20230518EIM Report_Attachments.pdf

Avista Corp.
1411 East Mission P.O. Box 3727
Spokane, Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170

May 18, 2023

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd.
Bldg. 8, Suite 201-A
Boise, Idaho 83714

Re: Case No. AVU-E-20-01 - Avista Corporation Energy Imbalance Market Report per
Order No. 34606

Dear Ms. Noriyuki:

Avista Corporation, dba Avista Utilities (Avista or the Company) provides this report on
the Company’s operation in the Energy Imbalance Market (EIM) after one year of operation,
detailing expenditures and informing the Commission of ongoing costs and benefits, as required
by Order No. 34606 in Case No. AVU-E-20-01.

I. Background
On January 10, 2020, Avista Corporation applied to the Commission for an order allowing
the Company to defer its Idaho jurisdictional incremental operation and maintenance ("O&M")
costs associated with joining the California Independent System Operator's ("CAISO") Western
Energy Imbalance Market ("EIM"). The Company sought to defer those costs until they could be
included in base rates through a general rate case proceeding. The Company expected to “go-live”
with the EIM by April 1, 2022.
The Commission approved the request for deferred accounting treatment, authorizing
Avista to track its Idaho jurisdictional incremental O&M expenses associated with joining the EIM
in a deferral account, with no carrying charge. The Company was also directed to cease booking
RECEIVED
2023 May 18, 3:07PM
IDAHO PUBLIC
UTILITIES COMMISSION

costs to the deferral account at the go-live date.1 In addition, as noted at page 5 of Order No. 34606
the Commission ordered:
[A]fter the Company has participated in the EIM for one-year, it will file a report
with the Commission describing the costs and benefits of participation as of the
date, in addition to any other relevant information. The Company is directed to
include in this report any available benefit and cost information, including but not
limited to the CAISO's quarterly Western EIM Benefits Report.

In addition to the deferred accounting treatment approved in Docket AVU-E-20-01, the
Commission also approved, per AVU-E-21-01 (Avista’s 2021 General Rate Case), Order No.
35169, that effective with the expected “go live” March 1, 2022 date, the Company will begin to
reflect Idaho’s share of incremental EIM O&M expenses through the PCA up to Idaho’s share of
EIM benefits that also will flow through the PCA. Any incremental EIM O&M expenses exceeding
EIM benefits would continue to be deferred for review and determination of recovery in a future
proceeding.
Finally, through Commission review of the Company’s Annual Power Cost Adjustment
(PCA) Application, Case No. AVU-E-22-11, Order No. 35543, the Commission continued to find
it just and reasonable to authorize the Company to continue to recover EIM incremental expenses
in the PCA, up to the benefits realized from the EIM, and to continue the current method of
addressing EIM incremental expenses in the PCA process. During the 2022 PCA review, Staff
verified the Company’s calculations of the EIM expenses, however the Commission directed the
Company to explain its methodology for measuring EIM benefits, and how that method differs
from CAISO’s method. Pursuant to Order No. 35543, the Company filed with the Commission
on October 11, 2022 its report on its method for measuring EIM benefits and how that method
differs from CAISO’s method (“EIM benefit report”). In Order No. 35606, the Commission
acknowledged Avista’s EIM benefit report was in compliance with Order No. 35543.

1 Order No. 34606 at page 5.

II. EIM REPORT DOCUMENTATION
In compliance with Order No. 34606, although certain information has been previously
reviewed or provided to the Commission, the following information is provided in support of
Avista’s operation in the Energy Imbalance Market (EIM), after one year of operation, detailing
expenditures and informing the Commission of ongoing costs and benefits:
• Attachment A - Energy Imbalance Market Program Summary Report – this
report summarizes the implementation of the EIM program, with total system
(Washington/Idaho) incremental integration costs of $27.4 million, with $24.2
million in capital and $3.2 million in incremental expense. Annual O&M expense
associated with incremental EIM employees and software maintenance costs are
estimated at $3.1 million, with an annual capital estimate of $0.5 million to support
software enhancements and upgrades.
• Attachment B – Life to date (3/1/2023) EIM Capital Investment
• Attachment C – Life to date (3/1/2023) EIM Expenses, Preliminary Benefit
Calculation and Net Revenues and Sales
• Attachment D – Avista’s October 11, 2022 EIM Benefit Compliance Report -
Per Case No. AVU-E-22-11, explaining Avista’s methodology for measuring EIM
benefits, and how that method differs from CAISO’s method.
• Attachment E - CAISO's quarterly Western EIM Benefits Reports

Additionally, listed below are incremental benefits Avista receives from participation in
the EIM that are not quantifiable:
• Enhanced grid reliability through sharing information on electricity delivery
conditions between balancing authorities across the EIM region.
• Congestion management functions in the market are more economically efficient than
non-market curtailments and bilateral redispatch capabilities.
• Balancing and regulation of renewable resources, allowing Avista to leverage
available footprint wide market resources, instead of relying on only Company
resources to provide regulation and meet flexible ramping requirements.
• Hourly bilateral market liquidity has decreased substantially as most Pacific
Northwest utilities are in the EIM. Since joining EIM Avista now accesses the 15-
minute interval commitment and redispatches footprint wide on the 5-minute interval.
• Better utilization of transmission for transfers between Avista and other EIM Entities.

Finally, as discussed in Attachment D, Avista’s October 11, 2022 EIM Benefit Compliance
Report, a process for determining Avista’s EIM benefits is defined and will be further developed
through practice over time. Avista will continue refining its EIM Benefit methodology, identifying
opportunities to further improve the accuracy of its EIM benefit calculation, and will provide an
update on the EIM benefit calculation and results with the Company’s next annual PCA filing.
For questions about this report please contact me at 509-495-8601 or
[e-mail].

Sincerely,
/s/ Elizabeth Andrews

Elizabeth Andrews
Sr. Manager, Revenue Requirements
Enclosure

ATTACHMENT A
ENERGY IMBALANCE MARKET
PROGRAM SUMMARY REPORT 11.29.2022

Program Approval to Close

Program Close Summary Avista Confidential Page 1 of 26

Program Name: Energy Imbalance Market
Program Manager: Kelly Dengel
Business Case Name: Energy Imbalance Market
Expenditure Request: 7141 – Energy Imbalance Market
Submit Date: November 29, 2022
1 Key Roles & Program Information
Program Sponsor(s): Scott Kinney/
Mike Magruder
Business Case
Owner(s): Kelly Dengel
Business Program
Manager: Kelly Dengel Executive Steering
Committee Members:
Jason Thackston, Heather
Rosentrater, Jim Kensok,
Ryan Krasselt, Kevin
Christie, Scott Kinney
Director Steering
Committee Members:
Kevin Holland, Alexis
Alexander, Mike
Magruder, Jim Corder,
Hossein Nikdel, Adam
Munson, John Wilcox, Pat
Ehrbar, Todd Colton, Clay
Storey
Other Stakeholders:
James Dykes, Robert Follini,
Annette Brandon, Jacob
Reidt, Kit Parker, Bob
Weisbeck, Tom Dempsey,
Alexis Alexander, Glen
Farmer, Brad Calbick, Craig
Figart, Kenny Dillon, Mike
Andrea, Glenn Madden,
Lamont Miles, Brian
Hoerner, Xin Shane, Jason
Pegg

Program Approval to Close

Program Close Summary Avista Confidential Page 2 of 26
2 Contents
1 KEY ROLES & PROGRAM INFORMATION ................................................................................................................................... 1
3 EXECUTIVE SUMMARY .............................................................................................................................................................. 3
4 PROGRAM IMPLEMENTATION COST COMPARISONS ................................................................................................................ 3
5 CAISO & AVISTA PROGRAM SCOPE ........................................................................................................................................... 4
6 AVISTA SCOPE DELIVERY BY CAISO EIM TRACK ......................................................................................................................... 6
6.1 TRACK 0/1 –EIM PROGRAM PLANNING & PROJECT MANAGEMENT DELIVERY ......................................................................................... 6
6.2 TRACK 2 – POLICY, LEGAL & SUPPORT DELIVERY ................................................................................................................................. 7
6.3 TRACK 3 – TRANSMISSION & GENERATION MODELING DELIVERY ........................................................................................................... 8
6.4 TRACK 4 – SYSTEM INTEGRATION & TESTING DELIVERY ........................................................................................................................ 9
6.5 TRACK 5 – METERING & SETTLEMENTS DELIVERY .............................................................................................................................. 12
6.6 TRACK 6 – OPERATIONS READINESS & TRAINING DELIVERY ................................................................................................................. 18
7 PROGRAM IMPLEMENTATION COSTS ..................................................................................................................................... 21
7.1 TOTAL PROGRAM COSTS ............................................................................................................................................................... 21
7.2 TOTAL PROGRAM COSTS BY BUSINESS UNIT ..................................................................................................................................... 22
7.3 TOTAL EXPENSE LABOR COSTS BY BUSINESS UNIT .............................................................................................................................. 22
7.4 TOTAL INCREMENTAL NON-LABOR EXPENSE COSTS ............................................................................................................................ 23
7.5 TOTAL INCREMENTAL COSTS .......................................................................................................................................................... 23
8 DIRECTOR APPROVALS ............................................................................................................................................................ 25
9 EXECUTIVE APPROVALS........................................................................................................................................................... 26

Program Approval to Close

Program Close Summary Avista Confidential Page 3 of 26
3 Executive Summary
On April 25, 2019, Avista signed the Western Energy Imbalance Market (WEIM) Implementation Agreement with the
California Independent System Operator (CAISO) to join the market in April 2022. After a three-year implementation
program, Avista successfully entered the WEIM ahead of schedule on March 2, 2022, under the allocated budget and
delivered the required scope for market operations – all while navigating the challenges of the COVID-19 Pandemic. To
support the integration effort, Avista contracted Utilicast as a market integration consultant to assist with market and
software expertise. In preparation for the first of four CAISO integrated testing phases, Avista completed the required
metering, controls and network upgrades by June 2021 and started connectivity/integration testing in early June 2021.
Avista also purchased and configured eight EIM software applications, supplemented with internal system upgrades and
integrations and began formal integration testing July 15, 2021. To support software integration testing and market
operations, Avista established 17 new EIM positions (EIM Human Resource Plan) and began hiring in the summer of
2020 through market entry. Avista entered the three-month parallel operations testing phase with CAISO on December
1, 2021, and entered the market just after midnight at 00:00:01 on March 2, 2022.

The EIM Implementation Program closed with total incremental integration costs at $27.4 million with $24.2 million in
capital and $3.2 million in incremental expense. Annual O&M expense associated with incremental EIM employees and
software maintenance costs are estimated at $3.1 million, with an annual capital estimate of $0.5 million to support
software enhancements and upgrades.

Table 1 – Incremental Implementation Program Actuals as of September 2022

4 Program Implementation Cost Comparisons
The EIM Program implementation undertook two cost estimation phases. The first cost estimation results were reflected
in the EIM Program Charter, finalized in May of 2019. The second cost estimation results were reflected in the EIM
Scope Document, finalized in October 2020. The actual implementation costs as of accounting period September 2022
are reflected in this EIM Close Document. To provide a cost comparison, the financial charts will display information in
terms of Charter vs. Scope vs. Close financials where applicable.

The implementation effort required both capital and expense investments. Avista began charging EIM expense projects
across six business units July 1, 2019, for both existing and incremental labor and non-labor costs. However, Avista did
not create an individual expense project for each expense deliverable, as expense reporting is not tracked by deliverable
within the Company financial records. When comparing expense estimates, some costs have been re-assigned from one
cost area to another, and a direct comparison is not possible. Where possible, this document will represent expense
costs in terms of existing and incremental labor. For metering projects, an estimated expense threshold of $10k was
established to track costs associated with an individual expense project. The EIM Program documentation expressed
costs in these terms:

▪ Implementation Capital – includes all known project costs for EIM software integration and testing,
network infrastucture and metering and controls upgrades.

▪ Implementation Expense – includes all known expense costs associated with market integration prior to
market entry, including existing Avista labor, new incremental Avista labor associated with the EIM HR
Plan and non-labor expense items such as the CAISO milestone payments and Utilicast support. Where
possible, a distinction of existing vs. incremental expense is noted.
EIM Program Closed Actuals
(as of 09/2022)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $24.1 $0.1 $24.2 $0.0 $0.5
Incremental Expense $3.1 $0.1 $3.2 $3.1 $0.0
Total Costs $27.2 $0.2 $27.4 $3.1 $0.5
Program Approval to Close

Program Close Summary Avista Confidential Page 4 of 26

▪ Contingency – includes an estimate for capital and expense funds to cover unknown costs or increased
costs above expected spend. This is consisent with Avista project estimating practices.

▪ Annual O&M Expenses – this includes all known updated costs associated with market operations post
go-live, including the incremental Avista labor to support EIM operations (EIM HR Plan), CAISO grid
management fees, and software maintenance and liscencing fees.

▪ Annual Capital – this represents anticipated capital costs for software enhancements and upgrades.
Avista will have a better estimate after gaining operational experience and understanding the impact
CAISO annual updates have on system integration. These annual capital costs were not included in the
cost benefit anaylsis.

The EIM Program closed with all financial activity complete as of the September 2022 accounting period. Costs in the
“Closed Actuals” columns reflect final actual costs.
5 CAISO & Avista Program Scope
The CAISO developed an implementation structure for market participants with six program tracks. A description with
requirements, along with an Avista scope has been provided.

CAISO EIM Track Avista Scope Complete –
Yes/No/In Progress
Track 0 Avista EIM Program Preparation

Avista program structure, leadership, documentation, change
management plan, internal project schedule, software procurement
and contracting
Yes
Select System Integrator Yes
Track 1 Planning & Project Management

Joint Avista-CAISO project plan and schedule Yes
Joint impact assessment document Yes
Avista go-live support plan document Yes
Joint checkpoint, progress evaluation meetings, etc. Yes
Joint monthly project leadership meetings Yes
Joint quarterly executive meetings Yes
Track 2 Policy, Legal, Support

EIM Entity Implementation Agreement Yes
EIM Entity Agreement Yes
EIM Entity Scheduling Coordinator (EESC) Agreement Yes
EIM Participating Resource Scheduling Coordinator (PRSC) Agreement Yes
EIM Participating Resource Agreement Yes
Department of Market Monitor Filings Yes
Market Base Rate Study Yes
CAISO Implementation Milestone Payments Yes
CAISO Grid Management Charge Yes
Open Access Transmission Tariff (OATT) Filing Yes
Track 3 Transmission & Generation Modeling

Transmission Full Network Model (FNM) creation & maintenance Yes
Integrate Energy Management System (EMS) to CAISO Automated
Dispatch System
Yes
Master File / Generation Participation & Cost Modeling Yes
Program Approval to Close

Program Close Summary Avista Confidential Page 5 of 26
Major Maintenance Adders & Default Energy Bid logic Yes
Energy Transfer System Resource (ETSRs) Yes
Track 4 System Integration & Testing

Acquire & configure Generation Outage Management software Yes
Acquire & configure Transmission Outage Management software Yes
Acquire & configure Participating Resource Scheduling Coordinator
(PRSC) bidding & scheduling software (merchant)
Yes
Acquire & configure EIM Entity Scheduling Coordinator (EESC)
scheduling software (transmission)
Yes
Acquire & configure PRSC settlement software (merchant) Yes
Acquire & configure EESC settlement software (transmission) Yes
Acquire & configure reporting & analytics software Yes
Enhance & integrate Avista Decision Support System (ADSS) Yes
Acquire & configure Energy Accounting software Yes
Acquire & configure a E-Tagging solution Yes
Enhance Nucleus functionality N/A
Install new instance of Itron MV90 xi for meter data collection Yes
Integrate EIM software systems Yes
Integrate EIM software with CAISO systems Yes
Pre-production testing with CAISO – Day in the Life phase Yes
Pre-production testing with CAISO – Market Simulation phase Yes
Pre-production testing with CAISO – Parallel Operations phase Yes
Track 5 Metering & Settlements

Low-Side Metering (LSM) installation at generation plants Yes
High-Side Metering (HSM) installation at generation plants Yes
Current Transformer (CT)/Potential Transformer (PT) testing/upgrades Yes
Interconnection meter upgrades/reconfiguration at substations Yes
Network and communications installations/upgrades Yes
Generation plant Programmable Logic Control (PLC) upgrades Yes
Creation, submission & approval of Settlement Quality Meter Data
(SQMD) plans and metering portfolio to CAISO
Yes
Track 6 Operations Readiness & Training

Create internal EIM training plan Yes
Complete CAISO EIM computer-based training modules Yes
CAISO conducts hands-on training for Avista Yes
Develop internal operational EIM procedures Yes
File internal operational EIM procedures with CAISO Yes
Complete CAISO market readiness criteria worksheet Yes
CAISO provides planned go-live operations procedure documents Yes
CAISO files market readiness certificate with FERC prior to go-live Yes
Develop & implement EIM operations & support model Yes
EIM Human Resource Plan Yes
EIM Transmission System Operations desk & remodel at Backup
Control Center (BuCC)
Yes
EIM Transmission System Operations desk & remodel at Mission Yes
Noxon 230kV Switchyard CIP Compliance Yes

Program Approval to Close

Program Close Summary Avista Confidential Page 6 of 26
6 Avista Scope Delivery by CAISO EIM Track
6.1 Track 0/1 –EIM Program Planning & Project Management Delivery
6.1.1 Utilicast – System Integrator Delivery Summary
Avista engaged with Utilicast in three phases, with the intent to evaluate performance and value before signing
additional EIM integration support agreements. Phase one in 2018 focused on the technology, metering, and network
model assessment, helping Avista understand the CAISO requirements and processes, and identifying the gaps to be
filled. After soliciting responses for a System Integrator via a Request for Information (RFI) proposal, Avista agreed to a
sole sourcing engagement with Utilicast. This led to a second agreement in 2019 that focused on metering and
generation control requirements and design, generation bidding strategies, development of technology application
requirements and RFPs and the evaluation/selection of EIM software vendors. The third engagement was signed in
December 2019 and focused on the program implementation efforts through go-live of 2022. When the 2020-22
Implementation agreement with Utilicast was signed, each deliverable was assigned an expense or capital indicator,
which allowed for an estimate of annual expense and capital charges by year. The primary Utilicast expense drivers were
associated with market training, business process design and generation/interchange modeling.

6.1.2 Utilicast Actuals
During the two-year EIM implementation agreement, Utilicast supported Avista with subject matter experts in the areas
of metering, resource modeling, bidding strategies, software implementation, market rules expertise, and training. The
Utilicast implementation agreement concluded in June 2022. Utilicast capital costs closed at $3.2 million, approximately
$0.5 million under the Scope budget, with savings attributed to limited travel (Covid-19 pandemic) and effective
management of deliverables between Avista and Utilicast. Utilicast expense costs closed at $1.2 million, approximately
$0.45 million under the Scope estimates, with savings also attributed to limited travel and effective joint management of
program deliverables.

Table 2 – Utilicast Agreements Financial Comparison as of September 2022

Table 3 – Utilicast 2020-2022 Implementation Agreement
Actuals by Business Unit Financial Comparison as of September 2022

Agreement Year Capital Expense Capital Expense Capital Expense
Technology RFP 2019 $ - $ 500,000 $ - $ 508,435 $ - 508,435$
Implementation 2020-2022 $ 3,200,000 $ - $ 3,700,000 $ 1,150,000 3,238,235$ 708,052$
$ 3,200,000 $ 500,000 $ 3,700,000 $ 1,658,435 3,238,235$ 1,216,486$
Actuals
Scope Estimates
(as of 08/2020)Utilicast Agreements Charter Estimates
(as of 05/2019)
Totals
Closed Actuals
(as of 09/2022)
Business Units CAISO Track Capital Expense Capital Expense Capital Expense
ET Applications Track 4 $ 2,986,181 $ 2,986,181 2,676,885$
ET Network Track 4 & 5 $ 67,060 $ 67,060 42,364$
GPSS Track 5 $ 67,060 $ 67,060 32,639$
Substation & Third Party Generation Track 5 $ 67,060 $ 67,060 35,539$
Transmission Track 4 $ 40,000 $ 40,000 25,841$
Facilities Track 6 $ - $ - -$
ADSS Track 4 $ 472,639 $ 472,639 424,967$
EIM Program All $ - $ 1,600,000 $ - $ 1,150,000 -$ 708,052$
Utilicast Totals $ 3,700,000 $ 1,600,000 $ 3,700,000 $ 1,150,000 3,238,235$ 708,052$
Implementation Agreement
(as of 10/2019)
Scope Estimates
(as of 08/2020)
Closed Actuals
(as of 09/2022)
Utilicast Implementation Agreement
(signed 10/2019)
Program Approval to Close

Program Close Summary Avista Confidential Page 7 of 26
6.2 Track 2 – Policy, Legal & Support Delivery
6.2.1 Policy, Legal & Support Delivery Summary
Apart from professional services to support the EIM Market Base Rate Study, most costs represented in this section are
implementation expense (existing and incremental). Although an estimate was provided by deliverable, actual expense
costs were not tracked by individual deliverable, but by business unit. See Table 24 – Total Incremental & Non-
Incremental Labor Actuals for expense costs by business unit, which includes delivery of these items.

