20221117Avista to Staff 1-5.pdf

:-iECTIVED
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i:,'.1'ji-i i'UBLiC' :l 1:'ri-- i COi{MlSSIONt04t2022" - -ruRISDICTION: IDAHO
CASE NO: AVU-E-22-15
REQUESTER: IPUCTYPE: Production Request
REQUEST NO.: Staff- 001
DATEPREPARED:1I
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATTON
Grant D. Forsyth, Ph.D.
Grant D. Forsyth, Ph.D.
Financial Planning & Analysis
(50e)-49s-276s
REQUEST:
a. Please provide a breakdown of the 2021 aadthe2022 forecasts by customer class (residential,
commercial, and industrial, etc.) in Excel format.
b. Please explain the method and basis used to determine the2022 forecast for each customer class.
c. Please explain why the 2022 energy forecast is growing more rapidly than the202l forecast. In
the explanation, please identifu the major drivers or causes for each customer class affecting the
change.
RESPONSE:
a. The load break down is shown in Staff PR_001 Attachment A. Note that the Company's
forecast model produces retail load forecasts in kWh by class and then aggregates them to
create a total retail load forecast in kWh. This aggregated retail load is then converted to a native
load forecast using a historically derived conversion value which reflects historic line losses.
Attachment A shows retail load by class for the 2023 and 2021 IRPs. In this file, kWh retail
forecasts are then converted to aMW, which include line losses. The difference between aMW
in the 2023 and 2021 IRPs will capture most of the change in observed syston native load.
b. The forecast out to 2026 is from the regression models that produce forecasts for the Company's
revenue model. After 2026, the Company uses an Excel based simulation model that bootstraps
offthe forecasts used for the Company's revenue model. The simulation model forecasts annual
retail load for each of the major customer classes: residential, commercial, industrial, and
streetlights. The simulation model requires inputs for customer growth (population growth),
natural gas penetration (for the residential and commercial classes), electric vehicle (EV)
accumulation (for the residential and commercial classes), and solar accumulation (for the
residential and commercial classes). In addition, the model includes assumptions for own-price
elasticity for the residential and commercial classes, long-run GDP growth for the industrial
class, and climate change (RCP 4.5). The simulation model starts with a break-out for Idaho and
Washington and then rolls that up into a system annual retail forecast. A monthly forecast is
then created by allocating out the annual values using a monthly load profile. The native load
forecast is arrived at by adjusting the total retail load for historically normal line losses.
c. The three main reasons load is growing faster in the 2023 IRP are: (1) faster long-run growth in
forecasted population, especially in Idaho; (2) Washington resfrictions on new commercial
natural gas connections starting in 2023; and, (3) a higher gpowth rate in EV accumulation,
especially in Washington.
In the first case, the higher rate of population growth has a significant impact on both
forecasted residential and commercial customer growth. The long-run population gpowth
forecasts come from IHS Connect. Between the development of the 2021 and 2023 IRP load
forecasts, Idaho in particular has experienced faster than expected population growth, which
resulted in an upward revision in IHS's population growth forecasts for the Company's Idaho
service area.
In the second case, Washington changed its building code to prevent, in most cases, new
natural gas connections to commercial and industrial customers starting in 2023. This
significantly reduces forecasted gas penetation rate in Washington compared to the 2021 IRP.
In turn, this will shift load from natural gas to electricity over the forecast horizon. Washington
also adopted a new building code requiring heat pumps in new residential construction
beginning in July 2023, which will add additional growth to system load in future IRPs. The
impact of the new requirement for residential heat pumps is not included in the attached
forecast as this change was made November 4,2022.
In the third case, faster growth in the adoption ofboth residential and commercial EVs account
for the majority of increased load growth between the 2021 and2023 IRP load forecasts. [n the
2021 IRP, the forecasted share of residential EVs to all registered residential vehicles was at
l3Yo in 2045.In comparison, the 2023 IRP's forecasted share of EVs has grown to 27%oby
2045. Consistent with the Company's Washington Transportation Electrification Plan, this
forecast of EV accumulation assumes that l\oh of all light-duty vehicle sales will be EVs by
2030 and by 2045 the Company assumes this will increase to almost 40Yo of sales. In short,
residential based EVs are the primary driver of the change in residential load growth by 2045.
