prices are in dollars per
MTCO2e
A higher price curve with
slightly higher conservation
potential.
The only case that identifies a
resource deficiency is the High
Growth/Low Price scenario.
Avista solved this case by
using existing resources plus
added contracted capacity on
GTN. Landfill RNG is also
selected as a resource in ,
Idaho. Also selected is the
upsized compressor on the
Medford lateral.
Prices
Supply Side
Resources
Price Curve
Supply Side
Scenarios
Table 1.2: Summary of changes from the 2016 IRP
Chapter 1 : lntroduction
2016 Natural Gas IRP
Expected Case customer
groMh is 1.1o/o compounded
annually.
Lower Price curve can drive
the conservation potential-
downward.
Three sensitivities on level of
carbon tax ($/ton) were
compared. The expected
case has a probability of 2
sigma of the likely policy.
The remainder of probability
equally assumed to Low and
Washington State's l-732
were used to represent the
tails in a normaldistribution.
The base carbon case is the
expected case. The high and
low cases help bracket the
base case results.
Lower Price curve can drive
the conservation potential-
downward.
The only case that identifies
a resource deficiency is the
High Growth/Low Price
scenario. Avista solved this
case by using existing
resources plus added
contracted capacity on GTN
forWA/lD. ln Klamath Falls,
Medford and Roseburg an
upsized compressor would
be added on the Medford
lateral.
Avista Corp 2018 Natural Gas IRP 25
Chapter 2: Demand Forecasts
2: Demand Forecasts
Overview
The integrated resource planning process begins
with the development of forecasted demand.
Understanding and analyzing key demand drivers
and their potential impact on forecasts is vitalto the
planning process. Utilization of historical data
provides a reliable baseline, however past trends
may not be indicative of future trends. This IRP
mitigates the uncertainty by considering a range of
scenarios to evaluate and prepare for a broad
spectrum of outcomes.
Demand Areas
Avista defined eleven demand areas, structured
around the pipeline transportation resources that serve them, within the SENDOUT@
model (Table 2.1). These demand areas are aggregated into five service territories and
further summarized as North or South divisions for presentation throughout this lRP.
Table 2.1 Demand Classifications
Cha pter
H igh lights
Washington NWP Spokane North
Washington GTN Spokane North
Washington Both Spokane North
ldaho NWP Coeur D'Alene North
ldaho GTN Coeur D'Alene North
ldaho Both Coeur D'Alene North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Roseburg South
Roseburg Medford/Roseburg South
Klamath Falls Klamath Falls South
La Grande La Grande South
Demand Area Service Territory Division
Avista Corp 2018 Natural Gas IRP 27
r An increase in customer
forecast over 20 years
versus the 2016 IRP. Lower use per customero Geographic demand
areas are now broken up
by state and territoryo Weather analysis points
to sustained risk of peak
weather, compared to a
base period, in most
areas
Chapter 2: Demand Forecasts
Demand Forecast Methodology
Avista uses the IRP process to develop two types of demand forecasts - annual and peak
day. Annual average demand forecasts are useful for preparing revenue budgets,
developing natural gas procurement plans, and preparing purchased gas adjustment
filings. Peak day demand forecasts are critical for determining the adequacy of existing
resources or the timing for acquiring new resources to meet customers' natural gas needs
in extreme weather conditions.
ln general, if existing resources are sufficient to meet peak day demand, they will be
sufficient to meet annual average day demand. Developing annual average demand first
and evaluating it against existing resources is an important step in understanding the
performance of the portfolio under normal circumstances. lt also facilitates
synchronization of modeling processes and assumptions for planning purposes.
Peak weather analysis aids in assessing resource adequacy and any differences in
resource utilization. For example, storage may be dispatched differently under peak
weather scenarios.
Demand Modeling Equation
Developing daily demand forecasts is essential because natural gas demand can vary
widely from day-to-day, especially in winter months when heating demand is at its highest.
ln its most basic form, natural gas demand is a function of customer base usage (non-
weather sensitive usage) plus customer weather sensitive usage. Basic demand takes
the formul a in T able 2.2:
Table 2.2: Basic Demand Formula
# of customers x daily base usage / customer
PIus
S of customers x daily weather sensitive usage / customer
SENDOUT@ requires inputs as expressed in the Table 2.3 format to compute daily
demand in dekatherms.
Avista Corp 2018 Natural Gas IRP 28
Chapter 2: Demand Forecasts
Table 2.3: SENDOUT@ Demand Formula
# of customers x daily Dth base usage / customer
Plus
# of customers x daily Dth weather sensitive usage / customer x # of daily degree days
Customer Forecasts
Avista's customer base includes firm residential, commercial and industrial categories.
For each of the customer categories, Avista develops customer forecasts incorporating
national economic forecasts and then drilling down into regional economies. U.S. GDP
groMh, national and regional employment growth, and regional population groMh
expectations are key drivers in regional economic forecasts and are useful in estimating
the number of natural gas customers. A detailed description of the customer forecast is
found in Appendix 2.1 - Economic Outlook and Customer Count Forecast. Avista
combines this data with local knowledge about sub-regional construction activity, age and
other demographic trends, and historical data to develop the 20-year customer forecasts.
Several Avista departments' use these forecasts including Finance, Accounting, Rates,
and Gas Supply. The natural gas distribution engineering group utilizes the forecast data
for system optimization and planning purposes (see discussion in Chapter 8 - Distribution
Planning).
Forecasting customer growth is an inexact science, so it is important to consider different
forecasts. Two alternative groMh forecasts were developed for this lRP. Avista developed
High and Low Growth forecasts to provide potential paths and test resource adequacy.
Appendix 2.1 contains a description of how these alternatives were developed.
Figure 2.1 shows the three customer growth forecasts. The expected case customer
counts are higher than the last lRP. This has impacted forecasted demand from both the
average and peak day perspective. Detailed customer count data by region and class for
all three scenarios is in Appendix.2.2 - Customer Forecasts by Region. ln comparison
to Avista's 2016 !RP, the base forecast for customer growth increases by nearly 12,000
new customers converting from electric to natural gas. This emerging natural gas demand
is attributed to both the Line Excess Allowance Program (LEAP) 1 and Fuel Efficiency
programs. Since conversion costs can be expensive, it is common for customers who
participate in the LEAP program to also apply for a fuel conversion rebate resulting in a
large overlap in participation between the two programs. !t was estimated that in 2017
t https://www.myavista.com/about-us/services-and-resources/natural-gas
Avista Corp 2018 Natural Gas IRP 29
Chapter 2: Demand Forecasts
approximalely 77% of LEAP participants also participated in the fuel conversion program
offerings.
Figure 2.1: Customer Growth Scenarios
System Firm Customer Rang e, 2018-2037
480,000
460,0(n
44{r,0m
420,0m
4m,0m
3g),om
360,Om
340,000
320,0{x)
3m,om q, or o d (Y o q ut ro l\ 00 qt o d N dl $ ln ro ]\86gg8ggggggg888898tstsN N SI N fiI OI hI N'\ N N'\l OI N N N N N N'\
-
SYSTEn CUS.syf Base - - - SYSfEMCUS,syf High - - - SYSTEi,lCUS.syf Low
Use-per-G ustomer Forecast
The goal for a use-per-customer forecast is to develop base and weather sensitive
demand coefficients that can be combined and applied to heating degree day (HDD)
weather parameters to reflect average use-per-customer. This produces a reliable
forecast because of the high correlation between usage and temperature as depicted in
the example scatter plot in Figure 2.2.
Variable
Customers
ILow
Growth
High
Growth
o.8%t.5%
Population 0.5%t.2%
,22,
aa-
2
Avista Corp 2018 Natural Gas IRP 30
Base
Growth
t.2%
o.9%l
Chapter 2: Demand Forecasts
Figure 2.2: Example Demand vs. Average Temperature - WA/ID
Daily Demand Profile
Washington and ldaho 300,000
250,000
@
200,000
150,000 -Fo
100,000
50,000
100 80 60 40 20
2006-2017 AVERAGE TEMP ('F)
-20
The first step in developing demand coefficients was gathering daily historical gas flow
data for all of Avista's city gates. The use of city gate data over revenue data is due to
the tight correlation between weather and demand. The revenue system does not capture
data on a daily basis and, therefore, makes a statistical analysis with tight correlations on
a daily basis virtually impossible. Avista reconciles city gate flow data to revenue data to
ensure that total demand is properly captured.
The historical city gate data was gathered, sorted by service territory/temperature zone,
and then by month. As in the last lRP, Avista used three years of historical data to derive
the use-per-customer coefficients, but also considered varying the number of years of
historical data as sensitivities. When comparing five years of historical use-per-customer
to three years of data, the five-year data had slightly higher use-per-customer, which may
overstate use as efficiency and use-per-customer-per-HDD have been on a downward
trend since 2006. The two-year use-per-customer was much more pronounced for
demand, likely based off of some cold weather in Avista's territories and a shorter
timeframe for weather to impact the overall use-per-customer. Three years struck a
balance between historical and current customer usage patterns. Figure 2.3 illustrates
the annual demand differences between the three and five-year use-per-customer with
normal and peak weather conditions.
0
0
Avista Corp 2018 Natural Gas IRP 31
You can see the three year and 5 year coefficients are very close, with the two year
coefficient clearly higher.
Figure 2.3: Annual Demand - Demand Sensitivities 2-Year, 3-Year and S-Year Use-per-
Customer
46,000
44,000
42,000
40,000
38,000
e6 36,000
34,000
32,000
30,000
-r^*r{r*rqr-$qrqrqr*r*rS*r*r*r$.{r$.S.S.$
1,O' tS' 1,Q' "LS" 1,S'1,S' .L$' ,1,$' ,l,S'1,S' tS" .l,S'"rS'.1,S' .l,S' ,),S' ,),S' "tS' tS' "l,S'ol year UPC
-ff1{spnate
Historical S-Year UPC -fflfsppate
Historical 2-Year UPC
The base usage calculation used three years of July and August data to derive
coefficients. Average usage in these months divided by the average number of customers
provides the base usage coefficient input into SENDOUT@. This calculation is done for
each area and customer class based on customer billing data demand ratios.
To derive weather sensitive demand coefficients for each monthly data subset, Avista
removed base demand from the total and plotted usage by HDD in a scatter plot chart to
verify correlation visually. The process included the application of a linear regression to
the data by month to capture the linear relationship of usage to HDD. The slopes of the
resulting lines are the monthly weather sensitive demand coefficients input into
SENDOUT@. Again, this calculation is done by area and by customer class using
allocations based on customer billing data demand ratios.
Avista Corp 2018 Natural Gas IRP 32
Chapter 2: Demand Forecasts
Chapter 2: Demand Forecasts
Weather Forecast
The last input in the demand modeling equation is weather (specifically HDDs). The most
current 20 years of daily weather data (minimums and maximums) from the National
Oceanic Atmospheric Administration (NOAA) is used to compute an average for each
day; this 2}-year daily average is used as a basis for the normal weather forecast. NOAA
data is obtained from five weather stations, corresponding to the areas where Avista
provides natural gas services (four in Oregon and one for Washington and ldaho), where
this same 2}-year daily average weather computation is completed for all five areas. The
HDD weather patterns between the Oregon areas are uncorrelated, while the HDD
weather patterns amongst eastern Washington and northern ldaho portions of the service
area are correlated. Thus, Spokane Airport weather data is used for all Washington and
ldaho demand areas.
The NOAA 2o-year average weather serves as the base weather forecast to prepare the
annual average demand forecast. The peak day demand forecast includes adjustments
to average weather to reflect a five-day cold weather event. This consists of adjusting the
middle day of the five-day cold weather event to the coldest temperature on record for a
service territory, as well as adjusting the two days on either side of the coldest day to
temperatures slightly warmer than the coldest day. For the Washington, ldaho and La
Grande service territories, the model assumes this event on and around February 15 each
year. For the southwestern Oregon service territories (Medford, Roseburg, Klamath
Falls), the model assumes this event on and around December 20 each year. The
following section provides details about the coldest days on record for each service
territory.
For, Washington and ldaho service areas, the coldest day on record observed in Spokane
was an 82 HDD that occurred on December 30, 1968. This is equal to an average daily
temperature of -17 degrees Fahrenheit. Only one 82 HDD has been experienced in the
last 51 years for this area; however, within that same time period, 80, 79 and 78 HDD
events occurred on December 29, 1968, December 31,1978 and December 30, 1978,
respectively.
Medford experienced the coldest day on record, a 61 HDD, on December 9, 1972. This
is equal to an average daily temperature of 4 degrees Fahrenheit. Medford has
experienced only one 61 HDD in the last 47 years; however, it has also experienced 59
and 58 HDD events on December 8, 1972 and December 21, 1990, respectively.
The other three areas in Oregon have similar weather data. For Klamath Falls, a72HDD
occurred on three separate occasions: December 21 , 1990, December 8,2013 and most
recently on January 6,2017;inLa Grande a 75 HDD occurred on January 31, 1996; and
Avista Corp 2018 Natural Gas IRP 33
Chapter 2: Demand Forecasts
a 55 HDD occurred in Roseburg on December 22,1990. As with Washington, ldaho and
Medford, these days are the peak day weather standard for modeling purposes.
Utilizing a peak planning standard of the coldest temperature on record may seem
aggressive given a temperature experienced rarely, or only once. Given the potential
impacts of an extreme weather event on customers' personal safety and property damage
to customer appliances and Avista's infrastructure, it is a prudent regionally accepted
planning standard. While remote, peak days do occur, as on January 6, 2017, when
Avista matched the previous peak HDD in Klamath Falls.
Avista analyzes an alternate planning standard using the coldest temperature in the last
twenty years. Washington and ldaho service area use a 76 HDD, which is equal to an
average daily temperature oI -11 degrees Fahrenheit. ln ttledford, the coldest day in 20
years is a 52 HDD, equivalent to an average daily temperature of 13 degrees Fahrenheit.
ln Roseburg, the coldest day in 20 years is a 48 HDD, equivalent to an average daily
temperature of 17 degrees Fahrenheit. ln Klamath Falls, the coldest day in 20 years is a
72 HDD, equivalent to an average daily temperature of -7 degree Fahrenheit. ln La
Grande, the coldest day in 20 years is a 66 HDD, equivalent to an average daily
temperature of -1 degree Fahrenheit. The HDDs by area, class and day entered into
SENDOUT@ are in Appendix2.4 - Heating Degree Day Data.
Average rolling 20 year weather is the current methodology used in Avista's planning in
this lRP. Unlike many peer utilities, Avista has some extreme weather that can have
deadly consequences to both persons and property if observed. lf taken into
consideration, wind chill has the potential to drastically change our planning standard.
During Spokane's coldest on record weather event the average temperature was -17
degrees Fahrenheit or 82HDD2; if combined with a Tmph wind chill, would create a
temperature of -33 Fahrenheit3. This would add an additional 16 HDD's to Avista's
planning standard, consequently increasing our new planning standard to 99 HDD. The
coldest in the past 20 years occurred on January 5, 2004 as Spokane lnternational
Airport's observed mean temperature of -10 Fahrenheit combined with an average wind
speed of 3 mph. The average temperature converts to 75 HDDs and when paired with
the wind-chill factor -18 Fahrenheit, would be 83 HDDs or 1 degree colder than our
planning standard. With the wind chill included, these temperatures appear to be
reasonable as these extreme events have been experienced in recent history. ln Oregon
territories, specifically Klamath Falls and La Grande, the coldest on record has occurred
multiple times in the past 30 years.
2 Weather Underground: www.wunderground.com/history
3 http ://www.wpc. ncep. no aa.gov /html /windchil lbody_txt. html
Avista Corp 2018 Natural Gas IRP 34
Chapter 2: Demand Forecasts
As discussed in lAC 2, warming trends are beginning to emerge in Roseburg and
Medford, though the volatility surrounding the peak is still present as seen in Figures 2.5
and 2.8. This indicates that although temperatures specifically in the Roseburg and
Medford areas are deviating from the base years of 1950-1981, the peaking potential
remains the same. The following figures show this same analysis for all weather areas.
Figure 2.4: Spokane
Spokane Dec-Jan-Feb Temperature Anomaly Histogram
o
q)
=Fo)
LL
30Yo
25o/o
200/?
'150h
1Oo/e
sq/o
Oo/o -5.O -4.5 -4.O -3.5 -3.O -2.5 -2.O -1.5 -1.O -O.5 0.O O_5 'l .O 1.5 2-O 2.5 3.O 3.5 4"A 4.5 5-0
Z-statistic
-1951t52-198O/81
Reference Period
-2OO1|O2
- 2O16/t17 period
Avista Corp 2018 Natural Gas IRP 35
Chapter 2: Demand Forecasts
Figure 2.5: Medford
Medford Dec-Jan-Feb Temperature Anomaly Histogram
o
(l,-ETd,
lJ-
?sVo
2OVo
1ssh
100/o
50h
o96
-5.O -4.5 -4.O -3_5 -3.O -2.5 -2.O -1.5 -1 .O -O.5 0.O O.5 1.O 1.5 2.O 2.5 3_O s-5 4.O 4.5 5.O
Z-statistic
-1951/52-1980/81
Reference Period
-?OO1|A?
- 2O16t17 Period
Figure 2.6: La Grande
La Grande Dec-Jan-Feb Temperature Anomaly Histogram
o=o=rq)
LL
3006
25Vo
2Q6/o
15o/c
1Qo/o
5o/o
Oo/o
-5.O -4.5 -4.O -3.5 -3.O -2.5 -2_O -'1 .3 -1 .O -O.5 0.O O_5 1.O 1.5 2.O 2.5 3.0 3.5 4.O 4.5 5.O
Z-statistic
-1951152-1980/81
Reference Period
-2OO1|O2
- 2016117 Petiod
Avista Corp 2018 Natural Gas IRP 36
25Vo
200h
,150h
lOVo
5?b
OVo
>o
o,ro,
LL
Chapter 2: Demand Forecasts
Figure 2.7: Klamath Falls
Klamath Falls Dec-Jan-Feb Temperature Anomaly Histogram
-5.O -4.5 -4.O -3.5 -3.O -2.5 -2.O -1 .5 -1 .O -O.5 0.O O.5 1.O 1.5 2.O 2.5 3.O 3.5 4.O 4.5 5.O
Z-statistic
-1951t52-198ol81
Reference Period
-2OO1|O2
- 2016117 Pe(iod
Figure 2.8: Roseburg
Roseburg Dec-Jan-Feb Temperature Anomaly Histogram
-5.O -4.5 4.O -3.5 -3.O -2.5 -2.O -1.5 -1 .O -O.5 0.O O.5 1.O 1.5 2.O 2.5 3.O 3.5 4.O 4.5 5.O
Z-statistic
-.t951t52-1980/81
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-2OO1|O2
- 2016/17 Period
o
o=qo
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20o/o
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1Oo/o
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Oo/o
Avista Corp 2018 Natural Gas IRP 37
Chapter 2: Demand Forecasts
Developing a Reference Case
To adjust for uncertainty, Avista developed a dynamic demand forecasting methodology
that is flexible to changing assumptions. To understand how various alternative
assumptions influence forecasted demand Avista needed a reference point for
comparative analysis. For this, Avista defined the reference case demand forecast shown
in Figure 2.4. This case is only a starting point to compare other cases.
Figure 2.4: Reference Case Assumptions
1. Customer Compound Annual Growth Rates
2. Use-Per-Customer Coefficients
Flat Across All Classes
3-year Average Use per Customer per HDD by AreaiClass
3. Weather
Z0-year Normal- NOAA (1998-2017)
4. Elasticity
None
5. Conservation
None
Dynamic Demand Methodology
The dynamic demand planning strategy examines a range of potential outcomes. The
approach consists of:
ldentifying key demand drivers behind natural gas consumption;
a
o
Performing sensitivity analysis on each demand driver;
Combining demand drivers under various scenarios to develop alternative
potential outcomes for forecasted demand; and
IMatching demand scenarios with supply scenarios to identify unserved demand
a
a
Washington/ ldaho 1.1%0.6%0.0%
Klamath Falls 1.3%0.9%o.o%
La Grande 0.6%0.4%0.1o/o
Medford 1.3%1.0%o.o%
Roseburg 1.1%0.2%0.0%
Residential Commercial lndustrialArea
Avista Corp 2018 Natural Gas IRP 38
Chapter 2: Demand Forecasts
Figure 2.5 represents Avista's methodology of starting with sensitivities, progressing to
portfolios, and ultimately selecting a preferred portfolio.
Figure 2.5: Sensitivities and Preferred Portfolio Selection
V
f,5 5
secfl,s,
i&Stochastic
Cost/RiskAnalysis
Prices and
Weather
t
Demandand L
Supply Side
Sensitivities )
Optimize
Resource
Portfolio )Y,
U,3 &s6,i
(
Highest
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Portfolios
selection
Sensitivity Analysis
ln analyzing demand drivers, Avista grouped them into two categories based on:
o Demand lnfluencing Factors directly influencing the volume of natural gas
consumed by core customers.
a Price lnfluencing Factors indirectly influencing the volume of natural gas consumed
by core customers through a price elasticity response.
After identifying demand and price influencing factors, Avista developed sensitivities to
focus on the analysis of a specific natural gas demand driver and its impact on forecasted
demand relative to the Reference Case when modifying the underlying input
assumptions.
Price ForecastCore Cases
Preferred
Portfolio
selection
Avista Corp 2018 Natural Gas IRP 39
Chapter 2: Demand Forecasts
Sensitivity assumptions reflect incremental adjustments not captured in the underlying
Reference Case forecast. Avista analyzed 18 demand sensitivities to determine the
results relative to the Reference Case. Table 2.4 lists these sensitivities. Detailed
information about these sensitivities is in Appendix 2.6 - Demand Forecast Sensitivities
and Scenarios Descriptions.
Table 2.4= Demand Sensitivities
Ee.cnd til Hdr Crtolr
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tWty Eluecled
Figure 2.6 shows the annual demand from each of the sensitivities modeled for this IRP
Figure 2.6: 2018 IRP Demand Sensitivities
50,000
45,000
40,000
35,000
30,000
25,000
20,000
15,000
10,000
High Prices-*.-**. Carbon Legislation-Expected
-
Low Cust GroMh
Alternate Historical s-Year UPC
80% belM 1990 emissions Ref Plus Peak
-
Reference case
-LowPri@s-
Carbon Leoislation-High
-
Expected Elasticity6&1,ffi Alternate Weather Std
-
ftgfs1g6sg Qase - Plus Peake DSM Case
-
Q6tuen Legislation-Low
-
High cust GroMh
Alternate Historical 2-Year UPC
80% below 1990 emissions
-Peak
Plus DSM Case
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Avista Corp 2018 Natural Gas IRP 40
DEilAflO IIFLUEIICI'{G . DIREC T PfrCE fiFLUET{Cn{G - rr{orRECT
?Ydllm fYarlm
Chapter 2: Demand Forecasts
Scenario Analysis
After testing the sensitivities, Avista grouped them into meaningful combinations of
demand drivers to develop demand forecasts representing scenarios. Table 2.5 identifies
the scenarios developed for this lRP. The Average Case represents the case used for
normal planning purposes, such as corporate budgeting, procurement planning, and
PGfuGeneral Rate Cases. The Expected Case reflects the demand forecast Avista
believes is most likely given peak weather conditions. The High Growth/Low Price and
Low Growth/High Price cases represent a range of possibilities for customer growth and
future prices. The Alternate Weather Standard case utilizes the coldest day in Avista's
service territories in the last 20 years. The 80% below 1990 emissions scenario is
intended to show a progressive loss of demand in the areas of Oregon and Washington
(ldaho is unaffected) from policies targeting methane and carbon dioxide emissions to an
estimated emissions levels. lt makes no assumptions as to how the reduction in
emissions are obtained just the levelized trend of overall use based on 2050 targets.
Each of these scenarios provides a "what if' analysis given the volatile nature of key
assumptions, including weather and price. Appendix 2.6 lists the specific assumptions
within the scenarios while Appendix 2.7 conlains a detailed description of each scenario.
Table 2.5: Demand Scenarios
Price Elasticity
The economic theory of price elasticity states that the quantity demanded for a good or
service will change with its price. Price elasticity is a numerical factor that identifies the
relationship of a customer's consumption change in response to a price change. Typically,
the factor is a negative number as customers normally reduce their consumption in
response to higher prices or will increase their consumption in response to lower prices.
For example, a price elasticity factor of negative 0.15 for a particular good or service
means a 10 percent price increase will prompt a 1 .5 percent consumption decrease and
a 10 percent price decrease will prompt a 1 .5 percent consumption increase.
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Alternate Weather Sta ndard
80% below 1990 emissions
2018 IRP Demand Scenarios
Avista Corp 2018 Natural Gas IRP 41
Chapter 2: Demand Forecasts
Complex relationships influence price elasticity and given the current economic
environment, Avista questions whether current behavior will become normal or if
customers will return to historic usage patterns. Furthermore, complex regulatory pricing
mechanisms shield customers from price volatility, thereby dampening price signals and
affecting price elastic responses. For example, budget billing averages a customer's bills
into equal payments throughout the year. This popular program helps customers manage
household budgets, but does not send a timely price signal. Additionally, natural gas cost
adjustments, such as the Purchased Gas Adjustment (PGA), annually adjusts the
commodity cost which shields customers from daily gas price volatility. These
mechanisms do not completely remove price signals, but they can significantly dampen
the potential demand impact.
Avista acknowledges changing price levels can and do influence natural gas usage. This
IRP includes a price elasticity of demand factor of -0.10 for every 10% change in price as
measured in the Roseburg and lt/edford service territories. We assume the same
elasticity for all service areas in this study. When putting this elasticity into our model, it
allows the use-per-customer to vary as the natural gas price forecast changes.
Recent usage data indicates that even with declines in the retail rate for natural gas, long
run use-per-customer continues to decline. This likely includes a confluence of factors
including increased investments in energy DSII/ measures, building code improvements,
behavioral changes, and heightened focus of consumers' household budgets.
Results
During 2018, the Average Case demand forecast indicates Avista will serve an average
of 348,000 core natural gas customers with 33,219,431 Dth of natural gas. By 2037,
Avista projects 412,000 core natural gas customers with an annual demand of over
36,154,721 Dth. ln Washington/ldaho, the projected number of customers increases at
an average annual rate of 1.30 percent, with demand growing at a compounded average
a Bernstein, M.A. and J. Griffin (2005). Regional Differences in Price-Elasticity of Demand for Energy,
Rand Corporation.
Avista Corp 2018 Natural Gas IRP 42
When considering a variety of studies on energy price elasticity, a range of potential
outcomes was identified, including the existence of positive price elastic adjustments to
demand. One study looking at the regional differences in price elasticity of demand for
energy found that the statistical significance of price becomes more uncertain as the
geographic area of measurement shrinks.a This is particularly important given Avista's
geographically diverse and relatively small service territories.
Chapter 2: Demand Forecasts
annual rate of 0.36 percent. ln Oregon, the projected number of customers increases at
an average annual rate of 0.9 percent, with demand growing 0.70 percent per year.
During 2018, the Expected Case demand forecast indicates Avista will serve an average
of 348,000 core natural gas customers with 34,369,993 Dth of natural gas. By 2037,
Avista projects 412,000 core naturalgas customers with an annual demand of 37,536,603
Dth.
Figure 2.7 shows system forecasted demand for the demand scenarios on an average
daily basis for each year.5
Figure 2.7: Average Daily Demand - 2018lRP Scenarios
s Appendix 2.1 shows gross demand, conservation savings and net demand
l-Po
120
110
100
90
80
70
60
50
40
30
20
10
0
"T$$ffiTS$ffi-fxpssted
Case
- - Cold Day 20yr Weather Std
Avista Corp 2018 Natural Gas IRP 43
High Growth & Low Prices
-
80 % Below 1990 Emissions
Chapter 2: Demand Forecasts
Figure 2.8 shows system forecasted demand for the Expected, High and Low Demand
cases on a peak day basis for each year relative to the Average Case average daily winter
demand. Detailed data for all demand scenarios is in Appendix 2.8 - Demand Before and
After DSM.
Figure 2.8: February 1Sth - Peak Day - 2016 IRP Demand Scenarios
The IRP balances forecasted demand with existing and new supply alternatives. Since
new supply sources include conservation resources, which act as a demand reduction,
the demand forecasts prepared and described in this section include existing DSIV
standards and normal market acceptance levels. The methodology for modeling DSI\/
initiatives is in Chapter 3 - Demand-Side Resources.
Alternative Forecasting Methodologies
There are many forecasting methods available and used throughout different industries.
Avista uses methods that enhance forecast accuracy, facilitate meaningful variance
analysis, and allows for modeling flexibility to incorporate different assumptions. Avista
believes the IRP statistical methodology to be sound and provides a robust range of
demand considerations. The methodology allows for the analysis of different statistical
500
400
----_---------------300
5 2oo
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100
0
" sffi}ffi
*,* 80 % Below 1990 Emissions - - Cold Day 20yr Weather Std
Avista Corp 2018 Natural Gas IRP 44
Chapter 2: Demand Forecasts
inputs by considering both qualitative and quantitative factors. These factors come from
data, surveys of market information, fundamental forecasts, and industry experts. Avista
is always open to new methods of forecasting natural gas demand and will continue to
assess which, if any, alternative methodologies to include in the dynamic demand
forecastin g methodology.
Key lssues
Demand forecasting is a critical component of the IRP requiring careful evaluation of the
current methodology and use of scenario planning to understand how changes to the
underlying assumptions will affect the results. The evolution of demand forecasting over
recent years has been dramatic, causing a heightened focus on variance analysis and
trend monitoring. Current techniques have provided sound forecasts with appropriate
variance capabilities. However, Avista is mindful of the importance of the assumptions
driving current forecasts and understands that these can and will change over time.
Therefore, monitoring key assumptions driving the demand forecast is an ongoing effort
that will be shared with the TAC as they develop.
FIat Demand Risk
Forecasting customer usage is a complex process because of the number of underlying
assumptions and the relative uncertainty of future patterns of usage with a goal of
increasing forecast accuracy. There are many factors that can be incorporated into these
models, assessing which ones are significant and improving the accuracy are key. Avista
continues to evaluate economic and non-economic drivers to determine which factors
improve forecasting accuracy. The forecasting process will continue to review research
on climate change and the best way to incorporate the results of that research into the
forecasting process.
For the last few planning cycles, the TAC has discussed the changing slope of forecasted
demand. Growth has slowed due to a declining use-per-customer. Use-per-customer
seems to have stabilized, though it is still on a downward trajectory.
This reduced demand pushes the need for resources beyond the planning horizon, which
means no new investment in resources is necessary. However, should assumptions
about lower customer growth prove to be inaccurate and there is a rebound in demand,
new resource needs will occur sooner than expected. Therefore, careful monitoring of
demand trends in order to identify signposts of accelerated demand groMh is critical to
the identification of new resource needs coming earlier than expected.
Avista Corp 2018 Natural Gas IRP 45
Chapter 2: Demand Forecasts
Emerging Natural Gas Demand
The shale gas revolution has fundamentally changed the longterm availability and price
of natural gas. An ever growing demand for natural gas-fired generation to integrate
variable wind and solar resources along with an increasing demand from coal retirements
and fuel switching has developed over the last few years. This demand is expected to
increase due to the availability of natural gas combined with its lower carbon emissions.
Other areas of emerging demand include everything from methanol plants to food
processors, and interest in industrial processes using natural gas as a feedstock is
growing.
Conclusion
Avista's 20 year outlook for customer growth has increased as a whole by nearly 12,000
customers, as compared to Avista's 20161RP. tVuch of this demand is from a conversion
program offered in Washington and ldaho helping electric customer's assistance in
converting to natural gas. With an increased amount of energy efficiency, known as DS[\4,
measures going into new construction and purchased through Avista's programs, homes
are becoming better equipped to keep the heat in. This in turn leads to a decreasing
amount of naturalgas usage. Until a point is reached where maximum efficiency is found,
these trends will likely continue to decline in nature.
Avista Corp 2018 Natural Gas IRP 46
3: Energy Efficiency & Demand-
Side Resources
Overview
Avista is committed to offering natural gas Energy
Efficiency porLfolios to residential, low income,
commercial and industrial customer segments when
it is feasible to do so in a cost-effective manner as
prescribed within each jurisdiction. Avista began
offering natural gas energy efflciency programs to its
customers in 1995. Program delivery includes both
prescriptive and site-specific offerings. Prescriptive
programs, or standard offerings, provide cash
incentives for standardized products such as the
installation of qualifying high-efficiency heating
equipment. Delivering programs through a
prescriptive approach works in situations where uniform products or offerings are applicable
for large groups of homogeneous customers and primarily occur in programs for residential
and small commercial customers. Site specific is the most comprehensive offering of the
nonresidential segment. Avista's Account Executives work with nonresidential customers to
provide assistance in identifying energy efficiency opportunities. Customers receive technical
assistance in determining potential energy and cost savings as well as identifying and
estimating incentives for participation. Other delivery methods build off these approaches and
may include upstream buy downs of low cost measures, free-to-customer direct install
programs, and coordination with regional entities for market transformation efforts.