Table 4 – Policy, Legal, Support Financial Comparison as of September 2022

6.2.1.1 EIM Agreements
Avista signed various CAISO agreements to conduct operations as a Merchant Scheduling Coordinator and
Entity Scheduling Coordinator to transact in the market. This also included items such as financial forms,
certifications, risk policies, and user and contact lists. All EIM agreements were executed by March 2021.
6.2.1.2 Open Access Transmission Tariff (OATT)
Avista made changes to its OATT to accommodate transmission utilization in the EIM, change ancillary service
charges and incorporate EIM financial settlement obligations. The updated OATT was filed with FERC on
October 27, 2021, and approved January 28, 2022.
6.2.1.3 Market Base Rate Study
Market Based Rate (MBR) authority represents permission granted by FERC to allow power to be sold at
market rates, as opposed to a traditional cost of service rate (also known as cost-plus). An EIM MBR study was
required to ensure Avista didn’t have the ability to set the market price within the market. The EIM MBR was
filed with FERC on June 30, 2021 and approved on February 28, 2022.
6.2.1.4 Professional Services
In addition to Utilicast support, Avista contracted Llyod Reed Consulting to conduct the EIM MBR study at a
cost of $0.05 million.
6.2.1.5 Department of Market Monitoring Filings
Avista submitted and negotiated Major Maintenance Adders (MMAs) and Default Energy Bids (DEB) by
generation resource with the ISO’s Department of Market Monitoring. These had multiple internal reviews
before submission and approval by the CAISO on February 7, 2022.
6.2.1.6 CAISO Milestone Payments
As part of the EIM Implementation Agreement with the CAISO, six milestone payments were required. Each
milestone payment was $50k, for a total implementation fee of $300k, and were planned as expense. Apart
from the first expense milestone payment, the remaining payments were reclassified to capital in support of
EIM software and system integration testing efforts and are captured in the software actuals costs in Table 8.

Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
EIM Agreements $ - $ - $ - $ - $ - $ - $ -
OATT $ - $ - $ - $ - $ - $ - $ -
Market Base Rate Study $ - $ - $ - $ - $ - $ - $ -
DMM Filings $ - $ - $ - $ - $ - $ - $ - $ -
Professional Services $ - $ 105,000 $ - $ - $ 105,000 $ - $ - $ 50,216 $ -
CAISO Payments $ - $ 300,000 $ - $ - $ 300,000 $ - $ 250,000 50,000$ $ -
CAISO Grid Management Fee $ - $ - $ 120,000 $ - $ - $ 120,000 $ - $ - 216,281$
Totals $ - $ 535,000 $ 120,000 $ - $ 535,000 $ 120,000 $ - $ - $ -
Utilicast $ - $ - $ - $ - $ - $ - $ - $ - $ -
Grand Totals $ - $ 535,000 $ 120,000 $ - $ 535,000 $ 120,000 $ 250,000 $ 100,216 $ 216,281
Charter Estimates (as of 05/2019)
$ 130,000 $ 130,000
Scope Estimates (as of 08/2020)
Track 2 - Policy & Legal
Closed Actuals (as of 09/2022)
Program Approval to Close

Program Close Summary Avista Confidential Page 8 of 26
Table 5 – CAISO EIM Implementation Agreement Milestone Payments

CAISO Milestone Dates for
March 2, 2022 Entry
Amount
Due
Milestone 1 – Sign EIM Implementation Agreement April 2020 $50,000
Milestone 2 – Deploy Avista’s FNM in a non-production CAISO environment June 30, 2021 $50,000
Milestone 3 – Promote Avista’s FNM to Market Simulation environment July 15, 2021 $50,000
Milestone 4 – Begin Market Simulation Testing October 1, 2021 $50,000
Milestone 5 – Begin Parallel Operations Testing December 1, 2021 $50,000
Milestone 5 – Begin EIM Operations in Production March 2, 2022 $50,000
Total $300,000

6.2.1.7 CAISO Grid Management Charge
The CAISO charges EIM participants a grid management fee based on the amount of MWhs transacted in the
market and is assessed through the CAISO settlement process. The Scope estimate for this on-going variable
expense charge was $0.1 million, while actuals as of September 2022 are $0.2 million.

6.3 Track 3 – Transmission & Generation Modeling Delivery
6.3.1 Transmission & Generation Modeling Delivery Summary
Apart from CAISO Dispatch Integration project, most of the costs represented in this section are implementation
expense (existing and incremental). Although an estimate was provided, actual expense costs were not tracked by
individual deliverable, but by business unit. See Table 24 – Total Incremental & Non-Incremental Labor Actuals for
expense costs by business unit, which includes delivery of the Master File/Generation Participation and Cost Modeling,
and Energy Transfer System Resource work.

Table 6 – Transmission & Generation Modeling Financial Comparison as of September 2022

6.3.1.1 Transmission Full Network Model (FNM) Creation
The creation of the transmission Full Network Model (FNM), real-time state estimation, and real-time
contingency analysis was not funded under the EIM implementation; however, it was critical for market
operations. Avista delivered the first version of the FNM in June 2021, in accordance with Milestone 2, and
updated the model as Avista progressed through the market testing phases. The model will be updated in
accordance with CAISO’s planned FNM database release schedule.
6.3.1.2 FNM EIM Support
The capital funds planned in the Charter and the Scope documents were allocated to support implementation
of the CAISO Dispatch Integration project, while the on-going expense labor was included in the EIM Human
Resource Plan costs (see Section 6.6.1.2).

Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
FNM Creation* $ - $ - $ - $ - $ - $ - $ - $ - $ -
FNM EIM Support $ 80,000 $ - $ 50,000 $ 80,000 $ - $ 50,000 $ - $ - $ -
EIM Dispatch Module $ 156,000 $ - $ - $ 160,000 $ - $ - $ 499,742 $ - $ -
Master File / Gen Cost Modeling $ 200,000 $ - $ - $ - $ 200,000 $ - $ - $ - $ -
Totals $ 436,000 $ - $ 50,000 $ 240,000 $ 200,000 $ 50,000 $ - $ -
Utilicast $ 40,000 $ - $ - $ 40,000 $ - $ - $ 25,841 $ - $ -
Grand Totals $ 476,000 $ - $ 50,000 $ 280,000 $ 200,000 $ 50,000 $ 525,583 $ - $ -
Track 3 - Transmission & Generation
Modeling
* Funded by SCADA Business Case
Scope Estimates (as of 08/2020)Charter Estimates (as of 05/2019)Closed Actuals (as of 09/2022)
Program Approval to Close

Program Close Summary Avista Confidential Page 9 of 26
6.3.1.3 EIM Dispatch Module / Integration with CAISO Automated Dispatch System
Avista integrated its Supervisory Control and Data Acquisition (SCADA) system with the CAISO Automated
Dispatch System (ADS) to receive market Dispatch Operating Targets (DOTs) and send them to the generation
plants control systems for targeted energy output. At the time of the Scope Document, it was unknown how
much scope would be completed within the GPSS control upgrade projects vs. the integration effort with
SCADA. After the GPSS control projects were complete, $336k was transferred from GPSS to this project, along
with $50k of the FNM EIM capital line listed above and a contingency request to fund the project. The CAISO
Dispatch Integration (EIM Dispatch Module listed in Table 4) project began in May 2021 to support Parallel
Operations testing in December 2021, transferred to plant in March 2022 and completed at $0.53 million,
inclusive of Utilicast costs.
6.3.1.4 Master File / Generation Participation & Cost Modeling
Avista began the data collection process for the Generation Resource Data Template (GRDT) and the
Interconnection Resource Data Template (IRDT) in December 2019 to support market operations and submit
to the CAISO Master File application. The GRDTs described the physical and operational properties of each
generation resource, while the IRDTs represented Energy Transfer System Resource (ETSR) physical locations
and market dispatch transmission limits between Balancing Authorities Areas (BAAs). The GRDT and IRDT data
files were configured with CAISO and in the EIM software to support market testing and will continue to be
evaluated/updated for operational efficiency and performance.
6.4 Track 4 – System Integration & Testing Delivery
6.4.1 EIM Software Summary
In June of 2019, Avista engaged with Utilicast to define the system requirements for various EIM software applications.
Avista issued two technology-based RFPs – the Generation and Transmission Outage Management System in August
2019 and the Bid to Bill EIM suite, including the PRSC and EESC for scheduling, the PRSC and EESC for settlements,
Energy Accounting and an Analytics/Reporting application in October 2019. A recommendation to purchase Power Cost,
Inc.’s (PCI) products for OMS, EESC, PRSC and Energy Accounting was made, along with Power Settlements (PS) products
for settlements and analytics, to the EIM Director Steering Committee in November 2019 and to the Executive Steering
Committee in December 2019. After the Executive Steering Committee approval, Avista engaged with PCI and Power
Settlements to negotiate the terms and conditions of the agreements, as well as the implementation costs (capital) and
on-going operating expense (expense). In March 2020, Avista concluded the negotiations with PCI, and in May 2020
concluded the negotiations with Power Settlements for the systems in Table 7.

Table 7 – EIM Bid to Bill Software Suite

Vendor Application Name Function
Power Costs, Inc Asset Operations Generation Outage Management
Transmission Outage Management
GenManager Front Office PRSC Bidding & Scheduling
EESC Scheduling
Energy Accounting Energy Accounting
Power Settlements Settle Core PRSC Settlements
EESC Settlements
Visual Analytics Performance & Analytics

Beyond the EIM Bid to Bill software provided by PCI and PS, Avista also implemented software to support meter data
collection and a Variable Energy Resource (VER) forecast submission. When Avista conducted the RFP, the Avista
Decision Support System (ADSS) was planned to perform EIM bid calculation and base schedule creation.

At the time of the Charter estimates, Utilicast estimates were provided as a total amount and were not separated by
program area. As such, the Charter Estimates in Table 8 below does not have Utilicast costs included for software
Program Approval to Close

Program Close Summary Avista Confidential Page 10 of 26
implementation. The Scope Estimate section of Table 8 below represents the EIM software implementation capital
estimates of $18.4 million, with vendor labor, software licensing, hardware and existing labor combined in the individual
project costs, while the Utilicast costs and labor associated with EIM Human Resources Plan are separate. The Close
Actuals section represents individual project costs with the inclusion of the EIM Human Resource Plan incremental labor,
existing Avista labor and vendor costs, while separating the Utilicast charges for the EIM software suite and ADSS from
the project totals. Most of the software projects transferred to plant in March 2022, had warranty charges through the
end of May and trailing charges through September 2022. The software warranty period completed May 31, 2022, and
Utilicast support completed by June 30, 2022.

The capital software implementation completed at $14.7 million, $3.7 million under the Scope Document budget with
savings attributed to reduced incremental and existing employee labor and avoided Utilicast and vendor travel costs.
Software implementation expense actuals were as planned, while on-going O&M EIM software expense is forecasted at
$0.55 million, $0.08 million over the Scope budget due to additional software purchased during the implementation.

Table 8 – EIM Software Financial Comparison as of September 2022

Capital Implementation
Expense
Ongoing
Expense Capital Implementatio
n Expense Ongoing Expense Capital Implementatio
n Expense
Ongoing
Expense
EIM Software Vendors $ 2,380,000 $ - $ 500,000 -$ -$ -$ -$ -$ -$
EIM Software Internal Labor $ 2,964,000 $ - $ - -$ -$ -$ -$ -$ -$
PCI EESC Scheduling $ - $ - $ - 1,599,004$ 10,152$ $ 100,395 1,326,475$ 10,152$ $ 129,945
PCI PRSC Bidding & Scheduling $ - $ - $ - 1,731,003$ 10,152$ $ 100,395 1,531,629$ 10,152$ $ 100,395
PCI OMS (Gen / Trans) Phase 1 1,421,499$ 1,048,885$
PCI OMS (Gen / Trans) Phase 2 459,591$ 294,550$
PCI Energy Accounting -$ -$ -$ 1,586,342$ 8,122$ $ 100,395 1,156,219$ 8,122$ $ 100,395
PS PRSC & EESC Settlement -$ -$ -$ 2,256,541$ 22,500$ $ 64,637 1,843,191$ 22,500$ $ 93,790
ADSS Phase 1 -$ -$ -$ -$ -$ 2,258,109$ -$ -$
ADSS Phase 2 -$ -$ -$ -$ -$ 1,285,466$ -$ -$
ADSS Disaster Recovery -$ -$ -$ -$ -$ -$ 96,561$ -$ -$
Itron MV90xi -$ -$ -$ 438,166$ -$ -$ 438,168$ -$ $ 21,816
Itron MV90xi Additional Licenses -$ -$ -$ -$ -$ -$ 23,143$ -$ -$
CT/PT Accuracy Testing -$ -$ -$ 11,004$ -$ -$ 11,004$ -$ -$
VER Forecast -$ -$ -$ 200,000$ -$ $ 15,000 323,905$ -$ $ 15,000
Totals $ 5,344,000 $ - $ 500,000 $ 12,690,641 $ 64,625 $ 465,783 $ 11,637,305 $ 64,625 $ 546,302
Utilicast (Technology RFP)-$ 500,000$ -$ -$ 508,435$ -$ 508,435$ -$
Utilicast (EIM Suite)-$ -$ -$ 2,986,181$ -$ -$ 2,676,885$ -$ -$
Utilicast (ADSS)-$ -$ -$ 472,639$ -$ -$ 424,967$ -$ -$
EIM HR Plan (Incremental Labor)-$ -$ -$ 2,255,219$ -$ -$ -$ -$ -$
Grand Totals 5,344,000$ 500,000$ 500,000$ 18,404,680$ 573,060$ 465,783$ 14,739,157$ 573,060$ 546,302$
$ 84,961
Closed Actuals (as of 09/2022)
$ 13,699
Scope Estimates (as of 08/2020)
2,987,491$
-$ -$ -$ $ 13,699 $ 84,961
Vendor Track 4 - EIM Software Projects
Charter Estimates (as of 05/2019)
Program Approval to Close

Program Close Summary Avista Confidential Page 11 of 26
6.4.1.1 EIM Software Projects – Capital Actuals Summary
Table 9 below represents EIM software capital projects Transferred to Plant (TTP) between January 2020 and March
2022, with total project costs associated with internal Avista labor (existing and incremental), Utilicast, software
vendors, and software hardware/licensing.

Table 9 – EIM Software Projects Capital Actuals as of September 2022

6.4.1.1.1 EIM Software Suite
The EIM software suite consisted of the applications purchased from PCI and Power Settlements. After
contract negotiations were complete in March 2020 (PCI) and May 2020 (PS), capital projects began in March
2020 (PCI) and in July 2020 (PS) in preparation for the first CAISO software testing milestone on July 15, 2021.

In the design phase for the EESC project, additional tagging software was needed to support EESC
settlements, which resulted in the purchase of Open Access Technology, Inc.’s (OATI) Tag Forwarding service
and PCI’s E-Tag Forwarding service. The OMS application was delivered into two phases: OMS Phase 1 to
support CAISO Reliability Coordination (RC) functionality, while OMS Phase 2 focused on functionality to
support market entry. Apart from OMS Phase 1, the EIM software suite applications transferred to plant in
March 2022 and completed at a total cost of $9.8 million.
6.4.1.1.2 Avista Decision Support System
Avista estimated $1 million in internal labor to perform the ADSS enhancements but did not include
estimates for professional services to develop the business logic functionality or data integration with other
EIM applications. The estimate was increased to $3.46 million in August 2020 to include updated labor
estimates, professional services, Utilicast costs and full integration costs. The ADSS delivery was separated
into two phases: ADSS Phase 1 supported the OMS Phase 1 project for CAISO Reliability Coordinator)
functionality, while ADSS Phase 2 focused on functionality required for market entry. ADSS Phase 1 and 2 is
completed at $4.0 million, $0.55 million over the Scope budget, with increased costs associated with
professional services for calculation logic and contracted non-labor.

In the event of a disaster rendering ADSS software unavailable from Mission Campus servers, Avista installed
a parallel version of the ADSS software and associated hardware in the San Jose Disaster Recovery
environment. This project was not planned in the Charter or the Scope Document and completed at $0.1
million.

TTP Date Labor Vendor Hardware /
Licenses Utilicast Total
PCI EESC Scheduling Mar-22 819,262$ 291,345$ 215,868$ 559,684$ 1,886,159$
PCI PRSC Bidding & Scheduling Mar-22 1,074,586$ 251,967$ 205,076$ 524,449$ 2,056,078$
PCI OMS (Gen / Trans) Phase 1 Jun-21 641,845$ 149,726$ 257,314$ 623,000$ 1,671,885$
PCI OMS (Gen / Trans) Phase 2 Mar-22 145,514$ 124,246$ 24,790$ 198,082$ 492,632$
PCI Energy Accounting Mar-22 698,360$ 253,857$ 204,002$ 377,210$ 1,533,429$
PS PRSC & EESC Settlement Mar-22 848,727$ 540,263$ 454,201$ 339,720$ 2,182,911$
4,228,294$ 1,611,404$ 1,361,251$ 2,622,145$ 9,823,094$
ADSS Phase 1 Jun-21 2,084,641$ 151,416$ 22,052$ 62,360$ 2,320,469$
ADSS Phase 2 Mar-22 1,133,914$ 72,800$ 78,752$ 362,607$ 1,648,073$
ADSS Disaster Recovery May-22 28,521$ -$ 68,040$ -$ 96,561$
Itron MV90xi Jan-20 228,262$ 13,247$ 196,659$ -$ 438,168$
Itron MV90xi Additional Licenses Nov-21 2,413$ -$ 20,730$ -$ 23,143$
CT/PT Accuracy Testing Apr-20 550$ -$ 10,454$ -$ 11,004$
VER Forecast Mar-22 323,905$ -$ -$ 54,740$ 378,645$
8,030,500$ 1,848,867$ 1,757,938$ 3,101,852$ 14,739,157$
Closed Actuals (as of 09/2022)
Grand Totals
EIM Software Suite Totals
Vendor Track 4 - EIM Software Projects
Program Approval to Close

Program Close Summary Avista Confidential Page 12 of 26
6.4.1.1.3 EIM MV90xi
Avista installed Itron’s MV90xi meter head-end system to collect interval meter data from generation and
substation interconnection sites for market submission. The project with Itron began in Q2 2019, transferred
to plant in January 2020 and completed at $0.44 million.
6.4.1.1.4 Current Transformer/Potential Transformer (CT/PT) Accuracy Testing
To support the transformer accuracy testing efforts at substation and generation locations, Avista purchased
software called “CT Analyzer” offered by Omicron. These costs were not planned in the Charter and the
actual software cost was $11k. This software supported metering research expense efforts shown in Table 10
and Table 12.
6.4.1.1.5 Variable Energy Resource (VER) Forecast
To forecast Variable Energy Resources (VER) generation output, Avista required a solution capable of a five-
minute generation forecast based on weather conditions for all VER generators in Avista’s Balancing
Authority Area (BAA). To satisfy this requirement, Avista expanded its existing forecasting agreement with
Vaisala for wind resources and contracted with CAISO to provide a solar generation forecast. The project
began in Q1 2021, transferred to plant in March 2022, and completed at $0.38 million.

6.4.1.2 EIM Software – Implementation Expense Actuals Summary
The software implementation expense covered cost associated with vendor-provided software training. This non-labor
incremental expense was planned at $0.57 million in the Scope Document and completed at $0.57 million.
6.4.1.3 EIM Software – On-Going Expense Estimate Summary
The on-going O&M expense associated with EIM software maintenance and service agreements was planned at $0.47
million in the Scope Document, while close actuals are planned at $0.55 million, with increases attributed to the EESC
tag forwarded services, MV90xi and the settlements software.
6.4.1.4 EIM Software – Annual Upgrades & Enhancements
The CAISO releases annual market enhancements which affect EIM software and may cause subsequent internal
integration changes. Avista has forecasted costs for annual upgrades and enhancements to expand capabilities and
increase efficiencies under the Energy Markets Modernization and Operational Efficiency Business Case at $500k
annually. These estimates are preliminary and will be refined as Avista gains operational market experience.

6.5 Track 5 – Metering & Settlements Delivery
6.5.1 Generation Production & Substation Support Delivery Summary
In 2018, Utilicast and Avista partnered to conduct a site-specific metering assessment to document Avista’s generation
metering and controls infrastructure, highlighting existing assets that were insufficient for EIM entry. Sites were divided
into two categories: market dispatch and non-dispatch, and very high-level cost estimates assigned.

Early in the first quarter of 2019, Generation Production & Substation Support (GPSS) refined these estimates based on
known participation decisions and market strategy information, however detailed site-specific scope was not yet
defined. In March 2019, GPSS completed their estimate updates, bringing the capital metering and controls costs to
approximately $5.07 million, as reflected in the EIM Program Charter document, and projects began in the summer of
2019. Throughout 2020, GPSS conducted Resource Participation Strategy Workshops by plant to finalize detailed project
scope at each generation site. As a result, some changes to project scope and cost estimates occurred. In August 2020,
GPSS updated its forecasted scope, schedule, and budget with an approved capital budget of $4.4 million, including
Utilicast support costs of $.06 million, and $0.28 million in implementation expense, as reflected in the October 2020
EIM Program Scope document.

Program Approval to Close

Program Close Summary Avista Confidential Page 13 of 26
By June of 2021, GPSS had transferred to plant nine capital metering and controls projects, and by December 2021 the
projects officially closed with a total capital investment of $4.22 million – approximately $0.24 million under the EIM
Program Scope Document approval. The Utilicast contribution to GPSS projects closed at $0.03 million, approximately
$0.04 million under Scope Document approvals. The total implementation expense charges closed at $0.24 million,
approximately $0.05 million under the Scope Document approvals.

Table 10 – GPSS Financial Comparison as of September 2022

6.5.1.1 GPSS Projects – Capital Actuals Summary
The below table represents GPSS EIM capital projects completed between summer 2019 and June 2021, with combined
Avista and Utilicast costs per location and project type.