Compared to the 2021 IRP, commercial EVs (electric medium duty vehicles) are treated more
explicitly in the 2023 IRP. This reflects better information on corlmercial EVs, evidence of
growing usage, and increased public policy attention. T\e2023IRP assumes that commercial
EVs will be about 1.3% of all commercial vehicle sales by 2030 and by 2045 the Company
assumes this will increase to about 25o/o of sales. The Company estimates the forecasted share
of commercial EVs to all commercial vehicles will rise from under 05% n 2023 to around
13% in 2045. In short, residential based EVs are the primary driver of the change in
commercial load by 2045.
Finally, it should be noted that climate change, which is now included as part of the expected
IRP forecast, has a relatively small impact on load growth; that is, the largest impact of climate
change is to shift load from winter to summer with only modest impacts on long-term load
growth.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATTON
ruRISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
AVU-E-22-15
Staff
Production Request
Staff-002
DATE PREPARED:
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
tUt712022
John Lyons
Energy Resources
509-49s-8sls
REQUEST:
Please respond to the following regarding the Public Utility Regulatory Policies Act of 1978
("PURP4') projects listed in the Excel file labeled: .AVU-E-22-15 Attachment A
Confi denti al) _l 0 - I 4 -22. xlsx. "
a. Please explain how Expected Energy is calculated.
b. Please explain how Peak Contribution is determined for each project and what peak
timeframes Peak Contribution corresponds to.
c. Please explain how Expected Energy and Peak Confribution are used in calculating
the Integrated Resource Plan ("IRP-based") avoided cost rates.
RESPONSE:
a. Regarding 'AVU-E-22-15 Attachment_A Confidential)_10-14-22.x1sx", Expected Energy
consists of the expectations for the annual energy that will be produced by each PURPA
project based on Avista's history with the project or based on the expectations and engineering
estimates of the owner of newer projects, such as the University of Idaho projects, that have no
prior generation history. This expectation is consistent with how Avista has treated expected
ensrgy from PURPA projects for past annual load filings, electric IRPs, and the load and
resource positions used by the Company for planning and operational purposes.
b. Peak Contribution is determined for each PURPA project based on the project and what months
and hours it is expected to deliver energy and capacity. The expectation is based on Avista's
history with the project for most PURPA projects being reported in this filing, as they are
updated contracts for existing resources. The peak contribution is based on engineering
estimates of the megawatts that will be produced by the owner of newer projects that have no
generation history to rely upon. This is consistent with how Avista has treated peak
contribution from PURPA projects for past annual load filings, elechic IRPs and the load and
resource positions used by the Company for planning and operational purposes. Traditionally,
winter peak loads generally occtr in January and summer peak loads in August.
c. The IRP-based avoided cost rates are developed separately from this filing as one of the results
of the IRP process. The expected energy and peak contribution shown in this filing are a
snapshot in time of expectations until the next IRP is completed and the new avoided costs are
issued.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INT'ORMATTON
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
AVU-E-22-15
Staff
Production Request
Staff-003
DATE PREPARED:
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
tUtT/2022
John Lyons
Energy Resources
509-495-8515
REQUEST:
Please respond to the following regarding the Chelan PUD contract listed in the Excel file labeled:
'AVU-E-22- I 5 Attachment A (Confi denti al) _l 0- I 4-22.x1sx. "
a. The nameplate capacity listed in the "Nameplate Capacity" column on Tab PPAs does not match
the nameplate capacity stated in the "Notes" column. Please reconcile the difference and provide
the most accurate amount.
b. Please explain how Peak Contribution is determined and provide the timeframe that
the Peak Contribution corresponds to.
c. Please explain how Expected Energy is calculated.
d. Please explain how Expected Energy and Peak Contribution are used in calculating
the IRP-based avoided cost rates.
RESPONSE:
Please see Avista's response 003C, which contain TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and are separately filed under IDAPA 31.01.01, Rule 067 and
233, and Section 9-340D,Idaho Code.
a. There are two components involved with the Chelan PUD contract with the following details:
a New Chelan PUD Contract lz 5o/o share of the output of Rock Island and Rocky Reach
dams from 2026 throtgh 2030 providing 88 aMW of nameplate capacity,96.2 MW of
sunmer peak contribution in August, 96.2 MW of winter peak contribution in January, and
51.7 aMW of expected enerry. The QCC percentages are still being processed and are not
being used at this time.