Recently, programs with the highest impacts on natural gas energy savings include the
residential prescriptive HVAC measures, residentialwater heat measures, and nonresidential
prescriptive and site-specific HVAC. ln the 2017 program year, conservation programs
exceeded the IRP savings targets in both Washington and ldaho.
lmproved drilling and extraction techniques of natural gas has led to declines in natural gas
prices in recent years which has made offering cost-effective DS[M programs challenging
using the Total Resource Cost Test (TRC) to test cost-effectiveness. Since January 1,2016,
Washington and ldaho programs utilize the Utility Cost Test (UCT). Effective January 1,2017,
all Oregon DSIV programs, with the exception of low-income conservation, are delivered and
administered by the Energy Trust of Oregon (ETO)1.
1As part of the settlement for the Avista 20L5 Oregon General Rate case
Avista Corp 2018 Natural Gas IRP 47
Chapter
Highlights
lncreased DSM potential
ETO manages Avista's
DSM programs in Oregon
ln future IRP's we will visit
new methodology to look at
DSM by scenarlo
Distribution willbe a
primary area of research for
potential integration in
avoided costs and as a
supply side resource
a
a
a
a
ln Washington, a $1O/IVTCO2e ($0.53/Dth) carbon cost starting July 2019 was included to
account for the potential carbon reduction approaches currently occurring in the state. ldaho
has no assumed carbon costs.
Conservation Potential Assessment Methodology Overview
During 2017, Avista issued an RFP and chose Applied Energy Group (AEG) to perform an
external independent evaluation of Avista's conservation potential. Included with this
evaluation was the technical, economic and achievable conservation potential for each of
Avista'sthree jurisdictionsover a2}-year planning horizon (2018-2037). As potentialfor2038
was also estimated for reference purposes but not utilized within the lRP, the remainder of
this chapter will refer only to the 2O-year planning horizon. This process involves indexing
AEG's existing nationally recognized Conservation Potential Assessment (CPA) tool,
LoadMAPrM, to the Avista service territory load forecast, housing stock, end-use saturations,
recent conservation accomplishments, and other key characteristics. Additional consideration
of the impact of energy codes and appliance standards for end-use equipment at both the
state and national level are incorporated into the projection of energy use and the baseline
for the evaluation of efficiency options. The modeling process also utilizes ramp rates for the
acquisition of efficiency resources over time in a manner generally consistent with the
assumptions used by the Northwest Power and Conservation Council (NPCC), adapted for
use in modeling natural gas DSM programs.
The process described above results in an Avista-specific supply curve for conservation
resources. Simultaneously, the avoided cost of natural gas consistent with serving the full
forecasted demand was defined as part of the SENDOUT@ modeling of the Avista system.
The preliminary cost-effective conservation potential is determined by applying the stream of
annual natural gas avoided costs to the Avista-specific supply curve for conservation
resources. This quantity of conservation acquisition is then decremented from the load which
the utility must serve and the SENDOUT@ model is rerun against the modified (reduced) load
requirements. The resulting avoided costs are compared to those obtained from the previous
iteration of SENDOUT@ avoided costs. This process continues until the differential between
the avoided cost streams of the most recent and the immediately previous iteration becomes
immaterial. The resulting avoided costs were provided to AEG to use in selecting cost-
effective potential within Avista's Washington and ldaho service territories. The cost-
effectiveness test used for Washington and ldaho was the UCT.
lntegrating the DSM portfolio into the IRP process by equilibrating the avoided costs in this
iterative process is useful since Avlsta's DSM acquisition is small relative to the totalwestern
natural gas market used to establish the commodity prices driving the avoided cost stream.
Therefore, few iterations are necessary to reach a stable avoided cost. Additionally, it provides
some assurance, at least at the aggregate level, that the quantity of DSM resource selected
will be cost-effective when the final avoided cost stream is used in retrospective portfolio
evaluation.
Avista Corp 2018 Natural Gas IRP 48
Conservation Potential Assessment Methodology
Prior to the development of potential conservation estimates, AEG created a baseline end-
use projection to quantify the use of natural gas by end use in the base year (2015), and
projections of consumption in the future in the absence of future utility programs and naturally
occurring conservation (through 2038). The end-use forecast includes the relatively certain
impacts of codes and standards that will unfold over the study timeframe. All such mandates
defined as of February 2018 are included in the baseline. The baseline forecast is the
foundation for the analysis of savings from future DSM programs as well as the metric against
which potential savings are measured.
lnputs to the baseline forecast include current economic growth forecasts (e.9. customer
growth and income growth), natural gas price forecasts, trends in fuel shares and equipment
saturations developed by AEG, existing and approved changes to building codes and
equipment standards, and Avista's internally developed load forecast. Since actual billing data
was available for 2016 and 2017, AEG calibrated the model to reflect recent consumption
trends and weather-actual consumption before aligning with Avista's weather-normal load
forecast in 2018.
According to the CPA, the residential sector natural gas consumption for all end uses and
technologies increases primarily due to the projected 1.3 percent annualgrowth in the number
of households forWashington, and 1.5 percent annual growth for ldaho. This projection aligns
well with Avista's official forecast, diverging in the later years due to two end-use modeling
assumptions. The first is the projected impact of the AFUE 92% federal furnace standard
being phased in over time (starting in 2021), resulting in slower primary space heating growth
compared to the other end uses. Furthermore, impacts of the 2015 Washington State Energy
Code (2015 WSEC) further reduce space heating consumption in Washington, where very
efficient building shell requirements reduce the annual runtime requirements on primary
heating systems.
For the commercial sector, natural gas use grows slowly over the 2l-year planning horizon
as new construction increases the overall square footage in this sector. Growth in the heating
end use mirrors overall sector growth while food preparation and miscellaneous consumption
outpace it. Food preparation, though a small percentage of total usage, grows at a higher rate
than the other end uses. Consumption by miscellaneous equipment and process heating are
also projected to increase.
Growth in the industrial sector is tied closely to historical trend and planned facility closures.
This is observed in Washington, where consumption drops by 0.3% annually between 2018
and 2037. ln ldaho, consumption between 2018 and 2037 remains quite flat for all end uses.
Table 3.1 illustrates the baseline consumption broken out by state and sector for selected
years over the 20-year planning horizon. The overall baseline consumption is expected to
increase 14 percent over the 2O-year planning horizon corresponding to an annualized groMh
of 0.7 percent. The forecast projects steady growth over the next 20 years with growth in the
Avista Corp 2018 Natural Gas IRP 49
residential sector making up for the flat or declining sales in the industrial sector. ldaho is
projected to experience a higher level of groMh than Washington due to less stringent energy
codes and a flat industrial baseline.
Table 3.1: Baseline Forecast Summary (Dth)
Residential 14,154,582 16,039,605 16,350,394 16,623,717 17,862,303 '19,126,196 19.2o/o O.9Yo
% Change Avg.('18-'37) GrowthEnd Use 2016 20't8 2019 2020 20372027
Commercial 8,479,816 9,247,911 9,242,949 9,243,720 9,362,277 9,736,948 5.3o/o O.3o/o
lndustrial 449,174 491 ,562 491,983 492,546 477,257 460,222 -6.40/o -O.3Yo
Total 23,083,572 25,779,078 26,085,326 26,359,983 27,701,837 29,323,366 13.7% 0.70/o
Washington 15,837,527 17,221,9O0 17,418,177 17,594,636 18,413,613 19,406,251 12.7o/o 0.60/o
ldaho 7,246,045 8,557,178 8,667,149 8,765,347 9,288,224 9,917,115 15.9o/o O.8o/o
Total 23,083,572 25,779,078 26,085,326 26,359,983 27,70',t,837 29,323,366 '.13.70/o 0.7%
The next step in the study is the development of three types of potential: technical, achievable
technical, and achievable economic. Technical potential is the theoretical upper limit of
conservation potential. This assumes that all customers replace equipment with the efficient
option available and adopt the most efficient energy use practices possible at every
opportunity without regard to cost-effectiveness.
Achievable technical potential refines technical potential by applying customer participation
rates that account for market barriers, customer awareness and attitudes, program maturity,
and other factors that affect market penetration of conservation measures. The Seventh
Electric Power Plan's ramp rates, which also include potential realized from delivery
mechanisms outside utility DSM programs, were used as a starting point when developing
these factors.
Achievable economic potential further refines achievable technical potential by applying an
economic screen, measured by the utility cost test (UCT), which assesses cost-effectiveness
from the utility's perspective. Please note that while AEG estimated potential under a
balanced total resource cost (TRC) test as a secondary test, results from this sensitivity were
not used for IRP modeling and are excluded from this discussion.
DSM measures that achieve generally uniform year-round energy savings independent of
weather are considered base load measures. Examples include high-efficiency water heaters,
cooking equipment and front-loading clothes washers. Weather-sensitive measures are those
which are influenced by heating degree day factors and include higher efficiency furnaces,
ceiling/wall/floor insulation, weather stripping, insulated windows, duct work improvements
(tighter sealing to reduce leaks) and ventilation heat recovery systems (capturing chimney
Avista Corp 20'18 Natural Gas IRP 50
heat). Weather-sensitive measures are often referred to as winter load shape measures and
were valued using a higher avoided cost (due to summer-to-winter natural gas pricing
differentials) while base-load measures, often called annual load shape measures, are valued
at a lower, year-round avoided cost.
Conservation measures are offered to residential, non-residential and low-income2
customers. N/easures offered to residentialcustomers are almost universally on a prescriptive
basis, meaning they have a fixed incentive for all customers and do not require individual pre-
project analysis by the utility. Low-income customers are treated with a more flexible approach
through cooperative arrangements with participating Community Action Agencies. Non-
residential customers have access to various prescriptive and site-specific conservation
measures. Site-specific measures are customized to specific applications and have cost and
therm savings that are unique to the individualfacility.
See Table 3.2for residential, commercial, and industrial measures evaluated in this study
for both states.
Table 3.2: Gonservation Measures
Furnace - Direct Fuel Furnace - Efficient Heating
Residentiat Measures Commercial and lndustrial Measures
Boiler - Direct Fuel Boiler - Efficient Heating
Fireplace Unit Heater - Efficient Heating
Water Heating - Efficient Heating Water Heater - Efficient Water Heating
Appliances - Clothes Dryer Food Preparation - Oven
Appliances - Stove/Oven Food Preparation - Conveyor Oven
Pool Heater - Efficient Water Heating Food Preparation - Double Rack Oven
lnsulation - Ceillng, lnstallation Food Preparation - Fryer
lnsulation - Ceiling, Upgrade Food Preparation - Broiler
lnsulation - Slab Foundation Food Preparation - Griddle
lnsulation - Basement Sidewall Food Preparation - Range
lnsulation - Ducting Food Preparation - Steamer
lnsulation - Infiltration Control (Air Sealing)Food Preparation - Other Food Prep
lnsulation - Floor/Crawlspace Pool Heater - Efficient Heater
lnsulation - Wall Cavity, Upgrade lnsulation - Roof/Ceiling
lnsulation - Wall Cavity, lnstallation lnsulation - Wall Cavity
Insulation - Wall Sheathing lnsulation - Ducting
Ducting - Repair and Sealing HVAC - Duct Repair and Sealing
Doors - Storm and Thermal Windows - High Efficiency
Windows - High Efficiency Gas Boiler - Maintenance
Thermostat - Programmable Gas Furnace - Maintenance
2 For purposes of tables, figures and targets, low income is a subset of residential class.
Avista Corp 2018 Natural Gas IRP 51
Residential Measures Commercial and lndustrial Measures
Thermostat - Wi-Fi/lnteractive Gas Boiler - Hot Water Reset
Gas Furnace - Maintenance Steam Trap Maintenance
Gas Boiler - Hot Water Reset Gas Boiler - High Turndown
Gas Boiler - Steam Trap Maintenance Gas Boiler - Burner Control Optimization
Gas Boiler - Maintenance HVAC - Shut Off Damper
Gas Boiler - Pipe lnsulation HVAC - Demand Controlled Ventilation
Water Heater - Drainwater Heat Recovery Gas Boiler - Stack Economizer
Water Heater - Faucet Aerators Gas Furnace Tube lnserts
Water Heater - Low Flow Showerhead (2.0 GPM)Gas Boiler - lnsulate Steam Lines/Condensate Tank
Water Heater - Low Flow Showerhead (1.5 GPM)Gas Boiler - lnsulate Hot Water Lines
Water Heater - Temperature Setback Space Heating - Heat Recovery Ventilator
Water Heater - Thermostatic Shower Restriction Valve Thermostat - Programmable
Water Heater - Pipe lnsulation Thermostat - WiFi Enabled
Water Heater - Solar System Water Heater - Ozone Laundry
Pool Heater - Solar System Water Heater - High MEF Commercial Laundry Washers
ENERGY STAR Dishwashers Water Heater - Motion Control Faucet
ENERGY STAR Clothes Washers Water Heater - Faucet Aerator
ENERGY STAR Homes Water Heater - Drainwater Heat Recovery
Combined Boiler + DHW System (Storage Tank)Water Heater - Efficient Dishwasher
Combined Boiler + DHW System (Tankless)Water Heater - Pre-Rinse Spray Valve
Water Heater - Central Controls
Water Heater - Solar System
Destratification Fans (HVLS)
Kitchen Hood - DCV/MUA
Pool Heater - Night Covers
Building Automation System
Steam System Effi ciency lmprovements
Commissioning - HVAC
Retrocommissioning - HVAC
Strategic Energy Management
Process - lnsulate Heated Process Fluids
Process Heat Recovery
Commissioning
Retrocommissioning
Avista Corp 2018 Natural Gas IRP 52
Conservation Potential Assessment Results
Based upon the previously described methodology and baseline forecasts, AEG developed
technical, achievable technical, and achievable economic potentials by state and segment
over a full 2O-year horizon. Although early-year potential differs by state due to maturity of
DSM programs3, 2}-year steady-state potential is quite similar between the two states since
ramp rates reach 85%for all non-emerging measures.
The technical potential for the overall Avista service territory for the full 20-year IRP horizon
period ultimately reaches 29.5 percent of the baseline end-use forecast.
Achievable technical potential applies customer participation and market penetration factors
to the technical potential. By the end of the 20-year timeframe, cumulative savings, including
non-utility delivery mechanisms, reach 24.7 percent of the baseline energy forecast.
Achievable economic potential applies the cost-effectiveness metric from the utility's
perspective to DStV measures identified within the achievable technical potential and quantify
the impact of the adoption of only those DS[\4 measures that are cost-effective. By the end of
the 2O-year timeframe this represents 20.6 percent of the baseline energy forecast. Although
falling natural gas avoided costs would significantly affect potential from a TRC perspective,
the UCT is quite similar to achievable technical in all years. This is because utility incentives
were developed using existing, approved Avista tariffs for current measures and incentives
for similar measures for identified new measures.
Tables 3.3 and 3.4 summarize cumulative conservation for each potential type for selected
years across the 20-year CPA and IRP horizon. As the largest sector in both states, the
residential sector accounts for a majority of both early and late-year potential. lndustrial
includes only Avista's core customers (e.9. customers that consume gas rather than transport
it), making the sector a small contributor to overall consumption and potential. For more
specific detail, please refer to the natural gas CPA provided in Appendix 3.1.
3 ln May 2012, Avista proposed to suspend its Washington and ldaho natural gas DSM programs due to decreased natural
gas prices. The WUTC guided utilities to continue natural gas programs using the Utility Cost Test (UCT). Avista
requested and was given approval to suspend Avista's ldaho natural gas DSM programs under the TRC and did not have
programs in 20'l 3, 2014 and 2015 (2013 saw some activity due to prior commitments). After the review of Avista's avoided
cost methodology and with an IPUC ruling that allows companies to emphasize the UCT when seeking prudence for their
DSM programs, Avista filed for and was approved to reinstate its ldaho Natural Gas DSIM programs January 1,2016.
Avista Corp 2018 Natural Gas IRP 53
Washington 2018 201 I 2027 20372020
Table 3.3: Summary of Cumulative Technica!, Achievable Technical, and Achievable
Economic Conservation Potential (Dth)
Baseline Forecast (Dth)17 ,221 ,900 17 ,418,177 17,594,636 18,413,613 19,406,251
Potential Forecasts (Dth)
Achievable Economic 17,160,621 17,284,602 17,367,858 16,799,979 15,397,752
Achievable Technical 17,188,007 17,345,078 17,286,475 16,373,787 14,624,564
Technical 17,135,511 17,232,112 16,934,070 15,584,410 13,703,268
Cumulative Savings (Dth)
Achievable Economic 61,279 1 33,576 226,777 1 ,613,635 4,008,500
Achievable Technical 33,893 73,1 00 308,'t61 2,039,826 4,781,688
Technical 86,389 186,065 660,565 2,829,203 5,702,984
Energy Savings (% of Baseline)
Achievable Economic 0.4o/o O.8o/o 1.3Yo 8.8Yo 20.7%
Achievable Technical 0.2To 0.4Yo 1.8%1 1 .1o/o 24.6%
Technical 0.5o/o 11%3.8%15.4o/o 29.4o/o
Baseline Forecast (Dth)8,557,178 8,667,149 8,765,347 9,288,224 9,917,115
Potential Forecasts (Dth)
Achievable Economic 8,530,838 8,608,797 8,665,006 8,480,677 7,879,230
Achievable Technical 8,547,332 8,644,716 8,627,624 8,261,653 7,466,149
Technical 8,519,855 8,585,623 8,450,043 7 ,851 ,146 6,976,401
Cumulative Savings (Dth)
Achievable Economic 26,340 58,352 100,341 807,547 2,037,885
Achievable Technical 9,846 22,432 137,724 1,026,571 2,450,966
Technical 37,324 81 ,526 315,305 1,437,078 2,940,714
Energy Savings (% of Baseline)
Achievable Economic 0.3o/o O.7o/o 1.10/o 8.7%20.5%
Achievable Technical 0.1%0.3o/o 1.60/o 11.1o/o 24.7%
Technical 0.4%0.9o/o 3.60/o 15.SYo 29.7o/o
ldaho 2018 2019 2020 2027 2037
Avista Corp 2018 Natural Gas IRP 54
The overall achievable potential is presented first by state and by sector in the following table.
Table 3.4: Summary of Cumulative Achievable Economic Potentia! by State and Sector (Dth)
Washington 61,279 133,576 226,777 1,613,635 4,008,500
Cumulative Savings (Dth)2018 2019 2020 2027 2037
ldaho 26,340 58,352 100,34 1 807,547 2,037,885
Total 87,619 191,927 327,118 2,421,181 6,046,385
Cumulative Savings (Dth)2018 2019 2020 20372027
Residential 58,333 129,227 223,729 1 ,727 ,462 4,565,013
Commercial 28,148 60,428 99,963 681,712 1,461 ,531
lndustrial 1,138 2,272 3,427 12,007 19,840
Total 87,619 191,927 327,1',18 2,421,181 6,046,385
Figure 3.1 illustrates the impact of the conservation potential forecast upon the end-use
baseline absent of any conservation acquisition.
Figure 3.1 - Conservation Potential Energy Forecast (Dth)
3s,000,000
30,000,000
25,000,000
Dth 20,000,000
15,000,000
-$65slins
Forecast
-trshigys!le
Economic Potential
-Achievable
Technical Potential
-fs6hnig3l
Potential
10,000,000
5,000,000
2075 20L7 2019 2021, 2023 2025 2027 2029 203L 2033 2035 2037
Potential Results - Residential
Single-family homes represent 61 percent of Avista's residential natural gas customers, but
account for 65 percent of the sector's consumption in 2018. ln the current lRP, residential
provides the largest opportunity for cumulative savings over the next 20 years. Table 3.5
provides a distribution of achievable economic potential by state for the residential sector.
Although potential as a percent of baseline is similar between the two states, there is one
notable difference. The less strict energy codes in ldaho should result in higher residential
potential, but this effect is counteracted by the recent "re-start" of DSM programs in the state
of ldaho, which lowers early-year potential as the programs "ramp" up.
Avista Corp 2018 Natural Gas IRP 55
Table 3.5 Residential Cumulative Achievable Economic Potential by State, Selected Years
Cumulative Savings (Dth)2018 2019 2020 2027 2037
Baseline Projection (Dth)
Washington 10,773,426 10,971,347 11,144,590 11,877,363 12,636,101
ldaho 5,266,179 5,379,047 5,479,126 5,984,940 6,490,095
Total 16,039,605 16,350,394 16,623,717 17,862,303 19,126,196
Natural Gas Cumulative Savings (Dth)
Washington 39,979 88,051 151 ,81 5 't ,131 ,0't 3 3,003,789
ldaho 18,354 41,176 71,914 596,450 1,561,225
Total 58,333 129,227 223,729 1,727,462 4,565,013
% of Total Residential Savings
Washington 690/o 68%68%6SYo 660/o
ldaho 31Yo 32%32%35o/o 34%
Table 3.6 identifies the top 10 residential measures by cumulative 2020 savings. Furnaces,
windows, tankless water heaters, and learning thermostats are the top measures. These are
ranked by their combined contribution to Washington and ldaho savings.
Table 3.6 Residential Top Measures, 2020
WA ID Total % of TotalRank Measure / Technology
Furnace - Direct Fuel - AFUE 95%69,659 40,893 110,552 49o/o
2 Windows - High Efficiency - Double Pane LowE CL22 28,074 4,076 32,150 14o/o
3 Water Heater <= 55 gal. - lnstantaneous - ENERGY STAR 18,893 8,936 27,829 12Yo
4 lnsulation - Floor/Crawlspace - R-30 5,646 3,861 9,507 4%
5 Thermostat - Wi-Fiilnteractive - lnteractive/learning thermostat 6j47 3,040 9,1 87 4%
6 lnsulation - Ceiling, lnstallation - R-38 (Retro only)3,286 1,638 4,923 2o/o
7 lnsulation - Wall Cavity, lnstallation - R-1 1 2,850 1,426 4,276 2%
8 ENERGY STAR Homes - Built Green spec (NC Only)2,480 1,229 3,709 2%
I Boiler - Direct Fuel - AFUE 96%2,175 1,069 3,244 1%
10 Water Heater - Low Flow Showerhead (1.5 GPM)1,853 922 2,775 1%o
Subtotal 141,063 67,090 208,153 93%
100%
Avista Corp
Total Savings in Year
2018 Natural Gas IRP
151,815 71,9',14 223,729
56
1
The bulk of the residential potential exists in space heating end-uses followed by water
heating applications. Appliances and miscellaneous end-use loads contribute a small
percentage of potential. Based on measure-by-measure findings of the potential study the
greatest sources of residential achievable potential across both jurisdictions are:
. High-efficiencyfurnaces;
. High-efficiency tankless water heaters;
. Low-emissivity windows;
. Shell measures and insulation;
. Thermostats and home energy monitoring systems;
. Water-saving devices (low-flow showerheads and faucet aerators); and
. ENERGY STAR/Built Green Washington new homes.
Avista does not capture end-use savings that are attributable to new construction
homes through "New Homes pathways" as the Energy Trust of Oregon (ETO) does.
The New Homes pathways are packages of savings in new construction homes that
span several end-uses. ETO assigns an end-use to each of the offered New Homes
pathways based on the most significant saving end-use of the packagea.
Gonservation Potential Results - Gommercial and
lndustrial
The commercial sector provides the next biggest opportunities for savings. Compared to their
portion of baseline consumption, early-year potential in ldaho is significantly lower than in
Washington. Similar to the residential sector, this is a result of the recent "re-start" of DSM
programs in the state of ldaho.
As seen in Table 3.4 above, Avista's core industrial customers represent a low fraction of the
load, and correspondingly comprise a small percentage of overall potential. Additionally, since
early-year consumption in the industrial sector is very similar between Washington and ldaho,
potential is split roughly in half.
Table 3.7 and Table 3.8 below details the achievable economic conservation potential by
sector for selected years.
a Avista 2018 IRP Draft DSM Chapter - Energy Trust of oregon
Avista Corp 2018 Natural Gas IRP 57
Table 3.7 CommercialAchievable Economic Potential by Selected Years
Cumulative Savings (Dth)20'18 2019 203720202027
Baseline Projection (Dth)
Washington 6,197,173 6,197,918 6,202,429 6,303,022 6,553,728
ldaho 3,050,738 3,045,031 3,041,291 3,059,255 3,183,220
Total 9,247,911 9,242,949 9,243,720 9,362,277 9,736,948
Natural Gas Cumulative Savings (Dth)
Washington 20,731 44,393 73,253 476,648 994,795
ldaho 7,417 16,035 26,709 205,064 466,736
Total 28,148 60,428 99,963 681,712 1,461,531
% ofTotal Residential Savings
Washington 74o/o 73o/o 73o/o 70%680/o
ldaho 260/o 27o/o 27o/o 30o/o 32o/o
Table 3.8 lndustrial Cumulative Achievable Economic Potential by Selected Years
Cumulative Savings (Dth)2018 2019 2027 20372020
Baseline Projection (Dth)
Washington 251,300 248,912 247,626 233,229 216,423
ldaho 240,261 243,071 244,930 244,029 243,799
Total 491,562 491,983 492,546 477,257 460,222
Natural Gas Gumulative Savings (Dth)
Washington 569 1.132 1.709 5,974 9.916
ldaho 569 1,140 1,718 6,034 9,924
Total 1,138 2,272 3,427 12,007 19,840
% of Total Residential Savings
Washington 50%50o/o 50Yo 5Oo/o 50%
ldaho 50o/o 50Yo 50%5Oo/o 50o/o
Table 3.9 identifies the top 20 commercial measures by cumulative savings in 2020. Boilers
are the top measure, followed food preparation and custom HVAC measures. These are
ranked by their combined contribution to Washington and ldaho savings.
Avista Corp 20'18 Natural Gas IRP 5B
Table 3.9 C&lTop Measures, 2020
Boiler - AFUE 97%22,515 5,909 28,423 27o/o
2 Fryer - ENERGY STAR 5,648 1,887 7,535 7o/o
3 Insulation - Roof/Ceiling - R-38 4,061 2,288 6,349 60/o
4 lnsulation - Wall Cavity - R-21 3,638 1,993 5,631 5o/o
5 Gas Boiler - lnsulate Steam Lines/Condensate Tank - Lines and
condensate tank insulated 3,331 1,975 5,306 5o/o
6 HVAC - Demand Controlled Ventilation - DCV enabled 2,985 1,679 46U 5o/o
7 Water Heater - TE 0.94 3,559 975 4,534 4o/o
I Gas Boiler - Hot Water Reset - Reset control installed 3,936 532 4,468 4%
9 Steam Trap Maintenance - Cleaning and maintenance 2,546 1,334 3,880 4%
10 Gas Boiler - lnsulate Hot Water Lines - lnsulated water lines 2,224 1 ,318 3,542 3o/o
Subtotal 54,442 19,890 74,332 72%
Total Savings in Year 74,962 28,427 103,389 't00%
Most of the commercial and industrial conservation potential exists within space heating and
water heating applications. Food preparation, process and miscellaneous represents a
smaller proportion of potential. One large measure that is not represented in the achievable
economic potential is commercial HVAC retrocommissioning. For this measure, AEG updated
the savings assumption from the Seventh Plan's value of roughly 15% of heating load lo 7o/o
to reflect space heating's higher end-use share of consumption. For further details on this
adjustment and other top measures, please refer to the natural gas CPA provided in Appendix
3.1. Primary sources of commercial and industrial sector achievable savings are:
. Equipment upgrades for furnaces, boilers and unit heaters;
. High R-value roof/ceiling and wall insulation
o Energy management systems and programmable thermostats
. High thermal efficiency water heaters
. Boiler operating measures such as maintenance;
o Hot water reset and efficient circulation; and
. Food service equipment.
Avista Corp 2018 Natural Gas IRP 59
Rank Measure / Technology WA ID Total o/o ol Tolal
1
Achievable Economic Conservation Potential Results
Tables 3.10 and 3.11 provide the 2018-2020 CPA identified conservation opportunity for
Washington and ldaho, respectively.
Table 3.10: Washington Natural Gas Target(2018-20201
Residential 39,979 48,1 88 63,970
Commercial & lndustrial 21,300 24,330 29,665
Total 61,279 72,518 93,63s
Table 3.11: ldaho Natural Gas 8-2020
Residential 18,3s4 22,851 30,784
Commercial & lndustrial 7,986 9,232 11,343
Total 26,340 32,083 42,127
Figure 3.2 presents the cumulative energy savings for the 2018 to 2020 period by end use,
for each sector and state. Space heating makes a majority of the potential, followed by
water heating. Food preparation equipment upgrades provide savings in the Commercial
sector.
Figure 3.2 - Conservation Potential by End Use, 2020 (Dth)
160,000
140,000
120,000 I Space Heating
r' Secondary Heating
I Water Heating
I Appliances
I Commercial Food Prep
w lndustrial Process
I Miscellaneous
100,000
40,000
80,000co
60,000
20,000
0
I
-Washington ldaho
Residential
Washington
c&r
lncremental Annual Savings
(Dth)2019 20202018
lncremental Annual Savings
(Drh)201 9 20202018
Avista Corp 2018 Natural Gas IRP
ldaho
60
Achievable Potential Factor Application
The development of achievable potential factors is an important step when estimating
achievable levels of potential. As part of the CPA, AEG took steps to more closely align with
the NPCC's Seventh Electric Power Plan Methodology. As part of the Plan, the NPCC
developed a suite of achievable "ramp rates" based on accomplishment data for various
electric EE measures and programs. They then projected them forward on a diffusion curve,
capping achievability at 85% of technical potential by the end of the 20-year planning period
for non-emerging measures.
As a starting point for the CPA, AEG applied these ramp rates to similar natural gas measures
where an electric analog was available. Since these were developed with electric DSM
programs in mind, AEG then adjusted the ramp rates following a similar course of action. AEG
reviewed Avista's recent program accomplishment data and either 1) reassigned ramp rates
or 2) accelerated/decelerated the mapped ramp rates to align with actual participation in
Avista's naturalgas DSM programs. Remapping was used primarily when a measure's actual
performance was significantly different than the electric ramp rate suggested while
acceleration/deceleration was used for more moderate adjustments. The result of this step
was a remapping of heating and food preparation equipment measures to faster ramp rates
and deceleration of weatherization measure installations to reflect lower program
participation. This process was conducted for the Washington and ldaho territories
separately, resulting in lower early-year potential in ldaho to reflect the DSM program re-start
referenced in the sections above.
ln the longer-term, all of the Seventh Plan's non-emerging ramp rates reach a steady-state
achievability of 85% of technical potential. This value is intended to represent both potentia!
realized within utility DSI\4 programs and potential through non-utility delivery mechanisms
such as naturally occurring efficiency, market transformation, and new future codes and
standards. Using this methodology, potential captured after the first year or two of the CPA
includes a portion of additional potential outside Avista's direct control. To account for this
and provide Avista with the utility-specific targets in Table 3.8 and Table 3.9, AEG slowed the
"ramp-up" of these measures by 50% in years two and three then re-accelerated the ramp
rates, so they re-align after year six. This adjustment is intended to estimate utility-specific
goals for the program planning process yet capture all achievable, cost-effective potential
(even potential realized through non-utility DSM mechanisms) in the later years of the study
period.
Natural Gas IRP Target - Historical Trends 201 4-2020
Figure 3.3 and 3.4 below illustrate the historical trend in natural gas IRP targets since 2014
2018 targets were selected by the 2016lRP and align well, but are not an exact match with
the CPA results for 2018.
Avista Corp 2018 Natural Gas IRP 61
tno0tr
(Ettl
-co
Figure 3.3: Washington Natural Gas IRP Targets
2014 2015 2016 20L7 2018
vlboc
(Etn
.E
o
Figure 3.4: Idaho Natural Gas IRP Targetss
20L4 20L5 20L6 20L7 2018
PRELIM
20L9
PRETIM
20L9
PRELIM
2020
PRELIM
2020
s Avista's ldaho natural gas DSM programs were suspended in 201 3, 2014 and 2015 (2013 saw some activity due to prior
commitments). Avista filed for and was approved to reinstate its ldaho Natural Gas DSM programs January 1,2016.
93,635
72,5L8
6L,283
73,7OO
48,9L1
28,
42,L27
24,644
t9,764
11,400
45,500
32,083
22,80O
Avista Corp 2018 Natural Gas IRP 62
Uses and Applications of the GPA
It is useful to place the IRP process and the CPA component of that process into the larger
perspective of Avista's efforts to acquire all available cost-effective conservation resources.
Activities outside the immediate scope of the IRP process include the formal annual
conservation planning and annual cost-effectiveness and acquisition reporting processes in
addition to the ongoing management of the DStt/ portfolio.
The lRP leads to the establishment of a 2l-year avoided cost stream that is essential to
determining the quantity of DSlttl resources that are cost-effective when compared to the CPA-
identified conservation supply curve and the management of the DSM portfolio between the
two-year IRP cycles. The many related and coordinated processes all contribute to the
planning and management of the DSM portfolio towards meeting its cost-effectiveness and
acquisition goals.