Table 11 – GPSS Capital Actuals as of September 2022

6.5.1.1.1 High Side Meter Project Actuals
The High-Side Meter (HSM) projects installed SEL-735 meters on the substation-side of the Generation Step-
up Units (GSU) in accordance with Avista’s SEL-735 Combined (interchange and generation) Meter Setting
Standard. Under GPSS direction, Avista delivered HSM upgrades at Noxon Rapids Hydro Electric Dam (HED),
Cabinet George HED and the Rathdrum Combustion Turbine (CT), with a total cost of $1.71 million.
6.5.1.1.2 Low Side Meter Project Actuals
The Low-side meter (LSM) projects installed SEL-735 meters at plant-side of the GSU in accordance with
Avista’s SEL-735 Combined Meter Setting Standard. Under GPSS direction, Avista delivered LSM upgrades at
Long Lake HED, Nine Mile HED, Post Falls HED and Boulder Park CT, with a total cost of $1.20 million.
6.5.1.1.3 Programmable Logic Control Project Actuals
GPSS
Project Type Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
HSM $ 2,336,696 $ - $ - $ 2,137,536 $ - $ - $ 1,699,561 $ - $ -
PLC $ 2,131,353 $ - $ - $ 1,594,331 $ - $ - $ 1,286,691 $ - $ -
LSM $ 607,615 $ - $ - $ 663,490 $ - $ - $ 1,199,237 $ - $ -
LSM Reconfiguration $ - $ - $ - $ - $ 222,326 $ - $ - $ 173,362 $ -
Metering Research $ - $ - $ - $ - $ 62,250 $ - $ - $ 62,250 $ -
Totals $ 5,075,664 $ - $ - $ 4,395,356 $ 284,576 $ - $ 4,185,489 $ 235,612 $ -
Utilicast $ - $ - $ - $ 67,060 $ - $ - $ 32,639 $ - $ -
Grand Totals $ 5,075,664 $ - $ - $ 4,462,416 $ 284,576 $ - $ 4,218,128 $ 235,612 $ -
Charter Estimates (as of 05/2019)Closed Actuals (as of 09/2022)Scope Estimates (as of 08/2020)
Location Project Type Actual Capital Cost
Noxon HSM 443,614$
Cabinet Gorge HSM 572,724$
Rathdrum CT HSM 698,522$
1,714,860$
Boulder Park LSM 261,349$
Long Lake LSM 403,553$
Nine Mile LSM 205,713$
Post Falls LSM 339,095$
1,209,710$
Noxon PLC 730,061$
Cabinet Gorge PLC 563,497$
1,293,558$
4,218,128$
Subtotal
Subtotal
Total Capital
Subtotal
GPSS Capital - Final Closed Actuals
Program Approval to Close

Program Close Summary Avista Confidential Page 14 of 26
The Programmable Logic Control projects (PLC) installed an EIM PLC system to act as an interface point
between SCADA system, plant high-side meters, low-side meters and plant unit controllers, with an input
switch for EIM participation and non-EIM participation mode. Under GPSS direction, Avista delivered PLC
upgrades at Noxon Rapids HED and Cabinet George HED, with a total cost of $1.29 million.
6.5.1.2 GPSS Implementation Expense Projects – Expense Actuals Summary
The below table represents GPSS EIM implementation expense projects completed between spring 2019 and June 2021,
with combined Avista and Utilicast costs per location and project type. An estimated expense threshold of $10k was
established to track expense costs associated with an individual project. The LSM and HSM projects listed below were
conducted with existing Avista labor, while the metering research project was conducted with contracted labor.

Table 12 – GPSS Implementation Expense Actuals as of September 2022

6.5.1.2.1 Meter Reconfiguration Implementation Expense Actuals
At some generation sites, the unit and/or station service meters were already upgraded to SEL-735 meters as
part of a previous project. These low-side meters required reconfiguration in accordance with Avista’s most
current SEL-735 Combined Meter Setting Standard. No new assets were planned for installation; therefore,
the work was classified as expense. Under GPSS direction, Avista conducted low side meter reconfiguration
at Little Falls HED and Kettle Falls CT, with a total expense cost of $0.17 million.
6.5.1.2.2 Metering & Transformer Research Implementation Expense Actuals
At some generation locations, the accuracy of the equipment burden rating was unknown and correction
factors would need to be applied. To determine where a correction factor was needed, metering and
transformer research was required. No new assets were planned for installation; therefore, this work was
classified as expense. Under GPSS direction, Avista conducted metering and transformer research at various
hydro and thermal generation locations with a total expense cost of $0.06 million
6.5.2 Substation Interconnection & Third-Party Generation Delivery Summary
In 2018, Utilicast and Avista partnered to conduct a site-by-site metering assessment to document Avista’s substation
interchange and third-party generation metering, highlighting existing assets that were insufficient for EIM entry. Sites
were divided into two categories: meter replacement and meter reconfiguration, and very high-level cost estimates
were assigned. These costs were estimated in the EIM Program Charter at $0.85 million.

Early in the first quarter of 2019, design for Substation interconnection projects began, while additional outreach to
third-party generation owners was needed before capital projects could begin. Throughout 2019, additional planning
efforts resulted in scope changes at various locations, the removal of some upgrade locations based on existing non-EIM
funded projects, and the need for centralized, substation-led project management. The capital cost estimates were
updated in the October 2020 EIM Program Scope document at $1.85 million, including Utilicast support costs of $0.07
million, and $0.05 million in implementation expense.

By June of 2021, Avista transferred to plant 23 capital metering projects and by March 2022 all projects had closed with
a total capital investment of $2.11 million, approximately $0.26 million over the approved Scope Document approvals.
The Utilicast contribution to Substation projects closed at $0.04 million, approximately $0.03 million under the Scope
Location Project Type Actual Expense Cost
Little Falls LSM 76,078$
Kettle Falls LSM 97,284$
Hydro Metering Research 46,688$
Thermal Metering Research 3,113$
Steam Metering Research 12,450$
235,613$ Total Implementation Expense
GPSS Implementation Expense - Final Closed Actuals
Program Approval to Close

Program Close Summary Avista Confidential Page 15 of 26
Document approvals. The total implementation expense charges completed at $0.01 million, approximately $0.05
million under the Scope Document approvals.

Table 13 – Substation Interconnection & Third-Party Generation
Financial Comparison as of September 2022

6.5.2.1 Substation Interconnection & Third-Party Generation Projects – Actuals Summary
The below table represents Substation Interconnection and Third-Party Generation EIM capital projects completed
between first quarter 2019 and June 2021, with combined Avista and Utilicast costs per location and project type.

Table 14 – Substation Interconnection & Third-Party Generation
Capital Actuals as of September 2022

Track 5 - Substation
Project Type Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Substation Interchange
Meter Replace $ 610,200 $ - $ - $ 1,312,291 $ - $ - $ 1,416,634 $ - -$
Meter Reconfiguration $ - $ - $ - $ - $ 18,720 $ - $ - $ - -$
Third-Party Generation
Meter Replace $ 242,000 $ - $ - $ 315,515 $ - $ - $ 407,507 -$ -$
Meter Reconfiguration $ - $ - $ - $ - $ 36,100 $ - $ - $ 6,410 -$
AGC $ - $ - $ - $ 157,724 $ - $ - $ 259,162 -$ -$
Totals $ 852,200 $ - $ - $ 1,785,530 $ 54,820 $ - $ 2,083,303 6,410$ -$
Utilicast $ - $ - $ - $ 67,060 $ - $ - $ 35,539 -$ -$
Grand Totals $ 852,200 $ - $ - $ 1,852,590 $ 54,820 $ - $ 2,118,842 6,410$ -$
Charter Estimates (as of 2019)Scope Estimates (as of 08/2020)Closed Actuals (as of 09/2022)

Location Project Type Actual Capital Cost
Northeast Meter Replace 62,629$
Burke Meter Replace 133,792$
Sagle Meter Replace 34,935$
Priest River Meter Replace 50,160$
Loon Lake Meter Replace 43,142$
Noxon 13kV Meter Replace 53,009$
Milan Meter Replace 87,859$
Kettle Falls Meter Replace 133,921$
Dry Creek Meter Replace 131,958$
Lolo Meter Replace 121,684$
Wilbur Meter Replace 78,492$
Mead Meter Replace 125,398$
Stratford Meter Replace 94,200$
Warden Meter Replace 122,037$
Noxon 230kV Meter Replace 161,915$
POPUD Distribution Meter Replace 5,768$
POPUD Transmission Meter Replace 9,453$
1,450,352$
Location Project Type Actual Capital Cost
Fighting Creek Meter Replace 74,025$
Waste to Energy Meter Replace 88,036$
Plummer Saw Mill Meter Replace 80,276$
Upriver Meter Replace 87,775$
Palouse Wind Meter Replace 79,216$
Lancaster AGC 259,162$
668,490$
2,118,842$
Third-Party Generation Capital Subtotal
Substation Interconnection Capital - Final Closed Actuals
Third-Party Generation Capital - Final Closed Actuals
Substation Capital Subtotal
Total Capital
Program Approval to Close

Program Close Summary Avista Confidential Page 16 of 26
6.5.2.1.1 Meter Replacement Project Actuals
At some interconnection and third-party generation locations, meter replacement projects were planned to
install one or more SEL-735 meters in accordance with Avista’s most current SEL-735 Combined Meter Setting
Standard. At some locations, accompanying integration and security equipment was also planned for
installation. Under Substation direction, Avista delivered new meters at 17 substation interconnection
locations, with a total cost of $1.45 million and five third-party generation sites, including automated
generation controls (AGC) at Lancaster CT with a total cost of $0.67 million.

6.5.2.2 Implementation Expense Projects – Financial Actuals Summary
The below table represents Substation and Third-Party Generation EIM implementation expense projects completed
between spring 2019 and June 2021, with combined Avista and Utilicast costs per location and project type.

Table 15 – Substation Interconnection & Third-Party Generation
Implementation Expense Actuals as of September 2022

6.5.2.2.1 Meter Reconfiguration Project Actuals
At one third-party generation location, SEL-735 meters had been installed as part of a previous project. These
meters required reconfiguration in accordance with Avista’s most current SEL-735 Combined Meter Setting
Standard. No new assets were planned for installation and the work was classified as expense. Under
Substation direction, Avista conducted meter reconfiguration at the third-party generation site, Solar
Select/Lind Solar, with a total expense cost of $0.01 million.

6.5.3 Network Communications Delivery Summary
In 2018, Utilicast and Avista partnered to conduct site-specific network assessments to support the metering assessment
for generation and substation interconnection sites. At that time, every known generation controls and meter upgrade
project assumed a parallel capital network communications project to support asset implementation. It was also
assumed Avista would remove dial-up communications in favor of third-party Internet Provided (IP) communications.
Each location was assigned a network scope “package,” with the goal of implementing an economic reliable and secure
network path. Throughout the middle of 2019 and into 2020, network site surveys were conducted, and package
assignments were updated based on the scope for each location. By June of 2021, the Network Communications
delivery team had transferred to plant 21 EIM network projects with a total capital investment of $2.1 million –
approximately $0.5 million over the Program Scope Document approval. The Utilicast contribution to network projects
closed at $0.04 million, approximately $0.02 million under Scope Document approvals. No EIM implementation expense
charges were incurred under network communications delivery.

Location Project Type Actual Capital Cost
NA Meter Reconfig -$
-$
Location Project Type Actual Expense Cost
Solar Select/Lind Solar Meter Reconfiguration 6,410$
6,410$
6,410$
Substation Interconnection Implementation Expense - Final Closed Actuals
Substation Expense Subtotal
Third-Party Generation Implementation Expense - Final Closed Actuals
Third-Party Generation Expense Subtotal
Total Implementation Expense
Program Approval to Close

Program Close Summary Avista Confidential Page 17 of 26
Table 16 – Network Communications Financial Comparison as of September 2022

6.5.3.1 Network Communications Projects – Capital Actuals Summary
The below table represents Network Communications EIM capital projects completed between first quarter 2019 and
June 2021, with combined Avista and Utilicast costs per location and project type.

Table 17 – Network Communications Capital Actuals as of September 2022

Track 5 - Network
Project Type Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Package 1 $ 270,000 $ - $ 91,000 $ - $ - $ 1,000 $ 116,828 -$ -$
Package 2 $ 1,016,000 $ - $ 72,800 $ 457,200 $ - $ 18,200 $ 711,169 -$ -$
Package 3 $ 208,000 $ - $ 36,400 $ - $ - $ - $ - -$ -$
Package 4 $ 225,000 $ - $ 15,000 $ 323,255 $ - $ 15,100 $ 521,613 -$ -$
Package 5 $ - $ - $ - $ 751,796 $ - $ 35,200 $ 711,606 -$ -$
Package 6 $ - $ - $ - $ - $ 10,000 $ - $ - -$ -$
Network PM (Line 24) $ 416,000 $ - $ - $ - $ - $ - $ - -$ -$
Totals $ 2,135,000 $ - $ 215,200 $ 1,532,251 $ 10,000 $ 69,500 $ 2,061,216 -$ -$
Utilicast $ - $ - $ - $ 67,060 $ - $ 42,364 -$ -$
Grand Totals $ 2,135,000 $ - $ 215,200 $ 1,599,311 $ 10,000 $ 69,500 $ 2,103,580 -$ -$
Scope Estimates (as of 08/2020)Charter Estimates (as of 2019)Closed Actuals (as of 09/2022)
Location Project Type Actual Capital Cost
Lancaster Package 1 116,828$
116,828$
Burke Package 2 383,783$
Kettle Falls Package 2 340,345$
724,128$
Cabinet Gorge Package 4 79,259$
Long Lake Package 4 -$
Monroe Street Package 4 129,339$
Nine Mile Package 4 51,668$
Noxon Rapids Package 4 42,312$
Post Falls Package 4 50,133$
Upper Falls Package 4 -$
Noxon 13 kV Construction SubPackage 4 77,803$
Coyote Springs 2 Package 4 106,983$
537,497$
Deer Park Package 5 113,682$
Loon Lake Package 5 72,809$
Milan Package 5 84,701$
Priest River Package 5 134,296$
Wilbur Package 5 84,680$
Fighting Creek Package 5 51,592$
Plummer Saw MillPackage 5 31,991$
Spokane Waste to EnergyPackage 5 91,536$
Upriver Package 5 59,840$
725,127$
2,103,580$
Network Capital - Final Closed Actuals
Subtotal
Total Capital
Subtotal
Subtotal
Subtotal
Program Approval to Close

Program Close Summary Avista Confidential Page 18 of 26
6.5.3.1.1 Package 1 – Standard Substation Communication Package Actuals
This package was for locations that did not have IP communications. It included contracting IP services from a
third-party Local Exchange Carrier (LEC) and the installation of communication hardware. Under Network
Communications direction, Avista delivered package 1 to support Automated Generation Controls at
Lancaster CT with a completed cost of $0.12 million.
6.5.3.1.2 Package 2 – Standard Substation Communication Package + High Voltage Protection Actuals
This package assumed the base installation of Package 1 and equipment to protect against Ground Potential
Rise with High Voltage Protection (HVP). Under Network Communications direction, Avista delivered package
2 at two locations with a total cost of $0.72 million.
6.5.3.1.3 Package 3 – Standard Substation Communication Package + Modified HVP Actuals
This package assumed the installation of packages 1 & 2, with a modification for HVP at the Copper-Fiber
Junction Box. Network Communications did not deliver this package at any location.
6.5.3.1.4 Package 4 – Network Capacity Increase and Extension Package Actuals
This package was identified for generation facilities where IP communications already existed, and an
extension of the Local Area Network (LAN) was needed to provide connectivity to new meters. Under
Network Communications direction, Avista deliver package 4 at seven locations with a total cost of $0.54
million.
6.5.3.1.5 Package 5 – Commercial Cellular Communications Actuals
This package was identified where locations could support IP communications via a wireless cellular option.
Under Network Communications direction, Avista delivered package 5 at nine locations with a total cost of
$0.73 million.
6.5.3.2 Network Communications Projects – Implementation Expense Actuals Summary
Package six was identified for locations where IP communications existed, and network configurations were
required to support metering. No new asset was planned for installation and this work was classified as
implementation expense. Network Communications did not deliver any expense work.
6.5.3.3 Network Communications Projects – On-Going Expense Actuals Summary
Although on-going expense was estimated at $0.07 million, and actual charges have and will continue to be
incurred, it is not possible to track network expense costs by location or network service due to the structure of
service agreements and invoice details. As a result, the on-going network communication costs are not included
in the expense or incremental expense totals.

6.6 Track 6 – Operations Readiness & Training Delivery
6.6.1 Operations Readiness & Training Delivery Summary
Under this track, Avista primarily planned for the hiring of new employees to support market operations, and market
training for existing employees and new employees.

Table 18 – Operations Readiness & Training Financial Comparison as of September 2022

Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Training & OCM $ - $ 480,000 $ - $ - $ 480,000 $ - $ - 629,514$ $ -
EIM HR Plan $ 550,000 $ 185,000 $ 2,500,000 $ 2,255,219 $ 1,033,570 $ 3,177,467 $ 494,265 1,147,406$ $ 2,397,128
System Ops Desk - Mission $ 233,000 $ - $ 225,071 $ - $ 4,000 191,499$ $ - $ -
System Ops Desk - BuCC $ - $ - $ 86,000 $ - $ 4,000 81,663$ $ - $ -
Noxon 230kV CIP PSP $ - $ - $ 110,624 $ 10,000 $ - 238,226$ $ - $ -
Totals $ 783,000 $ 665,000 $ 2,500,000 $ 2,676,914 $ 1,523,570 $ 3,185,467 $ 1,005,653 $ 1,776,921 $ 2,397,128
Utilicast $ - $ - $ - $ - $ - $ - $ - -$ -$
Grand Totals $ 783,000 $ 665,000 $ 2,500,000 $ 2,676,914 $ 1,523,570 $ 3,185,467 $ 1,005,653 1,776,921$ 2,397,128$
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)Closed Actuals (as of 09/2022)
Track 6 - Operation Readiness & Training
Program Approval to Close

Program Close Summary Avista Confidential Page 19 of 26
6.6.1.1 EIM Training
Avista personnel completed the CAISO computer-based training, software training, workshops, train-the-
trainer workshops and training for the phased testing: Day in the Life, Market Simulation, Parallel Operations
and Go-Live initiation. In addition, Avista developed an internal certification plan for the EIM Operator.
Training is considered expense and was tracked by department. The training actuals were $0.63 million for
both existing and incremental employees (EIM HR Plan). See Table 24 – Total Incremental & Non-Incremental
Labor Actuals training costs by business unit for additional detail.
6.6.1.2 EIM Human Resource Plan
In June 2020, the EIM Human Resource Plan was signed by the Executive Steering Committee members,
approving 17 incremental EIM FTE hires throughout 2020-2022 in preparation for market operations. In August
2020, some hiring date changes were made, with further updates reflected in the October 2020 Scope
Document estimates.

In the plan, a financial estimate for the implementation and post-implementation costs were estimated, and all
roles assumed an incremental external hire. Each role was assigned an estimated hire date, an annual salary
(assumed 78.05% loaded rate) and a breakout of efforts between capital and O&M. These resources were
further assigned an estimated annual 3% annual merit increase, and where applicable, incremental step
increases based on achieving certain experience levels. This framework provided an estimate of annual capital
and O&M FTE costs across 2020-2023, with 2022 representing a shift to primarily O&M expenses based on a
market go-live date of March 2022 and 2023 representing a fully burdened O&M year.

Prior to job posting, each position was reviewed and approved by the steering committees. In addition to
normal recruitment complexities, hiring for EIM positions was also challenged by replacing roles vacated by
Avista retirements and the Covid-19 pandemic. For an EIM hire to be considered incremental, the role had to
meet one of the following criteria:
o A new employee hired into an EIM position.
o An existing employee is hired into an EIM position, and the previous position is backfilled (with an
external hire).

Avista did not account for partial positions (i.e., an employee working on EIM and non-EIM work). Based on
these criteria, 14 of the planned 17 were considered incremental employees. The incremental FTE costs
associated with the capital implementation are planned to close at $0.5 million, $1.8 million under the Scope
Document estimates. Implementation expense is estimated to complete at $1.1 million, $0.1 million over the
Scope Document estimates. Fewer incremental hires, hiring time variance and shifts to O&M contributed to
savings in capital. The on-going annual O&M incremental expense is estimated at $2.4 million, $0.78 million
under the Scope Document estimates.

Program Approval to Close

Program Close Summary Avista Confidential Page 20 of 26
Table 19 – EIM Human Resource FTE Comparison

6.6.1.3 Transmission System Operations EIM Desk Scope – Mission
To accommodate the EIM Operators, a new workstation was needed at Mission campus in System Operations.
This project delivered two new computers, a phone console, new monitors, ergonomic chairs, a projector, and
a screen for the Mission Campus. This project began in the first quarter 2020 and transferred to plant in March
2021, with a total cost of $0.20 million.
6.6.1.4 Transmission System Operations EIM Desk Scope – BuCC
To accommodate the EIM Operators at the Backup Control Center (BuCC), a new workstation was needed with
two new computers, new monitors, and a new phone console. This project began in third quarter 2020 and
transferred to plant in March 2021, with a total cost of $0.08 million.
6.6.1.5 Noxon 230kV Switchyard CIP PSP Project
As part of the metering and network upgrade projects at the Noxon Hydro Electric Dam (HED) and the Noxon
230kV Switchyard, external routable communications were introduced, thus classifying the Noxon 230kV
Switchyard as a Medium Impact BES Cyber System. Due to this new classification, additional infrastructure was
needed to remain compliant with all relevant Critical Infrastructure Protection (CIP) requirements. This project
began in Q1 2020 and transferred to plant in April 2021, with a total cost of $0.24 million.