New Chelan PUD Contract 2: l0o/o share of the output from Rock Island and Rocky
Reach dams from 2031 through 2045. This contract provides 176 MW of nameplate
capacity,192.4 MW of winter peak contribution in January,192.4 MW of summer peak
contribution in August, and 103.4 aMW of expected energy. The QCC percentages are still
being processed and are not being used at this time.
a
b. Peak Contribution is determined based on the past and expected operations for the Rock Island
and Rocky Reach hydro pdects and what months and hours they are expected to deliver
energy and capacity in. The expectation is based on past operations at these hydro facilities and
engineering estimates for future operations and streamflow expectations. This is consistent
with the expected peak contribution from other Mid-Columbia hydro projects for past annual
load filings, electric IRPs and the load and resource positions used by the Company for
planning and operational purposes. Please refer to "New AVU-E-22-15 Attachment A
(Confidential)_ll-14-22.xlsx" for updated numbers from the original filing. The QCC
percentages are still being processed and are not being used at this time.
c. Expected Energy consists of the expectations for the annual energy that will be produced by
these contracts on the operational history ofthe dams and futtre engineering expectations from
Chelan PUD. This expectation is consistent with how Avista has heated expected energy from
Mid-Columbia hydro projects for past annual load filings, elecffic IRPs, and the load and
resource positions used by the Company for planning and operational purposes.
d. The IRP-based avoided cost rates are developed separately from this filing as one ofthe results
of the IRP process. The expected energy and peak confiibution shown in this filing are a
snapshot in time of expectations until the next IRP is completed and the new avoided costs are
issued.
AVISTA CORPORATION
RESPONSE TO REQITEST FOR TNFORMATTON
ruRISDICTION: IDAHO
CASE NO: AYU-E-22-15
REQUESTER: StaffTYPE: Production Request
REQUEST NO.: Staff-004
DATE PREPARED:
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
tUt712022
Annette Brandon
Energy Resources
509-495-4324
REQUEST:
Order No. 33357 requires utilities to create a queue to track the order in which QF projects have
entered negotiations with a utility to ensure proposed prices (indicative pricing in the IRP
Methodology) are more accurate. Please respond to the following.
a. Please describe the tlpes of projects in Avista's queue. Specifically, which of the following are
included:
. PURPA projects with contracts in negotiation
. Non-PURPA projects with conhacts in negotiation
. PURPA projects with signed conffacts but not yet Commission approved
. Non-PURPA projects with signed contracts but not yet Commission approved
. PURPA projects with Commission-approved contracts
b. Please describe in detail how Avista manages its queue. Specially, what criteria are used to
determine additions and removals of projects in the queue?
c. Please describe in detail how Avista determines the sequence of projects in the queue.
d. Please describe in detail how a QF's position in the queue determines its indicative pricing.
RESPONSE:
a. Avista does not currently have any QF projects in the queue and Avista is not currently in
negotiation with any Qualiffing Facilities.
o Avista is currently negotiating contracts with three Non-PURPA entities as a result of
the most recent Integrated Resources Plan. Two of these contracts were the result of
Avista's 2022 All Source RFP and one was part of a separate competitive process
solicited by the counter-party.
Avista has no PURPA projects with signed conkacts not yet approved by the
Commission. The Company is in the very early stages ofrenewing an existing PURPA
contract located within the State of Washington.
The Company executed trvo non-PURPA hydro deals in 2020, with delivery dates of
2024 and2026 whrchhave not been included in a General Rate Case for Washington or
Idaho. These contracts will be included in the proposed authorized power supply base
in upcoming General Rate Cases with the appropriate rate year.
Active contracts that have been approved by the Commission are comprised of Steam,
Solar, Hydro and Wood Waste.
b. The criteria used to determine additions and removals of the project in the queue are based on
the Company's Schedule 62. Employees within the Company's Wholesale Marketing Group
a
a
manage the process on ao individuat basis, coordinating with the legal departuent as
applicable.
c. The Company follows the timing established in Schodule 62 approved by the Idaho
Commission. The t'ming of the first point of contact would determine the schedule for
negotiations.
d. The indicative pricing for a project is based on the avoided costs provided by Avista's resource
planrring Soup or Avista's published avoided cost rate, as applicable. Once confracted, the
negotiated rate is depende,nt upon approval by the Idaho Public Utilities Comnrission.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
AW-E-22-15
Staff
Production Request
Stafl005
DATE PREPARED:
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
tvt7t2022
Annette Brandon
Energy Resources
s09-49s-4324
REQUEST:
Please confirm that the final IRP-based avoided cost rates used in a signed contact (not the initial
indicative pricing) are determined based on projects approved by the Commission at the time when
the IRP-based conhact is signed, which do not include "projects in negotiation" or "projects with a
signed contract but not yet Commission approved."
RESPONSE:
Yes, the final IRP-based avoided cost rates are based on the rates approved by the Commission at
the time when the contract is finalized.