The relationship between the CPA and the annual conservation planning process is of
particular note. The CPA is regarded as a high-level tool that is useful for establishing
aggregate targets and identifying general target markets and target measures. However, the
CPA of necessity must make certain broad assumptions regarding key characteristics that
are fine-tuned as part of the creation of an operational business plan. Some of the
assumptions that are most frequently modified include market segmentation, customer
eligibility, measure definition, incentive level, interaction between measures and the
opportunities for packaging measures or coordinating the delivery of measures.
One issue that inevitably arises as part of moving from the CPA analysis to the annual
conservation planning process is the treatment of market segments. The CPA defines market
segments (e.g. by residential building type or vintage) to appropriately define the cost-
effective potential for efficiency options and to ensure consistency with system loads and load
forecasts. However, it is often infeasible to recognize these distinctions on an operational
basis. This may result in aggregations of market segments into programs that could lead to
more or less operationally achievable savings.
A second issue that often arises is the "clumpiness" that often occurs with large commercial
and industrial projects. Large natural gas conservation projects typically have long lead times
with multiple years between the original customer contact and design of a project to the final
completion with any required measurement and verification. These projects can lead to over
or underperforming targets in individual years but typically average out over the 20-year time
frame of an lRP.
Conservation Action Plan
The analytical process for the CPA is based on a deterministic model as compared to the
assumptions within the Expected Case. !n order to further enhance the Company's analytical
methodology, Avista willfocus on the following:
Avista Corp 2018 Natural Gas IRP 63
o Recreate the Sendout model and inputs into a new Excel based methodology. This
methodology will allow flexibility to model DSlvl and other potential supply side
resources on a case by case basis.
Avista Corp 2018 Natural Gas IRP 64
Energy Trust of Oregon:
Background
Energy Trust of Oregon, lnc. (Energy Trust) is an independent nonprofit organization
dedicated to helping utility customers in Oregon and southwest Washington benefit from
saving energy and generating renewable power. Energy Trust funding comes exclusively
from utility customers and is invested on their behalf in lowest-cost energy efficiency and
clean, renewable energy. ln 1999, Oregon energy restructuring legislation (SB 1149)
required Oregon's two largest electric utilities-PGE and Pacific Power-to collect a public
purpose charge from their customers to support energy conservation in K-12 schools, low-
income housing energy assistance, and energy efficiency and renewable energy programs
for residential and business customers.6
ln 2001, Energy Trust entered into a grant agreement with the Oregon Public Utility
Commission (OPUC) to invest the majority of revenue from the 3 percent public purpose
charge in energy efficiency and renewable energy programs. Every dollar invested in energy
efficiency by Energy Trust will save residential, commercial and industrial customers nearly
$3 in deferred utility investment in generation, transmission, fuel purchase and other costs.
Appreciating these benefits, natural gas companies asked Energy Trust to provide service
to their customers-Nw Natural in 2003, Cascade Natural Gas in 2006 and Avista in 2017.
These arrangements stemmed from settlement agreements reached in Oregon Public Utility
Commission processes.
Energy Trust's model of delivering energy efficiency programs unilaterally across the service
territories of the five gas and electric utilities they serve has experienced a great deal of
success. Since the inception of the organization in 2002, Energy Trust has saved more than
607 aMW of electricity and 52 million annual therms. This equates to more than 20 million
tons of CO2 emissions avoided and is a significant factor relatively flat or lower energy sales
observed by both gas and electric utilities from 2007 to 2016, as shown in OPUC utility
statistic books.T
6 ln 2007, Oregon's Renewable Energy Act (SB 838) allowed the electric utilities to capture additional, cost-effective electric efficiency
above what could be obtained through the 3 percent charge, thereby avoiding the need to purchase more expensive electricity. This
new supplemental funding, combined with revenues from natural gas utility customers, increased Energy Trust revenues from about
$30 million in 2002 to s148.9 million in 2016.
7 OPUC 2015 Stat book - 10 Year Summary Tables: http://www.puc.state.or.us/docs/statbook20l6WEB.pdf
Avista Corp 2018 Natural Gas IRP 65
Energy Trust serves residential, commercial and firm industrial customers in Avista's natural
gas service territory in the areas of lt4edford, Klamath Falls, and La Grande, Oregon. 2017
was the first full year of Energy Trust's service to Avista customers and programs achieved
107% of goal - 341K therms achieved of the 318K therms goal, as shown in 3.5.
Figure 3.5 - 2017 Achieved Savings vs. Goals for Avista Service Territory
E
(.)
_cF
(.)
_ofo
o_
0.)E.
400,000
3s0,000
300,000
250,000
200,000
150,000
100,000
s0,000
0
Residential Commercial lndustrial Avista Total
I Annual Goal (therms) Actuals (therms)
ln addition to administering energy efficiency programs on behalf of the utilities, Energy
Trust also provides each utility with a 2}-year DSM resource forecast to identify cost-
effective savings potential. This forecast also examines how much of that potential is
estimated to be achieved by Energy Trust over the 2}-year period. The results are used by
Avista and other utilities in lntegrated Resource Plans (lRP) to inform the resource potential
in their territory and reduce their load forecast over the IRP period to meet their customer's
projected load.
Energy Trust 20-Year Forecast Methodology
20-Year Forecast Overview
Energy Trust developed a 2)-year DSNI resource forecast for Avista using Energy Trust's
DSM resource assessment modeling tool (hereinafter'RA Model') to identify the total 20-
year cost-effective modeled savings potential, which is 'deployed' exogenously of the model
to estimate the final savings forecast. There are four types of potential that are calculated to
develop the final savings potential estimate, which are shown in 3.6 and discussed in
greater detail in the sections below.
Avista Corp 2018 Natural Gas IRP 66
Figure 3.6: Types of Potential Calculated in 20-year Forecast Determination
Nof
Technically
Feasible
Technical Potential
Achievable Potentia!
(85%o of Technical Potential)
Calculated
within RA
Model
Atlarket
Barriers
Cost-Effective Ach iev.
Potential
Nof Cosf-
Effective Program
Design &
llarket
Penetration
Final Program
Savings
Potential
Developed
with
Programs &
Other
fiilarket
lnformation
The RA tVodel utilizes the modeling platform Analytica@8, an object-flow based modeling
platform that is designed to visually show how different objects and parts of the model
interrelate and flow throughout the modeling process. The model utilizes multidimensional
tables and arrays to compute large, complex datasets in a relatively simple user interface.
Energy Trust then deploys this cost-effective potential exogenously to the RA model into an
annual savings projection based on past program experience, knowledge of current and
developing markets, and future codes and standards. This final 20-year savings projection
is provided to Avista for inclusion in in their SENDOUT@ tVodel as a reduction to demand on
the system.
2O-Year Forecast Detailed Methodology
Energy Trust's 2}-year forecast for DStt/ savings follows six overarching steps from initial
calculations to deployed savings, as shown in Figure 1.7. The first five steps in the varying
shades of blue nodes - Data Collection and ltleasure Characterization to Cost-Effective
Achievable Energy Efficiency Potential- are calculated within Energy Trust's RA t\4odel.
This results in the tota! cost-effective potential that is achievable over the 20-year forecast.
The actual deployment of these savings (the acquisition percentage of the total potential
each year, represented in the green node of the flow chart) is done exogenously of the RA
model. The remainder of this section provides further detail each of the steps shown below
8 http:iiwww. lumina.com/whv-analvtica/what-is-analvtica 1 /
Avista Corp 20'18 Natural Gas IRP 67
Figure 3.7: Energy Trust's 20-Year DSM Forecast Determination Flow Chart
Utility'Global lnputs'
1. Data Collection and Measure Characterization
The first step of the modeling process is to identify and characterize a list of measures to
include in the model, as well as receive and format utility'global' inputs for use in the model.
Energy Trust compiles and loads a list of commercially available and emerging technology
measures for residential, commercial, industrial and agricultural applications installed in new
or existing structures. The list of measures is meant to reflect the full suite of measures
Utility Avoided
[Sfiherm Savedl
Baleline and
Efricient
Equipm€nt
Measure
$avings
Market Date
Density/Soturotioa
Buitobiltty
Load
FseEests
by Sector
Counts / BuildinE
StoEk ForecE5t
Customer Customer
Stock
IlemoEraphics
lnsemental
Costs
Measure Level lnputs
The totEl number of unitr that cn te€hniGlty be innelled, reEardless of market bariec, utilizing custom€r rcunts and
measure mlrket ddta inputs multiplied by meesure savinEs
Units' Meosure = Medsure Level lechnicol Potential
Technkal Potentbl muhiplied by 85g6 to account for martet barriers that prevent the adoption of all energy
measures.
Meosure Level Technicsl Potentisl 8596 = Maosure Level Achisoble Potentiol
CE|(ulate the benefit/ost ratio of each measure.
EenefiE = Utility Awided Costs of Savings + Non -Energy BenefrtsCosts = lncremstal Cost
fotol Resource Cost Tst Costs
Screen Cost-Effectiveness of Measure usinE TRC Test
Cost-Effective Aehievable Enercy Efficiencv Poteltial
Metssures that have a TRC Retio Breater than 1-O are considered Cost-Eff*tive end are included in the Cost-
Effestiw Achi€Eble Potential- Measures with TRC5 les tfian 1-O are excluded, except by OPUC ex.d.gtions
Cost-effedive achievtsble = E Achievable Potentitsl where TRC >= 1
Deplovment of Cost-Effective Achievable Energv Efficiengy Potential
"9eployfient is exogenous o.r'rhe RA MoCei')
Exogenous of thE fiA Model - Energy Trust works intemalh with programs and u*s the NWPPC suncil
methodology of acfiieving 1{X)96 of C/E Achieyable potentiel to determine scquisition ete: for eEEh meEsure and
ove€ll
Deployed Sovings = Meosure Level Cost Efrective Achievoble Potential r Acquisition Rote
Chsrasteriu ationDste f.€flection end
Avista Corp 2018 Natural Gas IRP 68
Achievable Energy Efliciencv Potential
offered by Energy Trust, plus a spectrum of emerging technologies.e Simultaneous to this
effort, Energy Trust collects necessary data from the utility to run the model and scale the
measure level savings to a given service territory (known as 'global inputs').
Measure Level lnputs:
Once the measures to include in the model have been identified, they must be
characterized in order to determine their savings potential and cost-effectiveness.
The characterization inputs are determined through a combination of Energy Trust
primary data analysis, regional secondary sourcesl0, and engineering analysis.
There are over 30 measure level inputs that feed into the model, but on a high
level, the inputs are put into the following categories:
1. Measure Definition and Equipment ldentificafion: This is the
definition of the efficient equipment and the baseline equipment it is
replacing (e.9. a 95% EF furnace replacing an 80% EF baseline furnace).
A measure's replacement type is also determined in this step - Retrofit
(RET), Replace on Burnout (ROB), or New Construction (NEW).
2. Measure Savrngs; the kWh or therms savings associated with an
efficient measure calculated by comparing the baseline and efficient
measure consumptions.
3. lncremenfal Cosfs; The incremental cost of an efficient measure over
the baseline. The definition of incremental cost depends upon the
replacement type of the measure. lf a measure is a RET measure, the
incremental cost of a measure is the full cost of the equipment and
installation. lf the measure is a ROB or NEW measure, the incremental
cost of the measure is the difference between the cost of the efficient
measure and the cost of the baseline measure.
4. Market Data: Market data of a measure includes the density,
saturation, and suitability of a measure. A density is the number of
measure units that can be installed per scaling basis (e.9. the average
e An emerging technology is defined as technology that is not yet commercially available, but is in some stage of
development with a reasonable chance of becoming commercially available within a 20-year timeframe. The model is
capable of quantifying costs, potential, and risks associated with uncertain, but high-saving emerging technology
measures. The savings from emerging technology measures are reduced by a risk-adjustment factor based on what
stage of development the technology is in. The working concept is that the incremental risk-adjusted savings from
emerging technology measures will result in a reasonable amount of savings over standard measures for those few
technologies that eventually come to market without having to try and pick winners and losers.
10 Secondary Regional Data sources include: The Northwest Power Planning Council (NWPPC), the Regional Technical
Forum (the technical arm of the NWPPC), and market reports such as NEEA's Residential and Commercial Building Stock
Assessments (RBSA and CBSA)
Avista Corp 2018 Natural Gas IRP 69
number of showers per home for showerhead measures). The saturation is
the average saturation of the density that is already efficient (e.9. 50% of
the showers already have a low flow showerhead). Suitability of a measure
is a percentage input to represent the percent of the density that the
efficient measure is actually suitable to be installed in. These data inputs
are all generally derived from regional market data sources such as
NEEA's Residential and Commercial Building Stock Assessments (RBSA
and CBSA).
Utility Global lnputs:
The RA tVodel requires several utility level inputs to create the DSM forecast
These inputs include:
1. Customer and Load Forecasts: These inputs are essential to scale the
measure level savings to a utility service territory. For example, residential
measures are characterized on a scaling basis'per home', so the measure
densities are calculated as the number of measures per home. The model
then takes the number of homes that Avista serves currently and the
forecasted number of homes to scale the measure level potential to their entire
service territory.
2. Customer Sfock Demographics: These data points are utility specific and
identify the percentage of stock that utilize different heating fuels for both
space heating and water heating. The RA Model uses these inputs to segment
the total stocks to the stocks that are applicable to a measure (e.9. gas
storage water heaters are only applicable to customers that have gas water
heat).
3. Utility Avoided Costs; Avoided costs are the net present value of avoided
energy purchases and delivery costs associated with energy efficiency savings
represented as $s per therm saved. These values are provided by Avista and
the components are discussed in other sections of this lRP. Avoided costs are
the primary 'benefit' of energy efficiency in the cost-effectiveness screen.
2. Calculate Technical Energy Efficiency Potential
Once measures have been characterized and utility data loaded into the model, the next
step is to determine the technical potential of energy that could be saved. Technical
potential is defined as the total potential of a measure in the service territory that could
be achieved regardless of market barriers, representing the maximum potential energy
savings available. The model calculates technical potential by multiplying the number of
applicable units for a measure in the service territory by the measure's savings. The
Avista Corp 2018 Natural Gas IRP 70
a
model determines the total number of applicable units for a measure utilizing several of
the measure level and utility inputs referenced above:
Total applicable units =
Mleasure Density * Baseline Saturation - Suitability Factor * Heat Fuel
hrlultipliers (if applicable) . Total Utility Stock (e.9. # of homes)
Technical Potential =Total Applicable Units * Aleasure Savlngs
The measure level technical potential is then summed up to show the total technical
potential across all sectors. This savings potential does not take into account the various
market barriers that will limit a 100 percent adoption rate.
3. Calculate Achievable Energy Efficiency Potential
Achievable potential is simply a reduction to the technical potential by 15 percent, to
account for market barriers that prevent total adoption of all cost-effective measures.
Defining the achievable potential as 85 percent of the technical potential is the generally
accepted method employed by many industry experts, including the Northwest Power
and Conservation Council (NWPCC) and National Renewable Energy Lab (NREL).
Achievable Potential =Technical Potential * 85%o
4. Determine Cost-effectiveness of Measure using TRG Screen
The RA tMode! screens all DSttI measures in every year of the forecast horizon using the
Total Resource Cost (TRC) test, a benefit-cost ratio (BCR) that measures the cost-
effectiveness of the investment being made in an efficiency measure. This test evaluates
the tota! present value of benefits attributable to the measure divided by the total present
value of all costs. A TRC test value equal to or greater than 1.0 means the value of
benefits is equal to or exceeds the costs of the measure, and is therefore cost-effective
and contributes to the total amount of cost-effective potential. The TRC is expressed
formulaically as follows:
TRC = Present Value of Benefits / Present Value of Cosfs
Where the Present Value of Benefits includes the sum of the following two
components:
a) Avoided Costs: The present value of natural gas energy saved over the life of the
measure, as determined by the total therms saved multiplied by Avista's avoided
Avista Corp 2018 Natural Gas IRP 71
cost per therm. The net present-value of these benefits is calculated based on the
measure's expected lifespan using the company's discount rate.
b) Non-energy benefits are also included when present and quantifiable by a
reasonable and practical method (e.9. water savings from low-flow showerheads,
operations and maintenance (O&M) cost reductions from advanced controls).
Where the Present Value of Cosfs includes
lncentives paid to the participant; and
a) The participant's remaining out-of-pocket costs for the installed cost of the
measures after incentives, minus state and federal tax credits.
b) The cost-effectiveness screen is a critical component for Energy Trust modeling
and program planning because Energy Trust is only allowed to incentivize cost-
effective measures, unless an exception has been granted by the OPUC.
5. Quantify the Cost-Effective Achievable Energy Efficiency Potential
The RA Model's final output of potential is the quantified cost-effective achievable potential.
lf a measure passes the TRC test described above, then achievable savings (85% of
technical potential) from a measure is included in this potential. lf the measure does not
pass the TRC test above, the measure is not included in cost-effective achievable potential.
However, the cost-effectiveness screen is overridden for some measures under two specific
conditions:
1. The OPUC has granted an exception to offer non-cost-effective measures under
strict conditions or,
2. When the measure isn't cost-effective using utility specific avoided costs but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.
6. Deployment of Cost-Effective Achievable Energy Efficiency Potential
After determining the 2}-year cost-effective achievable modeled potential, Energy Trust
develops a savings projection based on past program experience, knowledge of current
and developing markets, and future codes and standards. The savings projection is a
2}-year forecast of energy savings that will result in a reduction of load on Avista's
system. This savings forecast includes savings from program activity for existing
measures and emerging technologies, expected savings from market transformation
efforts that drive improvements in codes and standards, and a forecast of what Energy
Avista Corp 2018 Natural Gas IRP 72
Trust is describing as a 'megaproject adder'. The'megaproject adder' is characterized as
savings that account for large unidentified projects that consistently appear in Energy
Trust's historic savings record and have been a source of overachievement against IRP
targets in prior years for other utilities that Energy Trust serves.
3.8 below reiterates the types of potential shown in 3.6, and how the steps described
above and in the flow chart fit together.
Figure 3.8 - The Progression to Program Savings Projections
Data Collection and Measure Gharacterization Step 1
Nof
Technically
Feasible
Technical Potential Step 2
Irrlarket
Barriers
Achievable Potentia!
(85Yo of Technical Potential)Sfep 3
Nof Cosf-
Effective
Cost-Effective Achiev.
Potential Sfeps 4 & 5
Program
Design &
A/larket
Penetration
Final Program
Savings
Potential
Sfep 6
Forecast Results
The results will be shown in several different sections, as the RA model and the final
savings projections have different output capabilities. The RA model provides outputs in a
variety of different ways, including by segment, end use, and supply curves. The final
savings projection is provided by segment and program delivery type.
RA Model Results - Technical, Achievable and Cost-Effective Achievable Potential
The RA Model produces results by potential type, as well as several other useful outputs,
including a supply curve based on the levelized cost of energy efficiency measures. This
section discusses the overall model results by potential type and provides an overview of
the supply curve.
Avista Corp 2018 Natural Gas IRP 73
Forecasted Savings by Sector
Table summarizes the technical, achievable, and cost-effective potential for Avista's system
in Oregon. These savings represent the total 2}-year cumulative savings potential identified
in the RA Model by the three types identified in Figure and Figure . t\4odeled savings
represent the full spectrum of potential identified in Energy Trust's resource assessment
model through time, prior to deployment of these savings into the final annual savings
projection.
Table 3.12 - Summary of Cumulative Modeled Savings Potentia, - 2018-2037
0.3
Total
Figure 3.9 shows cumulative forecasted savings potential across the three sectors Energy
Trust serves, as well as the type of potential identified in Avista's service territory.
Residential sales make up the majority of Avista's service in Oregon, which is reflected in
the potential. Firm industrial sales represent a low percentage of the total sales in Oregon
for Avista, and subsequently shows very little savings potential (Avista's interruptible and
transport customers are not eligible to participate in Energy Trust programs) . 83% of the
industrial technical potential is cost-effective, while the residential and commercial sectors
cost-effective achievable potential are 53% and 47% of technical potential respectively.
Residential
Commercial 311 6.3
lndustrial 0.3
17.228.5
Avista Corp 2018 Natural Gas IRP 74
Achievable Potential
(Million Therms)
Sector
(Million Therms)
Technical Potential
(Million Therms)
Cost-Effective
Achievable Potential
Figure 3.9 - Savings Potential by Sector - Cumulative 2018-2037 (Millions of
Therms)
25
Residential Commercial lndustrial
r Technical r Achievable Cost-effective achievable
Cost-Effective Achievable Savings by End-Use
Figure 3.'10 below provides a breakdown of Avista's 2}-year cost-effective DSM savings
potential by end use.
Figure 3.10: 20-year Cost-Effective Cumulative Potential by End Use
20
Eg1sF
o
C.9 10
5
Weatherization
20%
Appliance
o.4%
Process Heating Other
L% 2%
Behavioral
t4%
HVAC
Water Heating
3L%
Avista Corp 2018 Natural Gas IRP 75
28%
As expected for a gas utility, the top saving end uses are water heating, HVAC and
weatherization. A large portion of the water heating end-use is attributable to new
construction homes due to how Energy Trust assigns end uses to the offered New Homes
pathways. The New Home pathways are packages of savings in new construction homes
that span several end-uses. Energy Trust assigns an end-use to each of the offered New
Homes pathways based on the most significant saving end-use of the package. For
example, the most cost-effective New Home pathway that was identified by the model
(because it achieves the most savings for the least cost) was designated as a water heating
end-use, though the package includes several other efficient gas equipment measures.
ln addition to the New Homes pathway savings, the water heating end-use includes water
heating equipment from all sectors, as well as showerheads and aerators. Weatherization
and HVAC end uses represent the savings associated with space heating equipment,
retrofit add-ons, and new construction packages. Behavioral consists primarily of potential
from Energy Trust's commercial strategic energy management measure, a service where
Energy Trust energy experts provide training to facilities teams and staff to identify
operations and maintenance changes that make a difference in a building's energy use.
Contribution of Emerging Technologies
As mentioned earlier in this report, Energy Trust includes a suite of emerging technologies
(ETs) in its model. The emerging technologies included in the model are listed in 3.13.
Table 3.13 - Eme Techn lncluded in the Model
Energy Trust recognizes that emerging technologies are inherently uncertain, and utilizes a
risk factor to hedge against that risk. The risk factor for each emerging technology is used to
. Path 5 Emerging Super
Efficient Whole Home
. Window Replacement (U<.20)
. Window Attachments
. Absorption Gas Heat Pump
Water Heaters
. Advanced lnsulation
. Behavior Competitions
. Advanced Ventilation
Controls
. DOAS/HRV
. DHW Circulation Pump
. Gas-fired HP HW
. Gas-fired HP, Heating
. Zero Net Energy Path
. AC Heat Recovery, HW
. Gas-fired HP Water
Heater
. Wall lnsulation- VlP,
R0-R35
Residential lndustrialCommercial
Avista Corp 2018 Natural Gas IRP 76
characterize the inherent uncertainty in the ability for ETs to produce reliable future savings
This risk factor was determined based on qualitative metrics of:
. Market risk
. Technical risk
o Data source risk
The framework for assigning the risk factor is shown in Table 3.14.14. Each ET was
assessed within each risk category; a total weighted score was then calculated. Well-
established and well-studied technologies have lower risk factors while nascent,
unevaluated technologies (e.9., gas absorption heat pump water heaters) have higher risk
factors. This risk factor was then used as a multiplier of the incremental savings potential of
the measure.
Table 3.14 - Emerging Technology Risk Factor Score Card
ET Risk Factor
Risk
Category
1iYo 30Yo 50%70%90%
Market
Risk
High Risk:Low Risk:
(25o/o
weighting)
. Requires neilchanged business
model. Start-up, or small manufacturer. Significant changes to infrastructure. Requires training of contractors.
Consumer acceplance barriers
exist.
High Risk: Low volume
Prototype in first manufacturer.
field tests.
Limited experience
A single or
unknown
approach
Trained contractors
Established business models
Already in U.S. Market
Manufacturer committed to
commercialization
Technical New product with
broad commercial
appeal
Proven technology
in different
application or
different region
Low Risk:
Proven
technology in
target
application.
Multiple
potentially
viable
approaches.
Risk
(25%
weighting)
Data
Source
Risk
High Risk: Based
only on
manufacturer
claims
Manufacturer case
studies
Engineering
assessment or lab
test
Third party case
study (real world
installation)
Low Risk:
Evaluation
results or
multiple third
party case
studies
(50%
weighting)
Avista Corp 2018 Natural Gas IRP 77
Figure 3.11 below shows the amount of emerging technology savings within each type of
DStvl cumulative potential. While emerging technologies make up a relatively large
percentage of the technical and achievable potential, nearly 25o/o, once the cost-
effectiveness screen is applied, the relative share of emerging technologies drops
significantly to aboul5% of total cost-effective achievable potential. This is due to the fact
that many of these technologies are still in early stages of development and are quite
expensive. Though Energy Trust includes factors to account for forecasted decreases in
cost and increased savings from these technologies over time, some are still never cost-
effective over the planning horizon or do not become cost-effective until later years.
Figure 3.11- Cumulative Gontribution of Emerging Technologies by Potential Type
s%
Tech nical Achievable
I Conventional r Emerging
Cost-Effective Achieva ble
Cost-Effective Override Effect
3.15 shows the savings potential in the RA model that was added by employing the cost-
effectiveness override option in the model. As discussed in the methodology section, the
cost-effectiveness override option forces non-cost-effective potential into the cost-effective
potential results and is used when a measure meets one of the following two criteria:
1. A measure is offered under an OPUC exception
2. When the measure isn't cost-effective using Avista-specific avoided costs but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.
Avista Corp 2018 Natural Gas IRP 78
40
35
30
Ezso,
FE20
co
=ls
10
5
23%
23%
Tabfe 3.15 - Cumulative Cost-Effective Potential (2018-20371due to Gost-effectiveness
override (millions of therms)
ln this lRP, 1 3% of the cost-effective potential identified by the model is due to the use of
the cost-effective override for measures with exceptions. The measures that had this option
applied to them included 0.67-0.69 Efficiency factor (EF) gas storage water heaters and
attic, floor, and wall insulation in the Residential Sector.
Supply Curves and Levelized Cost Outputs
An additional output of the RA Model is a resource supply curve developed from the
levelized cost of energy of each measure. The supply curve graphically depicts the total
potential therms that could be saved at various costs for all measures. The levelized cost for
each measure is determined by calculating the present value of the total cost of the
measure over its economic life, per therm of energy savings ($/therm saved). The levelized
cost calculation starts with the customer's incremental TRC of a given measure. The total
cost is amortized over an estimated measure lifetime using the Avista's discount rate
provided to Energy Trust. The annualized measure cost is then divided by the annual
therms savings. Some measures have negative levelized costs because non-energy
benefits amortized over the life of the measure are greater than the total cost of the
measure over the same period.
Figure 3.12 below shows the supply curve developed for this IRP that can be used for
comparing demand-side and supply-side resources. The cost threshold shown with a star
on the supply curve line represents the approximate levelized cost cutoff that corresponds
with the amount of TRC determined costeffective DSt\4 potential identified by the RA t\4odel
in the 2018, when ordering all measures based on their levelized cost.
Residential 10.63 8.33 2.30
Commercial 6.32 6.32
0.26 0.26lndustrial
Tota! DSM:17.21 14.91 2.30
Yes CE
Override
No CE
OverrideSector Difference
Avista Corp 2018 Natural Gas IRP 79
Figure 3.12 - Gas Supply Curve ($ per therm saved)
3s.00
30.00
25.00
20.00
15.00
1_0.00
5.00
$ Fr o o c! cn lJ) o F F{ (o N @ o 0o ro o o F ro (o lJ) Ln st @ oo4 q q q q q q n n cl .! cl c,? n n !q q c'?'4 oq n .! cQ q n ncO c\ O O O O O O O O O O O O O O -l rl -l il cn u) rO Ot sf ln<-G <t> lrt <J\ {t 1r} 1J> lJ\ <r\ 1J> 14 <J} <J> <t> <t> 1t> 1J> <-D <,/> <t> {> {/} {.r} {-+ Fl OoI I vlltt
Levelized Total Resouce Cost of Measures S/therm
Deployed Results - Final Savings Projection
The results of the final savings projection show that Energy Trust can save 1.65 million
therms across Avista's system in Oregon in the next five years from 2018 to 2022 and over
8.5 million therms by 2037 . This represents an 8.7 percent cumulative load reduction by
2037 and is an average of just under a 0.5 percent incremental annual load reduction. The
cumulative final savings projection is shown in Table 3.16 compared to the technical,
achievable and cost -effective achievable potential.
Approximate Cost-
Effective Cutoff
(-So.9zltherm)
Avista Corp 2018 Natural Gas IRP BO
Table 3.16: 20-Year Cumulative savings potentia! by type, including final savings projection
(Millions of Therms)
AII DSM 33.s 28.5 t7.2 8.8
The final deployed savings projection is just over half of the modeled cost-effective
achievable potential. There are several reasons for this additional step down in savings:
1. "Lost Opportunity Measures" - [Veasures that are meant to replace failed equipment
(ROB) or new construction measures (NEW) are considered lost opportunity
measures because programs have one opportunity to influence the installation of
efficient equipment over code baseline when the existing equipment fails or when the
new building is built. This is because these measures must be installed at that
specific point in time, and if a program administrator misses the opportunity to
influence the installation of more efficient equipment, the opportunity is lost until the
equipment fails again. Energy Trust expects that most of these opportunities will be
met in later years as efficient equipment becomes more readily adopted. However, in
early years, the level of acquisition for these opportunities is smaller and ramps
higher as time progresses.
2. "Hard to Reach Measures" - some measures that show high savings potential are
notoriously hard to reach and are capped at 67% of total retrofit potential. These
measures include insulation and windows.
3. New service territory - Avista is a new service territory for Energy Trust as of 2016
and it takes a few years for Energy Trust trade ally networks and systems become
established in new areas, which is reflected in this deployment. ln territories where
programs are already established, Energy Trust expects to achieve 100% penetration
of all cost-effective retrofit potential and ramp to 100% penetration of lost opportunity
measure potential in the later years of the 2l-year forecast. For this forecast, these
metrics have been reduced to 85% to reflect that Energy Trust programs are not yet
fully established in Avista territory.
Residential 20.0 17.0 10.6 5.2
1L.3 6.3 3.3Commercial 13.3
lndustrial 0.3 0.3 o.20.3
Avista Corp 2018 Natural Gas IRP 81
Technical Achievable
Potential Potential
Cost-
Effective
Potential
Energy Trust
Deployed
Savings
Projection
Figure 3.13 below shows the annual savings projection by sector and measure type. The
initial drop in savings from 2018 to 2019 is due to the expiration of market transformation
savings being claimed by the Residential New Homes program from past building code
changes. Most other sector and measure types ramp up over the forecast period, reflecting
the NWPCC ramp rates and methodology to achieve as much cost-effective potential as
possible.
Figure 3.13 - Annua! Deployed Final Savings Potential by Sector and Measure Type (Millions
of Therms)
I Mega-Project Adder
r RES.ROB
r RES-RET
I RES-NEW
* lnd-RoB
r lnd-RET
I Com-SEM
Com-ROB
I Com-RET
I Com-NEW
E
o)
-.CF
o
c
:
boc't
ror/)
(9
0.50
0.50
0.40
0.30
o.20
0.10
@ 01 O d N cO + r) (O a\ OO O) O d N m \t Ln (o F\d d N N N N N N N N N N fn rn m cO aO rn ro mooooooooooooooooooooN N N N N C{ N N C{ N N T! N N N N N N N N
Finally, Figure 3.14 shows the annual and cumulative savings as a percentage of Avista's
load forecast in Oregon. Annually, the savings as a percentage of load varies from about
0.35% at its lowest to 0.53% at its highest, as represented on the /eft Y-axis of the graph
and the blue line. Cumulatively, the savings as a percentage of load builds lo 8.7o/o by 2037,
shown on the rightY-axis and the gold line.
Avista Corp 2018 Natural Gas IRP 82
Figure 3.14 - Annua! and Cumulated Forecasted Savings as a Percentage of Annual and
Cumulative Load Forecasts
o.60%10.oo%
9.OOo/o
8.OO%
7.OO%
6.OO%
5.OOo/o
4.OO%
3.OO%
2.OO%
1.OO%
o.oo%
o.50%
0A0%T'(ooJ
o.:3
E
=U
ox
!tt!oJ
Ef
tr
o
o\
30%
20%
0.
0.
0.10%
0.00%
",i. "S "d,t "d| "dP,S "dP "d "&"
r$ "-p" "d "e" "d)rdP"dP "e" ".d "e" "d
-[nnu3l
% of Load Savings
-f
urnulaf ive % of Load Savings
Deployed Results - Peak Day Results
ln the state of Oregon and around the region, there is an increased focus on peak day
savings contributions of energy efficiency and their impact on capacity investments. This
new focus has led some utilities to embark on targeted load management efforts for
avoiding or delaying distribution system reinforcements. Additionally, the OPUC is
recommending that all investor-owned gas utilities review and consider the DSITI capacity
contribution analysis that NW Natural developed in recent years. Therefore, Avista and
Energy Trust have collaborated to develop estimates of peak day contributions from the
energy efficiency measures that Energy Trust forecasts to install.