Actual Hire Date
Quantity Hire Date
(mth/yr)Quantity Rev. Hire Date
(as of 08/2020)
Hire Date
(mth/yr)
Implementation Resources
EIM Program Manager 1 Jan-19 1 Jan-19 Feb-19
Org. Change Management Specialist 1 1 Sep-20 Oct-20
Substation Engineer 1 Jan-20
Total 2 3
Incremental EIM FTEs
Power Supply Analyst 1 Oct-20 1 Jul-21 Oct-21
Network Model Tech 1 Oct-20 1 Jun-20 Jun-20
SCADA Tech 1 Oct-20 0
EIM BA Desk Operator 1 Jul-21 1 Feb-20 Dec-20
EIM BA Desk Operator 1 Jul-21 1 Oct-20 Jan-21
EIM BA Desk Operator 1 Jul-21 1 Oct-20 Apr-21
EIM BA Desk Operator 1 Jul-21 1 Jan-21 Jul-21
EIM BA Desk Operator 1 Jul-21 1 Jan-21 Jun-20
EIM BA Desk Operator 0 1 Mar-22 Mar-22
Training Admin 0 1 Aug-22 Mar-22
EIM BA Analyst 0 1 Sep-21 Sep-21
Settlements Manager 0 1 Oct-20 Oct-20
Data Management Operator 1 Oct-20 1 Apr-21 Mar-21
Settlement Analyst 1 Apr-21 1 Apr-21 Apr-21
Settlement Analyst 0 1 Jun-21 May-21
Settlement Analyst 0 1 Aug-22 Nov-21
Compliance 0 or 1 Apr-21 0
IT Analyst 1 or 2 Oct-20 1 Oct-20 Jun-21
IT Analyst 0 1 Jan-21 Dec-21
Total 11 to 13 17
EIM FTE Estimates
Scope Estimates (as of 08/2020)Charter Estimates (as of 05/2019)
Program Approval to Close

Program Close Summary Avista Confidential Page 21 of 26
7 Program Implementation Costs
7.1 Total Program Costs
As of the Scope Document estimates, the total program costs (incremental and non-incremental) were estimated at
$32.1 million including contingency for capital and expense, with on-going O&M expense estimated at $3.9 million. As of
accounting period ending September 2022, the EIM program completed with total costs at $29.5 million, with $24.2
million in capital and $5.5 million in implementation expense (incremental and non-incremental). The annual O&M
expense associated with incremental EIM labor and software maintenance costs is estimated at $3.1 million, with annual
capital is estimated at $0.5 million.

Table 20 – Close Program Actuals as of September 2022

Table 21 – Scope Program Estimate as of August 2020

Table 22 – Charter Program Estimates as of May 2019

EIM Program Closed Actuals
(as of 09/2022) Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 24,131,373 $ 85,305 $ 24,216,678 $ - $ 500,000
Expense (existing & incremental) $ 5,382,967 $ 193,627 $ 5,576,594 $ 3,063,430 $ -
Total Costs $ 29,514,340 $ 278,932 $ 29,793,272 $ 3,063,430 $ 500,000
EIM Program Scope Estimates
(as of 08/2020)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 24,091,964 $ 2,600,000 $ 26,691,964 $ - $ 500,000
Expense (existing & incremental) $ 5,011,026 $ 400,000 $ 5,411,026 $ 3,907,100 $ -
Total Costs $ 29,102,990 $ 3,000,000 $ 32,102,990 $ 3,907,100 $ 500,000
EIM Program Charter Estimates
(as of 05/2019)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 18,969,000 $ 4,742,250 $ 23,711,250 $ - $0.0
Expense (existing & incremental) $ 2,380,000 $ 595,000 $ 2,975,000 $ 3,534,000 $0.0
Total Costs $ 21,349,000 $ 5,337,250 $ 26,686,250 $ 3,534,000 $0.0
Program Approval to Close

Program Close Summary Avista Confidential Page 22 of 26
7.2 Total Program Costs by Business Unit
Table 23 represents the total program costs by business unit as of September 2022. Capital charges are represented as
all Avista labor and non-labor charges, and all Utilicast non-labor charges by business unit. Expense charges are
represented as incremental and non-incremental with an allocation of corresponding Utilicast charges.

Table 23 – EIM Program Implementation Close Actual Costs
by Business Unit as of September 2022

7.3 Total Expense Labor Costs by Business Unit
Table 24 below identifies actual program implementation labor by business unit and separated by incremental labor
(EIM HR Plan) and non-incremental labor, including labor loadings. Tracking labor associated with the implementation,
and as documented in the totals below, ended February 28, 2022, prior to market entry to align with set pay periods.

Table 24 – Total Incremental & Non-Incremental Labor Close Actuals as of May 2022

Labor
Avista Utilicast Totals Avista Utilicast Other
ET Applications $ 7,997,169 $ 2,676,885 $ 10,674,054
ADSS $ 3,640,136 $ 424,967 $ 4,065,103
Facilities $ 273,162 $ - $ 273,162
Accounting, Legal, Rates $ - $ - $ -
ET Network $ 2,061,216 $ 42,364 $ 2,103,580 8,482$ -$ 8,482$
GPSS $ 4,185,489 $ 32,639 $ 4,218,128 399,652$ 88,523$ 488,174$
Substation $ 2,321,529 $ 35,539 $ 2,357,068 83,434$ 16,555$ 99,989$
Transmission $ 499,742 $ 25,841 $ 525,583 1,650,922$ -$ 1,650,922$
Power Supply $ - $ - $ - 687,742$ 328,247$ 1,015,989$
EIM Program $ - $ - $ - 1,216,486$ 24,769$ 1,241,255$
Totals $ 20,978,443 $ 3,238,235 $ 24,216,678 $ 3,518,849 1,216,486$ 841,259$ 5,576,594$
Grand Totals
Program Costs by Business Unit
Closed Actuals (as of 09/2022)
688,618$
Capital
$24,216,678
Implementation Expense
(existing & incremental)
Totals Non-Labor
383,166$ 1,071,783$
$5,576,594
Training Other Totals Training Other Totals
A&G Support (IS/IT, rates, legal, accounting, supply chain)52,042$ 289,048$ 341,090$ 15,358$ 332,170$ 347,527$ 688,618$
Transmission Operations 239,942$ 407,718$ 647,659$ 117,154$ 886,109$ 1,003,262$ 1,650,922$
Substation -$ -$ -$ -$ 83,434$ 83,434$ 83,434$
Power Supply 12,058$ 146,566$ 158,624$ 126,539$ 402,579$ 529,118$ 687,742$
GPSS -$ -$ -$ 66,215$ 333,437$ 399,652$ 399,652$
IT Network -$ 33$ 33$ 206$ 8,243$ 8,449$ 8,482$
Total 304,042$ 843,364$ 1,147,406$ 325,472$ 2,045,971$ 2,371,443$ 3,518,849$
Incremental Non-Incremental Grand Total
Actuals (as of 05/2022)Labor Expense by Department
(Existing & Incremental)
Program Approval to Close

Program Close Summary Avista Confidential Page 23 of 26
7.4 Total Incremental Non-Labor Expense Costs
As of accounting period ending September 2022, the EIM implementation program completed all financial transactions.
Table 25 below identifies actual incremental non-labor expense items.

Table 25 – Incremental Non-Labor Expense Close Actuals as of September 2022

7.5 Total Incremental Costs
As of accounting period ending September 2022, all EIM implementation transactions completed. Table 26 represents
total actual incremental implementation costs (capital and incremental expense) at $27.4 million and the anticipated on-
going total O&M costs at $3.1 million, with annual capital estimate of $0.5 million to support EIM software upgrades.
After a three-year implementation program, Avista successfully entered the WEIM one month ahead of the original
schedule on March 2, 2022, under the allocated budget and delivered the required scope for market operations – all
while navigating the challenges of the COVID-19 Pandemic.

Table 26 – Close Program Incremental Actuals as of September 2022

Table 27 – Scope Program Incremental Cost Estimates as of August 2020

Table 28 – Charter Program Incremental Cost Estimates as of May 2019

Non-Labor Expense Closed Actuals Detail
(as of 09/2022)Totals
Utilicast $ 1,216,486
CAISO Milestones $ 50,000
CAISO Grid Management Fee $ 216,281
Contractors - Substation Projects $ 16,555
Contractors - GPSS Projects $ 25,048
Market Based Rates Study $ 50,216
Metering Research/CTPT Testing $ 63,475
Contractors - ET Projects $ 30,798
Software Licensing Costs $ 298,992
Membership $ 11,750
Misc Gifts $ 4,861
Employee Meal, Travel, & Lodging $ 19,907
Vendor Software Training $ 53,376
Total Costs $ 2,057,745
EIM Program Closed Actuals
(as of 09/2022)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 24,131,373 $ 85,305 $ 24,216,678 $ - $ 500,000
Incremental Expense $ 3,062,980 $ 142,171 $ 3,205,151 $ 3,063,430 $ -
Total Costs $ 27,194,353 $ 227,476 $ 27,421,829 $ 3,063,430 $ 500,000
EIM Program Scope Estimates
(as of 08/2019)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 24,091,964 $ 2,600,000 $ 26,691,964 $ - $ 500,000
Incremental Expense $ 3,608,880 $ 400,000 $ 4,008,880 $ 3,907,100 $ -
Total Costs $ 27,700,844 $ 3,000,000 $ 30,700,844 $ 3,907,100 $ 500,000
EIM Program Charter Estimates
(as of 05/2019)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 18,129,000 $ 4,532,250 $ 22,661,250 $ - $0.0
Incremental Expense $ 1,465,000 $ - $ 1,465,000 $ 3,534,000 $0.0
Total Costs $ 19,594,000 $ 4,532,250 $ 24,126,250 $ 3,534,000 $0.0
Program Approval to Close

Program Close Summary Avista Confidential Page 24 of 26

Program Approval to Close

Program Close Summary Avista Confidential Page 25 of 26
8 Director Approvals

Approve EIM Program Close Document - Approvals by Nov. 11 - Kevin Holland - 11.22.2022
______________________________________________
Kevin Holland, Director of Power Supply

Approve EIM Program Close Document - Approvals by Nov. 11 - Alexis Alexander - 11.29.2022
_______________________________________________
Alexis Alexander, Director of Generation Production & Substation Support

Approve EIM Program Close Document - Approvals by Nov. 11 - Mike Magruder - 11.10.2022
_________________________________________
Mike Magruder, Director of System Operations & Planning

Approve EIM Program Close Document - Approvals by Nov. 11 - Jim Corder – 11.7.2022
____________________________________________
Jim Corder, Director of Information Technology & Security

Approve EIM Program Close Document - Approvals by Nov. 11 - Hossein Nikdel – 11.8.2022
___________________________________________
Hossein Nikdel, Director of Applications & System Planning

Approve EIM Program Close Document - Approvals by Nov. 11 - Clay Storey - 11.17.2022
_____________________________________________
Clay Storey, Director of Security

Approve EIM Program Close Document - Approvals by Nov. 11 - John Wilcox – 11.7.2022
_____________________________________________
John Wilcox, Director of Accounting

Approve EIM Program Close Document - Approvals by Nov. 11 - Adam Munson - 11.9.2022
_____________________________________________
Adam Munson, Director of Financial Planning & Analysis

Approve EIM Program Close Document - Approvals by Nov. 11 - Pat Ehrbar 11.7.2022
______________________________________________
Pat Ehrbar, Director of Regulatory Affairs
Program Approval to Close

Program Close Summary Avista Confidential Page 26 of 26

Approve EIM Program Close Document - Approvals by Nov. 11 - Todd Colton – 11.7.2022
______________________________________________
Todd Colton, Senior Legal Counsel
9 Executive Approvals

Approve EIM Program Close Document - Approvals by Nov. 17 - Heather Rosentrater - 11.14.2022
______________________________________________
Heather Rosentrater, Sr. VP of Energy Delivery

Approve EIM Program Close Document - Approvals by Nov. 17 - Jason Thackston - 11.22.2022
______________________________________________
Jason Thackston, Sr. VP of Energy Resources

Re EIM Program Close Document - Approvals by Nov. 17 - Kevin Christie - 11.11.2022
_____________________________________________
Kevin Christie, Sr. VP of External Affairs

Approve EIM Program Close Document - Approvals by Nov. 17 - Jim Kensok - 11.11.2022
__________________________________________
Jim Kensok, VP Chief Information & Security Officer

Approve EIM Program Close Document - Approvals by Nov. 17 - Ryan Krasselt - 11.23.2022
_____________________________________________
Ryan Krasselt, VP & Controller

Approve EIM Program Close Document - Approvals by Nov. 17 - Scott Kinney - 11.11.2022
_____________________________________________
Scott Kinney, VP of Energy Resources
ATTACHMENT B
ENERGY IMBALANCE MARKET
LIFE-TO-DATE (03/01/2023) CAPITAL INVESTMENT
Attachment B
Life To Date (03/01/2023 EIM Capital Investment
Sum of Actual Amount Year
Business Case ER_Description Svc.Jur 2020 2021 2022 Jan-Apr 2023 Grand Total
Energy Imbalance Market ER_7141 - Energy Imbalance Market CD.AA 571,908 1,390,077 25,837 1,987,822
ED.AN 2,226,135 8,631,139 10,809,523 21,666,797
ED.ID 34,284 205,025 239,310
ED.MT 53,009 53,009
ED.WA 305,679 2,811 308,491
ER_7141 - Energy Imbalance Market Total 2,832,327 10,584,930 10,838,171 24,255,428
Energy Imbalance Market Total 2,832,327 10,584,930 10,838,171 24,255,428 (1)
Energy Market Modernization & Operational Efficiency 485,829 17,919 503,748 (2)
Grand Total 2,832,327 10,584,930 11,324,000 17,919 24,759,175
(1) Energy Imbalance Market Investment to implement EIM at "go-live" 03.01.2022, plus trailing charges.
(2) Energy Market Modernization & Operational Efficiency project - annual additions related to the on-going annual capital investment needed to keep the EIM operational going forward.
ATTACHMENT C
ENERGY IMBALANCE MARKET
LIFE-TO-DATE (03/01/2023) EIM EXPENSES,
PRELIMINARY BENEFIT CALCULATION AND
NET REVENUES AND SALES
Attachment C
Life to date (3/1/2023) EIM Expenses, Preliminary Benefit Calculation and Net Revenues and Sales
Table No. 1 - O & M Expense Table No. 2 Preliminary Benefit Calculation
Year Month EIM Incremental O&M Year Month Preliminary Benefit Estimate
2022 March  NA 2022 March 1,804,150.00$
2022 April  NA 2022 April 1,934,303.00$
2022 May  NA 2022 May 1,421,074.00$
2022 June 257,367.00$ 2022 June 1,155,229.00$
2022 July 73,471.00$ 2022 July 745,971.00$
2022 August 74,681.00$ 2022 August 2,255,096.00$
2022 September 85,264.00$ 2022 September 3,799,470.00$
2022 October 83,009.00$ 2022 October 1,422,529.00$
2022 November 65,348.00$ 2022 November 2,228,826.00$
2022 December 54,278.00$ 2022 December 5,075,308.00$
2023 January 39,924.00$ 2023 January 2,396,977.00$
2023 February 49,912.00$ 2023 February 1,447,202.00$
Table No. 3 Net Revenue and Sales
Period Account Account Description PTD $Period Account Account Description PTD $
Mar-22 447740 SALE FOR RESALE - EIM (1,676,297)$ Mar-22 555740 PURCHASED POWER - EIM -$
Apr-22 447740 SALE FOR RESALE - EIM (1,519,257)$ Apr-22 555740 PURCHASED POWER - EIM 481$
May-22 447740 SALE FOR RESALE - EIM (906,081)$ May-22 555740 PURCHASED POWER - EIM 567,779$
Jun-22 447740 SALE FOR RESALE - EIM (1,454,402)$ Jun-22 555740 PURCHASED POWER - EIM 265,320$
Jul-22 447740 SALE FOR RESALE - EIM (1,115,537)$ Jul-22 555740 PURCHASED POWER - EIM 97,411$
Aug-22 447740 SALE FOR RESALE - EIM (84,192)$ Aug-22 555740 PURCHASED POWER - EIM 2,851,038$
Sep-22 447740 SALE FOR RESALE - EIM (1,583,409)$ Sep-22 555740 PURCHASED POWER - EIM 1,450,586$
Oct-22 447740 SALE FOR RESALE - EIM (667,012)$ Oct-22 555740 PURCHASED POWER - EIM 1,065,753$
Nov-22 447740 SALE FOR RESALE - EIM (1,487,145)$ Nov-22 555740 PURCHASED POWER - EIM 61,284$
Dec-22 447740 SALE FOR RESALE - EIM (1,302,373)$ Dec-22 555740 PURCHASED POWER - EIM 2,396,555$
Jan-23 447740 SALE FOR RESALE - EIM (1,449,798)$ Jan-23 555740 PURCHASED POWER - EIM 6,988,712$
Feb-23 447740 SALE FOR RESALE - EIM (1,525,010)$ Feb-23 555740 PURCHASED POWER - EIM (113,855)$
Mar-23 447740 SALE FOR RESALE - EIM (1,531,088)$ Mar-23 555740 PURCHASED POWER - EIM 1,463,726$

ATTACHMENT D
ENERGY IMBALANCE MARKET
AVISTA’S OCTOBER 11, 2022 BENEFIT COMPLIANCE REPORT
(PER CASE NO. AVU-E-22-11)

October 11, 2022

Commission Secretary
Idaho Public Utilities Commission
472 W. Washington St.
Boise, ID 83702

RE: Avista’s Annual Power Cost Adjustment (PCA)
Case No. AVU-E-22-11

Compliance Filing – Energy Imbalance Market (EIM) Benefit Methodology
Commission Order No. 35543 - Case No. AVU-E-22-11

Enclosed for electronic filing with the Commission is the Company’s Confidential EIM Benefit
Methodology Report, which explains the Company’s methodology for measuring EIM benefits,
and how that method differs from CAISO’s method, as required per Commission Order No.
35543.

The enclosed report is CONFIDENTIAL, rendering this document exempt from public
inspection, examination and copying pursuant to Sections 74-101 through 74-126 of the Idaho
Code. Avista believes that the identified CONFIDENTIAL document contains valuable
Company and third-party information.

If you have any questions regarding this filing, please contact Kaylene Schultz at (509) 495-
2482.

Sincerely,

/s/ Patrick Ehrbar

Patrick D. Ehrbar
Director of Regulatory Affairs

Enclosures
Avista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170

Via Electronic Mail

CONFIDENTIAL
AVISTA CORPORATION
STATE OF IDAHO
CASE NO. AVU-E-22-11
ANNUAL POWER COST ADJUSTMENT (PCA)
COMPLIANCE FILING
AVISTA’S ENERGY IMBLANCE MARKET (EIM) BENEFIT
METHODOLOGY

EIM Benefit Methodology

CONFIDENTIAL
Page 1 of 48
EIM Benefit Methodology

Copyright 2022, Avista
All rights reserved. Proprietary and confidential.
October 2022
Page 2 of 15

Table of Contents

Table of Contents
Document Version Control ................................................................................................................... 3
Document Sign Off ............................................................................................................................... 3
1.0 Introduction ............................................................................................................................. 4
2.0 Existing Methodologies Summary & Reference ......................................................................... 5
2.1 CAISO Benefit Methodology ......................................................................................................... 5
2.2 Power Settlement Benefits Methodology .................................................................................... 5
3.0 Avista’s EIM Benefit Methodology Overview ............................................................................ 6
4.0 Gap Analysis of CAISO’s EIM Benefit Methodology ................................................................... 7
4.1 Commitment Costs in EIM Are Not Included ................................................................................ 7
4.2 Benefits Not Adjusted for Third Party Loads and Generation ...................................................... 7
4.3 Discrepancy between Resource Bids and Actual Costs ................................................................ 7
4.4 Added Maintenance Cost driven by Increased Cycling ................................................................. 9
4.5 Incremental Cost of Donated Transmission by Avista Merchant ................................................. 9
4.6 Impact from Market Errors ........................................................................................................... 9
4.7 Other EIM Benefit Related Components .................................................................................... 10
4.8 Wind Contract Curtailment Cost ................................................................................................. 10
5.0 Avista’s EIM Benefit Methodology Details .............................................................................. 10
5.1 Part 1: Execute Initial Benefit Calculation ................................................................................... 10
5.2 Part 2: Validate Output, Adjust Input and Rerun as Necessary .................................................. 10
5.3 Add Components Excluded from CAISO Benefit Calculation ...................................................... 11
6.0 Future Methodology Considerations ....................................................................................... 13
6.1 Variable Energy Resource (VER) PMax (max generation of resource) Review ........................... 13
6.2 Commitment Cost Adjustments .................................................................................................. 14
6.3 FMM Settlements Value is not Considered ................................................................................ 14
6.4 Impact of BPA Rate of Change Constraints ................................................................................. 14
6.5 Third Party Loads and Generation is Included at BAA Level ....................................................... 14

CONFIDENTIAL
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Document Version Control

Version Date Author Comments
1.0 07/07/2022 Xin Shane This includes revised content from Xin Shane, Robert
Follini, Brandon Taylor, Brian Holmes (Utilicast), Russell
Miller (Utilicast)
2.0 07/27/2022 Xin Shane Reviewed and Edited by Clint Kalich

Document Sign Off

Person Role Signature Date
Xin Shane Manager, EIM Settlement & Analytics 10-06-2022
Robert Follini Manager, Power Trading 10-06-2022
Brandon Taylor Organized Market Manager 10-06-2002

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1.0 Introduction
Avista joined the Western Energy Imbalance Market (EIM) on March 2, 2022. Based on previous studies
by Energy and Environmental Economics (E3) and CAISO, Avista expects to realize multiple benefits
through EIM participation. This document details Avista’s approach to quantifying those benefits.
Avista’s EIM Benefit Methodology described within is based on CAISO’s EIM Benefit Methodology,
adjusted to more accurately quantify Avista’s EIM benefit. Previous entrants to the Western EIM have
utilized different techniques for calculating EIM Net Benefit, thus no standard has been established among
EIM entities. Beyond the CAISO EIM Benefit Methodology, Avista contracted with Energy and
Environmental Economics (E3) in the fall of 2017 to perform an exploratory EIM benefit analysis. Further,
Avista had multiple conversations with other western utilities who had previously joined the Western EIM.
This document is structured into the following sections:
1. Existing Methodologies Summary & Reference
2. Avista EIM Benefit Methodology Overview
3. Gap Analysis of CAISO's Benefits Methodology
4. Avista’s EIM Benefits Calculation Process
5. Future Methodology Consideration

Avista believes its EIM Benefit Methodology is aligned with the spirit of the broader CAISO EIM Benefit
Methodology and is generally congruent with other EIM entities’ methodologies.