Peak day coincident factors are the percentage of annual savings that occur on a peak day
over the total year, which are shown in Table 3.17 below. As mentioned, Avista is still
reviewing this methodology and for the purpose of this analysis, Energy Trust utilized the
peak day factors that are currently being used in Energy Trust's avoided costs. These
include residential and commercial space heating factors developed by NW Natural in
2016and hot water, process load (flat) and clothes washer factors sourced from the
Northwest Power and Conservation Council for electric measures that are analogous to gas
equipment. The peak day factors are the highest for the space heating load shapes, which
Avista Corp 2018 Natural Gas IRP B3
aligns with a typical winter system peak of natural gas utilities. These peak day factors will
be reviewed and updated by Avista to be specific to Avista's Oregon service territory in the
next lRP.
Table 3.17 - Peak Day Coincident Factors by Load Profile
Figure 3.15 below shows the annual, deployed peak day savings potential based upon the
results of the 2}-year forecast. Each measure analyzed is assigned a load shape and the
appropriate peak day factor is applied to the annual savings to calculate the overall DSM
contribution to peak day capacity. Cumulatively, this is equal to 1 10,551 therms, or 1.3o/o of
the total deployed savings potential in Avista's Oregon service territory over the 2O-year
forecast, as shown in Table 3.18 below.
Figure 3.15: Annual Deployed Peak Day DSM Savings Contribution by Sector (Therms)
E
o
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7,000
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20L8 2019 2020 202L 2022 2023 2024 202s 2026 2027 2028 2029 2030 203 1 2032 2033 2034 2035 2036 2037
I Commercial r Residential lndustrial
2018 Natural Gas IRP 84
Residential Space Heating 2.10%NW Natural
Commercial Space Heating 1.80%NW Natural
Water Heating 0.40o/o NWPCC
Clothes Washer 0.20%NWPCC
Process Load 0.30%NWPCC
Load Profile Peak Day Factor Source
Avista Corp
Table 3.18: Cumulative Deployed Peak Day DSM Savings Contribution by Sector (Therms)
Conclusion
Avista has a long-term commitment to responsibly pursuing all available and cost-effective
efficiency options as an important means to reduce its customer's energy cost. Cost-effective
demand-side management options are a key element in the Company's strategy to meet
those commitments. Falling avoided costs and lower groMh in customer demand have led to
a reduced role for conservation in the overall natural gas portfolio compared with lRPs done
prior to 2012, however, a regulatory shift to utilizing the UCT in Washington and ldaho DSttI
programs will continue to provide a vital role in offsetting future natural gas load groMh. The
company transitioned its Oregon DSt\4 regular income, commercial, and industrial customer
programs to the Energy Trust of Oregon (ETO), with the ETO being the sole administrator
effective January 1, 2017. Avista is continuing to adaptively manage its DSlt/ programs in
response to the ever-shifting economic climate.
Perhaps of most importance in the long-term are the Company's ongoing efforts to work with
key regional players to develop a regional naturalgas market transformation organization and
portfolio. The Northwest Energy Efficiency Alliance (NEEA) has been executing the first
stages of their 2015 - 2019 Natural Gas lVlarket Transformation Business Plan. While there
has not yet been any savings realized, there has been many studies and efforts towards
meeting their goals. NEEA is currently working to develop their 2020 - 2024 Business Plan
and we look fonruard to the conservation opportunities that arise out of theirwork in the coming
years.
Market transformation is not itself called out within the CPA since the CPA focuses upon
conservation potential without regard to how that potential is achieved. The prospect for a
regional market transformation entity will potentially bring a valuable tool to bear in working
towards the achievement of the cost-effective conservation opportunities identified within the
natural gas CPA.
Avista Corp 2018 Natural Gas IRP 85
35,263 0.7%Commercial
73,749 2.2%Residential
1,538 0.7%lndustrial
Total 110,551 13%
Cumulative Peak Day Savings
(Therms)% of Overall Sector SavingsSector
Chapter 4: Supply-Side Resources
4: Supply-Side Resources
Overview
Avista analyzed a range of future demand
scenarios and possible cost-effective conservation
measures to reduce demand. This chapter
discusses supply options to meet net demand.
Avista's objective is to provide reliable natural gas
to customers with an appropriate balance of price
stability and prudent cost under changing market
conditions. To achieve this objective, Avista
evaluates a variety of supply-side resources and
attempts to build a diversified natural gas supply
portfolio. The resource acquisition and commodity
procurement programs resulting from the
evaluation consider physical and financial risks,
market-related risks, and procurement execution
risks; and identifies methods to mitigate these
risks.
Avista manages natural gas procurement and related activities on a system-wide basis
with several regional supply options available to serve core customers. Supply options
include firm and non-firm supplies, firm and interruptible transportation on six interstate
pipelines, and storage. Because Avista's core customers span three states, the diversity
of delivery points and demand requirements adds to the options available to meet
customers' needs. The utilization of these components varies depending on demand and
operating conditions. This chapter discusses the available regional commodity resources
and Avista's procurement plan strategies, the regional pipeline resource options available
to deliver the commodity to customers, and the storage resource options available to
provide additional supply diversity, enhanced reliability, favorable price opportunities, and
flexibility to meet a varied demand profile. Non-traditional resources are also considered.
Commodity Resources
Supply Basins
The Northwest continues to enjoy a low cost commodity environment with abundant
supply availability, especially when compared across the globe. This is primarily due to
increasing production in areas of the Northeast and Southern United States. New large-
capacity pipelines, like the Rover pipeline located in Ohio and tr/ichigan, are entering
Cha pter
H igh lights
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resources to drive down
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An increased drilling
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Avista Corp 2018 Natural Gas IRP 87
service and increasing the take away capacity from these prolific production areas. This
supply is serving an increasing amount of demand in the population heavy areas in the
middle and eastern portions of Canada and the U.S displacing supplies that had
historically been delivered from the Western Canadian Sedimentary Basis (WCSB).
Current forecasts show a long-term regional price advantage for Western Canada and
Rockies gas basins as the need for this gas diminishes. To put this into perspective, 2005
Canadian imports accounted for nearly 20% of the U.S. demand. Fast foruvard to 2017
and this number is less than 107o, showing the sheer growth in U.S. supply. This glut of
Canadian gas paired with limited options for flowing gas into demand areas has created
a deeply discounted commodity in the Northwest when compared to the Henry Hub.
Adding to these fundamentals is the recent increase in the price of West Texas
lntermediate (WTl) oil to levels not seen since 2014 (figure 4.3). This is leading to an
increased level of drilling for oil throughout North America and with it a large amount of
associated gas.
Figure 4.3: WTI Spot Price FOB
S per Barrel
s120
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Access to these abundant supplies of natural gas and to major markets across the
continent has also led to the construction of multiple LNG plants. Sabine Pass and Cove
Point are both operational and will be supplying the world with a total of over 3 Bcf of
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Avista Corp 2018 Natural Gas IRP 88
Chapter 4: Supply-Side Resources
Chapter 4: Supply-Side Resources
natural gas daily. There are currently eighteen export terminalsl proposed in North
America, awaiting FERC review and approval which have a liquefaction capacity of over
23 Bcf per day. A listing of facilities awaiting approval for import or export in North
America is showing a large number of projects with pending applications. ln the western
U.S. there is one proposed project the Jordan Cove export facility in Oregon. After initially
being rejected for approval to export, Jordan Cove has refiled their application and is
expecting a FERC decision by the second half of 2019. A Canadian project - LNG
Canada located in Kitimat B.C., has received National Energy Board (NEB) approval and
is awaiting a final investment decision expected Q3 or Q4 2018. lts initial capacity, like
Jordan Cove, is roughly 1 Bcf per day, but contains an option for up to 3.5 Bcf per day in
total. The large increase of natural gas demand by either of these facilities moving
fonrvard could cause pressure on commodity prices with the limited infrastructure in the
Pacific Northwest.
Another relatively new demand area is Mexico. ln 2013, [\4exico reformed its energy
sector allowing new market participants, innovative technologies and foreign investment.
This market reformation opened up new opportunities for natural gas export to Mexico..
Since these market changes, Mexican imports which were historically less than 2 Bcf per
day have more than doubled and are expected to rise to more than triple by just 2021.
Recent estimates from both the EIA and Natural Resources Canada reflect a large
potential supply of natural gas in North America of over 4,000 trillion cubic feet (Tcf) or
enough supply to last 100's of years at current demand levels. This estimate, is based
on known geological areas combined with the ability to economically recover natural gas
as infrastructure expands and technology improves.
Regional Market Hubs
There are numerous regional market hubs in the Pacific Northwest where natural gas is
traded extending from the two primary basins. These regional hubs are typically located
at pipeline interconnects. Avista is located near, and transacts at, most of the Pacific
Northwest regional market hubs, enabling flexible access to geographically diverse
supply points. These supply points include:
AECO - The AECO-C/Nova lnventory Transfer market center located in Alberta is
a major connection region to long-distance transportation systems which take
natural gas to points throughout Canada and the United States. Alberta is the
major Canadian exporter of natural gas to the U.S. and historically produces 90
percent of Canada's natural gas.
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Avista Corp 2018 Natural Gas IRP 89
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Chapter 4: Supply-Side Resources
Rockies - This pricing point represents several locations on the southern end of
the NWP system in the Rocky Mountain region. The system draws on Rocky
Jt/ountain natural gas-producing areas clustered in areas of Colorado, Utah, New
Jvlexico and Wyoming.
Sumas/Huntingdon The Sumas, Washington pricing point is on the
U.S./Canadian border where the northern end of the NWP system connects with
Enbridge's Westcoast Pipeline and predominantly markets Canadian natural gas
from Northern British Columbia.
Malin - This pricing point is at lt/alin, Oregon, on the California/Oregon border
where TransCanada's Gas Transmission Northwest (GTN) and Pacific Gas &
Electric Company con nect.
Station 2 - Located at the center of the Enbridge's Westcoast Pipeline system
connecting to northern British Columbia natural gas production.
Stanfield - Located near the Washington/Oregon border at the intersection of the
NWP and GTN pipelines.
Kingsgate - Located at the U.S./Canadian (ldaho) border where the GTN pipeline
connects with the TransCanada Foothills pipeline.
Given the ability to transport natural gas across North America, natural gas pricing is often
compared to the Henry Hub price. Henry Hub, located in Louisiana, is the primary natural
gas pricing point in the U.S. and is the trading point used in NYTMEX futures contracts.
Figure 4.1 shows historic natural gas prices for first-of-month index physical purchases
at AECO, Station 2, Rockies and Henry Hub. The figure has changed in recent years due
to a change in flows of natural gas specifically coming from Western Canada. ln 2017
the United States flipped from being a net importer to a net exporter.
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Avista Corp 2018 Natural Gas IRP 90
Chapter 4: Supply-Side Resources
Figure 4.1: Monthly lndex Prices
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Northwest regional natural gas prices typically move together; however, the basis
differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints, and the ability to shift supplies to
higher-priced delivery points in the U.S. or Canada. By monitoring these price shifts,
Avista can often purchase at the lowest-priced trading hubs on a given day, subject to
operationa! and contractual constraints.
Liquidity is generally sufficient in the day-markets at most Northwest supply points. AECO
continues to be the most liquid supply point, especially for longer-term transactions.
Sumas has historically been the least liquid of the four major regional supply points
(AECO, Rockies, Sumas and Malin). This illiquidity contributes to generally higher relative
prices in the high demand winter months.
Avista procures natural gas via contracts. Contract specifics vary from transaction-to-
transaction, and many of those terms or conditions affect commodity pricing. Some of the
terms and conditions include:
Firm vs. Non-Firm: Most term contracts specify that supplies are firm except for
force majeure conditions. ln the case of non-firm supplies, the standard provision
is that they may be cut for reasons other than force majeure conditions.
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Avista Corp 2018 Natural Gas IRP 91
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Chapter 4: Supply-Side Resources
Fixed vs. Floating Pricing: The agreed-upon price for the delivered gas may be
fixed or based on a daily or monthly index.
Physical vs. Financial: Certain counterparties, such as banking institutions, may
not trade physical natural gas, but are still active in the naturalgas markets. Rather
than managing physical supplies, those counterparties choose to transact
financially rather than physically. Financial transactions provide another way for
Avista to financially hedge price.
Load Factor/Variable Take: Some contracts have fixed reservation charges
assessed during each of the winter months, while others have minimum daily or
monthly take requirements. Depending on the specific provisions, the resulting
commodity price will contain a discount or premium compared to standard terms.
Liquidated Damages: [Vost contracts contain provisions for symmetrical penalties
for failure to take or supply natural gas.
a
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For this lRP, the SENDOUT@ model assumes natural gas purchases under a firm,
physical, fixed-price contract, regardless of contract execution date and type of contract.
Avista pursues a variety of contractual terms and conditions to capture the most value for
customers. Avista's natural gas buyers actively assess the most cost-effective way to
meet customer demand and optimize unutilized resources.
Transportation Resources
Although proximity to liquid market hubs is important from a cost perspective, supplies
are only as reliable as the pipeline transportation from the hubs to Avista's service
territories. Capturing favorable price differentials and mitigating price and operational risk
can also be realized by holding multiple pipeline transportation options. Avista contracts
for a sufficient amount of diversified firm pipeline capacity from various receipt and
delivery points (including storage facilities), so that firm deliveries will meet peak day
demand. This combination of firm transportation rights to Avista's service territory, storage
facilities and access to liquid supply basins ensure peak supplies are available to serve
core customers.
Avista Corp 20'18 Natural Gas IRP 92
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Chapter 4: Supply-Side Resources
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The major pipelines servicing the region include:
Williams - Northwest Pipeline (NWP):
A natural gas transmission pipeline serving the Pacific Northwest moving natural
gas from the U.S./Canadian border in Washington and from the Rocky Mountain
region of the U.S.
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Avista Corp 2018 Natural Gas IRP 93
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Chapter 4: Supply-Side Resources
Transcanada Gas Transmission Northwest (GTN): A natural gas transmission
pipeline originating at Kingsgate, Idaho, (Canadian/U.S. border) and terminating
at the California/Oregon border close to Malin, Oregon.
TransGanada Alberta System (NGTL): This natural gas gathering and
transmission pipeline in Alberta, Canada, delivers natural gas into the
TransCanada Foothills pipeline at the Alberta/British Columbia border.
TransCanada Foothills System: This natural gas transmission pipeline delivers
natural gas between the Alberta - British Columbia border and the Canadian/U.S.
border at Kingsgate, ldaho.
Transcanada Tuscarora Gas Transmission: This natural gas transmission
pipeline originates at Malin, Oregon, and terminates at Wadsworth, Nevada.
Enbridge - Westcoast Pipeline: This natural gas transmission pipeline originates
at Fort Nelson, British Columbia, and terminates at the Canadian/U.S. border at
Huntington, British Columbia/Sumas, Washington.
EI Paso Natural Gas - Ruby pipeline: This natural gas transmission pipeline
brings supplies from the Rocky lMountain region of the U.S. to interconnections
near Malin, Oregon.
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Avista has contracts with all of the above pipelines (with the exception of Ruby Pipeline)
for firm transportation to serve core customers. Table 4.1 details the firm
transportation/resource services contracted by Avista. These contracts are of different
vintages with different expiration dates; however, all have the right to be renewed by
Avista. This gives Avista and its customer's available capacity to meet existing core
demand now and in the future.
Table 4.1: Firm Transportation Resources Contracted (Dth/Day)
Avista
North
Firm Transportation Vlrinter Summer
NWP TF-1 157,a69 157,a69
GTN T-1 100,605 75,782
NWP TF-2 91.200
Total 349,674 233,651
Firm Storage Resources - Max Deliverabilityr
Jackson Prairie
Avis{a
South
Winter Summer
42,699 42,699
42,260 20,640
2.623
47,5a2 63,339
(Owned and
Contracted) 346,667 54,6.23
Total 346,667 54,623
* Represents original contract amounts a1fter releases expire-
Avista Corp 2018 Natural Gas IRP 94
Chapter 4: Supply-Side Resources
Avista defines two categories of interstate pipeline capacity. Direct-connect pipelines
deliver supplies directly to Avista's local distribution system from production areas,
storage facilities or interconnections with other pipelines. Upstream pipelines deliver
natural gas to the direct-connect pipelines from remote production areas, market centers
and out-of-area storage facilities. Firm Storage Resources - [\4ax Deliverability is
specifically tied to Avista's withdrawal rights at the Jackson Prairie storage facility and is
based on our one third ownership rights. This number only indicates how much we can
withdraw from the facility as transport on NWP is needed to move it from the facility itself.
Figure 4.2 illustrates the direct-connect pipeline network relative to Avista's supply
sources and service territories.2
Figure 4.2: Direct-Connect Pipelines
AECOStation 2
Sumas
JP
Storage Washington & ldaho
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Klamath
Falls
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Supply-side resource decisions focus on where to purchase natural gas and how to
deliver it to customers. Each LDC has distinct service territories and geography relative
2 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a
natural gas transmission pipeline originating at Malin, Oregon, to service a small number of Oregon
customers near the southern border of the state.
Avista Corp 2018 Natural Gas IRP 95
Chapter 4: Supply-Side Resources
to supply sources and pipeline infrastructure. Solutions that deliver supply to service
territories among regional LDCs are similar but are rarely generic.
The NWP system is effectively a fully-contracted. With the exception of La Grande, OR,
Avista's service territories lie at the end of NWP pipeline laterals. The Spokane, Coeur
d'Alene and Lewiston laterals serve Washington and ldaho load, and the Grants Pass
lateral serves Roseburg and Medford. Capacity expansions of these laterals would be
lengthy and costly endeavors which Avista would likely bear most of the incremental
costs.
The GTN system runs from the Kingsgate trading point on the ldaho-Canadian border
down to Malin on the Oregon-California border. This pipeline runs directly through or near
most of Avista's service territories. Mileage based rates provide an attractive option for
securing incremental resource needs. Until recently, GTN had a large amount of
unsubscribed capacity. However as prices continue their downward fall, producers are
increasingly contracting for this excess capacity in order to move gas down to more
favorable markets themselves rather than relying on current market dynamics. This may
have some future pricing implications on the commodity side.
Peak day planning aside, both pipelines provide an arcay of options to flexibly manage
daily operations. The NWP and GTN pipelines directly serve Avista's two largest service
territories, providing diversification and risk mitigation with respect to supply source, price
and reliability. Northwest Pipeline (NWP) provides direct access to Rockies and British
Columbia supply and facilitates optionality for storage facility management. The Stanfield
interconnect of the two lines is also geographically well situated to Avista's service
territories.
The rates used in the planning model start with filed rates currently in effect (See
Appendix 4.1 - Current Transportation/Storage Rates and Assumptions). Forecasting
future pipeline rates is challenging. Assumptions for future rate changes are the result of
market information on comparable pipeline projects, prior rate case experience, and
informal discussions with regional pipeline owners. Pipelines will file to recover costs at
rates equal to their cost of service.
NWP and GTN also offer interruptible transportation services. lnterruptible transportation
is subject to curtailment when pipeline capacity constraints limit the amount of natural gas
that may be moved. Although the commodity cost per dekatherm transported is generally
the same as firm transportation, there are no demand or reservation charges in these
transportation contracts.. Avista does not rely on interruptible capacity to meet peak day
core demand requirements.
Avista Corp 2018 Natural Gas IRP 96
Chapter 4: Supply-Side Resources
Avista's transportation acquisition strategy is to contract for firm transportation to serve
core customers on a peak day in the planning horizon. Since contracts for pipeline
capacity are often lengthy and core customer demand needs can vary over time,
determining the appropriate level of firm transportation is a complex analysis. The
analysis includes the projected number of firm customers and their expected annual and
peak day demand, opportunities for future pipeline or storage expansions, and relative
costs between pipelines and upstream supplies. This analysis is done on semi-annual
basis and through the lRP. Active management of underutilized transportation capacity
either through the capacity release market or engaging in optimization transactions to
recover some transportation costs. Timely analysis is also important to maintain an
appropriate time cushion to allow for required lead times should the need for securing
new capacity arise (See Chapter 6 - lntegrated Resource Portfolio for a description of the
management of underutilized pipeline resources).
Avista manages existing resources through optimization to mitigate the costs incurred by
customers until the resource is required to meet demand. The recovery of transportation
costs is often market based with rules governed by the FERC. The management of long-
and short-term resources ensures the goal to meet firm customer demand in a reliable
and cost-effective manner. Unutilized resources like supply, transportation, storage and
capacity can be combined to create products that capture more value than the individual
pieces. Avista has structured long-term arrangements with other utilities that allow
available resources utilization and provide products that no individual component can
satisfy. These products provide more cost recovery of the fixed charges incurred for the
resources. Another strategy to mitigate transportation costs is to participate in the daily
market to assess if unutilized capacity has value. Avista seeks daily opportunities to
purchase natural gas, transport it on existing unutilized capacity, and sell it into a higher
priced market to capture the cost of the natural gas purchased and recover some pipeline
charges. The recovery is market dependent and may or may not recover all pipeline costs,
but mitigates pipeline costs to customers.
Storage Resources
Storage is a valuable strategic resource that enables improved management of a highly
seasonal and varied demand profile. Storage benefits include:
. Flexibility to serve peak period needs;
. Access to typically lower cost off-peak supplies;
. Reduced need for higher cost annual firm transportation;
2018 Natural Gas IRPAvista Corp 97
Chapter 4: Supply-Side Resources
lmproved utilization of existing firm transportation via off-season storage injections;
and
Additional supply point diversity.
While there are several storage facilities available in the region, Avista's existing storage
resources consist solely of ownership and leasehold rights at the Jackson Prairie Storage
facility.
Avista optimizes storage as part of its asset management program. This helps to ensure
a controlled cost mechanism is in place to manage the large supply found within the
storage facility. An example of this storage optimization is selling today at a cash price
and buying a fonruard month contract. Since fonruard months have risks or premiums built
into the price the result is Avista locking in a given spread. All optimization of assets go
directly to the customer to reduce their monthly billing.
Jackson Prairie Storage
Avista is one-third owner, with NWP and Puget Sound Energy (PSE), of the Jackson
Prairie Storage Project for the benefit of its core customers in all three states. Jackson
Prairie Storage is an underground reservoir facility located near Chehalis, Washington
approximately 30 miles south of Olympia, Washington. The total working natural gas
capacity of the facility is approximately 25 Bcf. Avista's current share of this capacity for
core customers is approximately 8.5 Bcf and includes 398,667 Dth of daily deliverability
rights. Besides ownership rights, Avista leased an additional 95,565 Dth of Jackson
Prairie capacity with 2,623 Dth of deliverability from NWP to serve Oregon customers.
lncremental Supply-Side Resource Options
Avista's existing portfolio of supply-side resources provides a mix of assets to manage
demand requirements for average and peak day events. Avista monitors the following
potential resource options to meet future requirements in anticipation of changing demand
requirements. When considering or selecting a transportation resource, the appropriate
natural gas supply pairs with the transportation resource and the SENDOUT@ model
prices the resources accordingly.
Capacity Release Recall
Pipeline capacity not utilized to serve core customer demand is available to sell to other
parties or optimized through daily or term transactions. Released capacity is generally
marketed through a competitive bidding process and can be on a short{erm (month-to-
Avista Corp 2018 Natural Gas IRP 9B
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Chapter 4: Supply-Side Resources
month) or long-term basis. Avista actively participates in the capacity release market with
short-term and long-term capacity releases. Avista assesses the need to recall capacity
or extend a release of capacity on an on-going basis. The IRP process evaluates if or
when to recall some or all long-term releases.
Existing Available Capacity
ln some instances, there is available capacity on existing pipelines. NWP's mainline is
fully subscribed and while GTN has recently seen a significant increase in contracting
activity, they currently maintain the ability to flow additional supply from Kingsgate to
Spokane as noted in Chapter 7. Avista has modeled access to the GTN capacity as an
option to meet future demand needs in addition to some capacity in the La Grande area
where some quantities are available on NWP.
GTN Backhauls
The GTN interconnection with the Ruby Pipeline has enabled GTN the physicalcapability
to provide a limited amount of firm back-haul service from Malin with minor modifications
to their system. Fees for utilizing this service are under the existing Firm Rate Schedule
(FTS-1) and currently include no fuel charges. Additional requests for back-haul service
may require additionalfacilities and compression (i.e., fuel).
This service can provide an interesting solution for Oregon customers. For example,
Avista can purchase supplies at Jt/alin, Oregon and transport those supplies to Klamath
Falls or Medford. Malin-based natural gas supplies typically include a higher basis
differential to AECO supplies, but are generally less expensive than the cost of fonryard-
haul transporting traditional supplies south and paying the associated demand charges.
The GTN system is a mileage-based system, so Avista pays only a fraction of the rate if
it is transporting supplies from Malin to Medford and Klamath Falls. The GTN system is
approximately 612 miles long and the distance from tValin to the Medford lateral is only
about 12 miles.
New Pipeli ne Transportation
Additional firm pipeline transportation resources are viable and attractive resource
options. However, determining the appropriate level, supply source and associated
pipeline path, costs and timing, and if existing resources will be available at the
appropriate time, make this resource difficult to analyze. Firm pipeline transportation
provides severa! advantages; it provides the ability to receive firm supplies at the
production basin, it provides for base-load demand, and it can be a low-cost option given
Avista Corp 2018 Natural Gas IRP 99
Chapter 4: Supply-Side Resources
optimization and capacity release opportunities. Pipeline transportation has several
drawbacks, including typically long-dated contract requirements, limited need in the
summer months (many pipelines require annual contracts), and limited availability and/or
inconvenient sizing/timing relative to resource need.
Pipeline expansions are typically more expensive than existing pipeline capacity and
often require long-term contracts. Even though expansions may be more expensive than
existing capacity, this approach may still provide the best option given that some of the
other options require matching pipeline transportation. [Matching pipeline transportation is
creating equivalent volumes on different pipelines from the basin to the delivery point in
orderto fully utilize subscribed capacity. Expansions may also provide increased reliability
or access to supply that cannot be obtained through existing pipelines. This is the case
with the Pacific Connector pipeline being proposed as the connecting feedstock for the
Jordan Cove LNG facility in Oregon. The pipeline's current path connects into Northwest
Pipelines Grants Pass Lateral where capacity is limited. The Pacific Connector pipeline
would add an additional 50,000 Dth/day of capacity along that lateral flowing south from
the Roseburg interconnect.
Several specific projects have been proposed for the region. The following summaries
describe these projects while Figure 4.3 illustrates their location.
Avista Corp 2018 Natural Gas IRP 100
Chapter 4: Supply-Side Resources
Figure 4.3: Proposed Pipeline Locations
Cordovalftrr nFliver
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FortisBC Southern Crossing Expansion:
The Southern Crossing pipeline system is a bidirectional pipeline connecting
Westcoast T South system at Kingsvale, BC and TransCanada's BC. This
expansion would include over 90 miles of pipeline looping allowing access to an
additional 300-400 Mlt/cfld of bi-directional capacity, tying together station 2 and
AECO markets.
a
Avista Corp 2018 Natural Gas IRP 101
I
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Avista Corp
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Chapter 4: Supply-Side Resources
TransCanada GTN Trail WesUN-MAX
The pipeline taking natural gas off of GTN and onto NWP hub near Molalla is
referred to as Trail WesUN-MAX. TransCanada GTN, Northwest Natural and
Northwest Pipeline are the project sponsors of this 106-mile, 30-inch diameter
pipeline. The initial design capacity of this pipeline is 500 ttllttllcfld and expandable
up to 1,000 ttltVcf/d. This could be an important project if built as it would bring
more gas into the l-5 corridor where unused pipeline capacity is quickly
disappearing based on the demand for natural gas and population increase.
Sumas Express
NWP continues to explore options to expand service from Sumas, Wash., to
markets along the lnterstate-S corridor. This project could help relieve the
congestion along this highly populated geographical region in both Washington
and Oregon. Various methods could be used to add this additional capacity
including looping, additional compression and increasing the pipe size and can be
scaled based off of demand.
Enbridge/FortisBC T-South System Looping
FortisBC and Enbridge are system enhancement on the T-South pipeline.
Removing constraints will allow expansion of Endbridge's T-South enhanced
service offering, which provides shippers the options of delivering to Sumas or the
Kingsgate market. Expanding the bi-directional Southern Crossing system would
increase capacity at Sumas during peak demand periods. lnitial capacity from the
Enbridge system to Kingsgate would increase capacity by 190MMcf/d. This would
add incremental gas into the Huntington/Sumas market through looping and
compressor station upgrades along the system.
Pacific Connector
Pembina is currently attempting to acquire approval for a 232-mile, 36-inch
diameter pipeline designed to transport up to 1.2 billion cubic feet of natural gas
per day from interconnects near Malin, Oregon, to the Jordan Cove LNG terminal
in Coos Bay, Oregon. The pipeline would deliver the feedstock to the LNG terminal
providing natural gas to international markets, but also to the Pacific Northwest.
The pipeline will connect with Williams' Northwest Pipeline on the Grants Pass
lateral. This ties in directly within Avista's service territory and will bring in an
2018 Natural Gas IRP 102
Chapter 4: Supply-Side Resources
additional 50,000 Dth/day of capacity into that area. This new option could provide
Avista's customers in the area new capacity for growth and supply diversity.
NGTL - West Path expansion
ln order to meet existing aggregate demand in southern AB and incremental long-
term delivery commitments at the fuBC border, NGTL is proposing this project
underpinned by long-term contracts to increase the delivery point capacity at the
fuBC border by 288,000 GJ/day. This project would operationally true-up capacity
differences between NGTL and Foothills and provide additional export capacity
into the US.
Avista supports proposals that bring supply diversity and reliability to the region. Supply
diversity provides a varied supply base in the procurement of natural gas. Since there are
few options in the Northwest, supply diversity provides options and security when
constraints or high demand are present. Avista engages in discussions and analysis of
the potential impact of each regional proposal from a demand serving and
reliability/supply diversity perspective. ln most cases, for Avista to consider them a viable
incremental resource to meet demand needs would require combining them with
additional capacity on existing pipeline resources. However, the IRP considers a generic
expansion that represents a new pipeline build to Avista's service territories.
ln-Ground Storage
ln-ground storage provides advantages when natural gas from storage can be delivered
to Avista's city-gates. lt enables deliveries of natural gas to customers during peak cold
weather events. It also facilitates potentially lower-cost supply for customers by capturing
peak/non-peak pricing differentials and potential arbitrage opportunities within individual
months. Although additional storage can be a valuable resource, without deliverability to
Avista's service territory, this storage cannot be an incremental firm peak serving
resource.
Jackson Prairie
Jackson Prairie is a potential resource for expansion opportunities. Any future storage
expansion capacity does not include transportation and therefore cannot be considered
an incremental peak day resource. However, Avista will continue to look for exchange
and transportation release opportunities that could fully utilize these additional resource
options. When an opportunity presents itself, Avista assesses the financial and reliability
impact to customers. Due to the fast paced growth in the region, and the need for new
Avista Corp 2018 Natural Gas IRP 103
o
Chapter 4: Supply-Side Resources
resources, a future expansion is possible, though a robust analysis would be required to
determine feasibility. Currently, there are no plans for immediate expansion of Jackson
Prairie.
Other ln-Ground Storage
Other regional storage facilities exist and may be cost effective. Additional capacity at
Northwest Natural's Mist facility, capacity at one of the Alberta area storage facilities,
Questar's Clay Basin facility in northeast Utah, Ryckman Creek in Uinta County, Wyo.,
and northern California storage are all possibilities. Transportation to and from these
facilities to Avista's service territories continues to be the largest impediment to these
options. Avista will continue to look for exchange and transportation release opportunities
while monitoring daily metrics of load, transport and market environment.
LNG and CNG
LNG is another resource option in Avista's service territories and is suited for meeting
peak day or cold weather events. Satellite LNG uses natural gas that is trucked to the
facilities in liquid form from an offsite liquefaction facility. Alternatively, small-scale
liquefaction and storage may also be an effective resource option if natural gas supply
during non-peak times is sufficient to build adequate inventory for peak events. Permitting
issues notwithstanding, facilities could be located in optimal locations within the
distribution system.
CNG is another resource option for meeting demand peaks and is operationally similar to
LNG. Naturalgas could be compressed offsite and delivered to a distribution supply point
or compressed locally at the distribution supply point if sufficient natural gas supply and
power for compression is available during non-peak times.
LNG and CNG supply resource options for LDCs are becoming more attractive as the
market for LNG and CNG as alternative transportation fuels develops. The combined
demand for peaking and transportation fuels can increase the volume and utilization of
these resource assets thus lowering unit costs for the benefit of both market segments.
Estimates for LNG and CNG resources vary because of sizing and location issues. This
IRP uses estimates from other facilities constructed in the area and from conversations
with experts in the industry. Avista will monitor and refine the costs of developing LNG
and CNG resources while considering lead time requirements and environmental issues.