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2.0 Existing Methodologies Summary & Reference
This section contains descriptions of some existing methodologies.
2.1 CAISO Benefit Methodology
CAISO publishes quarterly benefits for each EIM participant. Detailed calculations are described in the
Methodology document attached as Appendix A.
2.2 Power Settlement Benefits Methodology
Power Settlements has developed a methodology to shadow the CAISO’s EIM benefits. Detailed
calculations are described in the Methodology document attached as Confidential Appendix B.

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3.0 Avista’s EIM Benefit Methodology Overview
This section contains a description of the Methodology Avista will use to calculate EIM Benefits.
The CAISO EIM Benefit Methodology is relatively straightforward and intuitive. However, in its attempt to
create a single methodology for all EIM participants, certain components do not apply well to Avista and
some important components are excluded, leaving discrepancies. Discrepancy examples are provided
later in this document. Each can mask costs or over-state benefits. Nevertheless, this methodology is
widely known and thus serves as a starting point for Avista’s approach.
Avista built upon CAISO’s EIM Benefit Methodology by leveraging the vendor-supplied solution
“SettleCore,” allowing Avista to “shadow” CAISO daily settlement statements and validate for correctness
and completeness. Further, SettleCore provides “Shadow EIM Benefit” functionality, enabling Avista to
calculate potential benefits. Several other EIM entities also use the SettleCore module to evaluate their
expected Western EIM Benefits. Avista will continue evaluating its EIM Benefits Methodology and refine
it as improvements are identified.
The flow chart below summarizes Avista’s current EIM benefit calculation process, which will be further
detailed in section 5.0:

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4.0 Gap Analysis of CAISO’s EIM Benefit Methodology
Through discussions with other EIM entities and internal analyses, Avista has identified several areas for
which the CAISO EIM Benefits Methodology does not align well with Avista. A list of key divergences is
identified and addressed in this document. Some of the identified items are included in Avista’s EIM
Benefit Methodology scope, while others are excluded with justification. The in/out-of-scope decision is
based on the estimated magnitude of impact on EIM benefits, and the amount and availability of data.
4.1 Commitment Costs in EIM Are Not Included
The CAISO EIM Benefit calculation considers commitment costs for ISO BAAs (Balancing Authority Areas),
and not EIM BAAs like Avista. Thus, an EIM benefit calculation for Avista using CAISO’s methodology
incorrectly inflates or deflates benefits depending on the net load imbalance direction. SettleCore, from
Avista’s chosen vendor, also does not consider Avista’s commitment costs.
4.2 Benefits Not Adjusted for Third Party Loads and Generation
The Avista BAA includes Avista load and 3rd party loads served by Avista under contract, including those
of the Bonneville Power Administration (BPA). CAISO’s methodology incorrectly attributes benefits and
costs accruing to all loads to the Avista BAA.
Depending on the time of year, BPA loads alone can represent roughly 15% of the total Avista BAA load.
Any benefits methodology should pass load-related charges to the 3rd party load. Therefore, any EIM
benefit estimate associated should accrue reductions in the cost of serving BPA and other 3rd party loads
to those loads, not Avista.
Non-BPA 3rd party load served by the Avista’s merchant function under contracts includes Pend Oreille
PUD, Clearwater, Inland Paper and Kaiser. The EIM charge/payment associated with these contracts is
currently absorbed by Avista, but going forward it is reasonable to assume that contracts may be
modified to reflect best efforts to transfer these impacts to the 3rd party. As long as the contract follows
the contracting price, and not binding with EIM terms, this is not a relevant item to consider for Avista’s
EIM Benefit calculation.
4.3 Discrepancy between Resource Bids and Actual Costs
The CAISO’s EIM Benefit Methodology assumes that incremental Energy Bids, including mitigated
Incremental Energy Bids, represent an entity’s true cost structure. There are several reasons that this
may not be true.
1. Incremental costs are represented in ways other than in the incremental Energy Bid (e.g.,
Startup or Minimum Load Bids). This is highlighted in Section 4.1.
2. Mitigated Incremental Energy Bids can understate Avista’s true costs, including opportunity
costs.
3. Resource-related dispatch limitations require bids be placed strategically. Some further
details around bidding costs other than true opportunity are detailed in Section 4.3.1

4.3.1 Equipment Limitations Preventing Dispatch to Market
The EIM market design cannot represent certain capabilities and constraints of Avista’s generation fleet.
Avista has spent a great deal of time determining how to represent its capabilities, costs and constraints
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to EIM to ensure the best operational and financial outcomes in its marketplace. However, some
techniques used result in inflated benefits within the relatively simplistic CAISO counter-factual dispatch.
An example scenario is benefits being erroneously credited to Avista for the commitment of either its
Colstrip or Kettle Falls Biomass plants. Avista’s modified methodology identifies these CAISO-assigned
benefits and deduct them as appropriate. This section explains this risk.
Avista is a joint owner of Colstrip units 3 and 4. Avista has the rights to dispatch this plant on a 15-minute
basis with 20 minutes notice. However, the Colstrip plant is not capable of responding to CAISO’s 5-minute
market instructions. Thus, should Avista need to bid Colstrip in support of its Flexible Ramping Sufficiency
or Bid Range Capacity tests, Avista would likely do so at a higher cost to avoid 5-minute dispatch
instructions. Even with this bidding strategy, should the Avista EIM benefits counter-factual analysis
dispatch Colstrip, while in reality CAISO did not, CAISO’s benefit calculation would incorrectly attribute
the benefit of the avoidance of commitment costs when in fact we did not avoid a commitment.
Erroneous benefits can also arise within the Flexible Ramping Sufficiency Test itself. Avista must
demonstrate adequate capacity and flexibility via this test, and the Capacity Resource Sufficiency Test,
each hour – which Avista does via its bids. In situations where Avista needs to count Colstrip flexibility or
capacity, Avista may bid Colstrip at an inflated bid price (e.g., $100 instead of the cost, which we can
assume to be $25 in this example) because Avista will be unable to comply with market dispatches on a
5-minute basis and would need to ensure its bid would contain enough revenue to offset CAISO penalties
associated with Colstrip’s inability to follow 5-minute dispatch direction.
To the extent the CAISO EIM Benefits counter-factual dispatched Colstrip, while the actual market solution
did not, it would appear EIM provided benefits. However, no benefit is received. Pre-EIM operations, if
Avista had been short and needed to dispatch Colstrip intra-hour, it would do so at the dispatch cost. As
a result, any apparent EIM benefit for Colstrip is due to limitations around: the Colstrip plant, EIM, and
the CAISO EIM Benefit counter-factual, and thus do not represent reduced operational costs to Avista.
The same conditions exist for the Kettle Falls biomass and Northeast plants.
4.3.2 Fossil Use Limits
Two Avista plants have use limits as a function of their air permits – the duct burners at the Lancaster
plant, and the Northeast CT. At Lancaster, the limit applies on an annual basis; at Northeast CT the limit is
daily. The EIM solution horizon is just 4.5 hours, much shorter than both permit limits, and so these limits
cannot be accommodated by the market directly and must be accounted for through our bidding strategy.
Should Avista need to bid in either resource in support of the Flexible Ramping Sufficiency Test or the Bid
Range Capacity Test, Avista must do so at bid prices above our short-term costs to account for any
penalties incurred when we are unable to meet EIM-directed dispatch levels due to these limitations. Any
CAISO EIM benefit counter-factual based on these higher bid curves would result in over-stated benefits.
4.3.3 Hydro Use Limits
Avista owns a significant number of hydro resources, and they play a key role in daily EIM operations.
CAISO’s EIM market was designed around thermal plant operations, not hydro. Their operational
flexibility and limits cannot be represented in the EIM and so our bids must reflect the risks of EIM
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dispatch directions violating our capabilities. These bids can differ from our actual generation price,
causing the CAISO EIM benefit calculation to overstate benefits.
4.4 Added Maintenance Cost driven by Increased Cycling
Avista has a respectable amount of ramping capability within its fleet, which is called upon by EIM at
various times throughout the day. This leads to more resource movement than Avista has historically
experienced. Like its peers, Avista has noticed a significant increase in resource movement. This
movement leads to increased maintenance costs. Avista requires more time to better estimate these
potential increases in maintenance cost and include them in its bidding strategies.
4.5 Incremental Cost of Donated Transmission by Avista Merchant
The costs related to Avista EIM-donated transmission reduces our benefit and should reduce
CAISO/SettleCore benefit calculations. Two categories are associated with donated transmission:
• Lost transmission revenues: This requires the identification of the transfer enabled by the
redirect, and the estimated value of selling that amount of transmission.
• New transmission purchases specifically used to enable EIM Transfers: identify the amount of the
purchase intended for EIM vs. Non-EIM.
4.6 Impact from Market Errors
The EIM relies on input models and data to calculate its market solution. These inputs are numerous and
complex. Avista has noticed multiple instances where one or more modeling or data input were incorrect
and expects this behavior to continue in the future. As a result of these issues, market dispatches, ETSR
(Energy Transfer System Resource) transfers, and LMPs (Locational Marginal Prices) are not always an
accurate representation of what EIM participants’ costs would have been absent EIM. In some cases,
Avista may be able to successfully argue for a modification through a settlement dispute, or CAISO may
perform a price correction. In many cases, CAISO is unwilling or unable to make a correction.
In one recent example of a utility that joined in 2021, CAISO incorrectly modeled a linkage between a
generator and a dynamic export. The result was a false shortage of hundreds of MWs for several hours in
the BAA. The EIM market solution backfilled this apparent shortage, creating operational issues and
significant charges for the affected utility. CAISO was unable or unwilling to correct this issue because
other entities relied on the same market solution and provided energy incorrectly as identified by the EIM
solution. This was a significant loss for the entity not correctly reflected in CAISO’s EIM benefit calculation.
In another example, a May 2022 CAISO price correction had a direct negative financial impact on Avista.
We followed CAISO dispatch, leading to profitable operation of Avista resources. However, a CAISO price
correction later expunged those profits, creating significant lost opportunity costs having a direct impact
on Avista’s financial performance. This impact was not accounted for in CAISO’s EIM benefit calculation.
Unfortunately, modeling and data errors oftentimes are undetected. However, to the extent Avista can
identify the errors with its modified benefits calculation, we will ensure accurate accounting. The market
error identification process will evolve over time. Avista’s merchant group will leverage the recurring
CAISO market quality call and CAISO EIM Market Analysis report to identify market errors daily. A log will
be kept, and further analysis of the impact from market errors will be conducted between the merchant
and settlement group.
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4.7 Other EIM Benefit Related Components
While Avista earns greenhouse gas (GHG) payments from market participation, it is critical that Avista has
enough credits to meet its GHG compliance requirements. Any costs of GHG credit purchases will offset
benefits assumed in the CAISO EIM calculation.
4.8 Wind Contract Curtailment Cost
Avista wind resources are all controlled through contract; we do not own any wind resources directly.
When wind generation is curtailed, Avista must pay the resource owner the curtailed energy. If the
curtailment is directly caused by EIM market dispatch, the associated cost will be considered as an offset
component of the EIM benefit calculation. It is not considered by the CAISO EIM benefits methodology.
Avista expects other items impacting the benefit calculation are yet to be discovered. We will continue
monitoring for these impactors.

5.0 Avista’s EIM Benefit Methodology Details
Avista’s EIM Benefit Methodology is a three-part process developed to address findings in the Gap
Analysis of CAISO’s EIM Benefit Methodology. Avista executes this process monthly.
5.1 Part 1: Execute Initial Benefit Calculation
The initial execution of the shadow benefit calculation uses the SettleCore software and CAISO inputs.
Avista expects to receive CAISO’s benefit calculation output file three weeks after the trading month ends.
5.2 Part 2: Validate Output, Adjust Input and Rerun as Necessary
After the initial shadow benefit calculation runs, Avista receives the CAISO and SettleCore benefit
calculation files and a thorough review and validation can be conducted. During review, the SettleCore
shadow benefits calculation is rerun with any identified input adjustments, mainly resource bids.
5.2.1 CAISO Discrepancies
Avista’s settlement team reviews and compares CAISO Benefit calculation output with the SettleCore
Benefit calculation output, as this comparison forms the basis for Avista’s methodology. Typical review
areas include:

• Total benefit value.
• EIM transfer revenue.
• EIM dispatch cost.
• Counterfactual dispatch cost.
• GHG Revenue.
• GHG transfer revenue.
• Flex transfer revenue.

Avista applies the following thresholds to determine whether a further investigation is warranted:

a) Discrepancy in percentage of total CAISO Benefit value for the month > 2.5%
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b) Absolute value of discrepancy for the month > $100,000

If these thresholds are not met, no further adjustments or analyses are completed.
5.2.2 Cost Curve Adjustment
Most bids submitted to the EIM deviate from actual costs, for reasons described in Section 4.3. Avista will
address this by overwriting bids sourced from the CAISO SIBR (Scheduling Infrastructure & Business Rules)
with a value more closely reflecting its actual operating costs. The specific resources for which this applies
to are:
• Colstrip
• Kettle Falls Steam Turbine
• Northeast Combustion Turbine
• Long Lake (Ambient Rerate/derate)
• Little Falls (Ambient Rerate/derate)
• Boulder Park (Ambient Rerate/derate)
• Lancaster
• Noxon Rapids
• Cabinet Gorge
• Mid-C Contracted

Process:
1. Use Avista Merchant logs or other communications to identify where bids deviated from
opportunity cost.
2. In an internal workshop format or email communication, Avista Merchant and Settlement groups
review effective bid costs to confirm if any input adjustments are needed (Avista expects a more
systematic approach to be established, after the process is executed multiple times. As various
entities use a different price basis for adjustments, so too will Avista establish its own basis based
on accumulated EIM business expertise).
3. If an adjustment is necessary, Avista updates inputs for a potential rerun of the shadow benefit
calculation.
5.3 Add Components Excluded from CAISO Benefit Calculation
Once a review has established confidence in the shadow benefit calculation, a simple
addition/subtraction calculation is performed to include costs or benefits not addressed in the CAISO
Benefit Methodology.
5.3.1 Increased Cycling Maintenance Costs
Avista needs adequate time participating in EIM to evaluate the effect of increased cycling on the
maintenance requirements for the Avista generation fleet, so this cost component will likely affect the
EIM benefit in 2023. Therefore, a process is defined and will be further developed through practice over
time. The method includes detailed monitoring and inputs from the GPSS group and calculations
performed by the merchant group.
Avista has implemented a standard method of tracking cycling data, where a consistent interpretation of
data is enforced:
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• Mileage: MW “distance” that the unit ramps. It is calculated by comparing the metered actual
every 5 minutes to the metered actual in the prior 5 minutes. The MW value is calculated when
that difference is greater than 1 MW in an absolute value sense. These values are summed over
the period, which, at least initially, is monthly.
• ON/OFF: Measurement of breaker operations when generating plants are being cycled online
and offline.
The data is summarized in EIM Gen Mileage report in PI data system, and below is an example
screenshot

Due to the level of effort the evaluation process requires, Avista will likely evaluate increased cycling
maintenance costs on an annual basis to determine if adequate data exists to use in its EIM benefit
calculations.
5.3.2 Donated Transmission Incremental Costs
The Avista Merchant periodically has residual transmission from day-ahead and real-time market
optimization activities. After these markets close, the unused transmission typically has zero terminal
value. With Avista's entrance to EIM, Avista plans to donate this transmission to the EIM to benefit Avista's
load and marketing at zero cost. However, there may also be instances (due to transmission constraints
or optimization opportunities in the region) where Avista would allocate transmission earlier in the
optimization cycle to EIM.
To account for these activities, Avista has created an EIM Transmission Cost Book in their ETRM (Energy
Trading Risk Management) system to capture these types of donations and transfer any costs the
Merchant incurs to this book. Avista's Merchant will calculate the value of the quarterly early optimization
cycle transmission donations and provide them to the Avista staff preparing the Avista EIM Benefits
Report. In addition, Avista staff will note in the quarterly process log the values of any donated
transmission. These values will then be appropriately removed from the Avista EIM Benefit calculation.
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5.3.3 Market Error Corrections
“One-off” CAISO errors can impact Avista benefits. Where Avista identifies significant one-off errors by
CAISO, we will apply corrections to the benefits calculation.
We will use at least two general avenues to identify these market errors:
• From an operations perspective, Avista Merchant group will report market errors.
• From a settlement perspective, a valid CAISO dispute that isn’t financially resolved will be a
source of record for the benefit adjustment.

When a significant market error is identified, a thorough financial analysis will be conducted. Any
financial impact from market errors will be deducted in the final benefit calculation. May 2022 CAISO
price correction financial impact analysis will be an excellent example to demonstrate this process.
5.3.4 GHG Offset Purchase Cost
The monthly GHG offset cost will be provided by Avista Merchant group. Avista’s GHG analysis will
leverage a standard report in the PRSC (Participating Resource Schedule Coordinator) application.
5.3.5 Wind Curtailment Cost
Compensable curtailed energy charges will be reviewed monthly, upon receipt of Clearway invoices. The
amount associated with the compensable curtailed energy will be directly deducted from the final
benefit.

6.0 Future Methodology Considerations
Avista will continue refining its EIM Benefit methodology, identifying opportunities to further improve
the accuracy of its EIM benefit calculation. As a new entrant, we will be on a steep learning curve for
some time. With limited experience in the market, the focus required on the daily EIM operations limits
the scope of consideration in our initial EIM Benefit methodology. Below are some opportunities
identified for future consideration.
6.1 Variable Energy Resource (VER) PMax (max generation of resource) Review
Avista has preliminarily identified discrepancies between its VER (Variable Energy Resource) PMax in CMRI
(Customer Market Result Interface) and the ADS (Automatic Dispatch System) Dispatch report, due to a
data gap caused by data granularity issues in the CAISO VER forecast report. This leads to a potential
inaccurate benefits calculation when a VER resource is involved in the counter factual dispatch run at the
time interval. To accurately estimate this impact, and properly factor the effect in our benefit calculation,
a large data analysis effort is required. The proposed process will consist of: (1) performing a data gap
analysis, and (2) taking one of the following actions, should an adjustment be required:
• Adjust inputs for the rerun of the Shadow benefit calculation. This approach will require vendor
engagement and support, and we have not engaged in a conversation with the vendor on this
topic yet.
• Post process SettleCore Benefit Calculation output file to calculate the over-estimated benefit
portion. This approach will require a complex data model to be built.
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6.2 Commitment Cost Adjustments
As shared earlier in this document, the CAISO Benefit Methodology doesn’t consider unit commitment
cost, negatively impacting EIM dispatch cost and the counter factual dispatch cost calculation. Two areas
should be analyzed:
• CAISO’s ISO Commitment Cost Report captures start-up costs, minimum load costs, multi-stage
generation transition costs, and shut down costs for market committed resources. This report
can potentially be used to quantify the commitment cost that needs to be added to the EIM
dispatch cost. Start-up costs are straightforward to calculate, yet complications are expected
with the minimum load cost associated with the market-committed resource.
• An approach considering commitment cost in the counter factual cost calculation likely will be
done by post processing with the SettleCore shadow benefit run output file, with a calculation
model yet to be built.
6.3 FMM Settlements Value is not Considered
When EIM dispatch and counter factual dispatch costs are calculated, only RTD dispatch is considered.
The impact from RTPD dispatch is unknown but might negatively impact benefit calculations.
6.4 Impact of BPA Rate of Change Constraints
Avista relies on the BPA transmission system to move Mid-C generation and Coyote Springs generation
across BPA and to Avista’s BAA. There are many constraints associated with this transmission. Some of
these are reflected through a set of “rate of change constraints”. These constraints limit the change in
the dispatch between the FMM solution and the RTD solution. When these constraints are binding, they
will impact the LMPs that Avista pays and receives.
In current pre-EIM operations, Avista has certain contractual rights and obligations but is not directly
subject to financial impacts from the Rate of Change Constraints. Avista is attempting to learn more
about these constraints and how they will impact benefits achieved from EIM v. current operations, if at
all.
6.5 Third Party Loads and Generation is Included at BAA Level
As mentioned previously, BPA can account for up to roughly 15% of the AVA BAA load during specific
periods. Non-BPA loads also affect the calculations. This could impact Avista’s EIM Benefits calculation.
Options have been identified to quantify the BPA portion in the EIM benefit calculation number
produced by the SettleCore Shadow Benefit Calculation.
Option 1: Assume that a load-ratio share of the benefits is accruing to BPA. In this approach, Avista
would take the Adjusted EIM Benefits and pro-rate them based on a load ratio share. This would likely
be derived from the hourly Load Meters used in sub-allocations. The primary value of this approach is
simplicity. However, a significant drawback is that generation profits and fuel savings primarily accrue to
Avista. BPA would only benefit from reduced costs to serve its imbalance around its hourly schedule.
This method likely will understate Avista benefits.
Option 2: Evaluate BPA cost of imbalance directly using the LMP from the market and from the counter-
factual analysis. This approach would use the imbalance directly from sub-allocations multiplied by the
price differential and then deducted from the Adjusted EIM Benefits and provide a much better
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estimate of BPA benefits. However, it is unclear if counter factual LMP data will be available to support
this option; and, if so, if and how it can be normalized to the hourly LMP that BPA pays.
At this point, critical data availability will impede the analysis of a reasonable ratio assumption to net
out the BPA portion of the benefit. Therefore, further learning and investigation are required to
evaluate this component.

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AVISTA CORPORATION

STATE OF IDAHO
CASE NO. AVU-E-22-11
ANNUAL POWER COST ADJUSTMENT (PCA)

COMPLIANCE FILING

APPENDIX A

EIM QUARTERLY BENEFIT REPORT METHODOLOGY

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1
EIM Quarterly Benefit Report Methodology
Effective with Q1 2021 EIM benefits report
Prior to the creation of this document, the methodology for the benefits calculation was posted
in a technical bulletin and in the benefit report itself. This document consolidates these prior
materials into a concise paper for easier understanding of how the EIM benefits are calculated.
The total EIM benefit is the cost saving of the EIM dispatch compared with a counterfactual (CF)
without EIM dispatch. The counterfactual dispatch meets the same amount of real-time load
imbalance in each BAA without EIM transfers between neighboring EIM BAAs. For an EIM BAA,
the benefit can take the form of cost savings or profit or their combination. A BAA will be likely to
have energy cost savings when the BAA is importing energy economically, or its base
schedules are being optimized by the EIM. To the extent an entity base schedule is optimized
prior its submission into the EIM, the benefits may be lessened when compared to an entity that
has not submitted optimized base schedules into the EIM. A BAA will be likely to have an
energy profit when the BAA is exporting energy economically to other BAAs and being paid a
price higher than the bid cost. A BAA other than the ISO may also have a GHG profit when the
resource is allocated GHG MWs and is receiving GHG revenue based on marginal GHG cost
that is likely higher than its own GHG bid cost.
For each 5-minute interval, the EIM benefit for a BAA = counterfactual dispatch cost – (EIM
dispatch cost + transfer cost + flex ramp transfer cost) + GHG revenue – GHG cost. The
5-minute level EIM benefits are then aggregated each month with a multiplier 1/12 to convert
($/5 min) to a dollar amount.
EIM Benefit Calculation Components
EIM Dispatch Cost
The total dispatch cost for a BAA for an interval is the sum of all the unit level EIM dispatch
costs for that BAA for that interval.
For all BAAs other than CAISO, the dispatch cost only includes variable dispatch cost, i.e. the
bids submitted by the corresponding Scheduling Coordinator.
For the ISO’s long start units, we only consider variable dispatch cost. For the ISO’s short start
units, we use a generic cost formula, which includes variable dispatch cost, no load cost, and
startup cost. Specifically, the three-part cost for short start units includes:
 The variable dispatch cost of RTD, which is equal to the bid cost associated with the
delta instruction above or below the base schedule for each interval,
 the no load cost associated with the incremental dispatch, which is equal to the no load
cost divided by Pmax, then multiplied by the delta instruction from the base schedule,
 The startup cost associated with the incremental dispatch, which is equal to the startup
cost divided by the minimum online hours, then multiplied by the delta instruction from
base schedule divided by the Pmax.
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2

The purpose of this generic cost formula is to evaluate cost differences between EIM dispatches
and counterfactual dispatches without performing sophisticated unit commitment simulations.
Prior to Q1 2016, only variable dispatch cost was considered in the EIM benefit calculation. With
NV Energy joining EIM and improving the transfer capabilities from and to the ISO, we observed
a significantly increased transfer volume in EIM. The higher transfer volume cannot be
sufficiently replaced by resources online in EIM without committing or de-committing resources,
and hence the ISO adopted a three-part cost formula as of Q1 2016 to allow for unit
commitment decisions to better evaluate the production difference between EIM and the
counterfactual dispatch of the ISO. The unit commitment decisions were made only for short
start units that were not combined cycle units. The combined cycle units have complicated
models in EIM, so their counterfactual commitment status is fixed at the EIM commitment status
to avoid oversimplification.
We approximate the ISO’s commitment costs by converting the startup cost and no load cost
into variable dispatch cost, assuming a committed short start resource will be fully loaded for
minimum online hours. For each supply segment, the corresponding three-part variable cost is
equal to
bid_price + no_load_cost/Pmax + startup_cost/min_up_hour/Pmax
Note the formula above converts startup cost (in unit $) and no load cost (in unit $/h) into
variable dispatch cost (in unit $/MWh). By doing this, the commitment for the ISO’s short start
units can be determined based on the economic metric order of the three-part variable cost.
Transfer Cost
As a convention, select the importing direction as the default direction for a transfer, so the
importing transfer is positive and the exporting transfer is negative. The transfer cost is equal to
the transfer MW times the transfer price. For transfers involving the ISO in either the importing
direction or the exporting direction, the transfer price is the other BAA’s LMP plus the shadow
price of the transfer. In doing this, the congestion rent on the transfer will be fully attributed to
the other BAA. For transfers involving two BAAs that are not the ISO, the transfer price will split
the congestion shadow price on the transfer in half. For an importing BAA, the transfer price is
the LMP of the BAA minus half of the absolute value of the transfer shadow price. For an
exporting BAA, the transfer price is the LMP of the BAA plus half of the absolute value of the
transfer shadow price. The transfer could occur in both the 15-minute market and the 5-minute
market. In this case, the transfer cost is 15-minute transfer * 15-minute transfer price + (5-
minute transfer – 15-minute transfer) * 5-minute transfer price for each 5-minute interval.
For the prices (LMPs) used in the EIM benefits, the calculation uses the corresponding ELAP
prices of each EIM area. For CAISO prices, the calculation uses the prices associated at the
corresponding scheduling points at the Malin, Palo Verde, El Dorado or Rancho Seco interties.
The specific scheduling price to be used among these intertie locations is in relationship to the
benefit calculated to a specific EIM area. For instance, when calculating the benefits between
PAC West and CAISO, the calculation will use Malin scheduling point price (CAISO side).
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Flex Ramp Transfer Cost
In 2016, the ISO implemented the flexible ramping products to replace flexible ramping
constraints. The flexible ramping products are available capacities to handle future load and
generation uncertainties, and include both the upward ramping capacity and downward ramping
capacity. They may be put aside in RTD to enhance dispatch flexibility. One BAA’s flexible
ramping capacities in RTD may be helping other BAAs. In this case, the BAA that exports
flexible ramping products should receive payment from other BAAs to compensate the dispatch
cost of keeping flexible ramping capacities, and the BAA that imports flexible ramping products
should pay other BAAs to reflect its dispatch cost to handle future uncertainties. This is similar
to how energy transfer is treated in the EIM benefit calculation. Energy transfer is explicitly
modeled in EIM, while flexible ramping transfer is not. We need to calculate a BAA’s flexible
ramping transfer. First, we allocate the system flex ramp award to each BAA in proportion to its
individual BAA requirement. Then we calculate the flex ramp transfer as the BAA’s RTD flexible
ramping award minus its allocated share. The flex ramp transfer cost is equal to the flex ramp
transfer multiplied by the EIM whole footprint flex ramp shadow price.
Counterfactual Dispatch Cost
The counterfactual dispatch for an EIM BAA mimics the market operations without importing or
exporting through the EIM transfers. The counterfactual dispatch moves units inside the BAA to
meet the same real-time load imbalance as the EIM dispatch based on economic merit order
without considering transmission constraints. For PacifiCorp, the transfer limit between PACE
and PACW is enforced in the counterfactual dispatch.
Neglecting transmission constraints in a BAA tends to underestimate the EIM benefit. The
magnitude depends on how significant the congestion is. Severe congestion impacting EIM
benefits was not observed until October 2017, where transmission congestion happened
between the generation in Wyoming and PACE’s load in PacifiCorp. The impact of this
congestion to the EIM benefit calculation can be demonstrated with the following example.
Assume in PACE, load increased 10 MW from the base schedule, generation decreased 100
MW from the base schedule, and PACE imported 110 MW in EIM. Note that energy is balanced
in PACE with 110 MW of transfer import replacing 100 MW of generation and serving 10 MW of
load above the base schedule. Assume the decremented generation cost is $20/MWh, and the
import cost is $120/MWh. From an economic standpoint, the EIM dispatched the resources out-
of-merit with high cost supply being incremented and low cost supply being decremented. If we
were to calculate the EIM benefit ignoring the congestion effect, the benefit will be negative. The
calculation is as follows:
EIM dispatch cost = -100 MW * $20 = –$2,000.
EIM transfer cost = 110 MW * $120 = $13,200.
Counterfactual dispatch cost = 10 MW * $20 = $200.
For simplicity, ignore flex ramp and GHG. The EIM benefit is calculated as $200 – (–
$2,000 + $13,200) = –$11,000.
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To better understand the root cause of the negative benefit, we break the calculated benefit into
two components: infeasible base schedule and infeasible counterfactual.
1. Infeasible base schedule: In the EIM, the imported $120 transfer replaced 100 MW of $20
internal generation, and produced a negative benefit equal to 100*($20-$120) = -$10,000. The
extra dispatch cost in EIM is not due to economics, but due to infeasible base schedules for
certain constraints, which forces the EIM to mitigate congestion, and incurs additional cost. For
this reason, we need to add the congestion management cost to the counterfactual dispatch
cost to reflect the need to perform the same congestion management dispatch as in the EIM. In
the example, we add $10,000 to the counterfactual dispatch cost.
2. Infeasible counterfactual: In the counterfactual, the merit order dispatch did not know that
dispatching up the $20 generation would overload the transmission, and produced a negative
benefit equal to 10*($20-$120) = -$1,000. The counterfactual should recognize the economic
$20 supply is subject to transmission congestion, and cannot be dispatched. Therefore, in the
counterfactual dispatch, for increased net load, we dispatch only supply offers with a bid price
>= the transfer LMP. For decreased net load, we dispatch down only supply offers with a bid
price <= the transfer LMP. In the example, the net load is 10 MW, so we only dispatch
resources that bid above $120, assume these supplies cost $125/MWh.
With these two enhancements, we revise the benefit calculation as follows:
EIM dispatch cost = -100 MW * $20 = –$2,000.
EIM transfer cost = 110 MW * $120 = $13,200.
Counterfactual dispatch cost = 10 MW * $125 + $10,000 = $11,250.
The new EIM benefit is calculated to be $11,250 – (–$2,000 + $13,200) = $50.
These enhancements only apply when we detect significant congestion indicated by the LMP
difference between the BA’s ELAP and DGAP greater than a tolerance setting. Currently, the
tolerance is set to $5/MWh.
The counterfactual dispatch makes unit commitment decisions only for the ISO’s short start
units. The unit commitment decisions are based on the generic three-part variable cost formula,
which has converted startup cost and no load cost into variable dispatch cost, so unit
commitment can be determined by the economic metric order of the three-part cost.
Prior to the 2016 Q4 report, we used the resources’ RTD dispatching limits from the EIM in the
counterfactual. The EIM dispatching limits are 10-minute ramp limited in RTD, and they may be
overly constraining for the counterfactual theoretically. The counterfactual will replace the
transfers with internal dispatches, but it does not need to do it within 10-minute timeframe.
When EIM transfer volumes are moderate relative to the EIM dispatching range, this limitation
may not be a real problem, because the EIM dispatch range is mostly sufficient to replace the
transfers. As the EIM footprint increases, the transfer volume between BAAs also increases. We
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observed that some EIM transfers exceeded 1,000 MW frequently. The EIM dispatching range
started to show its limitation. In Q4 of 2016, we expanded the resources’ dispatching range to
base schedule and FMM dispatching limits. From Q2 of 2017, we decided not to use EIM
calculated limits. Instead, the dispatching range is constructed based on the resource’s
economic bid range in the following way:
a) Start with the resource’s bid range [bid_MW_min, bid_MW_max]
b) Block the ancillary service provisions, so the new range is [bid_MW_min+reg_down,
bid_MW_max – reg_up – spin – nonspin]
c) If the resource is a wind or solar resource, limit its upper limit by the forecasted output,
so the new range is [bid_MW_min+reg_down, min(bid_MW_max – reg_up – spin –
nonspin, wind or solar forecast)]

In cases where a counterfactual dispatch does not have sufficient supply offers to meet net load
imbalance, we assign a penalty cost for procuring more energy. If the BA does not import from
EIM, we extend its last economic bid segment. If the BA imports from EIM, we compare its last
economic segment against the EIM LMP, and set the penalty price to the higher of the two. In
summary, the penalty price per MWh is
 The highest offer price from the BA if the BA does not import from EIM,
 Max (the highest offer price from the BA, the transfer LMP) if the BA imports from EIM.

An EIM BAA may restrict the pool of dispatchable units in the counterfactual dispatch if that the
BAA’s practice prior to joining EIM was to balance real-time load from a limited pool.
ISO Counterfactual Dispatch
The ISO would need to meet load without EIM transfers in the counterfactual dispatch. The
counterfactual dispatch is constructed in the following way:
1. Calculate the ISO’s net EIM transfer;
2. Economically dispatch resources from the ISO to replace the transfer
A. If the ISO is importing from the EIM,
a. Find the ISO’s undispatched supply with the variable cost (bid and three-part
converted) greater than or equal to the reference transfer price;
b. Sort and stack the supply by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the transfer megawatts
B. If the ISO is exporting to the EIM,
a. Find the ISO’s dispatched supply with the variable cost (bid and three-part
converted) less than or equal to the reference FMM transfer price;
b. Sort and stack them by the variable cost from high cost to low cost; and
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c. Clear the supply stack from high cost to low cost up to the transfer megawatts

The reference transfer price for the ISO is the maximum price of the incoming transfer points if
the ISO is a net transfer importer, and the minimum price of the outgoing transfer points if the
ISO is a net transfer exporter in RTD. Undispatched supply at lower bid cost than the reference
price is dispatched out of merit when the ISO is importing transfer at the reference price.
Dispatched supply at higher bid cost than the reference price is also dispatched out of merit
when the ISO is exporting transfer at the reference price. The ISO has complex networks and
constraints that are modeled in the EIM but not in the counterfactual. For example, supplies can
be locally transmission constrained and undispatched in the EIM, which have available supply at
lower bid cost than the LMP of the rest of the ISO. They should remain undispatched in the
counterfactual even they have lower supply cost, because they are constrained by transmission.
In the ISO’s counterfactual dispatch, we only consider supplies above the reference transfer
price to replace incoming transfer into the ISO, and thus preventing the transmission
constrained lower cost supply being dispatched. Vice versa for the supplies below the reference
transfer price to replace outgoing transfer. The counter factual dispatch (applies for whole EIM,
not just the ISO) was based on 5-minute dispatch capability, and the reference price is the RTD
price.
Counterfactual Dispatch
All EIM entities, with the exception of Pacificorp, have their counterfactual dispatch constructed
in the following way. We will use NVE as an example.
1. Calculate the real-time net load imbalance for NVE;
2. Economically dispatch resources from NVE on top of the base schedules to meet NVE’s
net load imbalance
A. If the net load imbalance is positive,
a. Dispatch NV Energy’s bid-in supply above base schedules;
b. Sort and stack them by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the net load
imbalance.
B. If the net load imbalance is negative,
a. Dispatch NV Energy’s bid-in supply below base schedules;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the net load
imbalance.
PacifiCorp Counterfactual Dispatch
PacifiCorp East BAA and PacifiCorp West BAA would need to meet demand without intra-hour
transfers between PacifiCorp and the ISO, but transfers could occur between PACE and PACW
in the counterfactual dispatch. The PacifiCorp counter factual dispatch will be constructed in the
following way:
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1. Calculate the real-time net load imbalance for each BAA;
2. Economically dispatch resources from PacifiCorp on top of the base schedules to meet
net PacifiCorp load imbalance without violating the transfer limitations between PACE
and PACW.
A. If the net load imbalance is positive,
a. Find PacifiCorp’s bid-in supply above base schedules;
b. Sort and stack them by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the net load imbalance
subject to the transfer limit between PACE and PACW
B. If the net load imbalance is negative,
a. Find PacifiCorp’s bid-in supply below base schedules;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the net load imbalance
subject to the transfer limit between PACE and PACW
GHG Revenue
Greenhouse gas (GHG) revenue for a resource is equal to its GHG allocation MW times the
GHG price.
GHG Cost
GHG cost for a resource is equal to its GHG allocation MW times its GHG bid.
Example
This example illustrates how the EIM benefit is calculated.
The transfers out of the EIM optimization are listed in Table 1. Base scheduled transfers have
been excluded in the FMM transfers and RTD transfers.

From
BAA
To
BAA
FMM
transfer
FMM
transfer
price
RTD incremental
transfer
RTD transfer
price
Transfer
cost
PACE NEV
P
140 $26 10 $25 $3,890
NEVP CISO 160 $26 20 $30 $4,760
PACE PAC
W
190 $26 10 $25 $5,190
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PACW CISO 110 $26 -10 $30 $2,560
Table 1. An example of BAA to BAA transfers and prices
Assume the EIM energy imbalance and prices are as follows. Every BAA is balanced with Gen
+ Transfer – Load = 0. Assume the EIM optimization results in $1 GHG price, which means the
ISO’s LMP is $1 higher than the neighboring BAA (NEVP and PACW), because there is no
congestion going into the ISO in the example. In the table below, positive transfer MW means
the BAA is importing and negative transfer MW means it is exporting. Also, transfers in the table
are sum of the transfers occur in both the FMM and the RTD with base scheduled transfer being
excluded.
BAA Gen Load Net transfer in MW LMP GHG price
CISO 0 280 280 $31
$1
NEVP 50 20 -30 $30
PACE 150 -200 -350 $20
PACW 100 200 100 $30
Table 2. EIM energy imbalance and prices by BAA for one 5-minute interval
Transfer Cost
The transfers occur in both FMM and RTD, and their volume and prices are listed in Table 3.
They are calculated from applying the convention that importing is positive and exporting is
negative the BAA to BAA transfers, and summing them over all the neighboring BAAs.
BAA transfer cost
CISO $7,320 = $4,760+$2,560
NEVP ($870) = $3,890-$4,760
PACE ($9,080) = -$3,890-$5,190
PACW $2,630 = $5,190-$2,560
Table 3. EIM transfer cost by BAA
For flex ramp, we calculate its transfer and transfer cost in Table 4.
BAA Direction Req. Award Allocation Flex ramp
transfer in
Flex
ramp
price
Flex ramp
transfer
cost
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CISO upward 150 100 75 -25 $1 -$25
NEVP upward 10 0 5 5 $1 $5
PACE upward 20 0 10 10 $1 $10
PACW upward 20 0 10 10 $1 $10
CISO downward 0 0 0 0 $2 $0
NEVP downward 10 10 2 -8 $2 -$16
PACE downward 20 0 4 4 $2 $8
PACW downward 20 0 4 4 $2 $8
Table 4. Flex ramp transfer example
EIM Dispatch Cost
Now calculate the total bid cost associated with the EIM dispatches (delta from base
schedules). The EIM dispatch costs are listed in Table 5.
BAA Gen_EIM EIM dispatch cost
CISO 0 $0
NEVP 50 $1,450
PACE 150 $2,700
PACW 100 $2,800
Table 5. EIM dispatch cost by BAA
Counterfactual Dispatch Cost
Then construct the counterfactual dispatches as described in the previous section, and sum up
the counter factual dispatch cost for each BAA as shown in Table 6.
BAA Gen_CF Counterfactual dispatch cost
CISO 280 $9,240
NEVP 20 $640
PACE -200 ($3,800)
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PACW 200 $6,200
Table 6. Counterfactual dispatch cost by BAA
GHG Cost and Revenue
The GHG costs associated with the 280 MW of importing transfer into CISO, and the revenues
received by the GHG allocated MWs in both FMM and RTD are listed in Table 7.
BAA GHG FMM MW GHG RTD MW GHG cost GHG revenue
CISO 270 280 $0 -$280
NEVP 0 0 $0 $0
PACE 200 200 $20 $200
PACW 70 80 $75 $80
Table 7. GHG cost and revenue by BAA
EIM Benefit
With all the cost and revenue for each BAA available, we can use the formula EIM benefit for a
BAA = counterfactual dispatch cost – (EIM dispatch cost + transfer cost + flex ramp transfer
cost) + GHG revenue – GHG cost to calculate EIM benefit for each BAA. The results are shown
in Table 8.
BAA CF dispatch
cost
EIM dispatch
cost
Transfer
cost
Flex
transf
er
cost
GHG
cost
GHG
revenue
EIM
benefit
CISO $9,240 $0 $7,320 ($25) $0 ($280) $1,665
NEV
P
$640 $1,450 ($870) ($11) $0 $0 $71
PAC
E
($3,800) $2,700 ($9,080) $18 $20 $200 $2,742
PAC
W
$6,200 $2,800 $2,630 $18 $75 $80 $757
Table 8. EIM benefit for one 5-minute interval
This calculation is performed for each 5-minute interval with unit $/hr. We convert the $/hr
benefit into the dollar benefit by multiplying 1/12. Then the 5-minute interval benefits in dollar
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amount can be aggregated into the monthly benefit by summing all the 5-minute intervals in the
month.
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CONFIDENTIAL

AVISTA CORPORATION

STATE OF IDAHO
CASE NO. AVU-E-22-11
ANNUAL POWER COST ADJUSTMENT (PCA)

COMPLIANCE FILING

CONFIDENTIAL APPENDIX B

EIM BENEFITS EVALUATION FOR EIM CUSTOMERS

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EIM Benefits Evaluation
for EIM Customers

May 07, 2019

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Change log:
Added an option, CFDispatchwithCongestionModel, to allow to switch on/off the

Reference:
1. EIM Quarterly Benefit Report Methodology, https://www.westerneim.com/Documents/EIM_BenefitMethodology.pdf
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Table of Contents
1 Background ................................................................................................................................................................................................... 4
2 EIM Benefit Evaluation Methodology ............................................................................................................................................................. 4
3 EIM Benefit Calculation Components ............................................................................................................................................................. 4
3.1 EIM Dispatch Cost .................................................................................................................................................................................. 4
3.1.1 Examples of EIM Dispatch Cost Calculation in EIM Study ................................................................................................................ 5
3.2 CF Dispatch Cost .................................................................................................................................................................................... 5
3.2.1 Net Load Imbalance Calculation ...................................................................................................................................................... 5
3.2.2 Detailed logic of CF dispatch ........................................................................................................................................................... 7
3.2.3 Examples of CF Dispatch ................................................................................................................................................................. 9
3.2.4 Detailed Logic of CF Dispatch with Heavy Congestion in BS ............................................................................................................15
3.3 EIM Net Transfer Revenue.....................................................................................................................................................................10
3.3.1 Transfer Price calculation ..............................................................................................................................................................11
3.4 GHG Net Revenue .................................................................................................................................................................................13
3.5 FRP Net Revenue ...................................................................................................................................................................................14
4 Appendix: Logic to handle Configuration Change of Multi-Stage Generators (MSG) ......................................................................................14

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1 Background
CAISO has published the general methodology for EIM benefits calculation (as seen in the reference of this document). The heuristic approach
allows to estimate EIM benefits without performing sophisticated optimization-based unit commitment and dispatch studies.
By using the same methodology described in the CAISO document in high-level, the goal of this design is to replicate CAISO benefit calculation
for EIM customers.
2 EIM Benefit Evaluation Methodology

For an EIM balancing authority area (BAA), the benefit can take the form of cost savings or profit or their combination[1]:
• Energy Cost Savings: BAA imports energy economically, or its base schedules (BS) are re-optimized by the EIM on an intra-hour basis.
• Energy Profit: BAA exports energy which are paid above the resource costs.
• Green House Gas (GHG) profit: BAA exports of GHG resources into California, that are paid the GHG price.
• Flexible Ramp Product (FRP) profit : BAA exports FRP and is paid at the FRP price (profit occurs when the FRP price is higher than the
opportunity cost of not providing FRP).