Avista Corp 2018 Natural Gas IRP 104
Chapter 4: Supply-Side Resources
Plymouth LNG
NWP owns and operates an LNG storage facility at Plymouth, Wash., which provides
natural gas liquefaction, storage and vaporization service under its LS-1, LS-2F and LS-
3F tariffs. An example ratio of injection and withdrawal rates show that it can take more
than 200 days to fill to capacity, but only three to five days to empty. As such, the resource
is best suited for needle-peak demands. lncremental transportation capacity to Avista's
service territories would have to be obtained in order for it to be an effective peaking
resource. With available capacity, Plymouth LNG was considered in our supply side
resource modeling but was not selected.
Avista-Owned Liquefaction LNG
Avista could construct a liquefaction LNG facility in the service area. Doing so could use
excess transportation during off-peak periods to fill the facility, avoid tying up
transportation during peak weather events, and it may avoid additional annual pipeline
charges.
Construction would depend on regulatory and environmental approval as well as cost-
effectiveness requirements. Preliminary estimates of the construction, environmental,
right-of-way, legal, operating and maintenance, required lead times, and inventory costs
indicate company-owned LNG facilities have significant development risks. Avista
modeling included LNG, but it was not selected as a resource when compared to existing
resources.
Renewable Natural Gas (RNG)
Renewable Natural Gas, or biogas, typically refers to a mixture of gases produced by the
biological breakdown of organic matter in the absence of oxygen. RNG can be produced
by anaerobic digestion or fermentation of biodegradable materials such as woody
biomass, manure or sewage, municipalwaste, green waste and energy crops. Depending
on the type of RNG there are different factors for the amount of methane saved by its
capture as methane has been found to have a multiplier effect on global warming of, at a
minimum, 253 times that of carbon dioxide. Each type of RNG has a different carbon
intensity as compared to natural gas as shown in table 4.2.
3 https://www.epa.gov/ghgemissions/understanding-global-warming-potentials
Avista Corp 20'18 Natural Gas IRP 105
Table 4.2 Garbon intensitya:
Landfill
Dairy
WWT
Solid Waste
RNG is a renewable fuel, so it may qualify for renewable energy subsidies. Once
contained, RNG can be used by boilers for heat, as power generation, compressed
natural gas vehicles for transportation or directly injected into the natural gas grid. The
further down this line greater the need for pipeline quality gas.
Biogas projects are unique, so reliable cost estimates are difficult to obtain. Project
sponsorship has many complex issues, and the more likely participation in such a project
is as a long-term contracted purchaser. Avista considered biogas as a resource in this
planning cycle, as depending on the location of the facility it may be cost effective. This
is especially the case when found within Avista's internal distribution system where
transportation and fuel costs can be avoided.
Avista's Natural Gas Procurement Plan
No company can accurately predict future natural gas prices, but market conditions and
experience help shape the overall approach to procurement. Avista's natural gas
procurement plan process seeks to acquire natural gas supplies while reducing exposure
to shortterm price volatility. The procurement strategy includes hedging, storage
utilization and index purchases. Although the specific provisions of the procurement plan
will change based on ongoing analysis and experience, the following principles guide
Avista's procurement plan.
Avista employs a time, Iocation and counterpafi diversified hedging strategy. lt is
appropriate to hedge over a period of time and establish hedge phases when portions of
future demand are physically and/or financially hedged. Avista views hedging as a type
4 California Air Resources Board
78.37 100%717
46.42 4L%48
-216.24 -4sz%(s2e)
19.34 7s%88
(1sL)-22.93 -L29%
Carhon lntensity
(s coue/MJ)
Carbon
lntensity as
compared to
Natural Gas
lbs. of carbon
per Dth
Avista Corp 2018 Natural Gas IRP 106
Chapter 4: Supply-Side Resources
Natural Gas
Source
Chapter 4: Supply-Side Resources
of risk insurance and an appropriate part of a diversified procurement plan with a mission
to provide a diversified portfolio of reliable supply and a level of price certainty in
volatile markets. Hedges may not be at the lowest possible price, but they still protect
customers from price volatility. With access to multiple supply basins, Avista transacts
with the lowest priced basin at the time of the hedge. Furthermore, Avista transacts with
a range of counterparties to spread supply among a wider range of market participants.
ln utilizing
Avista uses a disciplined, but flexible hedging approach. Avista's hedging strategy
begins with the prompt month and extends for up to thirty six months out based on market
availability of winter and summer pricing strips. This program is run through a mechanism
utilizing an upper and lower control limit or bands to help control market cost and risk.
These control limits measure the volatility in the market place, by basin, and will adjust
inward toward the price, when rising, or allow the lower control limit to fall with volatility
when prices go down. Also, in response to the Washington Utilities and Transportation
Commission (WUTC) hedging policy UG-132019, Avista is also developing an additional
methodology to measure the totalvalue at risk (VaR) of its entire portfolio of hedges. This
methodology is based off of market volatility and statistical measurements of the
marketplace and may allow Avista to hedge less based on current market fundamentals,
while also controlling the financial risk of a rising market.
Avista regularly reviews its procurement plan in light of changing market
conditions and opportunities. Avista's plan is open to change in response to ongoing
review of the procurement plan assumptions. Even though the initial plan establishes
various targets, policies provide flexibility to exercise judgment to revise targets in
response to changing conditions.
Avista utilizes a number of tools to help mitigate financial risks. Avista purchases gas in
the spot market and fonruard markets. Spot purchases are for the next day or weekend.
Fonruard purchases are for future delivery. Many of these tools are financial instruments
or derivatives that can provide fixed prices or dampen price volatility. Avista continues to
evaluate how to manage daily demand volatility, whether through option tools from
counterparties or through access to additional storage capacity and/or transportation.
Market-Related Risks and Risk Management
There are several types of risk and approaches to risk management. The 2018 IRP
focuses on two areas of risk: the financial risk of the cost of natural gas to supply
customers will be unreasonably high or volatile, and the physical risk that there may not
be enough natural gas resources (either transportation capacity or the commodity) to
serve core customers.
Avista Corp 2018 Natural Gas IRP 107
Chapter 4: Supply-Side Resources
Avista's Risk Management Policy describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses issues
related to management oversight and responsibilities, internal reporting requirements,
documentation and transaction tracking, and credit risk.
Two internal organizations assist in the establishment, reporting and review of Avista's
business activities as they relate to management of natural gas business risks:
The Risk Management Committee includes corporate officers and senior-level
management. The committee establishes the Risk [Vanagement Policy and
monitors compliance. They receive regular reports on naturalgas activity and meet
regularly to discuss market conditions, hedging activity and other natural gas-
related matters.
The Strategic Oversight Group coordinates natural gas matters among internal
natural gas-related stakeholders and serves as a reference/sounding board for
strategic decisions, including hedges, made by the Natural Gas Supply
department. [Members include representatives from the Gas Supply, Accounting,
Regulatory, Credit, Power Resources, and Risk Management departments. While
the Natural Gas Supply department is responsible for implementing hedge
transactions, the Strategic Oversight Group provides input and advice.
a
a
Supply Scenarios
The 20'18 IRP includes two supply scenarios. Additional details about the results of the
supply scenarios are in Chapters 6 and 7.
. Existing Resources: This scenario represents all resources currently owned or
contracted by Avista.
. Existing + Expected Available: ln this scenario, existing resources plus supply
resource options expected to be available when resource needs are identified. This
includes currently available south and north bound GTN, NWP, capacity release
recalls, RNG, Hydrogen and LNG.
Supply lssues
The abundance and accessibility of shale gas has fundamentally altered North American
natural gas supply and the outlook for future natural gas prices. Even though the supply
is available and the technology exists to access it, there are issues that can affect the
cost and availability of natural gas.
Avista Corp 2018 Natural Gas IRP 108
Chapter 4: Supply-Side Resources
Hydraulic Fracturing
Hydraulic fracturing (commonly referred to as fracking) was invented by Hubbert and
Willis of Standard Oil and Gas Corporation back in the late 1940's. The process involves
a technique to fracture shale rock with a pressurized liquid. ln the past 15 years, the
techniques and materials used have become increasingly perfected opening up large
deposits of shale gas formations at a low prices. The Energy lnformation Administration
(ElA) tracks production per well in the seven key oil and natural gas production formations
in the United States as shown in Figure 4.4. Figure 4.5 shows the continued increase in
efficiency of production compared to just a year ago as shown by the EIA's Drilling
Productivity Report 4. 55.
Figure 4.4 - seven major drilling regions in the United States
Bakken
Eagle
s Drilling Productivity Report, https://www.eia.govlpetroleum/drilling/pdflsummary.pdf
AEdarfto
Avista Corp 20'18 Natural Gas IRP 109
Niobraa
Figure 4.5 - June 2018 Drilling Productivity Report, EIA
New-well gas production per rig
th rlu :- it rrd cLr il i c; f eet'tl aV
mJuly-2017 rJuly-2018
18.000
15.000
12,000
9.000
6.000
3,000
0
Anadarko Appalachia Bakken Eagle Ford Haynesville Niobrara Permian
With the increasingly prevalent use of hydraulic fracturing came concerns of chemicals
used in the process. The publicity caused by movies, documentaries and articles in
national newspapers about "fracking" has plagued the natural gas and oil industry. There
is concern that hydraulic fracturing is contaminating aquifers, increasing air pollution and
causing earthquakes. One common misconception with the process is that hydraulic
fracturing causes earthquakes. The actual cause of earthquakes is wastewater injection
used in operations at the well site. Based on research at the U.S. Geological Survey,
only a small number of these earthquakes are from fracking itself.6 Additionally,
wastewater injections are used for all wells, not just those where fracking is involved.
The wide-spread publicity generated interest in the production process and caused some
states to issue bans or moratoriums on drilling until further research was conducted. To
help combat these fears, Frac FocusT was created and is a chemical disclosure registry
allowing users to view chemicals used by over 125,000 wells throughout North America.
This information, voluntarily submitted by Exploration and production companies,
provides a detailed list of materials used to frack each individual well.
6 https://profile.usgs.gov/myscience/uplo ad_folder/ci2015Jun10120057556001nduced_EQs_Review.pdf
7 https: / / f r acfocus. org/
Avista Corp 2018 Natural Gas IRP 110
Chapter 4: Supply-Side Resources
Chapter 4: Supply-Side Resources
Pipeline Availability
The Pacific Northwest has efficiently utilized its relatively sparse network of pipeline
infrastructure to meet the region's needs. As the amount of renewable energy increases,
future demand for natural gas-fired generation will increase. Pipeline capacity is the link
between natural gas and power.
There are currently a few industrial plants being considered in the Pacific Northwest. The
project with the highest likelihood is the project located in Washington's Port of Kalama.
This process uses large amounts of natural gas as a feedstock for creating methanol,
which is used to make other chemicals and as a fuel. At over 300,000 Dth per day this
plant would consume large amounts of natural gas.
Ongoing Activity
Without resource deficiencies or a need to acquire incremental supply-side resources to
meet peak day demands over the next 20 years, Avista will focus on normal activities in
the near term, including:
Continue to monitor supply resource trends including the availability and price of
natural gas to the region, LNG exports, supply dynamics and marketplace, and
pipeline and storage infrastructure availability.
lMonitor availability of resource options and assess new resource lead-time
requirements relative to resource need to preserve flexibility.
Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.
Gonclusion
Abundant supply availability around the Northwest may lead to an increased demand in
this planning horizon by large industrials. While keeping a watchful eye on the market,
Avista has continued to make adjustments to its procurement plan to help reduce short
term volatility and is actively engaged in new strategies and mechanisms to help manage
overall financial risk related to hedging. Our supply mix is diversified between multiple
basins with firm take away rights thus helping to reduce the risk of not meeting demand
on a cold day. This in combination with the optimization of our storage, transportation and
basin resources have helped Avista to provide natural gas reliably to our customers at a
fair and reasonable price.
Avista Corp 2018 Natural Gas IRP 111
a
a
a
Chapter 4: Supply-Side Resources
Avista Corp 2018 Natural Gas IRP 112
Chapter 5-Policy Considerations
5: Policy Gonsiderations
Regulatory environments regarding energy topics
such as renewable energy and greenhouse gas
regulation continue to evolve since publication of
the last lRP. Current and proposed regulations by
federal and state agencies, coupled with political
and legal efforts, have implications for the
development and continued use of coal and natural
gas-fired generation. This chapter discusses
pertinent public policy issues relevant to the lRP.
Environmental lssues
The evolving and sometimes contradictory nature
of environmental regulation from state and federal
perspectives creates challenges for resource
planning. The IRP cannot add renewables or
reduce emissions in isolation from topics such as
system reliability, least cost requirements, price
mitigation, financial risk management, and meeting
changing environmental requirements. Each generating resource has distinctive
operating characteristics, cost structures, and environmental regulatory challenges that
can change significantly based on timing and location. All resource choices have costs
and benefits requiring careful consideration of the utility and customer needs being
fulfilled, their location, and the regulatory and policy environment at the time of
procurement.
Renewable energy technologies such as renewable natural gas (RNG) have different
benefits and challenges. Renewable resources have low or no fuel costs and few, if any,
direct emissions. Renewable resources are often located to maximize capability rather
than proximity to load centers. The need to site renewable resources in remote locations
often requires significant investments in distribution and capacity expansion, as well as
mitigating possible wildlife and aesthetic issues. Transportation costs and logistics also
complicate the location of RNG plants.
The long-term economics of renewable resources also faces some uncertainties. Federal
investment and production tax credits are set to expire. The extension credits and grants
may not be sustainable given their impact on government finances and the maturity of
wind and solar technologies. lt4any relatively unpredictable factors affect renewables,
such as renewable portfolio standards (RPS), construction and component prices,
international trade issues and currency exchange rates. Decreasing capital costs for wind
and solar may slow or stop.
The design and scope of greenhouse gas regulation is in a state of flux due to legal
challenges and evolving political realities. As a result, greenhouse gas policy-making is
shifting from the federal to the state and local level. Since the 2016 IRP publication,
Chapter Highlights
Electrification has become
an increasingly recurrent
topic in the Northwest
Avista's Climate PolicyCouncil monitorsgreenhouse gaslegislation and
environmental regulation
issuesBoth Washington and
Oregon are actively
creating bills to tax, trade,or charge a fee for
releasing carbon dioxide
into the atmosphere
a
a
a
Avista Corp 2018 Natural Gas IRP 113
Chapter 5-Policy Considerations
changes in the approach to greenhouse gas emissions regulation and supporting
programs, include:
o The EPA proposed actions to regulate greenhouse gas emissions under the Clean
Air Act (CAA) through the proposed Clean Power Plan (CPP) were stayed by the
U.S. Supreme Court on February 9, 2016;
o On August 20,2018 the EPA proposed a CPP replacement rule, referred to as the
"Affordable Clean Energy Rule", establishing individual plant greenhouse gas
emissions in contrast to the CPP which targeted emission's across each states
energy sector;
. The President signaled a shift in federal priorities through Executive Orders as well
as proposed budgets.
. The State of Washington invalidated the Clean Air Rule
. Regulations or laws placing a monetary value on the cost of carbon through a tax,
fee or cap-andtrade program are becoming increasingly recurrent in the states of
Oregon and Washington.
Natural Gas System Emissions
The physical makeup of the natural gas system includes extraction rigs, pipelines and
storage; each of these facilities have fugitive emissions. Fugitive emissions are the
unintended or irregular releases of natural gas as part of the production cycle. The EPA
introduced the Natural Gas STAR Program in 1993 in response to these emissions
concerns. This Natural Gas STAR Program is a voluntary program allowing the self-
reporting of emission reduction technologies and practices and includes all of the major
industry sectors. ln [t4ay 2016, the EPA finalized rules to reduce methane emissions from
wells under the CAA. The program requires natural gas well owners to find and repair
leaks at the well site no less than twice per year and four times per year at compressor
stations. The EPA placed a 90-day delay on portions of the rule to allow additional
comments.
Natural gas wells utilizing shale deposits have a high production curve at the beginning
of the extraction process and then dramatically levels off. lf not constructed properly, there
is a risk of leakage that may lower the return on investment. ln addition, risk of increased
regulation incentivizes producers to manage emissions as effectively as possible as more
regulations generally increase costs and reduce return on investments. Over time a
smaller return on investment could mean the difference in survival outcomes for each
producer. Natural gas emissions in 1990, as shown in table 7.1 , were higher than in 2016
even though the production was just slightly over 50 Bcf/day compared to roughly 78
Bcf/day in 2016. This is nearly equivalent to reducing emissions by half when accounting
for the additional production.
Avista Corp 2018 Natural Gas IRP 114
Chapter 5-Policy Considerations
Table 5.1: Non-combustion CO2 Emissions from Natural Gas Systems (kt)l
1990 2012 2013 2014 2015 2016
Note: Totals may not sum due to independent rounding.
Avista's Glimate Change Policy Efforts
Avista's Climate Policy Council is an interdisciplinary team of management and other
employees that:
o Facilitates internaland external communications regarding climate change issues;
. Analyzes policy impacts, anticipates opportunities, and evaluates strategies for
Avista Corporation; and
o Develops recommendations on climate related policy positions and action plans.
The core team of the Climate Policy Council includes members from Environmental
Affairs, Government Relations, External Communications, Engineering, Energy
Solutions, and Resource Planning groups. Other areas participate for topics as needed.
The meetings for this group include work for both immediate and longterm concerns.
lmmediate concerns include reviewing and analyzing proposed or pending state and
federal legislation and regulation, reviewing corporate climate change policy, and
responding to internal and external requests about climate change issues. Longer-term
issues involve emissions measurement and reporting, different greenhouse gas policies,
actively participating in legislation, and benchmarking climate change policies and
activities against other organ izations.
EPA Regulations
EPA regulations, or the States' authorized versions, directly, or indirectly, affecting
electricity generation include the CAA, along with its various components, including the
Acid Rain Program, the National Ambient Air Quality Standard, the Hazardous Air
Pollutant rules, and Regional Haze Programs. The U.S. Supreme Court ruled the EPA
has authority under the CAA to regulate greenhouse gas emissions from new motor
vehicles and the EPA has issued such regulations. When these regulations became
effective, carbon dioxide and other greenhouse gases became regulated pollutants under
the Prevention of Significant Deterioration (PSD) preconstruction permit program and the
Title V operating permit program. Both of these programs apply to power plants and other
commercial and industrial facilities. ln 2010, the EPA issued a final rule, known as the
Tailoring Rule, governing the application of these programs to stationary sources, such
as power plants. EPA proposed a rule in early 2012, and modified in 2013, setting
1 Source is from "3-80 lnventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2016" Pg. B0
https://www.epa.qov/sites/production/files/2018-0'l/documents/2018 chapter 3 enerqv.pdf
2005
Avista Corp 2018 Natural Gas IRP 't15
Exploration
Production
Ihocessing
Transmission and Storage
Distribution
404
E7l
2E.338
166
51
1.761
1,709
lE.E75
140
27
1,323
2,6E3
19.120
135
l5
1,1 59
3,003
20.508
t42
t4
851
3,278
21,044
l4E
t4
287
3,396
21,044
147
L4
13E
3,212
22.009
t43
t4
Totfll 29,831 22,512 23276 24,E27 25"336 24,EEE 25,516
Chapter 5-Policy Considerations
standards of performance for greenhouse gas emissions from new and modified fossil
fuel-fired electric generating units and for existing sources through the draft CPP in June
2014. The EPA released the final CPP rules and the Carbon Pollution Standards (CPS)
as published in the Federal Register on October 23, 2015, when they were both
challenged thorough a series of lawsuits. Standards under Section 1 1 1(d) of the CAA are
currently stayed by the Supreme Court. The EPA also finalized new source performance
standards (NSPS) for new, modified and reconstructed fossil fuel-fired generation under
CAA section 111(b).
EPA Mandatory Reporting Rule
Any facility emitting over 25,000 metric tons of greenhouse gases per year must report
its emissions to EPA. The lr4andatory Reporting Rule requires greenhouse gas reporting
for natural gas distribution system throughput, fugitive emissions from electric power
transmission and distribution systems, fugitive emissions from natural gas distribution
systems, and from natural gas storage facilities. Washington requires mandatory
greenhouse gas emissions reporting similar to the EPA requirements and Oregon has
similar reporting requirements.
State and Regional Level Policy Considerations
The lack of a comprehensive federal greenhouse gas policy encouraged states, such as
California, to develop their own climate change laws and regulations. Climate change
legislation takes many forms, including economy-wide regulation under a cap and trade
system, a carbon tax, and emissions performance standards for power plants.
Comprehensive climate change policy can include multiple components, such as
renewable portfolio standards, DS[\4 standards, and emission performance standards.
Washington enacted all of these components, but other Avista jurisdictions have not.
lndividual state actions produce a patchwork of competing rules and regulations for
utilities to follow and may be particularly problematic for multi-jurisdictional utilities such
as Avista.
ldaho Policy Considerations
ldaho does not regulate greenhouse gases. There is no indication ldaho is moving toward
regulation of greenhouse gas emissions beyond federal regulations.
Oregon Policy Considerations
The State of Oregon has a history of greenhouse gas emissions and renewable portfolio
standards legislation. The Legislature enacted House Bill 3543 in 2007, calling for, but
not requiring, reductions of greenhouse gas emissions to 10 percent below 1990 levels
by 2020 and 75 percent below 1990 levels by 2050. Compliance is expected through a
combination of the RPS and other complementary policies, like low carbon fuel standards
and DStM measures. The state has been working towards the adaptation of
comprehensive requirements to meet these goals. HB 2135, or the cap and trade bill, is
under consideration at the time this chapter is being written. This bill would repeal the
greenhouse gas emissions goals stated above and would require the Environmental
Quality Commission to adopt greenhouse gas emissions goals for 2A25, and set limits for
years 2035 and 2050.
Avista Corp 2018 Natural Gas IRP 116
Chapter 5-Policy Considerations
These reduction goals are in addition to a 1997 regulation requiring fossil-fueled
generation developers to offset carbon dioxide (COz) emissions exceeding 83 percent of
the emissions of a state-of-the-art gas-fired combined cycle combustion turbine by
funding offsets through the Climate Trust of Oregon.
Oregon's Gap-and-Trade
A set of cap-andtrade bills were included in the Oregon Legislature, but did not make it
out due to the short session. ln spite of this, a joint legislative committee announced
plans to create a "cap-and-invest" program in time for the 2019 session. This committee
will be funded by $t.4 million to help fund a Carbon Policy Office and to determine how
these programs would impact Oregon's economy, jobs and emissions. These two bills,
HB 4001 and SB 1507 would both create a cap and trade system for entities emitting over
25,000 metric tons of carbon annually. ln 2021, the Oregon Environmental Quality
Commission would set a statewide emissions on about 100 companies who would need
to reduce emissions or buy allowances. The revenue from these programs would be
invested in clean energy or emissions mitigation programs leading to the final goal of 80%
emissions reduction by 2050.
Washington State Policy Considerations
Former Governor Christine Gregoire signed Executive Order 07-02 in February 2007
establishing the following GHG emissions goals:
o 1990 levels by 2020;
. 25 percent below 1990 levels by 2035;
. 50 percent below 1990 levels by 2050 or 70 percent below Washington's expected
emissions in 2050;
. lncrease clean energy jobs to 25,000 by 2020; and
. Reduce statewide fuel imports by 20 percent.
The Washington Department of Ecology adopted regulations to ensure that its State
lmplementation Plan comports with the requirements of the EPA's regulation of
greenhouse gas emissions. We will continue to monitor actions by the Department as it
may proceed to adopt additional regulations under its CAA authorities.
2 https://qlis. leq.state.or. us/lizl20
Avista Corp 2018 Natural Gas IRP 117
Oregon RNG
ln Oregon, Senate Bill 3342 was passed to help develop, update, and maintain the biogas
inventory available. This includes the sites and potential production quantities available
in addition to the quantity of renewable naturalgas available for use to reduce greenhouse
gas emissions. This bill will also help promote RNG and identify the barriers and removal
of barriers to develop and utilize RNG. A report is due by September 2018.
Chapter 5-Policy Considerations
April 29, 2014, Washington Governor Jay lnslee issued Executive Order 14-04,
"Washington Carbon Pollution Reduction and Clean Energy Action." The order created a
"Climate Emissions Reduction Task Force" tasked with providing recommendations to the
Governor on designing and implementing a market-based carbon pollution program to
inform possible legislative proposals in 2015. The order also called on the program to
"establish a cap on carbon pollution emissions, with binding requirements to meet our
statutory emission limits." The order also states that the Governor's Legislative Affairs
and Policy Office "will seek negotiated agreements with key utilities and others to reduce
and eliminate over time the use of electrical power produced from coal." The Task Force
issued a report summarizing its efforts, which included a range of potential carbon-
reducing proposals. Subsequently, in January 2015, at Governor lnslee's request, the
Carbon Pollution Accountability Act was introduced as a bill in the Washington legislature.
The bill includes a proposed cap and trade system for carbon emissions from a wide
range of sources, including fossil-fired electrical generation, "imported" power generated
by fossil fuels, natural gas sales and use, and certain uses of biomass for electrical
generation. The bill was not enacted during the 2015 legislative session. After the
conclusion of the 20lS legislative sessions, Governor lnslee directed the Department of
Ecology to commence a rulemaking process to impose a greenhouse gas emission
limitation and reduction mechanism under the agency's CAA authority to meet the future
emissions limits established by the Legislature in 2008. This resulted in Washington's
Clean Air Rule (CAR).
The CAR intended to impose new compliance obligations on sources identified by
Ecology. The rule imposes caps and requirements to reduce or offset emissions on large
emitting facilities, fuel providers and natural gas distribution companies. lt initially applies
to 29 entities. Compliance obligations for energy-intensive trade-exposed industries,
including pulp and paper manufacturers, steel and aluminum manufacturers and food
processors, are deferred for three years. When fully implemented, the CAR could cover
as many as 70 emitters who account for about two-thirds of Washington's emissions. The
CAR caps emissions for facilities emitting more than 100,000 metric tons per year, and
reduces the emissions threshold by 5,000 metric tons per year, until covering all entities
emitting over 70,000 metric tons by 2035. The Washington Commission may implement
rules regarding RCW 70.235, from the Executive Order 07-02. The CAR became effective
January 1,2017, but was ruled invalid on December 15,2017 in Thurston County
Superior Court. This ruling found that local distribution companies are not emitters, and
have no choice under the law to meet the supply demands of its customers. On May 14,
2018 the Department of Ecology appealed this ruling with the Washington State Supreme
Court. lf a policy comes into law comparable to the CAR, the number of ERU's required
for Avista's natural gas customers would create a demand for renewable energy. This
would likely lead to the procurement of RNG, but due to the large amount of needed
It/TCO2e offsets would also drive the need for wind and solar. Figure 5.1 shows a
potential outcome of a program like the CAR and its impacts on Avista's Washington
customers.
Avista Corp 2018 Natural Gas IRP 118
Chapter 5-Policy Considerations
Figure 5.1 : Avista - Washington only CO2e emissions reduction estimate from CAR
r# of Needed ERUs IAvista WA CO2e..CAR Goal
1,400,000
1,200,000
L,000,000
800,000
600,000
400,000
200,000
oc!oUF
"$"S"S#'r$"SC"ulCC"$"S"So",""S"grSr&W
Deep Decarbonization
ln December of 2016 Governor lnslee's office commissioned a deep decarbonization
pathway study on reducing emissions required to curb a globaltemperature increase to below
two degrees Celsius. This study lists three possible scenarios seen as a pathway for
Washington State to reduce 1990 emission to below 80% 2050. These methods are
electrification, renewable pipeline and innovation. Electrification involves electrifying end-
uses to the greatest extent possible while reducing natural gas use. The second involves
creating a renewable pipeline where all gas comes from decarbonized biogas, synthetic
natural gas and hydrogen. Finally innovation is seen as both electrifying end-uses coupled
with innovation in the areas of electric and autonomous vehicles, fuel cells, and offshore wind.
ln order to show demand impacts of this type of scenario within Avista's natural gas
operations, we modeled this scenario as "80% below 1990 emissions". This scenario does
not assume the technology, costs involved, or methods used to reduce emissions. Rather,
the intent is to show the overall loss of demand if the resource mix is solely natural gas with
no renewable supply resources. Please refer to Chapter 7 - Alternate Scenarios, Portfolios
and Stochastic Analysis for results.
Avista Corp 2018 Natural Gas IRP 119
I tr n E I I
Chapter 5-Policy Considerations
Washington RNG
Washington State House Bill 25803 was signed by Governor Jay lnslee on March 22,
2018 and will become effective on July 1,2018 bringing into law a bill to help encourage
production of renewable natural gas (RNG). This bill requires the Washington State
University Extension Energy Program and the Department of Commerce (DOC) along
with the consulting of the Washington State Utilities and Transportation Commission, to
submit recommendations on promoting the sustainable development of RNG. The DOC
will consult with natural gas utilities and other state agencies to explore developing
voluntary gas quality standards for the injection of RNG into natural gas pipeline systems
in the state. The tax incentive is equal to the value of the product multiplied by the rate
of the specific commodity or product as detailed in the bill.
3 http://apps2.leg.wa.gov/billsummary?Year=2017&BillNumber=2580&Year=2017&BillNumber=2580
Avista Corp 2018 Natural Gas IRP 120
Chapter 6: lntegrated Resource Portfolio
6: lntegrated Resource
Portfolio
Overview
This chapter combines the previously discussed
IRP components and the model used to determine
resource deficiencies during the 2O-year planning
horizon. This chapter provides an analysis of
potential resource options to meet resource
deficiencies as exhibited in the High Growth, Low
Prices scenario.
The foundation for integrated resource planning is
the criteria used for developing demand forecasts.
Avista uses the coldest day on record as its
weather-planning standard for determining peak-day demand. This is consistent with past
lRPs as described in Chapter 2 - Demand Forecasts. This IRP utilizes coldest day on
record and average weather data for each demand region. Avista plans to serve expected
peak day in each demand region with firm resources. Firm resources include natural gas
supplies, firm pipeline transportation and storage resources. ln addition to peak
requirements, Avista also plans for non-peak periods such as winter, shoulder and
summer demand. The modeling process includes a daily optimization for every day of the
2}-year planning period.
It is assumed that on a peak day all interruptible customers have left the system to provide
service to firm customers. Avista does not make firm commitments to serve interruptible
customers, so IRP analysis of demand-serving capabilities only includes the firm
residential, commercial and industrial classes. Using coldest day on record weather
criteria, a blended price curve developed by industry experts, and an academically
backed customer forecast all work together to develop stringent planning criteria.
Forecasted demand represents the amount of natural gas supply needed. ln order to
deliver the forecasted demand, the supply forecast needs to increase between 1.0
percent and 3.0 percent on both an annual and peak-day basis to account for additional
supplies purchased primarily for pipeline compressor station fuel. The range of 1.0
percent to 3.0 percent, known as fuel, varies depending on the pipeline. The FERC and
National Energy Board approved tariffs govern the percentage of required additionalfuel
supply.
Chapter Highlights
No resource shortage in
the expected case
An increase in DSM
potential in Washington
and Oregon
ldaho is now broken out
into its own demand area
Higher Carbon Costs vs.
2016 rRP
a
a
o
o
Avista Corp 2018 Natural Gas IRP 121
Chapter 6: lntegrated Resource Portfolio
SENDOUT@ Planning Model
The SENDOUT@ Gas Planning System from Ventyx performs integrated resource
optimization modeling. Avista purchased the SENDOUT@ model in April 1992 and has
used it to prepare all lRPs since then. Avista has a maintenance agreement with Ventyx
for software updates and enhancements. Enhancements include software corrections
and improvements driven by industry needs.
SENDOUT@ is a linear programming model widely used to solve natural gas supply and
transportation optimization questions. Linear programming is a proven technique to solve
minimization/maximization problems. SENDOUT@ analyzes the complete problem at one
time within the study horizon, while accounting for physical limitations and contractual
constraints.
The software analyzes thousands of variables and evaluates possible solutions to
generate a least cost solution given a set of constraints. The model considers the
following variables:
Demand data, such as customer count forecasts and demand
coefficients by customer type (e.9., residential, commercial and
industrial).
Weather data, including minimum, maximum and average
temperatures.
Existing and potential transportation data which describes the network
for physical movement of natural gas and associated pipeline costs.
Existing and potential supply options including supply basins, revenue
requirements as the key cost metric for all asset additions and prices.
Natural gas storage options with injection/withdrawal rates, capacities
and costs.
Conservation potential.
Figure 6.1 is a SENDOUT@ network diagram of Avista's demand centers and resources.
This diagram illustrates current transportation and storage assets, flow paths and
constraint points.
a
a
a
a
a
Avista Corp 2018 Natural Gas IRP 122
Chapter 6: lntegrated Resource Portfolio
Figure 6.1 SENDOUT@ Model Diagram
The SENDOUT@ model provides a flexible tool to analyze scenarios such as:
Pipeline capacity needs and capacity releases;a
a
a
a
a
Effects of different weather patterns upon demand;
Effects of natural gas price increases upon total natural gas costs;
Storage optimization studies;
Resource mix analysis for conservation;
Avista Corp 2018 Natural Gas IRP 123
Chapter 6: lntegrated Resource Portfolio
Weather pattern testing and analysis;
Transportation cost analysis;
a
a
Avoided cost calculations; and
Short-term planning comparisons
SENDOUT@ also includes lt4onte Carlo capabilities, which facilitates price and demand
uncertainty modeling and detailed portfolio optimization techniques to produce probability
distributions. N/ore information and analytical results are located in Chapter 7 - Alternate
Scenarios, Portfolios and Stochastic Analysis. The SENDOUT@ model is used by many
LDC's across the U.S., however it is becoming increasingly outdated for the current
regulatory environment. Because of this, Avista will be looking into additional software
products or alternatives to help increase the necessary flexibility when modeling the future
lRPs.