The EIM Benefits calculation, from a summarized level, is the following. It calculates the cost savings of the EIM’s dispatch compared to what
would have occurred if there was no EIM dispatch (counterfactual dispatch).

EIM benefit = CF dispatch cost – EIM dispatch cost + EIM net transfer revenue + GHG net revenue + FRP net revenue

The following components of the EIM Benefits Calculation are performed at the 5-minute level. The results are then summed to the monthly-
level, which is the level at which the CAISO posts their EIM Benefits Calculation results.
3 EIM Benefit Calculation Components
3.1 EIM Dispatch Cost

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For participating resources (PR), the EIM dispatch cost is calculated as the EIM Dispatch from the base schedule (BS) in order to meet the net
load imbalance with the EIM Transfer. The EIM dispatch cost uses the resource’s bid price.
For non-participating resources (NPR), their output may deviate from the BS too. With the assumption of consistent deviation behavior between
in EIM and not in EIM, the impacts should be the same to CF dispatch cost and EIM dispatch cost, that is, they cancel out each other. Therefore,
there is no need to add the costs in the terms.

The current CAISO rule is, if a unit in transition, the transition period will not be included in EIM dispatch cost calculation. The reason is, the cost
impact on EIM dispatch and CF are the same, so they wash-out.

For MSG with DOT and BS at different configurations, please refer to appendix “Logic to handle Configuration Change of Multi-Stage Generators
(MSG)”.
3.1.1 Examples of EIM Dispatch Cost Calculation in EIM Study
In the table below, Inc MW stands for unit incremental dispatch above the BS, Dec MW for unit decremental dispatch below the BS.
Table 1. EIM Dispatch Cost Calculation

3.2 CF Dispatch Cost

For a specific EIM customer, the CF study simulates the system operations without importing or exporting through the EIM transfers. Using
hourly BS as the baseline, it redispatches the resources to meet the real-time net load imbalance.

3.2.1 Net Load Imbalance Calculation

Conceptually, net load imbalance is the imbalance caused by:
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• Load forecast (LF) error: Deviation between the LF value used for T-40 BS submission and the LF for real time dispatch (RTD) market
clearing;
• Supply deviations caused by
o outage/derate of units with BS; or
o dispatch of renewable resources away from the BS based on the actual output or curtailment.

Net load imbalance is calculated based on EIM RTD dispatch and EIM RTD transfer. In this design, the convention is, exporting transfer is positive
and importing transfer is negative.

Net load imbalance MW= Total RTD dispatch MW of PRs - Total BS MW of PRs - EIM RTD transfer MW

Here
EIM RTD transfer MW is the delta transfer MW dispatched by EIM on top of base transfer. It’s calculated as:
RTD transfer MW – RTD_Base_transfer.
where
RTD transfer MW: overall transfer MW cleared in CAISO RT market;
RTD_Base_transfer: base transfer submitted by EIM customers.
Note：RTD transfer MW is the transfer result from CAISO; RTD_Base_transfer is the tagged transfer MW from EIM customers.
If a unit in transition, at transition period it's not included in net load imbalance calculation.
For MSG with DOT and BS at different configurations, please refer to appendix “Logic to handle Configuration Change of Multi-Stage Generators
(MSG)”.
Table 2.1 Net Load Imbalance Calculation

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The dispatch will be based on merit order of bid price to ensure minimum bid costs, with consideration of congestion as needed. Resource ramp
rate limit and Losses are ignored in the dispatch.

Currently, it’s assumed by CAISO that there is no need to commit/decommit resources for load imbalance. The general logic for CF calculation is,
to stack up available capacity economically to meet load imbalance. Here available capacity includes all online resources in RTD and offline non-
MSG resources. For MSG resources, only the configuration dispatched by RTD shall be considered. The CF dispatch range is constructed based on
the resource’s economic bid range in the following way:
a) Start with the resource’s bid range [bid_MW_min, bid_MW_max] , which should not exceed the economic dispatch range[Pmin, Pmax]
b) Block the ancillary service provisions, so the new range is [bid_MW_min+Reg_down, bid_MW_max – Reg_up – Spin] c) If the resource is renewable resource, such as wind or solar resource, limit its upper limit by the forecasted output, so the new range is
[bid_MW_min+Reg_down, min(bid_MW_max – Reg_up – Spin, wind or solar forecast)]

If load imbalance cannot be satisfied using available capacity, the highest available bid (including both online and offline) will be extended as the
bid price to procure more supply. Here the highest available bid is identified among all the available resources, that is, not include offline
configuration of MSGs.

In cases CF does not have sufficient supply offers to meet net load imbalance, a pseudo price will be assigned to the extended segment for
procuring more energy.
o If the BA does not import from EIM in RTD, we extend its last economic bid segment. Here the import is net over all RTD transfers.
o If the BA imports from EIM, we compare its last economic segment against the EIM transfer price, and set the pseudo price to the higher
of the two.
In summary, the pseudo price per MWh is:
• the highest offer price from the BA if the BA does not import from EIM,
• max(the highest offer price from the BA, the EIM transfer price) if the BA imports from EIM.
Here, the EIM transfer price is a weighted average transfer revenue from imports. Taking EIM customer A as an example, with net import, A may
import from both CAISO and NVE, and export to PACE. The EIM transfer price can be calculated as:

abs (Transfer Revenue_with CAISO + Transfer Revenue_with NVE) / (RTD import MW from CAISO + RTD import MW from NVE)

3.2.2 Detailed logic of CF dispatch
Detailed steps for the CF dispatch and cost calculation are described in the below sections.
If a unit in transition, during the transition period, it's not eligible for CF dispatch.

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3.2.2.1 Detailed logic of CF dispatch for Non- PacifiCorp BAAs
1. For each 5-min interval, calculate the real-time net load imbalance based on the corresponding EIM case;
2. Based on the BS, re-dispatch non-outaged resources economically to meet the net load imbalance:
A. If the net load imbalance is positive,
a. Find resources’ bid-in supply above BS.
b. The bid-in supply is sorted by the respective resources’ bid price in ascending order.
c. Clear the bid-in supply from the lowest cost to the highest cost, until the net load is re-balanced.
B. If the net load imbalance is negative,
a. Find resources’ bid-in supply below BS;
b. The bid-in supply is sorted by the respective resources’ bid price in descending order.
c. Clear the bid-in supply from highest cost to lowest cost, until the net load is re-balanced.

3.2.2.2 Detailed logic of CF dispatch for PacifiCorp BAAs

With consideration of transfers between PACE and PACW in the counterfactual dispatch, the PacifiCorp counter factual dispatch will be
constructed using the below method:
1. For each 5-min interval, calculate the real-time net load imbalance for each BAA respectively, i.e., PACE BAA and PACW BAA, based on
the corresponding EIM case;
2. Based on the BS, re-dispatch non-outaged resources economically to meet the net load imbalance without violating the transfer
limitations between PACE and PACW:
A. If the net load imbalance is positive,
a. Find resources’ bid-in supply above BS;
b. Sort the bid-in supply by the respective resources’ bid price in ascending order;
c. Clear the supply stack from the lowest cost to the highest cost subject to the transfer limit between PACE and PACW, until the
net load is re-balanced.
B. If the net load imbalance is negative,
a. Find resources’ bid-in supply below BS;
b. Sort the bid-in supply by the respective resources’ bid price in descending order;
c. Clear the supply stack from the highest cost to the lowest cost subject to the transfer limit between PACE and PACW, until the
net load is re-balanced.
Here the transfer limit only considers export transfer limits on the HMWY tie from PACE to PACW, that is, in CF dispatch, only allow the
flow from PACE to PACW. The export transfer limits on the HMWY tie can be retrieved from the OASIS report “EIM Transfer Limits by
Tie”.
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(For implementation, make sure the logic to cover at least the two scenarios below:
1. PACW sees positive net load imbalance, and PACE has cheaper available bid-in capacity, PACE resources are dispatched up, and
transfer to PACW to support PACW’s power balance;
2. PACE sees negative net load imbalance, and PACW has more expensive available bid-in capacity to reduce, PACW resources are
dispatched down to support PACE’s power balance with transfer from PACE to PACW )
3.2.3 Examples of CF Dispatch

There are four scenarios of CF Dispatch shown in below tables. The scenarios include: 1) a net load imbalance of 50 MW, 2) a net load
imbalance of 100 MW, 3) a net load imbalance of – 50 MW, and a net load imbalance of – 100 MW.

Inc stands for unit incremental dispatch above the BS, Dec for unit decremental dispatch below the BS. Unless the capacity is extended,
the Inc/Dec dispatch shall be within the range of [Pmin, Pmax] and with ancillary services (AS) MW being carved out. Since offline units
are considered in this dispatch, in addition to regulation and spinning reserve, we also need to consider non-spinning reserve MW as
well.

Table 3.1. Scenario 1: Ordered bid stack and bids clearing with net load imbalance 50MW

Table 3.2. Scenario 2: Ordered bid stack and bids clearing with net load imbalance 100 MW

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Table 3.3. Scenario 3: Ordered bid stack and bids clearing with net load imbalance -50MW

Table 3.4. Scenario 4: Ordered bid stack and bids clearing with net load imbalance -100MW

3.3 EIM Net Transfer Revenue

The EIM net transfer revenue formula is (EIM export revenue - EIM import cost). For a BAA, EIM export revenue is the revenue of sales to other
BAAs. The EIM import cost is the cost of purchases from other BAAs.
Transfers may occur in both the fifteen-minute market (FMM) and the 5-minute markets (RTD). Transfers in the two markets at the same period
can be in opposite directions. For example, a BAA can import in the FMM and export in the RTD, or vice versa. In this design document,
exporting transfer is positive and importing transfer is negative.

In general, for a 5-minute interval, the transfer revenue of with each transfer counterparty can be calculated as:
Transfer Revenue_withCounterparty = EIM FMM transfer * FMM transfer price + (EIM RTD transfer – EIM FMM transfer) * RTD transfer price.
Here
EIM FMM transfer = FMM transfer – FMM base transfer;
EIM RTD transfer = RTD transfer – RTD base transfer.

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Due to tagging change, RTD base transfer can be different from FMM base transfer. This happened to IPC in the past months.
For EIM BAA A, it may transfer with multiple BAAs, say CAISO, NVE and PACE, as shown in below diagram.
The total net transfer revenue will be:
Transfer Revenue_with CAISO + Transfer Revenue_with NVE + Transfer Revenue_with PACE

Figure 1. EIM BAA A direct interconnection with other EIM BAAs

3.3.1 Transfer Price calculation
Currently, if BAA A transfers with CAISO, A always collects the congestion rent; if counter party is not CAISO, A only collects half of the
congestion rent. The detailed calculation is described below.
If counter party is CAISO, then
Transfer price = if A exports, then
CAISO
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LMP_ELAP_A + abs(transfer constraint shadow price)
Else if A imports, then
LMP_ELAP_A - abs(transfer constraint shadow price)
Endif;
Else (i.e., counter party is not CAISO)
Transfer price = 0.5*( LMP_ELAP_A + ELAP of Counterparty)
Endif.
Where
for ELAP of counterparty, taking transfer with NVE as an example,
If NVE is not locked out, then
ELAP of Counterparty = LMP_ELAP_NVE
Else (i.e., NVE got locked out due to failing sufficiency test )ELAP of Counterparty* (can be Magnolia’s LMP)
endif
* As currently none of the EIM customers has access to other BAAs’ failure information, for monthly EIM benefit evaluation of a specific month,
EIM customers will have to request a spreadsheet from CAISO with the HE, interval and adjustment to the counterparties’ transfer price. Both
FMM and RTD adjustments are included. The PowerSettlements’s benefit calculation tool needs to subtract the adjustment price from the CAISO
price to obtain the ELAP of Counterparty. (CAISO is working on a long-term solution to post the data on public GUIs.)

Table 7.1: Examples of Transfer Net Revenue Calculation between A and CAISO
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nario _A price) ($/MWh) ($/MWh) _A price) ($/MWh) ($/MWh) revenue ($)

Table 7.2: Examples of Transfer Net Revenue Calculation
nario revenue ($)
_NVE ($/MWh) ($/MWh) _NVE ($/MWh) ($/MWh)

3.4 GHG Net Revenue
GHG net revenue is calculated as (GHG Revenue - GHG Cost).
For each 5-minute interval, the GHG revenue can be calculated as:
FMM GHG allocation MW * FMM GHG price + (RTD GHG allocation MW – FMM GHG allocation MW) * RTD GHG price.

For each 5-minute interval, the GHG cost can be calculated as:
RTD GHG allocation MW * GHG bid price.

Table 8: Examples of GHG Net Revenue Calculation
nario ($/MWh) ($) ($) revenue ($)
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3.5 FRP Net Revenue
FRP net revenue is calculated as (FRP revenue - FRP Cost). FRP revenue represents the payment received from other BAAs importing FRP
capacity from BAA A; FRP cost A’s payment to other BAAs exporting FRP capacity to A.
In general, for a 5-minute interval, the FRP net revenue can be calculated as for FRP Up:

RTD FRP up export * RTD FRP up price+ RTD FRP down export * RTD FRP down price

where
• RTD FRP export = A’s total RTD FRP award – EIM area’s RTD FRP award* (A’s RTD FRP requirement /sum of each BAA’s RTD FRP
requirement)
• RTD FRP price = A’s RTD FRP price
The same calculation applies to FRP down as well.
4 Appendix I: Logic to handle Configuration Change of Multi-Stage Generators (MSG)

The current rules to handle configuration changes/commitment status changes in EIM benefit calculation are:
• If the BS of a MSG is in a different configuration from the current dispatch in RTD: 1. Reset BS using Pmin_current_config; 2. Net load imbalance will be calculated with the updated BS; 3. EIM dispatch cost and CF cost calculation will be based on the updated BS; 4. Current configuration’s bid shall be treated as available for CF calculation (no change).
• If FMM commit a unit with zero BS: 1. Reset BS using Pmin; 2. Net load imbalance will be calculated with the updated BS;
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3. EIM dispatch cost and CF cost calculation will be based on the updated BS

If a unit is committed by CAISO, it’s assumed to be online in CF as well.
5 Appendix II: Detailed Logic of CF Dispatch with Heavy Congestion in BS
This logic is controlled by an option, CFDispatchwithCongestionModel. The default value of this option is 0, that is, the logic is switched off in all
BAAs’ EIM benefit evaluation.
5.1 Background
Neglecting transmission congestion within a BAA during BS calculation will lead to underestimate the EIM benefit. The impact can be explained
with the following example, as shown in Table 5.1.
In this example, the reason behind that EIM dispatched the resources out-of-merit with high cost import being incremented and low cost
internal generation being decremented is congestion. EIM dispatch considers impacts of congestion. If we were to calculate the CF dispatch cost
ignoring the congestion, the benefit would be inaccurate, sometimes even negative. The calculation is described in Table 5.1. For simplicity, flex
ramp and GHG terms are ignored in this example, and there is no consideration of 5 min granularity in the dispatch.
Table 5.1. EIM benefit with no congestion impacts
Actual Deviation/
EIM redispatch MW
Price
($/MWh)
EIM dispatch cost
($)
EIM transfer cost
($)
Counterfactual dispatch cost
($)
Load
Generation
Import
EIM benefit calculated without considering congestion ($)

To better understand the root cause of the negative benefit, we break the cause into two components: infeasible BS and infeasible CF:
• Infeasible BS:
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In the EIM dispatch, the imported $120 transfer replaced 100 MW of $20 internal generation, and produced an extra cost of 100*($120-$20) =
$10,000. This extra cost is caused by infeasible BS. Therefore, this congestion management cost should also incur to the CF dispatch, to reflect
the need to perform the same congestion management dispatch as in the EIM. That is, in the example, $10,000 needs to be added to the CF cost
term.
• Infeasible CF:
The CF dispatch should recognize the economic $20 generation will cause transmission congestion, therefore cannot be dispatched.
o For increased net load, the CF can only dispatch up supply offers with a bid price >= the transfer price;
o For decreased net load, it can only dispatch down supply offers with a bid price <= the transfer price.
In the example, the CF can only dispatch resources that bid above $120 to meet the 10 MW net load. It’s assumed that the next supply in the
offer stack costs $125/MWh.
Table 5.2. EIM benefit considering congestion impacts
Actual Deviation/
EIM redispatch MW
Price
($/MWh)
Supply Price >=
Transfer price($/MWh)
EIM dispatch
cost ($)
EIM transfer
cost ($)
Counterfactual dispatch cost
($)
Load
Generation
Import
EIM benefit considering congestion ($)

5.2 CF Dispatch Cost Calculation Logic Considering Congestion Impacts

If significant congestion is detected, the below logic will be triggered to ensure congestion impacts to be considered in the CF study. The
situation is indicated by the LMP difference between the BAA’s ELAP and DGAP greater than a tolerance setting. Currently, the tolerance is set to
$5/MWh in CAISO calculation.
If LMP_ELAP - LMP_DGAP > 5 then
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CF dispatch cost = Infeasible BS cost + Infeasible CF cost
Else
CF dispatch cost is calculated based on the logic described in section 3.2.2.
End if
Detailed logic to calculate Infeasible BS cost and Infeasible CF cost is:
For any RTD interval, if (total net RTD transfer is import)
and (Total RTD redispatch MW of PRs < Total BS of PRs ) (i.e., RTD dispatches down PRs)
and exists(bid segment, RTD import price > bid price of EIM dispatched bid segment) then (i.e., import expensive MW to replace cheaper
internal resources)
Infeasible BS cost = if net load imbalance > 0 , then
[sum(BAA, Import MW*RTD import price) - Sum(bid segment, RTD dispatch down segment MW* segment bid price)]/12
else (i.e., net load imbalance < 0 )
[sum(BAA, Import MW*RTD import price) - Sum(bid segment, RTD dispatch down segment MW for BS infeasibility*
segment bid price)]/12
endif
Note:
1. For Infeasible BS cost calculation, only consider PRs.
2. Here BAA represents BAAs transfer with the studied BAA. Import MW should be positive.
3. For RTD import price, please refer to section 3.3 RTD transfer price calculation.
4. For a unit, RTD dispatch down MW = RTD dispatch MW – BS MW
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5. RTD dispatch down segment MW for BS infeasibility is RTD dispatch down segment MW capped by net transfer MW.

Infeasible CF cost = if net load imbalance > 0 , then
[sum(available bid segment| bid price >= max(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
else (i.e., net load imbalance < 0 )
[sum(available bid segment | bid price <= min(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
end if
End if
Note:
1. For Infeasible CF cost calculation, PRs should be included.
2. Here BAA represents BAAs transfer with the studied BAA.
3. For RT import price, please refer to section 3.3 RT transfer price calculation.