Resource lntegration
The following sections summarize the comprehensive analysis bringing demand
forecasting and existing and potential supply and demand-side resources together to form
the 20-year, least-cost plan.
Demand Forecasting
Chapter 2 - Demand Forecasts describes Avista's demand forecasting approach
Avista forecasts demand in the SENDOUT@ model in eleven service areas given the
existence of distinct weather and demand patterns for each area and pipeline
infrastructure dynamics. The SENDOUT@ areas are Washington and ldaho (each state
is disaggregated into three sub-areas because of pipeline flow limitations); tt/edford
(disaggregated into two sub-areas because of pipeline flow limitations); and Roseburg,
Klamath Falls and La Grande. ln addition to area distinction, Avista also models demand
by customer class within each area. The relevant customer classes are residential,
commercial and firm industrial customers.
Customer demand is highly weather-sensitive. Avista's customer demand is not only
highly seasonable, but also highly variable. Figure 6.2 captures this variability showing
monthly system-wide average demand, minimum demand day observed by month,
maximum demand day observed in each month, and winter projected peak day demand
for the first year of the Expected Case forecast as determined in SENDOUT@.
a
a
Avista Corp 2018 Natural Gas IRP 124
Chapter 6: Integrated Resource Portfolio
Figure 6.2: TotalSystem Average Daily Load (Average, Minimum and Maximum)
TotalSystem Average Daily Load
Go
o
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
$ds "/ -.r. **foou.'* -r."-$.""- ,.o- .$-o,*-,.-" "J
-ffi3y
162fl Min Load Average Load
-Peak
Day
Natural Gas Price Forecasts
Natural gas prices play a central part of the IRP and has the largest impact on the costs
used for determining the cost-effectiveness of DSN/ measures as well as new potential
resources. The price of natural gas also influences consumption, so price elasticity is part
of the demand evaluation shown in Chapter 2 - Demand Forecasts.
The natural gas price outlook has changed dramatically in recent years in response to
several influential events and trends affecting the industry including drilling methods and
technology used in oil and natural gas production, export demand from Mexico and LNG.
These factors combined with the renewable energy standards and the increased need to
back these resources up with natural gas-fired generation are creating. The rapidly
changing environment and uncertainty in predicting future events and trends, requires
modeling a range of forecasts.
The two consultants end up in the same expected price by around 2027 timeframe,
though differ in the timing of LNG export facilities and industrial demand, causing a split
in pricing around the 2021 timeframe. Both consultants expect similar power burn
reaching levels of around 50 Bcf per day by 2035. The Nymex fonruard curve expects
sufficient supply to provide additional demand throughout its time horizon causing a flat
price curve.
_-lA
\
\
\./
\.._/
Avista Corp 2018 Natural Gas IRP 125
Chapter 6: lntegrated Resource Portfolio
Ir4any additional factors influence natural gas pricing and volatility, such as regional
supply/demand issues, weather conditions, storage levels, natural gas-fired generation,
infrastructure disruptions, and infrastructure additions (e.9. new pipelines and LNG
terminals).
Even though Avista continually monitors these factors, we cannot accurately predict
future prices for the 2O-year horizon of this lRP. This IRP reviewed several price forecasts
from credible industry experts. Figure 6.3 depicts the price forecasts considered in the
IRP analyses.
Figure 6.3: Henry Hub Forecasted Price (Nominal $/Dth)
sPo
oo_
{,D
Ss.oo
s7.00
5o.oo
Ss.oo
s4.00
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s2.00
s1.oo
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-l\yrnsx(7/912018) -fensultant
2 :Consultant L
ln the outer years the fundamental curves from the two consultants were more heavily
weighted. This is based on the premise that the market knows more than any single entity
Avista Corp 2018 Natural Gas IRP 126
The expected curve was a blended price derived from two consulting services
subscriptions along with the New York Nlercantile Exchange (NYMEX) foruvard strip on
February 9,2018. The expected price curve was weighted heavily toward the NYMEX
prices in the first few years
Chapter 6: lntegrated Resource Portfolio
or model in the near term
expected price curve:
Below is the specific methodology used to develop the
o Two fundamental forecasts (Consultant #1 & Consultant#2)
. Forward prices
1. Year 1 - fonruard price only
2. Year 2 - 75% forward price / 25o/o average consultant forecasts
3. Year 3 - 50o/o foruvard price / 50% average consultant forecasts
4. Year 4 - 6 25o/o forward price I 75% average consultant forecasts
5. Year 7 - 50% average consultant without CO2 I 50o/o average consultant with CO2
The high and low price curves were derived by varying the price from the expected price
to create a reasonably higher and lower curve while maintaining symmetry. These high
and low prices provide a way to measure pricing risk all while maintaining the balance to
the expected price. The curves are in nominal dollars in Figure 6.4. Additionally,
stochastic modeling of naturalgas prices is also completed. The results from that analysis
are in Chapter 7 - Alternate Scenarios, Portfolios and Stochastic Analysis. With the
assistance of the TAC, Avista selected high, expected and low price curves to consider
possible outcomes and their impact on resource planning.
Avista Corp 2018 Natural Gas IRP 127
.Po
LqJo-lt>
Chapter 6: lntegrated Resource Portfolio
Figure 6.4 Henry Hub Forecasts for lRP Low/ Expected/ High Forecasted Price - Nominal
$/Dth
s12.oo
Srr.oo
Sro.oo
00
00
00
00
00
se
ss
57
s6
ss
s4.oo
s3.oo
Sz.oo
s1.oo
S-
-fligfu
Price Low Price
-fypgsted
Price
Each of the price forecasts above are for Henry Hub, which is located in Louisiana just
onshore from the Gulf of [Vexico. Henry Hub is recognized as the most important pricing
point in the U.S. because of its proximity to a large portion of U.S. natural gas production
and the sheer volume traded in the daily or spot market, as well as the fonruard markets
via the NYTMEX futures contracts. Consequently, all other trading points tend to be priced
off of the Henry Hub with a positive or negative basis differential and is based off of a
consultant forecast. Of the two consultants Avista uses, only one has basis pricing going
throughout the twenty year timeframe and at the points modeled. Two of the market points
modeled by Avista, Kingsgate and Stanfield, do not have a futures market making it
difficult to derive a price expectation without a global model of the North America gas
supply landscape.
The primary physical supply points at Sumas, AECO and the Rockies (and other
secondary regional market hubs) determine Avista's costs. Prices at these points typically
trade at a discount, or negative basis differential, to Henry Hub because of their proximity
to the two largest naturalgas basins in North America (Western Canada and the Rockies).
0O O) O Fl c! rn rt Ln rO N 0O O) O rl N cn sl LO (.o F
-l el N N r! c! N N c'.1 N N N cn cn .O cO rn cn cn rnooooooooooooooooooooC! N N N N N N N C\ C! C{ N N N N C\ N N N C\tttttltllrllllllllllF 0O Ot O rl c\ rn sf Ln (o N @ O) O rl N cn $ |J} (OFl Fl rl N N N N N N N c! N N cn cn cn an cO cO cnooooooooooooooooooooC\.I C\l N N N N N N (\ C! C\l N N N N C\ N N N N
Avista Corp 2018 Natural Gas IRP 128
Chapter 6: lntegrated Resource Portfolio
Table 6.1 shows the Pacific Northwest regional prices from the consultants, historic
averages and the prior IRP as a percent of Henry Hub price, along with three-year
h istorical comparisons.
Table 6.1: Regional Price as a Percent of Henry Hub Price
This IRP used monthly prices for modeling purposes because of Avista's winter-weighted
demand profile. Table 6.2 depicts the monthly price shape used in this lRP. A slight
change to the shape of the pricing curve occurred since the 2016 lRP. Supply availability
drove this change because the forecasted differential between winter and summer pricing
has decreased to some extent compared to historic data.
Table 6.2: Monthly Price as a Percent of Average Price
Avista selected a blend of Consultant 1 and Consultant 2's forecast of regional prices and
monthly shapes. Appendix 6.1 - Monthly Price Data by Basin contains detailed monthly
price data behind the summary table information discussed above.
Gonsultantl
Forecast Average
79.Oo/o 89.7% 89.7o/o g2.8Yo 90.5%
Consultant2
Forecast Average
68.4% 86.0% 92.8% 101.9% 97.9%
Historic Cash
Three Year
Average
67.3% 88.2% 90.5% 94.4%90.7%
2016 tRP 88.5% 95.5% 96.8% 98.9%97.5%
AECO Sumas Rockies Malin Stanfield
Gonsultantl 104.2% 103.8% 100.5% 95.0% 95.6Yo 96.7%
Gonsultant2 100.4% 100.3% 98.8% 97.9% 98.4% 99.8%
2016 IRP 107.0% 107.2% 97.5% 95.2% 95.6% 96.20h
Jul Aug Sep Oct Nov Dec
Gonsultantl 100.3% 1O1.9% 100.4% 1O0.7o/o 98.3% 102.5%
Consultant2 100.9% 101.6% 101.2% 100.7% 100.1% 100.1%
20't6 tRP 97 .6% 98.40/o 98.3% 98.6% 101.8% 106.7%
Jan Feb Mar Apr May Jun
Avista Corp 2018 Natural Gas IRP 129
Chapter 6: lntegrated Resource Portfolio
Carbon Policy
Avista models carbon as an incremental price adder to address any potential policy.
Carbon adders increase the price of a dekatherm of natural gas and can impact resource
selections and demand through expected elasticity (Chapter 2 - Demand Forecasts,
Price Elasticity). The price of carbon in Oregon was based on the 2018 California annual
auction reserye price of $14.53 per greenhouse gas emissions allowance while growing
by the 5% plus the rate of inflation as indicated by the program structure section 95911
of the California Cap-and-Trade Regulation.l The starting price for Oregon was assumed
to be similar to California's cap and trade system where the initial floor was set at $17.86
per metric tons of carbon dioxide equivalent (lVITCOze) and begins in January 20212 rising
to $51 .58 by 2037 . Washington State was modeled at $10 per tVlTCOze starting in 2019
and rising to $30 per IIITCO2e by 2030. These carbon tax figures were based on the
initial proposed carbon legislation from Governor lnslee known as Senate Bill 6203.3 The
State of ldaho does not have a carbon adder as there is no current or proposed state or
federal legislation associated with carbon in that jurisdiction. Avista also completed
sensitivities with both a lower and higher than expected price of carbon. These derived
values were taken from the EPA calculations of the social cost of carbon as updated on
January 19, 2017.4 The low carbon price is based on 5 percent average (discount rate
and statistic) and begins at $11.60 per MTCOze in2018 and increases to $21 .2Oby 2037.
The high carbon price is the EPA's high impact scenario of the average of g5 percent of
results at a 3 percent discount rate. This rate produces much higher cost of carbon
beginning in 2018 at $1 1 5.80 and increasing to $llq per ItITCOze by 2037 . The effect of
these modeled carbon prices, combined with our expected elasticity as described in
Chapter 2 Demand Forecasts, change demand as shown in Figure 6.5.
1 Article 5 California Cap on Greenhouse gas emissions and market-based compliance mechanisms
https://www.arb.ca.qov/cc/capandtrade/capandtrade/unofficial ct 100217.pdf
2 Senate Bill 1070 https./lqlis.leq.state.or.us/lizl2017R1/Downloads/MeasureDocument/S81070
3 Senate Bill 6203 http://laMilesext.leq.wa.qov/biennium/2017-18/Pdf/Bills/Senate%20Bills/6203-S.pdf
aSocial cost of carbon EPA https:/i l9ianuarv20l Tsnapshot.epa.qoviclimatechanqe/social-cost-
carbon .html
2018 Natural Gas IRP 130Avista Corp
Chapter 6: lntegrated Resource Portfolio
Figure 6.5: Carbon Legislation sensitivities
44,000
42,000
40,000
38,000
36,000
2018 Demand Sensitivities - Carbon Legislation
Annual Demand - Total System
o> 34,000
32,000
30,000
-Q2;'[en
Legislation-Low oQ21[sn Legislation-Expected eQsl[sn Legislation-High
Transportation and Storage
Valuing natural gas supplies is a critical first step in resource integration. Equally
important is capturing all costs to deliver the natural gas to customers. Daily capacity of
existing transportation resources (described in Chapter 4 - Supply-Side Resources) is
represented by the firm resource duration curyes depicted in Figures 6.6 and 6.7.
Avista Corp 2018 Natural Gas IRP 131
Chapter 6: lntegrated Resource Portfolio
Figure 6.6: Existing Firm Transportation Resources - Washington & ldaho
MDth
500
450
400
350
300
2so
200
1s0
100
50
0
1 31 61 91. 12L L51 181 211. 241. 27L 301 331 36L
Day of Year
Figure 6.7: Existing Firm Transportation Resources - Oregon
MDth
200
L80
160
L40
L20
L00
80
60
40
20
0
t 31. 67 91 Lzt 151 181 2L1 247 27L 301 331_ 361
Day of Year
Avista Corp 2018 Natural Gas IRP 132
Chapter 6: lntegrated Resource Portfolio
Current rates for capacity are in Appendix 6.1 - Monthly Price Data by Basin. Forecasting
future pipeline rates can be challenging because of the need to estimate the amount and
timing of rate changes. Avista's estimates and timing of future pipeline rate increases are
based on knowledge obtained from industry discussions and participation in pipeline rate
cases. This IRP assumes pipelines will file to recover costs at rates equal to increases in
GDP (see Appendix 6.2 - Weighted Average Cost of Capital).
Demand-Side Management
Chapter 3 - Demand-Side Resources describes the methodology used to identify
conservation potential and the interactive process that utilizes avoided cost thresholds for
determining the cost effectiveness of conservation measures on an equivalent basis with
su pply-side resources.
Preliminary Results
After incorporating the above data into the SENDOUT@ model, Avista generated an
assessment of demand compared to existing resources for several scenarios. Chapter 2
- Demand Forecasts discusses the demand results from these cases, with additional
details in Appendices 2.1 through 2.9.
Figures 6.8 through 6.11 provide graphic summaries of Average Case demand as
compared to existing resources on a peak day. This demand is net of conservation
savings and shows the adequacy of Avista's resources under normal weather conditions.
For this case, current resources meet demand needs over the planning horizon.
Avista Corp 2018 Natural Gas IRP 133
Chapter 6: lntegrated Resource Portfolio
Figure 6.8: Average Gase - Washington/ldaho Existing Resources vs. Peak Day Demand
- February 15th
Figure 6.9: Average Case - Medford / Roseburg Existing Resources vs. Peak Day
Demand - December 20th
Dth
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
"o9 "o9 "te" "d> "-fl "otr "of "d "$," "S "&" "d "e"
d|
"dP "dP "&" ".str "&" "dIExisting NWP
Average Day Demand
IExisting GTN
ISpokane Supply
r-----rJP TF-2
Dth
120,000
100,000
80,000
60,000
40,000
20,000
0
,$ "$,. "dP
Ct "-f dP rdP "d "d .5}" ,S ,&" .f, ,&" "o* "dP
rdP "e" "d "e"I Existing GTN I Existing NWP l-rJP TF-2 Average Day Demand
Avista Corp 2018 Natural Gas IRP 134
Chapter 6: lntegrated Resource Portfolio
Figure 6.10: Average Gase - Klamath Falls Existing Resources vs. Peak Day Demand -
December 20th
Dth
22,000
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,O0O
0
"$ ".I. "d "et "d) "dP "S "$ "d "&" "d "S "d "&t "-f "dP "-f "e" "d "&"IKlamath Lateral Average Day Demand
Figure 6.11: Average Case - La Grande Existing Resources vs. Peak Day Demand -
February 1Sth
Dth
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
"$i" "dP "&t
d|
"dP "dP "$ "of "d," "d "dtt "d "&" "d) "dry "dP "e" "d "&" ".SIExisting NWP r-----rJP TF-2 Average Day Demand
Avista Corp 2018 Natural Gas IRP "t35
Chapter 6: lntegrated Resource Porlfolio
Figures 6.12 through 6.15 summarize Expected Case peak day demand compared to
existing resources, as well as demand comparisons to the 2016 lRP. This demand is net
of conservation savings. Based on this information, and more specifically where a
resource deficiency is nearly present as shown in Figure 6.9, Avista has time to carefully
monitor, plan and take action on potential resource additions as described in the Ongoing
Activities section of Chapter 9 - Action Plan. Any underutilized resources will be optimized
to mitigate the costs incurred by customers untilthe resource is required to meet demand.
This management, of both long- and short-term resources, ensures the goal to meet firm
customer demand in a reliable and cost-effective manner as described in Supply Side
Resources - Chapter 4.
Figure 6.12: Expected Case - Washington & ldaho Existing Resources vs. Peak Day
Demand - February 15th
Dth
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
"e" "d "$p"
"dP "dP "dP "dF "of "$P" "$ "dtt "o.? "&" "dl "dP "dP "&" "-d "&" "SI Existing GTN
&@ Spokane Supply
IExisting NWP
*Peak Day Demand
r------1 J P TF-2
Prior IRP Peak Day Demand
Avista Corp 2018 Natural Gas IRP 136
Chapter 6: lntegrated Resource Portfolio
Figure 6.13: Expected Case - Medford / Roseburg Existing Resources vs. Peak Day
Demand - December 20th
Figure 6.14: Expected Case - Klamath Falls Existing Resources vs. Peak Day Demand -
December 20th
Dth
22,000
20,000
18,000
16,000
14,000
72,000
10,000
8,000
6,000
4,000
2,000
0
"$ "*. "d .tlt
"d> "dP "S "dF "d dp" "S "d,t "d "&t "S "B "dr "&" "d "e"IKlamath Lateral
Dth
120,000
100,000
80,000
60,000
40,000
20,000
0
"$ "-i. "d "d,,t "of "dP "dP "d "d 4P" "S "o.9 "d "&t "dl "-* rdP "&" "d "e"IExisting GTN IExisting NWP I-TJP TF-2
Avista Corp 2018 Natural Gas IRP 137
IIIIII
Chapter 6: lntegrated Resource Portfolio
Figure 6.15: Expected Case - La Grande Existing Resources vs. Peak Day Demand -
February 15th
Dth
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
d|t "S "&t "d) "dP "dP "$ ,S "$9" "S "te" "d "..gt "d| "B "dP "&" "d "&" "SIExisting NWP r-----rJP TF-2 *Peak Day Demand Prior IRP Peak Day Demand
llEl_lI
=r=r
rrrrlIFIIFT l!t-r-r=l=Er
lf demand grows faster than expected, the need for new resources will be earlier. Flat
demand risk requires close monitoring for signs of increasing demand and reevaluation
of lead times to acquire preferred incremental resources. Monitoring of flat demand risk
includes a reconciliation of forecasted demand to actualdemand on a monthly basis. This
reconciliation helps identify customer growth trends and use-per-customer trends. lf they
meaningfully differ compared to forecasted trends, Avista will assess the impacts on
planning from procurement and resource sufficiency standing.
Table 6.3 quantifies the forecasted total demand net of conservation savings and
unserved demand from the above charts.
Avista Corp 2018 Natural Gas IRP 138
Chapter 6: lntegrated Resource Portfolio
Table 6.3: Peak Day Demand - Served and Unserved (MDth/day)
Case Gas Year
Case Gas Year
2011-2018 753 753 ioff6f 89.42 89.42 100%187.91 187 91 100%
201&2019 755 7.55 roo%f 90 4i m47 100s6 1 90.1 7 190.17 1 0090
7.59 1m96r 9151 91.51 100%191.91 191.91 100702019-2020 7.59
7.62 10061 92.53 92.53 10090 't93.44 193 44 1000,6202U2021lot
2V21-2022 761 76l 10096r 93.41 93.41 100%195.m 195.00 1000,/o
2022-2023 7M 764 lm%r 9423 94.23 100.q6 196 28 196 28 100%
t.6t 100e6r 95.33 95.33 't00%198.21 198.21 100%2U2T2V24 1.67
768 100e6[ 95 88 95 BB 100%1 99.1 7 199 17 1000262U24-2025 768
1.71 10tr6r 96.57 100%2N42 2N.42 '100p,6202t2V267.11 96 57
2026-2027 713 1m%r s7.22 91.22 100s6 201 5t 201.57 100%
2027-2028 1.76 7.76 100961 97 98 97 98 100%202 m 202ffi 100%
7.79 779 1oo%r 98 54 98 54 100%24311 203 71 100Y0202&2029
7.81 1000/6r w22 99.n 1m%2M74 2M74 100%2U29-2030 7.81
203G2031 7U tu 100e6[ 99 95 99 95 100%20518 205 78 10070
2031-2032 7.87 t.8t 1000/6r tm90 100,90 100%207.14 207.14 10090
2032-2033 789 7.89 100e6r 101 59 101 59 100%20t.92 207 92 10090
7.9'l 7,91 1m96r lm50 lmff)100%209 03 209.03 100%203}203/.
793 1m%r 103 47 103.47 100%210 17 210 17 100%2034-2035 7S3
100%r 1M 68 211.74 100%203t2036 7.96 7.S6 1M_6S 'r00%211 74
2036-2037 7.91 797 1mo/or 105 53 105 53 1009'0 212ffi 212.fi 1 0070
La
Grande
Served
La ta
Grande Grande
Unserved Tohl
[a Grand€
% ofPeal
oay
Served
2017-2018 13.24 13.24 100%74.U 74.U 100o/o
13.36 13.36 1000/o 75.65 75 65 1000/o201V2019
13.49 1009o 76.43 76.43 1000/o201S-2420 13.49
lOOo/o202G242113.62 13 62 'loo010 77 22 77 22
2021-2022 13.67 13.67 100o/o 77.59 17.59 100Yo
2A2-2023 13.78 13 78 100%78.29 78.29 1000/o
2023-2024 13 91 13.91 10006 79.O2 79.O2 lAOo/o
14.42 MA2 'l00oib 79.60 79 60 1000/o2024-2A25
14.14 14.14 100%80 28 80.28 1000/o2025-2026
14.26 1000./o 80.95 80.95 100olo2026-2027 14.26
14.37 10006 81.61 81.61 1000/o2027-2028 14.37
14.48 82.24 100%202V2029 14 48 1000/o 82.24
1000/o249-2030 14.59 14.59 100%82.86 82.86
203G2031 14.69 14.69 '1000/o 83.44 83.44 1000/o
2031-2032 14.79 14.79 100%83.99 83.99 '1000/o
2032-2033 14 89 14.89 1000/o u52 u.52 1000/o
15.00 15.00 1000,6 85.03 85.03 1000/o2033-2034
15.10 15 r0 100%85 52 85.52 100o/o2034-2035
15.20 lOOo/o 86.01 86 01 1fi)o/o2035-2036 15.20
l OOo/o2036-2037 't5 30 15 30 100o/o 86 49 86.49
Klamath
Falls
Served
Klamath
Falls
Unserved
Klamath
Falls Total
Klamath
Fdls % of
Peak 0ay
Served
Avista Corp 2018 Natural Gas IRP 't 39
lD%ot
Peak D
Served mllil$IIiEi!'E
WA
Served
WA
Unserved
WA
Total
WA% of
Peak Day
Served
773
Medfordj
Roseburg
Unserved
Medfordl
Roseburg
alo ol
Peak Day
Served
lledford/
Roeeburg
Served
Medford/
Roseburg
Total
Chapter 6: lntegrated Resource Porlfolio
New Resource Options
When existing resources are not sufficient to meet expected demand, there are many
important considerations in determining the appropriateness of potential resources.
lnterruptible customers'transportation may be cut, as needed, when existing resources
are not sufficient to meet firm customer demand.
Resource Cost
Resource cost is the primary consideration when evaluating resource options, although
other factors mentioned below also influence resource decisions. Newly constructed
resources are typically more expensive than existing resources, but existing resources
are in shorter supply. Newly constructed resources provided by a third party, such as a
pipeline, may require a significant contractual commitment. However, newly constructed
resources are often less expensive per unit, if a larger facility is constructed, because of
economies of scale.
Lead Time Requirements
New resource options can take one to five or more years to put in service. Open season
processes to determine interest in proposed pipelines, planning and permitting,
environmental review, design, construction, and testing contribute to lead time
requirements for new facilities. Recalls of released pipeline capacity typically require
advance notice of up to one year. Even DSII/ programs can require significant time from
program development and rollout to the realization of natural gas savings.
Peak versus Base Load
Avista's planning efforts include the ability to serve firm natural gas loads on a peak day,
as well as all other demand periods. Avista's core loads are considerably higher in the
winter than the summer. Due to the winter-peaking nature of Avista's demand, resources
that cost-effectively serve the winter without an associated summer commitment may be
preferable. Alternatively, it is possible that the costs of a winter-only resource may exceed
the cost of annual resources after capacity release or optimization opportunities are
considered.
Resource Usefulness
Available resources must effectively deliver natural gas to the intended region. Given
Avista's unique service territories, it is often impossible to deliver resources from a
Avista Corp 2018 Natural Gas IRP 140
Chapter 6: lntegrated Resource Portfolio
resource option, such as storage, without acquiring additional pipeline transportation.
Pairing resources with transportation increases cost. Other key factors that can contribute
to the usefulness of a resource are viability and reliability. lf the potential resource is either
not available currently (e.9., new technology) or not reliable on a peak day (e.9., firm),
they may not be considered as an option for meeting unserved demand.
"Lumpiness" of Resource Options
Newly constructed resource options are often "lumpy." This means that new resources
may only be available in larger-than-needed quantities and only available every few
years. This lumpiness of resources is driven by the cost dynamics of new construction,
where lower unit costs are available with larger expansions and the economics of
expansion of existing pipelines or the construction of new resources dictate additions
infrequently. The lumpiness of new resources provides a cushion for future groMh.
Economies of scale for pipeline construction provide the opportunity to secure resources
to serve future demand increases.
Competition
LDCs, end-users and marketers compete for regional resources. The Northwest has
efficiently utilized existing resources and has an appropriately sized system. Currently,
the region can accommodate the regional demand needs. However, future needs vary,
and regional LDCs may find they are competing with each other and other parties to
secure firm resources for customers.
Risks and Uncertainties
lnvestigation, identification, and assessment of risks and uncertainties are critical
considerations when evaluating supply resource options. For example, resource costs
are subject to degrees of estimation, partly influenced by the expected timeframe of the
resource need and rigor determining estimates, or estimation difficulties because of the
uniqueness of a resource. Lead times can have varying degrees of certainty ranging from
securing currently available transport (high certainty) to building underground storage
(low certainty).
Avista Corp 2018 Natural Gas IRP 141
Chapter 6: lntegrated Resource Portfolio
Resource Selection
After identifying supply-side resource options and evaluating them based on the above
considerations, Avista entered the supply-side scenarios (see Table 6.2) and
conservation measures (see Chapter 3 - Demand-Side Resources) into the SENDOUT@
model for it to select the least cost approach to meeting resource deficiencies, if they
exist. SENDOUT@ compares demand-side and supply-side resources (see Appendix 6.3
- Supply Side Resource Options for a list of available options) using PVRR analysis to
determine which resource is a least cosUleast risk resource.
Demand-Side Resources
lntegration by Price
As described in Chapter 3 - Demand-Side Resources, the model runs without future DSM
programs. This preliminary model run provides an avoided cost curye for Applied Energy
Group (AEG) to evaluate the cost effectiveness of DSM programs against the initial
avoided cost curve using the Utility Cost Test, Program Administrator Costs Test, Total
Resource Cost Test, and Participant Cost Test. The therm savings and associated
program costs are incorporated into the SENDOUT@ mode!. After incorporation, the
avoided costs are re-evaluated. This process continues until the change in avoided cost
curve is immaterial.
Avoided Cost
The SENDOUT@ model determined avoided-cost figures represent the unit cost to serve
the next unit of demand with a supply-side resource option during a given period. lf a
conservation measure's total resource cost (for ldaho and Oregon), or utility cost (for
Washington), is less than this avoided cost, it will be cost effective to reduce customer
demand and Avista can avoid commodity, storage, transportation and other supply
resource costs.
SENDOUT@ calculates marginal cost data by day, month and yearfor each demand area.A summary graphical depiction of avoided annual and winter costs for the
Washington/ldaho and Oregon areas is in Figure 6.16. The detailed data is in Appendix
6.4 - Avoided Cost Details. Other than the carbon tax adder embedded in the expected
price curve, avoided costs do not include additional environmental externality adders for
adverse environmental impacts. Appendix 3.2 - Environmental Externalities discusses
this concept more fully and includes specific requirements required in modeling for the
Oregon service territory.
Avista Corp 2018 Natural Gas IRP 142
Chapter 6: lntegrated Resource Portfolio
Figure 6.16: Avoided Cost (lncludes Commodity & Transport Cost -2016 vs. 2018 $/Dth)
$/Dth Avoided Cost Comparison
2016 IRP vs. 2018 IRP
$9.00
$8.00
$7.00
$6.00
$s.oo
$4.00
$3.00
$2.00
$1.00
$0.00 i- @ o) o r N co s lo (o F- @ o) o N cf) $ lr) (o l.-F N N N N N N N N N N OO CO CD CD CD Cq CA Cf)oooooooooooooooooooooN N N N N N N N N N C\I N N N N N N N N N N
a-!\/fl/lP Annual - 2018 +OR Annual - 2018
Gonservation Potential
Using the avoided cost thresholds, AEG selected all potential cost effective DSIM
programs. Table 6.4 shows potential DSII/ savings in each region from the selected
conservation potential for the Expected Case. The conservation potential includes
anticipated annual acquisition and is cumulative.
Avista Corp 2018 Natural Gas IRP 143
Chapter 6: lntegrated Resource Portfolio
Table 6.4: Annual and Average Daily Demand Served by Conservation
Case Gas Year
Case Gas Year
20't7-2018 4.83 0.01 320 0,01 23.O2 0.06 31.05 0.09
201*2019 9.75 003 6.63 002 47.05 0.13 63 44 o.17
2019-2020 14.50 0.M 9.85 0.03 70 44 0,19 94.79 0.26
126.7',|0.352020-2021 19.34 0.05 13.00 0.04 94.37 0.26
o.442021-2022 24 31 007 16.13 004 118.99 0.33 159 43
2022-2423 29 61 008 19.46 0.05 145.15 0,40 194.22 0.53
2023-2024 35.27 0.10 23.M 0.06 172.98 0.47 231.28 0.63
2024-2025 41 29 0.11 26.U 0.07 202.63 0,56 270 75 0.74
202*2026 47.68 0.13 30.90 0.08 2U.03 0.64 312.61 0.86
0.73 356 79 0982026-2027 54.43 0.15 35 22 0,10 267.14
403.40 1.112027-2028 61,56 0-17 39.81 0.11 302.03 0.83
2028-2029 69.00 0.19 44 63 0.12 338 35 0.93 451.98 1.24
202v2030 76.67 0.21 49.58 0.14 375.74 1-03 502.00 1.38
203G203'l 84.50 0.23 54.67 0.15 4't3.85 1.13 553.02 1.52
452.37 1.24 6M.67 1.662031-2032 92.42 0.25 5S 87 016
'I .802032-2033 100.48 0.28 65.21 0.18 491.54 1.35 657.24
2033-2AU 108.58 0.30 70 61 0.19 530.88 1.45 710.07 1.95
2A34-2035 116.68 032 76 04 4.21 570.22 1.56 762.93 2.49
2035-2036 124.76 0.34 8't.48 o.22 60s 46 1-67 815.70 2.23
132 75 0.36 86 86 0.24 648.32 1.78 867 93 2.382036-2037
Annual
0regon
DSil
2017-2018 51.07 014 24.40 0.07 106.52 0.29
0.16 243.55 0.672018-2019 121.53 0.33 58.59
2019-2020 211.24 0.58 102.30 o28 408.34 1.12
202G202',|323.71 0.89 1 59.1 5 0.44 609.57 1.67
2021-2022 474 20 130 238.08 0.65 871.71 2.39
2022-2023 666.23 1.83 340.08 0.93 1,200.53 3.29
2023-2024 774.13 2.'.t2 391.72 1.O7 1,397.14 3.83
510.85 1.40 1,781.02 4.882024-2025 999.43 2.74
2425-2026 1,272.34 3.49 656.39 1.80 2,241.U 6.'14
2026-2027 1,564 45 4.25 810.54 2.22 2.731,78 7.48
3.zfi.42 8.872027-2028 1,865.97 5.11 969.05 2.65
202&2029 2,169.90 5.94 '1,127.52 3.09 3,749.40 10.27
2029-2030 2.465.74 6.76 1.280.95 3.5'l 4,248.69 11.64
12.94203U20312,745.42 7.52 1,425.04 3.90 4,723.43
2031-2032 3,005.70 8.23 1,557.75 4.27 5,168.12 14.16
2432-2433 3,243.05 B.89 1,677.50 4.60 5,577.78 15.28
16.312033-2034.3,458.48 9.48 1,785.00 4.89 5,953.55
203/.-2035 3,651.12 10.00 1,880.62 5.15 6,294.67 't7.25
2035-2036 3.825.66 10.48 1.967.14 5.39 6,608 51 18.11
2036-2037 3,982.80 10 91 2,M5.06 5.60 6,895.78 18.89
Daily
Annual Washington
Washington DSM
DsM (MDthl (MBth/Day)
Annual
Total
System
Bsrrl (lrD$l
Avista Corp 2018 Natural Gas IRP 144
Annual
Klamath
DSlt
(UDtttl
mY
Klarnath
DSU
flrDthltlevl
Annual La
Grande
DSIT
illDthl
Daily La
Grande
DSil
IllDthIDavI
Annual
Medford,
Roscburg
DSM
mDthl
Daily
MedfordJ
Roseburg
DSM
lMDthlDavl
Daily
Oregon
DSil
{llDthj[}avl
Annual
Haho DSM
tHrlthl
Daily ldaho
DSM
{illDthJDavl
Daily Total
System
DSil
(ilDth/Davl
Chapter 6: lntegrated Resource Portfolio
Conservation Acquisition Goals
The avoided cost established in SENDOUT@, the conservation potential selected, and
the amount of therm savings is the basis for determining conservation acquisition goals
and subsequent DSM program implementation planning. Chapter 3 - Demand-Side
Resources has additional details on this process.
Supply-Side Resources
SENDOUT@ considers all options entered into the model, determines when and what
resources are needed, and which options are cost effective. Selected resources represent
the best cosUrisk solution, within given constraints, to serve anticipated customer
requirements. Since the Expected Case has no resource additions in the planning
horizon, Avista will continue to review and refine knowledge of resource options and will
act to secure best cosUrisk options when necessary or advantageous.
Resource Utilization
Avista plans to meet firm customer demand requirements in a cost-effective manner. This
goal encompasses a range of activities from meeting peak day requirements in the winter
to acting as a responsible steward of resources during periods of lower resource
utilization. As the analysis presented in this IRP indicates, Avista has ample resources to
meet highly variable demand under multiple scenarios, including peak weather events.
Avista acquired the majority of its upstream pipeline capacity during the deregulation or
unbundling of the natural gas industry. Pipelines were required to allocate capacity and
costs to their existing customers as they transitioned to transportation only service
providers. The FERC allowed a rate structure for pipelines to recover costs through a
Straight Fixed Variable rate design. This structure is based on a higher reservation charge
to cover pipeline costs whether natural gas is transported or not, and a much smaller
variable charge which is incurred only when natural gas is transported. An additionalfuel
charge is assessed to account for the compressors required to move the natural gas to
customers. Avista maintains enough firm capacity to meet peak day requirements under
the Expected Case in this lRP. This requires pipeline capacity contracts at levels in
excess of the average and above minimum load requirements. Given this load profile and
the Straight Fixed Variable rate design, Avista incurs ongoing pipeline costs during non-
peak periods.
Avista chooses to have an active, hands-on management of resources to mitigate
upstream pipeline and commodity costs for customers when the capacity is not utilized
for system load requirements. This management simultaneously deploys multiple long-
Avista Corp 2018 Natural Gas IRP 145
Chapter 6: lntegrated Resource Portfolio
and short-term strategies to meet firm demand requirements in a cost effective manner
The resource strategies addressed are:
. Pipeline contract terms;
. Pipeline capacity;
. Storage;
. Commodity and transport optimization; and
. Combination of available resources.
Pipeline Contract Terms
Some pipeline costs are incurred whether the capacity is utilized or not. Winter demand
must be satisfied and peak days must be met. ldeally, capacity could be contracted from
pipelines only for the time and days it is required. Unfortunately, this is not how pipelines
are contracted or built. Long-term agreements at fixed volumes are usually required for
building or acquiring firm transport. This assures the pipeline of long-term, reasonable
cost recovery.
Avista has negotiated and contracted for several seasonal transportation agreements.
These agreements allow volumes to increase during the demand intensive winter months
and decrease over the lower demand summer period. This is a preferred contracting
strategy because it eliminates costs when demand is low. Avista refers to this as a front
line strategy because it attempts to mitigate costs prior to contracting the resource. Not
all pipelines offer this option. Avista seeks this type of arrangement where available.
Avista currently has some seasonal transportation contracts on TransCanada GTN,
TransCanada BC and TransCanada Alberta. These pipelines match up transport capacity
to move natural gas from Alberta (AECO) to Avista's service territories. Avista also
contracted for IF2 on NWP. This is a storage specific contract and matches up the
withdrawal capacity at Jackson Prairie with pipeline transport to Avista's service
territories. TF2 is a firm service and allows for contracting a daily amount of transportation
for a specified number of days rather than a daily amount on an annual basis as is usually
required. For example, one of the TF2 agreements allows Avista to transport 91,200
Dth/day for 31 days. This is a more cost effective strategy for storage transport than
contracting for an annual amount. Through NWP's tariff, Avista maintains an option to
increase and decrease the number of days this transportation option is available. More
days correspond to increased costs, so balancing storage, transport and demand is
important to ensure an optimal blend of cost and reliability.
Avista Corp 2018 Natural Gas IRP 146
Chapter 6: lntegrated Resource Portfolio
Pipeline Capacity
After contracting for pipeline capacity, its management and utilization determine the
actual costs. The worst-case economic scenario is to do nothing and simply incur the
costs associated with this transport contract over the longterm to meet current and future
peak demand requirements. Avista develops strategies to ensure this does not happen
on a regular basis if at all possible.
Capacity Release
Through the pipeline unbundling of transportation, the FERC establishes rules and
procedures to ensure a fair market developed to manage pipeline capacity as a
commodity. This evolved into the capacity release market and is governed by FERC
regulations through individual pipelines. The pipelines implement the FERC's posting
requirements to ensure a transparent and fair market is maintained for the capacity. All
capacity releases are posted on the pipelines Bulletin Boards and, depending on the
terms, may be subject to bidding in an open market. This provides the transparency
sought by the FERC in establishing the release requirements. Avista utilizes the capacity
release market to manage both long-term and short{erm transportation capacity.
For capacity under contract that may exceed current demand, Avista seeks other parties
that may need it and arranges for capacity releases to transfer rights, obligations and
costs. This shifts all or a portion of the costs away from Avista's customers to a third party
until it is needed to meet customer demand.
lrlany variables determine the value of natural gas transportation. Certain pipeline paths
are more valuable and this can vary by year, season, month and day. The term, volume
and conditions present also contribute to the value recoverable through a capacity
release. For example, a release of winter capacity to a third party may allow for full cost
recovery; while a release for the same period that allows Avista to recall the capacity for
up to 10 days during the winter may not be as valuable to the third party, but of high value
to us. Avista may be willing to offer a discount to retain the recall rights during high
demand periods. This turns a seasonal-for-annual cost into a peaking-only cost. [Varket
terms and conditions are negotiated to determine the value or discount required by both
parties.
Avista has several long-term releases, some extending through 2025 providing full
recovery of allthe pipeline costs. These releases maintain Avista's long-term rights to the
transportation capacity without incurring the costs of waiting until demand increases. As
the end of these release terms near, Avista surveys the market against the IRP to
determine if these contracts should be reclaimed or released, and for what duration.
Avista Corp 2018 Natural Gas IRP 147
Chapter 6: lntegrated Resource Portfolio
Through this process, Avista retains the rights to vintage capacity without incurring the
costs or having to participate in future pipeline expansions that will cost more than current
capacity.
On a shorter term, excess capacity not fully utilized on a seasonal, monthly or daily basis
can also be released. tt/arket conditions often dictate less than full cost recovery for
shorter-term requirements. Mitigating some costs for an unutilized, but required resource
reduces costs to our customers.
Segmentation
Through a process called segmentation, Avista creates new firm pipeline capacity for the
service territory. This doubles some of the capacity volumes at no additional cost to
customers. With increased firm capacity, Avista can continue some long-term releases,
or even reduce some contract levels, if the release market does not provide adequate
recovery. An example of segmentation is if the original receipt and delivery points are
from Sumas to Spokane. Avista can alter this path from Sumas to Sipi, Sipi to Jackson
Prairie, Jackson Prairie to Spokane. This segmentation allows Avista to flow three times
the amount of natural gas on most days or non-peak weather events. ln the event of a
peak day, and the transport needs to be firm, the transportation can be rolled back up to
ensure the natural gas will be delivered into the original firm path.
Storage
As a one-third owner of the Jackson Prairie Storage facility, Avista holds an equal share
of capacity (space available to store natural gas) and delivery (the amount of natural gas
that can be withdrawn on a daily basis).
Storage allows lower summer-priced natural gas to be stored and used in the winter
during high demand or peak day events. Similar to transportation, unneeded capacity and
delivery can be optimized by selling into a future higher priced market. This allows Avista
to manage storage capacity and delivery to meet growing peak day requirements when
needed.
The injection of natural gas into storage during the summer utilizes existing pipeline
transport and helps increase the utilization factor of pipeline agreements. Avista employs
several storage optimization strategies to mitigate costs. Revenue from this activity flows
through the annual PGA/Deferral process.
Avista Corp 2018 Natural Gas IRP 148
Chapter 6: lntegrated Resource Portfolio
Commod ity and Transportation Optim ization
Another strategy to mitigate transportation costs is to participate in the daily market to
assess if unutilized capacity has value. Avista seeks daily opportunities to purchase
natural gas, transport it on existing unutilized capacity, and sell it into a higher priced
market to capture the cost of the natural gas purchased and recover some pipeline
charges. The amount of recovery is market dependent and may or may not recover all
pipeline costs, but does mitigate pipeline costs to customers.
Gombination of Resources
Unutilized resources like supply, transportation, storage and capacity can combine to
create products that capture more value than the individual pieces. Avista has structured
long-term arrangements with other utilities that allow available resource utilization and
provide products that no individual component can satisfy. These products provide more
cost recovery of the fixed charges incurred for the resources while maintaining the rights
to utilize the resource for future customer needs.
Resource Utilization Summary
As determined through the IRP modeling of demand and existing resources, new
resources under the Expected Case are not required over the next 20 years. Avista
manages the existing resources to mitigate the costs incurred by customers until the
resource is required to meet demand. The recovery of costs is often market based with
rules governed by the FERC. Avista is recovering full costs on some resources and partial
costs on others. The management of long- and short-term resources meets firm customer
demand in a reliable and cost-effective manner.
Conclusion
Choosing reliable information and methods to utilize in these analyses help Avista
determine an expected criteria. To do this, Avista utilizes industry experts to help
determine an expected price and market environment, decades of historic weather by
major service atea, daily weather adjusted usage metrics combined with a statistical
based customer forecast all help to provide a reasonable range of expectations for this
planning period. There are no expected resource deficiencies during this 2O-year forecast
in either the Average Case or Expected Case in this lRP. Avista will rely on its Expected
Case for peak operational planning activities and in its optimization programs to
sufficiently plan for cold day events.
Avista Corp 2018 Natural Gas IRP 149
Chapter 6: lntegrated Resource Portfolio
Avista recognizes that there are other potential outcomes. The process described in this
chapter applies to the alternate demand and supply resource scenarios covered in
Chapter 7 - Alternate Scenarios, Portfolios and Stochastic Analysis.
Avista Corp 2018 Natural Gas IRP 150
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
7: Alternate Scenarios,
Portfolios and Stochastic
Analysis
Overview
Avista applied the IRP analysis in Chapter 6 -
lntegrated Resource Portfolio to alternate demand
and supply resource scenarios to develop a range
of alternate portfolios. This deterministic modeling
approach considered different underlying
assumptions vetted with the TAC members to
develop a consensus about the number of cases to
model.
Avista also performed stochastic modeling for
estimating probability distributions of potential
outcomes by allowing for random variation in
natural gas prices and weather based on
fluctuations in historicaldata. This statistical analysis, in conjunction with the deterministic
analysis, enabled statistical quantification of risk from reliability and cost perspectives
related to resource portfolios under varying price and weather conditions.
Alternate Demand Scenarios
As discussed in the Demand Forecasting section, Avista identified alternate scenarios for
detailed analysis to capture a range of possible outcomes over the planning horizon.
Table 7.1 summarizes these scenarios and Chapter 2 - Demand Forecasts and
Appendices 2.6 and 2.7 describes them in detail. The scenarios consider different
demand influencing factors and price elasticity effects for various price influencing factors.
2018 Natural Gas IRP 151
Cha pter
H igh Iights
High Growth and Low
Price case results in
unserved demand
Multiple portfolios
considered to help
measure range of
possible outcomes
RNG and Hydrogen are
considered in the
available resource stack
for the first time
Landfill RNG is selected
as a resource in the High
Growth and Low Price
case
a
a
a
a
Avista Corp
Reference Case Cust Growth Rates Low Growth Rate
Reference Cass
grorth rvith
ernissions 80%
belolr 1990 target
High Growth Rate
3 yr Flat + Price Ebsticity 3 yr Flat + Price
Elasticitv
Yes
Historical Coldest
Dav
Coldest in 20
years 20 year a\€raqe Historical CoUest Day
Expected High Low
$1G$30 WA
$17.8G$51.58 0R
$0 lD
None
Proposed Scenarios ftpccted cold oay 20yr Average Low crot/v0r 80 % below High Growth
INPUTASSUMPIONS
RESULTS
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Table 7.1: 2O18lRP Scenarios
Customer Growth Rate
Use p€r Customer
Weather Standard
Pricc!
Price cun€
Carbon Legislation
($/Metric Ton)
First Gas Year Unserved
Washingiton
ldaho
Medford
Roseburg
Klamath
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N.iA
NIA
NJA
NJA
NJA
N/A
NIA
N/A
NIA
NIA
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2032
2032
2031
2031
N/A
2032La
Mostaggressi\e Evaluates Casemost Stagnantgrowth Reductionoftie Aggressi\regroudt
peak planning adopting an representative of assumptions in use of nafural gas assumptions in
case utilizing altemate peak our a'\rerage order to evaluate rf to 80% bebw order to evaluate
AverageCase weatherstandard. (budget,pga,rate ashortagedoes 1990targetsin whenourearllest
assumplrons as a Helps pro/ide case) phnning occur. Not likely to OR and WA by resource shortage
starting point and some bounds criteria. occur, 2050. The case could occur- Not
layering in coldest around our assumeslhe likelyto occur.
weather on sensitivity to o\,eran reduction
record- The weather. is an a\,erage goal
likelihood of before applying
occurrence is low. figures like
elasticrty and dsm.
Demand profiles over the planning horizon for each of the scenarios shown in Figures 7.1
and 7.2 reflect the two winter peaks modeled for the different service territories (Dec. 20
and Feb. 15).
Sccnario Summary
Avista Corp 20'18 Natural Gas IRP 152
Case Weather Std Case
4s0
400
350
300
= 25O
Po> 200
150
100
_-------o------
----o-
ooooooooooooaooooooo
High and Low
-80
% Below 1990 Emissions
O Average Case
e fxpssted Case
- - Cold Day 20yr Weather Std
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 7.1Peak Day (Feb 15) - 2018 IRP Demand Scenarios
Figure 7.2Peak Day (Dec 201-2018lRP Demand Scenarios
450
400
350
300
_c 25O
Po
150
100
------------
aooooooo'ooooo oo
High and Low
-80
% Below 1990 Emissions
O Average Case -[xps6ted
Case
- - Cold Day 20yr Weather Std
Avista Corp 2018 Natural Gas IRP 153
2023
1' 2024i zo2sg 2026trr 2027E 2oz8
E zo2st 2o3o
E 2O3LE zo3z
E 2033ir zo34
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
As in the Expected Case, Avista used SENDOUT@ to model the same resource
integration and optimization process described in this section for each of the six demand
scenarios (see Appendix 2.7 for a complete listing of portfolios considered). This
deterministic analysis identified the first year unserved dates for each scenario by service
territory shown in Figure 7.3.
Figure 7.3: First Year Peak Demand Not Met with Existing Resources
WA/ID Medford/Roseburg Klamath La Grande
20L8
20L9
2020
202t
2022
2035
2036
2037
I Expected Case
High Growth & Low Pricesr Cold Day 20yr Weather Std
.80% Below 1990 Emissionsr Low Growth & High Prices
Average Case
Steeper demand highlights the flat demand risk discussed earlier. The likelihood of this
scenario occurring is remote due to a yearly recurrence of coldest day on record weather
paired with a much steeper growth of customer population; however, any potential for
accelerated unserved dates warrants close monitoring of demand trends and resource
lead times as described in the Ongoing Activities section of Chapter 9 - Action Plan. The
remaining scenarios do not identify resource deficiencies in the planning horizon.
Avista Corp 2018 Natural Gas IRP 154
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Alternate Su pply Resources
Avista identified supply-side resources that could meet resource deficiencies or provide
a least cost solution. There are other options Avista considered in its modeling approach
to solve for High Growth & Low Price unserved conditions and to determine whether the
Expected Case with existing resources is least cosUleast risk. A list of the modeled
available supply resources are included in Table 7.2 and potential future resources are
included in Table 7.3.
Table 7.2: Available Supply Resources
Noteg
Future Resources Size CosURates Availabi
Table 7.3: Future Supply Resources
Cunenlly avaibble umubscribed capacily from XiEsgab to ISpokanc I
coorpresSion to tocimsh rEre gas lo iorx irom mainline
GTN to Msdtud
Cosl eatinet€s obtairEd frun a corxubnt ls,clued cost inchrd€s
rcycnuc rcqurrcmcn$, cpcchd cofbon oddcr 0m osgumc{ rctail
Cosb estm&s obtarned lrm a cmlult$l lor e*h specftc type
af RllG. btrtJized cosE irrcbde raurrw ruXrilunerrts, dslibulxir
c06ls, and frqadfd cartnn inlensily 6d&r(i{vin0s) Ihis noct
*o inchdes any incertres frqn bits $ch as !ryasianolon House
Bil 2580 or orclon Scnolc 8il 334
Frwrdss tur peckiru ser'ric6 arx, dwiatBs llH rued fu ooslJy
prynlinc cq$nsions
Parr tritr cxccss
Notes
Co. Owned LNG
Various pipelines - Pacific
Connector, Cross-Cascades, etc
Large Scale LNG
ln Ground Storage
Additional Regource Size CosURates Availability
Uttsuk;ur ibed Glll Capacrty Up lo 50.000 Dllr Gnl Rule
l,ledford Laterd Ap 50,000 D$ / Day $35M caprtal r GIN Rate 2019
ID OR
Hyrlru;en 186 DUr i Diry
s401 u'rr $4U I L)th $4fi r U0t
WA ID ORRcocsEuctl8turdGos Disfr,bubd
Lamfit 635 mh r DAy
S13 / DIlr $13 I Dtlr $13 i Dlh
?frn
ORRcocwablc Noturol Gog
CefltralEed Landtl 1,81{ Bh I f}f,y
Sl l i Dltr $lItDth S12 rDllr ?ffn
WA ID ORRem.*€ble Niltrd Crs - Darry 435 Dt i DPry
S34 i Dlh $39 OUr 533 iOUr ?trm
WA ORRcoc{rabhNatudco5 WGe
Water 513 D$ i Dsy
S19 I otr $18 Drh Sl9 / Dfr 2020
wA ID ORRentrotle Nonrel Cns - Ffid
l/Yasts lo (RNG)298 Un I Uay
S38 i ofrr $39 Dth $38 i Dth
2o?tl
l-lymoufi tHG
2{'l.700 Drl
wll0,5fl) Utl
rhlisabiity
NWP Rale 2U1rl
600,000 Dth M
150,000 of
delverability
$75 Million plus
$2 Million annual
o&M
2024
On site, in seMce territory
liquefaction and vaporization
facility
Varies Precedent
Agreement Rates 2022
Requires additional mainline
capacity on NWPL or GTN to get
to service territory
Varies Commodity less Fuel 2024 Speculative, needs pipeline
transport
Varies Varies Varies
Requires additional mainline
transport to get to service
territory
90,0@ Dth with
30,000
deliverabilrty
$13M capital cost
plus 665k O&lvl 2422
provrdes for peaking services
and alleviates the need for costty
pipeline expansions. $3,000 per
m3 with O&M assumed at5.4o/o.
Avista Corp
Satellite LNG
2018 Natural Gas IRP 155
ID
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
For example, contracted city gate deliveries in the form of a structured purchase
transaction could meet peak conditions. However, the market-based price and other
terms are difficult to reliably determine until a formal agreement is negotiated. Exchange
agreements also have market-based terms and are hard to reliably model when the
resource need is later in the planning horizon. Current tariff prices were used to model
additional GTN capacity and Plymouth LNG, while an estimate was provided from GTN
for the upsized lt/edford lateral compressor combined with tariff rates in order to flow the
gas. For those costs specifically related to all four RNG projects and hydrogen Avista
contracted with a consultant to provide cost estimates for these types of facilities. Some
of the major costs include: Capital, O&M, Avista's revenue requirement, federal income
tax, and depreciation. Avista also included any subsidies known at the time of modeling.
These projects include a cost of carbon adder for any amount of carbon intensity still
associated with each project type. Specifically, dairy and solid waste have a negative
carbon intensity as compared to natural gas as a fuel source (Table 4.2). The net effect
of using this is the removal of carbon from the atmosphere. Finally, Renewable
ldentification Number (RlN)1 values were not included in the valuation of RNG as it is
assumed that these RIN's would be needed to provide proof of Avista's utilization of RNG
or in complying with new environmental legislation.
Ir4any of the potentia! resources are not yet commercially available or well tested,
technically making them speculative. Resources such as coal-bed methane, LNG imports
and natural gas hydrates would fall into this category. Avista will continue to monitor all
resources and assess their appropriateness for inclusion in future lRPs as described in
Chapter9-Action Plan.
One resource which will be closely observed is exported LNG. While Avista considered
LNG exports, it was primarily as a price-influencing factor. However, if the proposed
export LNG terminal in Oregon is approved and a pipeline built to supply that facility, it
potentially could bring new supply through Avista's service territory. Avista will monitor
(Chapter 9 - Action Plan) this situation through industry publications and daily operations
to consider inclusion of this supply scenario for future lRPs.
Deterministic - Portfolio Evaluation
There is no resource deficiency identified in the planning period and the existing resource
portfolio is adequate to meet forecasted demand. The alternate demand scenarios and
supply scenarios are placed in the model as predicted future conditions that the supply
portfolio will have to satisfy via least cost and least risk strategies. This creates bounds
for analyzing the Expected Case by creating high and low boundaries for customer count,
weather and pricing. Each portfolio runs through SENDOUT@ where the supply resources
t https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-
renewa ble-fuel-sta ndard
Avista Corp 2018 Natural Gas IRP 156
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
(Chapter 4 - Supply Side Resources) and conservation resources (Chapter 3 - Demand
Side tManagement - see tables 3.2,3.3 and 3.4) are compared and selected on a least
cost basis. Once new resources are determined, a net present value of the revenue
requirement (PVRR) is calculated.
Table 7.4: PVRR Portfolio
Stochastic Analysis2
The scenario (deterministic) analysis described earlier in this chapter represents specific
what if situations based on predetermined assumptions, including price and weather.
These factors are an integral part of scenario analysis. To understand a particular
portfolio's response to cost and risk, through price and weather, Avista applied stochastic
analysis to generate a variety of price and weather events.
Deterministic analysis is a valuable tool for selecting an optimal portfolio. The model
selects resources to meet peak weather conditions in each of the 20 years. However, due
to the recurrence of design conditions in each of the 20 years, total system costs over the
planning horizon can be overstated because of annual recurrence of design conditions
and the recurrence of price increases in the fonryard price curve. As a result, deterministic
analysis does not provide a comprehensive look at future events. Utilizing [vlonte Carlo
simulation in conjunction with deterministic analysis provides a more complete picture of
portfolio performance under multiple weather and price profiles.
This IRP employs stochastic analysis in two ways. The first tested the weather-planning
standard and the second assessed risk related to costs of our Expected Case (existing
portfolio) under varying price environments. The Monte Carlo simulation in SENDOUT@
can vary index price and weather simultaneously. This simulates the effects each have
on the other.
2 SENDOUT@ uses Monte Carlo simulation to support stochastic analysis, which is a mathematical
technique for evaluating risk and uncertainty. Monte Carlo simulation is a statistical modeling method
used to imitate future possibilities that exist with a real-life system.
Scenario System Cost (PVRR)
Expected Case $ (5,035,892)
Hiqh Growth & Low Prices $ (3,0e3,0e7)
80% Below 1990 Levels $ (2,990,501)
Averaqe Case $ (4,900,092)
Cold Day 20yr Weather Std $ (5,018,719)
Low Growth & High Prices $ (6,087,380)
Avista Corp 2018 Natural Gas IRP 157
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Weather
ln order to evaluate weather and its effect on the portfolio, Avista developed 200
simulations (draws) through SENDOUT@'s stochastic capabilities. Unlike deterministic
scenarios or sensitivities, the draws have more variability from month-to-month and year-
to-year. ln the model, random monthly total HDD draw values (subject to [\4onte Carlo
parameters - see Table 7.5) are distributed on a daily basis for a month in history with
similar HDD totals. The resulting draws provide a weather pattern with variability in the
total HDD values, as well as variability in the shape of the weather pattern. This provides
a more robust basis for stress testing the deterministic analysis.
Table 7.5: Example of Monte Garlo Weather lnputs - Spokane
HDD Mean
HDD Std Dev
HDD Max
HDD Min
70 935 799 541
87
740
269
318
81
494
146
140 31 40 1s4 523179 129 99 51m317386
168 144 363 695
Avista models five weather areas: Spokane, Medford, Roseburg, Klamath Falls and La
Grande. Avista assessed the frequency that the peak day occurs in each area from the
simulation data. The stochastic analysis shows that in over 200, 2}-year simulations,
peak day (or more) occurs with enough frequency to maintain the current planning
standard for this lRP. This topic remains a subject of continued analysis. For example,
the ttledford weather pattern over the 200 2}-year draws (i.e, 4,000 years). HDDs at or
above peak weather (61 HDDs) occur 128 times. This equates to a peak day occurrence
once every 31 years (4,000 simulation years divided by 128 occurrences). The Spokane
area has the least occurrences of peak day (or more) occurrences and La Grande has
the most occurrences. This is primarily due to the frequency in which each region's peak
day HDD occurs within the historical data, as well as near peak day HDDs. See Figures
7.4 through 7.8 for the number of peak day occurrences by weather area.
Avista Corp 2018 Natural Gas IRP 158
59 334
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 7.4: Frequency of Peak Day Occurrences - Spokane
Figure 7.5: Frequency of Peak Day Occurrences - Medford
|J)Nr{N (o (nNQFl el
T] 61HDD
r\NFl
<f Flan slFl F{
Avista Corp 2018 Natural Gas IRP 159
Medford
3.5
3
lnol)c ?q.o ''"
:,L'^9)o
t!o 1.5J(!oo-
o
t+
0.5
0
ni j
j l
I
l tl l i
Spokane
t-.1 @ tn N CD (o m O r\ sf el OO ln N Ol (O cO O f\ <f rl 0O r,) 6l Ot (o (n O Nr{ N N m sf lJ) rJ.) r.o N N oo ot ot o F{ N N (n st sf l, (o (I) r\ oo o) o)Fl Fl F.{ F.{ Fl Fl Fl Fl Fl Fl rl rl r.l r.{
tr 82HDD
2.5
62o
co
3 r.suo
(!orz 1,(uott
o+ 0.5
0
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 7.6: Frequency of Peak Day Occurrences - Roseburg
Figure 7.7: Frequency of Peak Day Occurrences - Klamath Falls
it A
I I
iIl\/\Il ,t
/\
t\ilti
rl
il
Avista Corp 2018 Natural Gas IRP 160
Roseburg
H OO rn N O) (O (n O F. sl rr 00 l.r) N O) (.o cO O F d il OO rn N Ot (O aO O F.F{ N N Cn sf t') Ln (o F\ r.- @ o) o) o F{ N N rn $ st lr) (o (o l-. 00 0) o)
d r{ r-l Fl Fl Fi Fl Fl Fl Fl Fl Fi Fl F'l
N 55HDD
7
6
5
4
3
2
1
0
tao(,co
=(,lJo
(Eo
J(Eq,
A.
o
{+
I
I
I
1
I
Klamath Falls
i @ tn N or (o co o I\ sf rl @ rn N o) (o fn o N <t r.r oo lJ) N ot r.o fo o NF{ N N cO sl rn ln (o N N @ ot ot o F{ N N co sl st tfr (o (o N @ ot olF{ Fl Fl e{ el F{ Ft Fl r{ e{ e{ F{ el Fl
tr 72HDD
2.5
q)o-
co
3 r.sIJo
(E6.y1(!oo.
or* 0.5
0
I
il
I
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 7.8: Frequency of Peak Day Occurrences - La Grande
Price
While weather is an important driver for the lRP, price is also important. As seen in recent
years, significant price volatility can affect the portfolio. ln deterministic modeling, a single
price curve for each scenario is used for analysis. There is risk that the price curve in the
scenario will not reflect actual results.
Avista used [\4onte Carlo simulation to test the portfolio and quantify the risk to customers
when prices do not materialize as forecast. Avista performed a simulation of 200 draws,
varying prices, to investigate whether the Expected Case total portfolio costs from the
deterministic analysis is within the range of occurrences in the stochastic analysis. Figure
6.9 shows a histogram of the total portfolio cost of all 200 draws, plus the Expected Case
results. This histogram depicts the frequency and the total cost of the portfolio among all
the draws, the mean of the draws, the standard deviation of the total costs, and the total
costs from the Expected Case. The figure confirms that Expected Case total portfolio cost
is within an acceptable range of total portfolio costs based on 200 unique pricing
scenarios.
Fr OO to N (,r (O m O N \f cl @ U) r! Or (O cO O I\ <l rl O IJ.) N Or (O cn O r\Ft N N Cn sf ln lJ) lO I\ N @ Or Or O rt (\t N (n <l st In rc, (O f\ @ Ol Olrl r,{ F{ F{ F{ Fl e{ F{ Fl Fl Fl Fl Fl F.{
.Y(!(u
CL
oIt
- 74HDD
t
0
Avista Corp 2018 Natural Gas IRP 161
La Grande
il /1 I
I
\t
I
I I li
j
it \i 'ir
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 7.9:2018|RP Total 20-Year Cost
!xrh
oco
oo
L
35
30
25
20
15
10
1o00h
ggo/o
a096
70%
6096
500,5
40%
3096
20%
1096
o96
@-zo
=Eaq)
5
o 4.332 4.3eO 4.347 4.414 4.44'.t 4.469 4.496 4.523 4.551 4.578 4.605 4.632 4.660 4.687
S Billions
Performing stochastic analysis on weather and price in the demand analysis provided a
statistical approach to evaluate and confirm the findings in the scenario analysis with
respect to adequacy and reasonableness of the weather-planning standard and the
natural gas price forecast. This analytical perspective provides confidence in the
conclusions and stress tests the robustness of the selected portfolio of resources, thereby
mitigating analytical risks.
Solving Unserved Demand
The components, methods and topics covered in this and previous chapters will now help
to solve unserved demand in The High Growth & Low Price scenario. This scenario
includes customer growth rates higher than the Expected Case, incremental demand
driven by emerging markets and no adjustment for price elasticity. Even with aggressive
assumptions, deterministic analysis shows resource shortages do not occur until late in
the planning horizon.
2032 in Washington/ldaho
2031 in Medford/Roseburg
. 2032 in La Grande
a
a
o o7a4 3t'4 594484I 675{ 9{ro
lFrequency
-Cumulative
P(CosF{ sga} lB10%
I
Avista Corp 2018 Natural Gas IRP 162
/
-1
95ah
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
We begin to solve for unserved demand by adding additional resources as supply side
options. The resources Avista modeled for the current IRP include 5 types of renewable
naturalgas, hydrogen, and an upsized compressor on the Medford lateral, additional GTN
capacity and Plymouth LNG as seen in Table 7.2. All costs are entered by location with
the associated daily, pipeline quality, volume available to inform the model. A
deterministic resource mix is performed allowing the model to solve the demand based
on the optimal least cost solution for the system as a whole. Avista performed this
selection process both deterministically and stochastically. ln Figure 7.10, the
deterministic resource add by supply type is shown by cost and risk.
Figure 7.10: Deterministic analysis by resource
12,@O
a tlyd.o8cn onlv
10mo
8,OOO
5,Om
uBb6abcd GTR Clp.dty
Ottly
RNG Onh
a
iledtord L.t...l Exp onh
4,OOO aa
SOLVE
Phmuth LNG Onh
2,Om
3,O@,Om 3,2@,0@ 3,4@,0@ 3,6@,0@ 3,8m,O@ 4,O@,O@ 4,2@,O@ 4,4@,O@ 4,600,0@
Systcm Crsts (thousands)
Table 7.6 demonstrates, by new supply resource or type from the deterministic runs:
1. the twenty year system cost of only the specific resource
2. the average monthly risk or standard deviation of the system cost and
3. if resource would solve system unserved demand.
Avista Corp 2018 Natural Gas IRP 163
1'c.o
:,o!
J
G,
=co
=
s3,090,m0 $,1m,m0 s3,110,000 s3,120,0m s3,130,m
u1tuEY@ a sowtaxsqu
S3.640
s3,620
S3,5oo
s3,s80
o a
l{dtdErE,
Oalr
s3.s60
$,@,(m
a
PtrnM t aG O.*r
s3,087,370 s3,s70 2030
s3,091,928 s3,s73 2032
S3,o93,o97 S3,580 None
S3,123,163 s3,62e 2030
53,469,2r9 s4,763 None
54,477,127 S10,599 2034
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Table 7.6 - System cost, standard deviation and outcome of adding resource to system:
Low Price - Unsubscribed GTN
Low Price - Medford Lateral
Growth, Low Price
Lorv Price -LNG
Low Price - RNG
Low Price -
Once an optimal resource is found deterministically a stochastic analysis takes place to
measure risk. FigureT.ll depicts a stochastic simulation with all options available in order
to solve the unserved system demand in a least cost solution.
The optima! solution Figure 7.11: High Growth and Low Price Cost vs. Risk (200 Draws)
S6,ooo
G^_Tr )5,trruttl
=(ao f "-cPJ sg,.2
G,a s2,-cPco s1.
000
000
000
000
000
so
o
"n
o a o Solve
(Deterministic)o a
oi
52,600,000 52,700,000 52,800,000 52,900,000 53,000,000 53,100,000
System Cost (thousands)
Avista Corp 2018 Natural Gas IRP 164
System Cost
(thousands)Std Dev
Unserved Demand
o
aa
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Stochastically, the model solved the unserved demand by selecting the following supply
sources, below, and can be seen in Figure 7.12:
1. Additional capacity from Kingsgate to Spokane in 2026
2. Centralized landfill gas in ldaho (LFC_ID35) in 2035
3. Upsized compressor on Medford lateral in 2026
Figure 7.12: Htgh Growth and Low Price - Average Supply by Source and Area on
February 15th (200 Draws)
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Avista Corp 2018 Natural Gas IRP 165
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
The stochastic analysis shows a supply resource need in the 2026 timeframe. ln a
stochastic analysis, variability and randomness based on historical information is utilized
to measure risk and unknown elements (price and weather). An example of this lies within
our expected coldest on record weather assumption. Within the deterministic model this
value is equalto exactly 82 HDD in Avista's Washington and ldaho service territories, but
in a single random draw, this value is slightly higher at 82.18 HDD affecting the overall
demand. A slight increase in weather expectations can alter the unserved timeframe,
especially in areas with higher populations or those nearing their current resource limits.
Of the 200 -20 year futures, less than 10 observe an unserved demand earlier than those
in the deterministic analysis. Randomly simulated future prices provide the modelwith the
ability to select from a variety of potential supply side resources over a range of 2OO - 20
year future draws. When looking for the lowest cost and least risk portfolio, the model will
look to solve unserved demand in each 20 year scenario with the lowest cost resources
based on the values simulated (weather and price) and provided costs(transportation
costs, storage costs, etc.) Additional detailed information on this and other scenarios is
included in the following appendices:
1. Demand and Existing Resources graph by service territory (High Growth Case
only) - AppendixT.l
2. Peak Day Demand, Served and Unserved table (all cases) - Appendix7.2
Regulatory Requ irements
IRP regulatory requirements in ldaho, Oregon and Washington call for several key
components. The completed plan must demonstrate that the IRP:
a
o Examines feasible means of meeting demand with both supply-side and demand-
side resources.
a Treats supply-side and demand-side resources equally
a Describes the long-term plan for meeting expected demand growth
a Describes the plan for resource acquisitions between planning cycles
a Takes planning uncertainties into consideration
a lnvolves the public in the planning process
Avista Corp 2018 Natural Gas IRP 166
Examines a range of demand forecasts.
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Avista addressed the applicable requirements throughout this document. Appendix 1.2 -
IRP Guideline Compliance Summaries lists the specific requirements and guidelines of
each jurisdiction and describes Avista's compliance.
The IRP is also required to consider risks and uncertainties throughout the planning and
analytical processes. Avista's approach in addressing this requirement was to identify
factors that could cause significant deviation from the Expected Case planning
conclusions. This included dynamic demand analytical methods and sensitivity analysis
on demand drivers that impacted demand forecast assumptions. From this, Avista
created 15 demand sensitivities and modeled five demand scenario alternatives, which
incorporated different customer groMh, use-per-customer, weather, and price elasticity
assumptions.
Avista analyzed peak day weather planning standard, performing sensitivity on HDDs and
modeling an alternate weather-planning standard using the coldest day in 20 years.
Stochastic analysis using [t/onte Carlo simulations in SENDOUT@ supplemented this
analysis. Avista also used simulations from SENDOUT@ to analyze price uncertainty and
the effect on total portfolio cost.
Avista examined risk factors and uncertainties that could affect expectations and
assumptions with respect to DSM programs and supply-side scenarios. From this, Avista
assessed the expected available supply-side resources and potential conservation
savings for evaluation.
The investigation, identification, and assessment of risks and uncertainties in our IRP
process should reasonably mitigate surprise outcomes.
Conclusion
ln planning, a reasonable set of criteria is necessary to help measure the inherent risk of
the unknown in future events. ln prior years the "Low GroMh and High Prices" scenario
was considered our lower band of risk. ln the 20181RP, Avista has added a new risk in
the scenario referred to as "B0o/o below 1990 emissions" due to a continued policy shift
toward a reduced role of naturalgas as a fuelchoice. ln all but one scenario, High Growth
and Low Prices, the firm customer demand is served with existing resources. Simulating
random future events by case with unserved demand provides a better idea of the risk
and costs involved in each resource. This will allow Avista to monitor customer growth
and demand while maintaining a watchful eye on policy and new resources.
Avista Corp 2018 Natural Gas IRP 167
Chapter 7: Alternate Scenario, Portfolios and Stochastic Analysis
Avista Corp 2018 Natural Gas IRP 168
Chapter 8: Distribution Planning
8: Distribution Planning
Overview
Avista's IRP evaluates the safe, economical and
reliable full-path delivery of natural gas from basin
to the customer meter. Securing adequate natural
gas supply and ensuring sufficient pipeline
transportation capacity to Avista's city gates
become secondary issues if distribution system
groMh behind the city gates increases faster than
expected and the system becomes severely
constrained. lmportant parts of the distribution
planning process include forecasting local demand
growth, determining potential distribution system
constraints, analyzing possible solutions and
estimating costs for el iminating constraints.
Analyzing resource needs to this point has focused
on ensuring adequate capacity to the city gates, especially during a peak event.
Distribution planning focuses on determining if there will be adequate pressure during a
peak hour. Despite this altered perspective, distribution planning shares many of the
same goals, objectives, risks and solutions as integrated resource planning.
Avista's natural gas distribution system consists of approximately 3,300 miles of
distribution main and services pipelines in ldaho, 3,700 miles in Oregon and 5,800 miles
in Washington; as well as numerous regulator stations, service distribution lines,
monitoring and metering devices, and other equipment. Currently, there are no storage
facilities or compression systems within Avista's distribution system. Distribution network
pipelines and regulating stations operate and maintain system pressure solely from the
pressure provided by the interstate transportation pipelines.
Distribution System Planning
Avista conducts two primary types of evaluations in its distribution system planning
efforts: capacity requirements and integrity assessments.
Capacity requirements include distribution system reinforcements and expansions.
Reinforcements are upgrades to existing infrastructure, or new system additions, which
increase system capacity, reliability and safety. Expansions are new system additions to
accommodate new demand. Collectively, these reinforcements and expansions are
d istribution enhancements.
Chapter
Highlights
Avista maintains its
distribution system based
on economics, safety and
reliability
Avista maintains a total of
12,800 miles of
distribution in three
jurisdictions
o
Avista Corp 2018 Natural Gas IRP 169
a
Chapter 8: Distribution Planning
Ongoing evaluations of each distribution network in the four primary service territories
identify strategies for addressing local distribution requirements resulting from customer
groMh. Customer growth assessments are made based on factors including IRP demand
forecasts, monitoring gate station flows and other system metering, new service requests,
field personnel discussion, and inquiries from major developers.
Avista regularly conducts integrity assessments of its distribution systems. Ongoing
system evaluation can indicate distribution-upgrading requirements for system
maintenance needs rather than customer and load groMh. ln some cases, the timing for
system integrity upgrades coincides with growth-related expansion requirements. These
planning efforts provide a long-term planning and strategy outlook and integrate into the
capital planning and budgeting process, which incorporates planning for other types of
distribution capital expenditures and infrastructure upgrades.
Gas Engineering planning models are also compared with capacity limitations at each
city gate station. Referred to as city gate analysis, the design day hourly demand
generated from planning analyses must not exceed the actual physical limitation of the
city gate station. A capacity deficiency found at a city gate station establishes a potential
need to rebuild or add a new city gate station.
Network Design Fundamentals
Natural gas distribution networks rely on pressure differentials to flow natural gas from
one place to another. When pressures are the same on both ends of a pipe, the natural
gas does not move. As natural gas exits the pipeline network, it causes a pressure drop
due to its movement and friction. As customer demand increases, pressure losses
increase, reducing the pressure differential across the pipeline network. lf the pressure
differential is too small, flow stalls and the network could run out of pressure.
It is important to design a distribution network such that intake pressure from gate stations
and/or regulator stations within the network is high enough to maintain an adequate
pressure differential when natural gas leaves the network.
Not all natural gas flows equally throughout a network. Certain points within the network
constrain flow and restrict overall network capacity. Network constraints can occur as
demand requirements evolve. Anticipating these demand requirements, identifying
potential constraints and forming cost-effective solutions with sufficient lead times without
overbuilding infrastructure are the key challenges in network design.
Gomputer Modeling
Developing and maintaining effective network design is aided by computer modeling for
network demand studies. Demand studies have evolved with technology to become a
Avista Corp 2018 Natural Gas IRP 170
Chapter B: Distribution Planning
highly technical and powerful means of analyzing distribution system performance. Using
a pipeline fluid flow formula, a specified parameter for each pipe element can be
simultaneously solved. It/any pipeline equations exist, each tailored to a specific flow
behavior. These equations have been refined through years of research to the point
where modeling solutions closely resemble actual system behavior.
Avista conducts network load studies using GL Noble Denton's Synergi software. This
modeling tool allows users to analyze and interpret solutions graphically.
Determining Peak Demand
Avista's distribution network is comprised of high pressure (90-500 psig) and intermediate
pressure (5-60 psig) mains. Avista operates its intermediate networks at a relatively low
maximum pressure of 60 psig or less for ease of maintenance and operation, public
safety, reliable service, and cost considerations. Since most distribution systems operate
through relatively small diameter pipes, there is essentially no line-pack capability for
managing hourly demand fluctuations. Line pack is the difference between the natural
gas contents of the pipeline under packed (fully pressurized) and unpacked
(depressurized) conditions. Line pack is negligible in Avista's distribution system due to
the smaller diameter pipes and lower pressures. ln transmission and inter-state pipelines,
line-pack contributes to the overall capacity due to the larger diameter pipes and higher
operating pressures.
Core demand typically has a morning peaking period between 6 a.m. and 10 a.m. and
the peak hour demand for these customers can be as much as 50 percent above the
hourly average of daily demand. Because of the importance of responding to hourly
peaking in the distribution system, planning capacity requirements for distribution systems
uses peak hour demand.l
Distribution System Enhancements
Demand studies facilitate modeling multiple demand forecasting scenarios, constraint
identification and corresponding optimum combinations of pipe modification, and
pressure modification solutions to maintain adequate pressures throughout the network.
Distribution system enhancements do not reduce demand nor do they create additional
supply. Enhancements can increase the overall capacity of a distribution pipeline system
while utilizing existing gate station supply points. The two broad categories of distribution
enhancement solutions are pipelines and regulators.
I This method differs from the approach that Avista uses for IRP peak demand planning, which focuses
on peak day requirements to the city gate.
Avista Corp 2018 Natural Gas IRP 171
Chapter 8: Distribution Planning
Pipelines
Pipeline solutions consist of looping, upsizing and uprating. Pipeline looping is the most
common method of increasing capacity in an existing distribution system. Looping
involves constructing new pipe parallel to an existing pipeline that has, or may become,
a constraint point. Constraint points inhibit flow capacities downstream of the constraint
creating inadequate pressures during periods of high demand. When the parallel line
connects to the system, this alternative path allows natural gas flow to bypass the original
constraint and bolsters downstream pressures. Looping can also involve connecting
previously unconnected mains. The feasibility of looping a pipeline depends upon the
location where the pipeline will be constructed. lnstalling natural gas pipelines through
private easements, residential areas, existing paved surfaces, and steep or rocky terrain
can increase the cost to a point where alternative solutions are more cost effective.
Pipeline upsizing involves replacing existing plpe with a larger size pipe. The increased
pipe capacity relative to surface area results in less friction, and therefore a lower
pressure drop. This option is usually pursued when there is damaged pipe or where pipe
integrity issues exist. lf the existing pipe is othenryise in satisfactory condition, looping
augments existing pipe, which remains in use.
Pipeline uprating increases the maximum allowable operating pressure of an existing
pipeline. This enhancement can be a quick and relatively inexpensive method of
increasing capacity in the existing distribution system before constructing more costly
additionalfacilities. However, safety considerations and pipe regulations may prohibit the
feasibility or lengthen the time before completion of this option. Also, increasing line
pressure may produce leaks and other pipeline damage creating costly repairs. A
thorough review is conducted to ensure pipeline integrity before pressure is increased.
Regulators
Regulators, or regulator stations, reduce pipeline pressure at various stages in the
distribution system. Regulation provides a specified and constant outlet pressure before
natural gas continues its downstream travel to a city's distribution system, customer's
property or natural gas appliance. Regulators also ensure that flow requirements are met
at a desired pressure regardless of pressure fluctuations upstream of the regulator.
Regulators are at city gate stations, district regulator stations, farm taps and customer
services.
Compression
Compressor stations present a capacity enhancing option for pipelines with significant
natural gas flow and the ability to operate at higher pressures. For pipelines experiencing
a relatively high and constant flow of natural gas, a large volume compressor installation
along the pipeline boosts downstream pressure.
Avista Corp 20'18 Natural Gas IRP 172
Chapter 8: Distribution Planning
A second option is the installation of smaller compressors located close together or
strategically placed along a pipeline. tt/ultiple compressors accommodate a large flow
range and use smaller and very reliable compressors. These smaller compressor stations
are well suited for areas where natural gas demand is growing at a relatively slow and
steady pace, so that purchasing and installing these less expensive compressors over
time allows a pipeline to serve growing customer demand into the future.
Compressors can be a cost effective option to resolving system constraints; however,
regulatory and environmental approvals to install a compressor station, along with
engineering and construction time can be a significant deterrent. Adding compressor
stations typically involves considerable capital expenditure. Based on Avista's detailed
knowledge of the distribution system, there are no foreseeable plans to add compressors
to the distribution network.
Gonservation Resou rces
The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence conservation through the DSM
measures discussed in Chapter 3 - Demand-Side Resources, but does not depend on
estimates of peak day demand reductions from conservation to eliminate near-term
distribution system constraints. Over the longer-term, targeted conservation programs
may provide a cumulative benefit that could offset potential constraint areas and may be
an effective strategy.
Distribution Scenario Decision-Making Process
After achieving a working load study, analyses are performed on every system at design
day conditions to identify areas where potential outages may occur.
Avista's design HDD for distribution system modeling is determined using the coldest day
on record for each given service area. This practice is consistent with the peak day
demand forecast utilized in other sections of Avista's natural gas lRP.
Utilizing a peak planning standard of the coldest temperature on record may seem
aggressive given a temperature experienced rarely, or only once. Given the potential
impacts of an extreme weather event on customers' personal safety and property damage
to customer appliances and Avista's infrastructure, it is a prudent regionally accepted
planning standard.
Avista Corp 2018 Natural Gas IRP 173
Chapter 8: Distribution Planning
These areas of concern are then risk ranked against each other to ensure the highest risk
areas are corrected first. Within a given area, projects/reinforcements are selected using
the following criteria:
. The shortest segment(s) of pipe that improves the deficient part of the distribution
system.. The segment of pipe with the most favorable construction conditions, such as
ease of access or rights or traffic issues.o lMinimal to no water, railroad, major highway crossings, etc.. The segment of pipe that minimizes environmental concerns including minimal to
no wetland involvement, and the minimization of impacts to local communities
and neighborhoods.. The segment of pipe that provides opportunity to add additional customers.. Total construction costs including restoration.
Once a projecUreinforcement is identified, the design engineer or construction project
coordinator begins a more thorough investigation by surveying the route and filing for
permits. This process may uncover additional impacts such as moratoriums on road
excavation, underground hazards, discontent among landowners, etc., resulting in
another iteration of the above projecUreinforcement selection criteria. Figure 7.1 provides
a schematic representation of the distribution scenario process.
Avista Corp 2018 Natural Gas IRP 174
Chapter 8: Distribution Planning
Figure 8.1: Distribution Scenario Process
Distributisn Scenario Process
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An example of the distribution scenario decision making process is from the tvledford high
pressure loop reinforcement where the analysis resulted in multiple paths or pipeline
routes. The initial path was based on quantitative factors, specifically the shortest length
and least cost route. However, as field investigations and coordination with local city and
county governments began, alternative routes had to be determined to minimize future
conflicts, environmental considerations, and field and community disruptions. The final
path was based on several qualitative factors that including:
. Available right-of-way along city streets;. Availability of private easements from property owners;o Restrictions due to City of Medford future planned groMh with limited planning
information; and. Potential to avoid conflict with other utilities including a large electric substation
along the initial route.
Planning Results
Table 8.1 summarizes the cost and timing, as of the publication date of this lRP, of major
distribution system enhancements addressing groMh-related system constraints, system
integrity issues and the timing of expenditures.
Avista Corp 2018 Natural Gas IRP 175
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Chapter 8: Distribution Planning
The Distribution Planning Capital Projects criteria includes:
o Prioritized need for system reliability (necessary to maintain reliable service);o Scale of project (large in magnitude and will require significant engineering
and design support); ando Budget approval (will require approvalfor capitalfunding).
These projects are preliminary estimates of timing and costs of major reinforcement
solutions. The scope and needs of distribution system enhancement projects generally
evolve with new information requiring ongoing reassessment. Actual solutions may differ
due to differences in actual growth patterns and/or construction conditions that differ from
the initial assessment and timing of planned completion may change based on the
aforementioned ongoing reassessment of information.
The following discussion provides information about key near-term projects.
Coeur d'Alene High Pressure Reinforcement - Post Falls Phase: The last phase of
this project will reinforce the Post Falls distribution system, where the current distribution
pipe has not been able to meet growing customer demand. Additionally, during cold
weather conditions, supply resources have been constrained. Approximately 14,600 feet
of high pressure steel gas main was designed in 2017 and construction began in 2018.
Cheney High Pressure Reinforcement: This project will reinforce the Cheney
distribution system, whose customer demands have exceeded the capacity of the high
pressure feeder constructed in 1957. During cold weather conditions, Avista periodically
asks some large customers to reduce their nature gas usage in order to serve core
customer demand. Approximately 27,700 feet of high pressure steel gas main will be
designed in 2018 and construction is expected to begin in 2019.
Schweitzer Mountain Road and Warden High Pressure Reinforcements: The
Schweitzer Mountain Road and Warden high pressure reinforcements are necessary to
serve either new or increased industrial customer demand. At this time, both industrial
customers, whose projected demands necessitated reinforcements, have either
cancelled expansion plans or are considering alternative locations. ln anticipation of
similar industrial loads in the future, Avista will continue to list each project, but defer
construction u nti I d istrib ution constraints materi alize.
Avista Corp 2018 Natural Gas IRP 176
Coeur d'Alene High
Pressure
Reinforcement; Post
Falls Phase
$4,000,000
Cheney High
Pressure
Reinforcement
$4,900,000 $4,100,000
Schweitzer
lt4ountain Rd High
Pressure
Reinforcement
$1,500,000
Warden High
Pressure
Reinforcement
$6,000,000
Chapter 8: Distribution P[anning
Table 8.1 Distribution Planning Capital Projects
Table 8.2 shows city gate stations identified as over utilized or under capacity. Estimated
cost, year and the plan to remediate the capacity concern are shown.
These projects are preliminary estimates of timing and costs of city gate station upgrades.
The scope and needs of each project generally evolve with new information requiring
ongoing reassessment. Actual solutions may differ due to differences in actual growth
patterns and/or construction conditions that differ from the initial assessment.
The Post Falls City Gate Station will be reconfigured to accommodate a new high
pressure feeder. The supplying pipeline has not been able to meet the increase in
customer growth and demand in this area. An increase in flow and capacity will be
achieved by the new high pressure feeder directing gas from Rathdrum to Post Falls, the
third phase of the Coeur d'Alene High Pressure Reinforcement.
The remaining city gate station projects in Table 8.2 have relatively small capacity
constraints, and thus will be periodically reevaluated to determine if upgrades need to be
accelerated or deferred. Under current planning considerations, these projects will be
tentatively scheduled for 2020 or later.
Avista Corp 2018 Natural Gas IRP 177
Location 2018 2019 2020+
Chapter 8: Distribution Planning
Table 8.2 City Gate Station Upgrades
CONGLUSION
Avista's goal is to maintain its naturalgas distribution systems reliably and cost effectively
to deliver natural gas to every customer. This goal relies on modeling to increase the
capacity and reliability of the distribution system by identifying specific areas that may
require changes. The ability to meet the goal of reliable and cost effective natural gas
delivery is enhanced through localized distribution planning, which enables coordinated
targeting of distribution projects responsive to customer groMh patterns.
Post Falls, lD Post Falls #215 Reconfigure
lncluded
in Table
7.1
2018
CDA (East),
ID CDAEast#221 TBD 2020+
Athol, lD Athol#219 TBD 2020+
Bonners
Ferry, lD Bonners Ferry #208 TBD 2020+
Colton, WA Colton #316 TBD 2020+
Genesee, lD Genesee #320 TBD 2020+
Klamath
Falls, OR Klamath Falls#2703 TBD 2022+
Mead, WA Mead #1 TBD 2020+
Mica, WA Mica #15 TBD 2020+
Pullman, WA Pullman #350 TBD 2020+
Sprague, WA Sprague #1 17 TBD 2020+
Sutherlin, OR Sutherlin #2626 TBD 2022+
Avista Corp 2018 Natural Gas IRP 178
Location Gate Station Project to Remediate Cost Year
o
Chapter 9: Action Plan
9: Action Plan
The purpose of an action plan is to position Avista to provide the best cosUrisk resource
portfolio and to support and improve IRP planning. The Action Plan identifies needed
supply and demand side resources and highlights key analytical needs in the near term.
It also highlights essential ongoing planning initiatives and natural gas industry trends
Avista will monitor as a part of its planning processes.
2017-2018 Action Plan Review
The price of natural gas has dropped significantly since the 2014lRP. This is primarily
due to the amount of economically extractable natural gas in shale formations, more
efficient drilling techniques, and warmer than normal weather. Wells have been drilled,
but left uncompleted due to the poor market economics. This is depressing natural
gas prices and forcing many oil and natural gas companies into bankruptcy. Due to
historically low prices Avista will research market opportunities including procuring a
derivative based contract, 10-yearfonryard strip, and natural gas reserves.
o Result: After exploring the opportunity of some type of reserves ownership, it
was determined the price as compared to risk of ownership was inappropriate
to go fonvard with at this time. As an ongoing aspect of managing the business,
Avista will continue to look for opportunities to help stabilize rates and/or reduce
risk to our customers.
o Avista's 2018 IRP will contain a dynamic DSM program structure in its analytics. ln
prior IRP's, it was a deterministic method based on Expected Case assumptions. ln
the 2018 lRP, each portfolio will have the ability to select conservation to meet
unserved customer demand. Avista will explore methods to enable a dynamic
analytical process for the evaluation of conservation potential within individual
portfolios.
o Result: After attempting to get dynamic dsm into the Sendout model we
determined an alternate method will be necessary. Some reasons for this are:
t I - The total dsm measures has a maximum of 999 measures. lf we
were to model our areas as is combined with 400 measures by area we
would come up with a total need of 4400 measures.
t ) - lf we were able to group them by dollars or efficiency levels it takes
away the desired approach of measure by measure.
Avista Corp 2018 Natural Gas IRP 179
o
Chapter 9: Action Plan
3 - We have every bit of data both ETO and AEG can provide and the
model is not acting appropriately and cannot determine a stopping point
for taking a single measure. This means it would take the maximum, if
cheaper than gas, to fill the entire demand.
4 - The output data from ETO and AEG is very different and we need to
understand it better before modeling.
[\4onitor actual demand for accelerated growth to address resource deficiencies arising
from exposure to "flat demand" risk. This will include providing Commission Staff with
IRP demand forecast-to-actual variance analysis on customer growth and use-per-
customer at least bi-annually.
o Result: actual demand was closely tracked and shared with Commissions in
semi-annual or quarterly meetings and trended closely to the IRP forecast per
customer. No new resources were necessary during this timeframe.
ln the 20181RP, include a section in the IRP that discusses the specific impacts of the
new Clean Air Rule in Washington (WAC 173-441 and 173-442).
o Result: Carbon Policy including the Clean Power Plan and Clean Air Rule
were both reviewed and included in TAC 2 Meeting materials on212212018. An
indicator of where Avista's carbon reduction requirements under the CAR was
also included. Since the CAR was invalidated on 1211512017 in Thurston
County Superior Court this analysis is intended to meet the action item in
addition to showing the potential impacts of similar policies.
ln the 2018 lRP, provide more detail on Avista's natural gas hedging strategy,
including information on upper and lower pricing points, transactions with
counterparties, and how diversification of the portfolio is achieved.
o Result: Avista's natural gas hedging strategy was discussed during the TAC
2 Meeting on 212212018. The upper and lower pricing points in Avista's
programmatic hedges is controlled by taking into consideration the volatility
over the past year for the specific hedging period. This volatility is weighted
toward the more recent volatility. The window length and quantity of windows
is also a part of the equation. Avista transacts on ICE with counterparties
meeting our credit rating criteria. The diversification of the portfolio is achieved
through the following methods:
. Gomponents: The plan utilizes a mix of index, fixed price, and storage
transactions.
Transaction Dates: Hedge windows are developed to distribute the
transactions throughout the plan.
o
o
Avista Corp 2018 Natural Gas IRP 180
Chapter 9: Action Plan
Supply Basins: Plan to primarily utilize AECO, execute at lowest price
basis at the time.
I Delivery Periods: Hedges are completed in annual and/or seasonal
timeframes. Long-term hedges may be executed.
o
o Carbon Policy including federal and state regulations specifically those surrounding
the clean air rule and clean power plan.
o Result: Carbon Policy including the Clean Power Plan and Clean Air Rule
were both reviewed and included in TAC 2lVeeting materials on212212018. An
indicator of where Avista's carbon reduction requirements under the CAR was
also included. Since the CAR was invalidated on 1211512017 in Thurston
County Superior Court this analysis is intended to meet the action item in
addition to showing the potential impacts of similar policies.
o Weather analysis specific to Avista's service territories.
o Result: A weather analysis was included and reviewed in TAC 2 meeting
materials on2122120'18 and can be found in Chapter 2 Demand Forecasts.
o Stochastic Modeling and supply resources.
o Result: This was shown in detail and with risk and cost in TAC 4 on 5/1012018.
Regional pipelines were discussed in TAC 2 meeting on 212212018. Potential
resources were 4 types of RNG, Plymouth LNG, additional Kingsgate to
Spokane and an upsized compressor on GTN's tt/edford lateral. A list of these
resources modeled can be found in Chapter 7 Alternate Scenarios Portfolios
Stochastic Analysis along with the results.
o Updated DSlt/ methodology including the integration of ETO.
o Result: See chapter 3 Demand Side Resources and action item
o ln the 2018 lRP, ensure that the entity performing the Conservation Potential
Assessment (CPA) evaluates and includes the following information:
o All conservation measures excluded from the CPA, including those excluded
prior to technical potential determination;
. @!f Very few measures were excluded from the current CPA prior
to estimation of technical potential. Those explicitly excluded were highly
custom commercial and industrial controls/process measures that were
instead captured under a retrocommissioning or strategic energy
management program.
o Rationale for excluding any measure;
Avista Corp 2018 Natural Gas IRP 181
Chapter 9: Action Plan
. Result: Measures that did not pass the economic screen were still
counted within achievable technical potential, allowing Avista to review
for inclusion in programs if portfolio-level cost-effectiveness allows.
o Description of Unit Energy Savings (UES) for each measure included in the
CPA; specify how it was derived and the source of the data; and
. Result: 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 NEls) may be found in the
"l/easure Summary" spreadsheet delivered as an appendix to the final
report. This will include the name of the source and version (if
applicable)
o Explain the efforts to create a fully-balanced TRC cost effectiveness metric
within the planning horizon. Additionally, while evaluating the effort to
eventually revert back to the TRC, Avista should consult the DSITI Advisory
Group and discuss appropriate non-energy benefits to include in the CPA.
. Result: TRC potential was estimated alongside UCT for each measure
analyzed.ln this study, we expanded the scope of non-energy/non-gas
impacts to include the following:
. 10o/o Conservation Credit in Washington
. Quantified and monetized non-energy impacts (e.g. water,
detergent, wood)
. Projected cost of carbon in Washington
. Heating calibration credit for secondary fuels (12% for space
heating, 60/o for secondary heating)
. Electric benefits for applicable measures (e.9. cooling savings for
smart thermostats, lighting and refrigeration savings for retro-
commissioning)
o Staff believes public participation could be further enhanced through "bill stuffers,
public flyers, local media, individual invitations, and other methods."
o Result: Avista utilized it's Regional Business Managers in addition to digital
communications and newsletters in all states in order to try and gain more
public participation in addition to an eCommunity newsletter was distributed
January 15,2018.
Avista Corp 2018 Natural Gas IRP 182
Chapter 9: Action Plan
o Avista forecast its number of customers using at least two different methods and to
compare the accuracy of the different methods using actual data as a future task in its
next lRP.
o Result: Avista analyzed the data, but there was nothing material discovered
the come up with a meaningfulforecast alternative.
2019-2020 Action Plan
Avista's 2019-2020 Action Plan outlines activities for study, development and preparation
for the 2020 lRP.
New Activities for the 2020 lRP
1. Avista's 2020 IRP will contain an individual measure level for dynamic DSt\4
program structure in its analytics. ln prior IRP's, it was a deterministic method
based on based on Expected Case assumptions. ln the 2020 lRP, each portfolio
will have the ability to select conservation to meet unserved customer demand.
Avista will explore methods to enable a dynamic analytical process for the
evaluation of conservation potential within individual portfolios.
2. Work with Staff to get clarification on types of natural gas distribution system
analyses for possible inclusion in the 2020 lRP.
3. Work with Staff to clarify types of distribution system costs for possible inclusion in
our avoided cost calculation.
4. Revisit coldest on record planning standard and discuss with TAC for prudency.
5. Provide additional information on resource optimization benefits and analyze risk
exposure.
6. DSM-lntegration of ETO and AEG/CPA data. Discuss the integration of ETO and
AEG/CPA data as well as past program(s) experience, knowledge of current and
developing markets, and future codes and standards.
7. Carbon Costs - consult Washington State Commission's Acknowledgement Letter
Attachmenf in its 2017 Electric IRP (Docket UE-161036), where emissions price
modeling is discussed, including the cost of risk of future greenhouse gas
regulation, in addition to known regulations.
B. Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.
Avista Corp 2018 Natural Gas IRP 183
Chapter 9: Action Plan
9. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
. Natural gas infrastructure investment not included as discrete projects in IRP
Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
"':"ilffi:'ff -i:
;l]i:i'l.'," A,dy, A rep,acement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
a
Anticipated PHTVSA guidance or rules related to 49 CFR Part 5192
that will likely requires additional capitalto comply
. Officials from both PHtt/SA and the AGA have indicated it is not
prudent for operators to wait for the federal rules to become final
before improving their systems to address these expected rules.
Construction of gas infrastructure associated with grovrrth
Other special contract projects not known at the time the IRP was
published
Other non-lRP investments common to all jurisdictions that are ongoing, for
example:
Enterprise technology projects & programs
Corporate facilities capital maintenance and improvements
Avista Corp 2018 Natural Gas IRP 184
Chapter 9: Action Plan
Ongoing Activities
a Continue to monitor supply resource trends including the avallability and price of
natural gas to the region, LNG exports, methanol plants, supply and market
dynamics and pipeline and storage infrastructure availability.
lt/onitor availability of resource options and assess new resource lead-time
requirements relative to resource need to preserve flexibility.
Meet regularly with Commission Staff to provide information on market activities
and significant changes in assumptions and/or status of Avista activities related to
the IRP or natural gas procurement practices.
Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.
a
a
a
Avista Corp 2018 Natural Gas IRP 185