5.3 Examples of CF Cost Components Considering Congestion
Examples are constructed in this section to show how to implement the detailed logic described in the previous section.
• Scenario 1: Positive net load imbalance
Table 5.3. Scenario 1: Positive net load imbalance
Load Generation Import
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Table 5.4. Scenario 1: Bid segment dispatched down by EIM for BS infeasibility (Total = - 100MW)

Infeasible BS cost = [sum(BAA, ImportMW*RTD import price) - Sum(bid segment, RTD dispatch down segment MW* segment bid price)]/12
= [50*130+70*120 – (40*70 + 30*60 +30*20)]/12
= 808.33
Table 5.5. Scenario 1: Bid segments available for CF dispatch up

Infeasible CF cost = [sum(available bid segment| bid price >= max(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
= [10*130]/12
= 108.33
CF dispatch cost = Infeasible BS cost+ Infeasible CF cost = $916.66

• Scenario 2: Negative net load imbalance
Table 5.6. Scenario 2: Negative net load imbalance
Load Generation Import
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Table 5.7. Scenario 2: Bid segment dispatched down by EIM for BS infeasibility (Total = - 90MW)

Infeasible BS cost = [sum(BAA, Import MW*RTD import price) - Sum(bid segment, RTD dispatch down segment MW for BS infeasibility*
segment bid price)]/12
= [30*130+70*120 – (40*70 + 30*60 +20*20)]/12
= 608.33
Table 5.8. Scenario 2: Bid segments available for CF dispatch down

Infeasible CF cost = [sum(available bid segment | bid price <= min(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
= [5*120+5*80]/12
= 83.33
CF dispatch cost = Infeasible BS cost+ Infeasible CF cost = $691.67

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ATTACHMENT E
ENERGY IMBALANCE MARKET
CAISO 2022-2023 QUARTERLY BENEFIT
REPORTS
Attachment E Page 1 of 178
WESTERN EIM BENEFITS REPORT
First Quarter 2022
Prepared by: Market Analysis and Forecasting
April 21, 2022
Attachment E Page 2 of 178
CONTENTS
EXECUTIVE SUMMARY ........................................................................................................... 3
BACKGROUND ......................................................................................................................... 4
WESTERN EIM ECONOMIC BENEFITS IN Q1 2022 ................................................................ 4
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION ................................................................... 5
INTER-REGIONAL TRANSFERS ............................................................................................................. 6
WHEEL THROUGH TRANSFERS .......................................................................................................... 16
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS ....................................22
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS ..............................................24
CONCLUSION ..........................................................................................................................28
APPENDIX 1: GLOSSARY OF ABBREVIATIONS...................................................................29
Attachment E Page 3 of 178

EXECUTIVE SUMMARY
This report presents the benefits associated with
participation in the Western Energy Imbalance
Market (EIM).
The measured benefits of participation in the
Western EIM include cost savings, increased
integration of renewable energy, and improved
operational efficiencies including the reduction of
the need for real-time flexible reserves.
This analysis demonstrates the benefit of
economic dispatch in the real time market across a larger
EIM footprint with more diverse resources and geography.

Q1 2022 Gross Benefits by Participant
(millions $)
Avista $1.95
Arizona Public Service $7.41
BANC $18.58
California ISO $63.56
Idaho Power $6.29
LADWP $10.35
NorthWestern Energy $4.41
NV Energy $5.53
PacifiCorp $26.40
PNM $8.59
Portland General Electric $3.31
Powerex $3.85
Puget Sound Energy $1.54
Salt River Project $3.60
Seattle City Light $5.50
TID $1.29
TPWR $0.15
Total $172.31

Gross benefits from EIM since November 2014
$2.10 billion
ECONOMICAL
$172.31 M
Gross benefits realized due to more
efficient inter-and intra-regional
dispatch in the Fifteen-Minute
Market (FMM) and Real-Time
Dispatch (RTD)*

ENVIRONMENTAL
40,304
Metric tons of CO2** avoided
curtailments

OPERATIONAL
54%
Average reduction in flexibility
reserves across the footprint
2022
Q1 BENEFITS
Attachment E Page 4 of 178
*EIM Quarterly Benefit Report Methodology: https://www.westerneim.com/Documents/EIM-BenefitMethodology.pdf.
**The GHG emission reduction reported is associated with the avoided curtailment only. The current market process and
counterfactual methodology cannot differentiate the GHG emissions resulting from serving ISO load via the EIM versus dispatch that
would have occurred external to the ISO without the EIM. For more details, see
http://www.caiso.com/Documents/GreenhouseGasEmissionsTrackingReport-FrequentlyAskedQuestions.pdf
BACKGROUND
The Western EIM began financially binding operation on November 1, 2014 by optimizing
resources across the ISO and PacifiCorp Balancing Authority Areas (BAAs). NV Energy began
participating in December 2015, Arizona Public Service and Puget Sound Energy began
participating in October 2016, and Portland General Electric began participating in October
2017. Idaho Power and Powerex began participating in April 2018, and the Balancing Authority
of Northern California (BANC) began participating in April 2019. Seattle City Light and Salt River
Project began participating in April 2020.
In 2021, new balancing authorities began participating in the Western EIM, with the Turlock
Irrigation District (TID) in March 2021, the second phase of BANC in March 2021, and the Los
Angeles Department of Water and Power (LADWP) and Public Service Company of New
Mexico (PNM) in April 2021, followed by NorthWestern Energy (NWMT) starting in June 2021.
Avista Utilities (AVA) and Tacoma Power (TPWR), two utilities serving a combined 600,000
electric customers in the Pacific Northwest, became the newest members of the Western EIM,
with both beginning their participation on March 2, 2022.
The Western EIM footprint now includes portions of Arizona, California, Idaho, Montana,
Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, and extends to the border with
Canada.
WESTERN EIM ECONOMIC BENEFITS IN Q1 2022
Table 1 shows the estimated EIM gross benefits by each region per month1. The monthly
savings presented show $51.55 million for January, $54.31 million for February, and $66.45
million for March with a total estimated benefit of $172.31 million for this quarter2. This level of
EIM benefits accrued from having additional EIM areas participating in the market and
economical transfers displacing more expensive generation.

1 The EIM benefits reported here are calculated based on available data. Intervals without complete data are
excluded in the calculation. The intervals excluded due to unavailable data are normally within a few percent
points of the total intervals.
2 For several quarterly estimates, CAISO benefits have been calculated on a variation of the counterfactual
methodology. For CAISO only the logic has considered offline resources as part of the bid stack in the
counterfactual. In Q4 2021, CAISO has identified some questionable results that drove persistent negative
benefits for CAISO when considering offline resources. Consequently this logic has been not used for Q4
CAISO benefits in the meantime CAISO further asses this logic component. With this approach the
counterfactual calculation for CAISO follows the same methodology applicable to all EIM entities.
Attachment E Page 5 of 178
Region January February March Total
AVA $1.95 $1.95
APS $2.85 $2.04 $2.52 $7.41
BANC $5.04 $3.83 $9.71 $18.58
CISO $15.03 $19.66 $28.87 $63.56
IPCO $2.66 $2.34 $1.29 $6.29
LADWP $2.81 $4.25 $3.29 $10.35
NVE $1.36 $1.61 $1.44 $4.41
NWMT $1.91 $1.73 $1.89 $5.53
PAC $10.36 $9.82 $6.22 $26.40
PGE $2.67 $3.23 $2.69 $8.59
PNM $1.51 $0.97 $0.83 $3.31
PSE $1.68 $0.97 $1.20 $3.85
PWRX $0.15 $0.56 $0.83 $1.54
SCL $1.55 $1.06 $0.99 $3.60
SRP $1.63 $1.88 $1.99 $5.50
TID $0.34 $0.36 $0.59 $1.29
TPWR $0.15 $0.15
Total $51.55 $54.31 $66.45 $172.31
TABLE 1: Q1 2022 benefits in millions USD
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION
Since the start of the EIM in November 2014, the cumulative economic benefits of the market
have totaled $2.10 billion. The quarterly benefits have grown over time as a result of the
participation of new BAAs, which results in benefits for both the individual BAA but also
compounds the benefits to adjacent BAAs through additional transfers. The ISO began
publishing quarterly EIM benefit reports in April 2015.3
Graph 1 illustrates the gross economic benefits of the EIM by quarter for each participating
BAA.
3 Prior reports are available at https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx
Attachment E Page 6 of 178

GRAPH 1: Cumulative economic benefits for each quarter by BAA
INTER-REGIONAL TRANSFERS
A significant contributor to EIM benefits is transfers across balancing areas, providing access to
lower cost supply, while factoring in the cost of compliance with greenhouse gas (GHG)
emissions regulations when energy is transferred into the ISO. As such, the transfer volumes
are a good indicator of a portion of the benefits attributed to the EIM. Transfers can take place in
both the 15-Minute Market and Real-Time Dispatch (RTD).
Generally, transfer limits are based on transmission and interchange rights that participating
balancing authority areas make available to the EIM, with the exception of the PacifiCorp West
(PACW) -ISO transfer limit and the Portland General Electric (PGE) -ISO transfer limit in RTD.
These RTD transfer capacities between PACW/PGE and the ISO are determined based on the
allocated dynamic transfer capability driven by system operating conditions. This report does
not quantify a BAA’s opportunity cost that the utility considered when using its transfer rights for
the EIM.
Table 2 provides the 15-minute and 5-minute EIM transfer volumes with base schedule
transfers excluded. The EIM entities submit inter-BAA transfers in their base schedules. The
benefits quantified in this report are only attributable to the transfers that occurred through the
EIM. The benefits do not include any transfers attributed to transfers submitted in the base
schedules that are scheduled prior to the start of the EIM.
The transfer from BAA_x to BAA_y and the transfer from BAA_y to BAA_x are separately
reported. For example, if there is a 100 Megawatt-Hour (MWh) transfer during a 5-minute
interval, in addition to a base transfer from ISO to NVE, it will be reported as 100 MWh
from_BAA ISO to_BAA NEVP, and 0 MWh from_BAA NEVP to_BAA ISO in the opposite
Attachment E Page 7 of 178
direction. The 15-minute transfer volume is the result of optimization in the 15-minute market
using all bids and base schedules submitted into the EIM. The 5-minute transfer volume is the
result of optimization using all bids and base schedules submitted into EIM, based on unit
commitments determined in the 15-minute market optimization. The maximum transfer
capacities between EIM entities are shown in Graph 2 below.

Month

From BAA

To BAA
15min EIM transfer
(15m – base)
5min EIM transfer
(5m – base)
AZPS CISO 118,743 72,202
January AZPS LADWP 17,593 19,952
AZPS NEVP 5,240 5,947
AZPS PACE 18,980 38,259
AZPS PNM 39,390 38,395
AZPS SRP 26,147 24,154
BANC CISO 6,501 2,743
BANC TIDC 22 88
CISO AZPS 35,068 51,172
CISO BANC 87,894 123,607
CISO LADWP 32,845 41,818
CISO NEVP 57,698 75,616
CISO PACW 11,572 38,255
CISO PGE 15,777 32,445
CISO PWRX 32,316 45,374
CISO SRP 38,033 52,578
CISO TIDC 9,917 13,188
IPCO NEVP 35,809 14,639
IPCO NWMT 2,198 2,108
IPCO PACE 6,504 2,754
IPCO PACW 24,319 20,997
IPCO PSEI 0 0
IPCO SCL 2,955 3,196
Attachment E Page 8 of 178

LADWP AZPS 2,499 2,983
LADWP CISO 110,255 66,932
LADWP NEVP 7,764 13,365
LADWP PACE 9,819 13,274
NEVP AZPS 603 697
NEVP CISO 82,891 34,904
NEVP IPCO 88,744 109,290
NEVP LADWP 11,639 11,550
NEVP PACE 14,381 17,254
NWMT IPCO 10,483 10,886
NWMT PACE 6,560 3,857
NWMT PACW 39 49
NWMT PGE 2 48
NWMT PSEI 4 44
PACE AZPS 66,803 54,583
PACE IPCO 84,861 99,770
PACE LADWP 101,746 79,610
PACE NEVP 85,711 73,798
PACE NWMT 16,441 22,356
January PACE PACW 12,168 17,532
PACE SRP 0 0
PACW CISO 43,940 68,282
PACW IPCO 39,803 36,397
PACW NWMT 0 2
PACW PGE 31,998 26,535
PACW PSEI 16,214 20,511
PACW SCL 843 808
PGE CISO 32,750 27,570
Attachment E Page 9 of 178
PGE NWMT 126 70
PGE PACW 34,210 37,935
PGE PSEI 0 0
PGE SCL 1,151 1,090
PNM AZPS 19,222 18,520
PNM SRP 312 360
PSEI IPCO 0 0
PSEI NWMT 5 42
PSEI PACW 47,747 50,679
PSEI PGE 0 0
PSEI PWRX 13,773 15,743
PSEI SCL 21,217 24,309
PWRX CISO 0 0
PWRX PSEI 12,946 11,866
SCL IPCO 11,803 11,429
SCL PACW 1,294 1,499
SCL PGE 1,580 1,780
SCL PSEI 18,800 13,864
SRP AZPS 33,808 27,442
SRP CISO 48,933 41,814
SRP PACE 0 0
SRP PNM 1,661 2,127
TIDC BANC 15 88
TIDC CISO 10,199 5,785
February AZPS CISO 64,740 33,432
AZPS LADWP 12,726 11,670
AZPS NEVP 2,979 6,546
AZPS PACE 36,868 37,003
Attachment E Page 10 of 178

AZPS PNM 33,789 36,984
AZPS SRP 20,211 13,646
BANC CISO 5,393 2,879
BANC TIDC 75 153
CISO AZPS 91,629 90,842
CISO BANC 90,169 114,869
CISO LADWP 93,651 111,393
CISO NEVP 98,608 114,495
CISO PACW 8,025 25,307
CISO PGE 19,898 30,506
CISO PWRX 50,574 63,110
CISO SRP 55,299 66,382
CISO TIDC 6,634 8,786
IPCO NEVP 33,090 17,165
IPCO NWMT 3,549 3,519
IPCO PACE 8,691 4,326
IPCO PACW 13,523 15,421
IPCO PSEI 0 0
IPCO SCL 3,639 4,237
LADWP AZPS 1,401 1,956
LADWP CISO 44,004 27,577
LADWP NEVP 10,989 12,432
LADWP PACE 20,430 21,959
February NEVP AZPS 1,999 2,058
NEVP CISO 64,069 28,650
NEVP IPCO 73,018 86,247
NEVP LADWP 24,884 23,174
NEVP PACE 36,121 34,598
Attachment E Page 11 of 178
NWMT IPCO 8,047 7,862
NWMT PACE 4,896 3,244
NWMT PACW 54 13
NWMT PGE 6 50
NWMT PSEI 8 30
PACE AZPS 64,346 55,733
PACE IPCO 66,977 71,276
PACE LADWP 69,256 59,490
PACE NEVP 50,173 32,607
PACE NWMT 15,196 17,340
PACE PACW 12,210 13,675
PACE SRP 0 0
PACW CISO 44,430 91,933
February PACW IPCO 34,274 32,700
PACW NWMT 0 6
PACW PGE 25,339 21,244
PACW PSEI 27,220 27,962
PACW SCL 1,347 1,199
PGE CISO 46,152 35,837
PGE NWMT 1 49
PGE PACW 32,444 45,060
PGE PSEI 0 0
PGE SCL 1,542 1,557
PNM AZPS 24,075 20,191
PNM SRP 5,260 4,259
PSEI IPCO 0 0
PSEI NWMT 1 29
PSEI PACW 29,025 32,855
Attachment E Page 12 of 178
PSEI PGE 0 0
PSEI PWRX 14,595 15,700
PSEI SCL 30,478 30,119
PWRX CISO 0 0
PWRX PSEI 11,200 11,315
SCL IPCO 12,239 11,581
SCL PACW 685 907
SCL PGE 940 1,033
SCL PSEI 6,165 6,049
SRP AZPS 13,542 19,966
SRP CISO 54,897 40,795
SRP PACE 0 0
SRP PNM 1,072 2,058
TIDC BANC 3,513 2,603
TIDC CISO 8,730 5,714
March AVA CISO 36 35
AVA IPCO 41,079 30,694
AVA NWMT 20,262 13,976
AVA PACW 492 934
AVA PGE 0 62
AVA PSEI 2 42
AVA SCL 4 2
AZPS CISO 118,636 60,827
AZPS LADWP 13,543 12,957
AZPS NEVP 3,359 4,346
AZPS PACE 70,436 94,386
AZPS PNM 36,302 40,678
AZPS SRP 31,055 26,305
Attachment E Page 13 of 178
BANC CISO 9,468 4,768
BANC TIDC 145 157
CISO AVA 0 0
CISO AZPS 128,838 147,868
CISO BANC 135,926 151,421
CISO LADWP 91,221 113,805
CISO NEVP 155,740 190,858
CISO PACW 10,484 44,930
CISO PGE 23,431 49,823
CISO PWRX 70,105 87,960
CISO SRP 71,743 82,831
CISO TIDC 8,870 11,526
IPCO AVA 6,766 11,113
IPCO NEVP 40,989 22,055
IPCO NWMT 3,196 4,284
IPCO PACE 43,574 20,184
IPCO PACW 14,394 22,587
IPCO PSEI 0 0
IPCO SCL 3,515 5,295
LADWP AZPS 1,597 2,993
LADWP CISO 35,241 24,140
LADWP NEVP 3,317 4,833
LADWP PACE 7,525 8,585
NEVP AZPS 800 1,131
March NEVP CISO 127,997 56,105
NEVP IPCO 38,306 59,337
NEVP LADWP 51,570 45,547
NEVP PACE 84,835 110,488
Attachment E Page 14 of 178
NWMT AVA 18,172 27,943
NWMT IPCO 6,996 7,745
NWMT PACE 17,012 10,016
NWMT PACW 32 16
NWMT PGE 62 85
NWMT PSEI 4 37
March PACE AZPS 117,183 84,121
PACE IPCO 75,351 90,801
PACE LADWP 26,324 22,494
PACE NEVP 102,187 55,974
PACE NWMT 22,459 33,316
PACE PACW 28,363 37,696
PACE SRP 0 0
PACW AVA 10,199 10,169
PACW CISO 37,888 79,115
PACW IPCO 43,457 35,531
PACW NWMT 0 3
PACW PGE 37,555 31,476
PACW PSEI 27,452 41,994
PACW SCL 1,013 1,029
PGE AVA 0 63
PGE CISO 24,281 19,273
PGE NWMT 48 48
PGE PACW 28,165 32,661
PGE PSEI 0 0
PGE SCL 1,172 1,322
PGE TPWR 32 60
PNM AZPS 22,036 21,389
Attachment E Page 15 of 178

TABLE 2: Energy transfers (MWh) in the FMM and RTD markets for Q1 2022

PNM SRP 4,832 2,788
PSEI AVA 0 41
PSEI IPCO 0 0
PSEI NWMT 5 37
PSEI PACW 32,839 33,619
PSEI PGE 0 0
PSEI PWRX 18,220 20,675
PSEI SCL 20,542 18,715
PSEI TPWR 4,539 5,345
PWRX CISO 0 0
PWRX PSEI 9,950 8,828
SCL AVA 13 10
SCL IPCO 12,814 10,554
SCL PACW 885 1,101
SCL PGE 1,480 1,364
SCL PSEI 11,788 15,118
SRP AZPS 4,890 8,533
SRP CISO 36,340 23,202
SRP PACE 0 0
SRP PNM 282 447
TIDC BANC 4,112 2,716
TIDC CISO 8,868 4,532
TPWR PGE 1 31
TPWR PSEI 6,687 6,442
Attachment E Page 16 of 178

GRAPH 2: Estimated maximum transfer capacity (EIM entities operating in Q4 2021)
WHEEL THROUGH TRANSFERS
As the footprint of the Western EIM grows, wheel-through transfers may become more common.
In order to derive the wheel-through transfers for each EIM BAA, the ISO uses the following
calculation for every real-time interval dispatch:

• Total import: summation of transfers above base transfers coming into the EIM BAA
under analysis
• Total export: summation of all transfers above base transfers going out of the EIM
BAA under analysis
• Net import: the maximum of zero or the difference between total imports and total
exports
Attachment E Page 17 of 178
• Net export: the maximum of zero or the difference between total exports and total
imports
• Wheel through: the minimum of the EIM transfers into (total import) or EIM transfer
out (total export) of a BAA for a given interval

All wheel-through transfers are summed over both the month and the quarter.

Currently, an EIM entity facilitating a wheel through receives no direct financial benefit for
facilitating the wheel; only the sink and source directly benefit. As part of the Western EIM
Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel
through volumes to assess whether, after the addition of new EIM entities, there is a potential
future need to pursue a market solution to address the equitable sharing of wheeling benefits.

The ISO will continue to track the volume of wheel-through transfers in the EIM market in the
quarterly reports.

This volume reflects the total wheel-through transfers for each EIM BAA, regardless of the
potential paths used to wheel through. The net imports and exports estimated in this section
reflect the overall volume of net imports and exports; in contrast, the imports and exports
provided in Table 2 reflect the gross transfers between two EIM BAAs.

The metric is measured as energy in MWh for each month and the corresponding calendar
quarter, as shown in Tables 3 through 6 and Graphs 3 through 6.

BAA Net Export Net Import Wheel Through
AVA 43,306 46,901 2,440
AZPS 166,484 200,973 411,205
BANC 10,493 395,010 295
CISO 1,638,892 517,173 341,873
IPCO 63,929 602,149 109,952
LADWP 70,422 422,855 130,606
NEVP 156,110 179,757 464,919
NWMT 40,301 65,558 31,625
PACE 723,253 224,613 198,918
PACW 219,342 162,824 310,904
PGE 143,166 137,055 59,428
Attachment E Page 18 of 178
PNM 67,062 120,243 446
PSEI 149,085 65,281 98,823
PWRX 17,740 234,291 14,270
SCL 54,694 71,285 21,596
SRP 161,794 268,713 4,590
TIDC 21,091 33,551 347
TPWR 6,412 5,343 62

TABLE 3: Estimated wheel-through transfers in Q1 2022

GRAPH 3: Estimated wheel-through transfers in Q4 2021

BAA Net Export Net Import Wheel-Through
AZPS 80,872 37,360 118,037
BANC 2,744 123,608 87
CISO 347,913 194,094 126,139
IPCO 17,171 241,249 26,523
Attachment E Page 19 of 178
LADWP 36,061 92,437 60,493
NEVP 50,033 59,702 123,661
NWMT 14,045 23,739 838
PACE 307,611 36,519 40,037
PACW 56,453 69,703 97,242
PGE 47,549 41,692 19,117
PNM 18,774 40,416 106
PSEI 61,849 17,362 28,924
PWRX 6,539 55,790 5,327
SCL 21,816 22,648 6,757
SRP 70,183 75,893 1,199
TIDC 5,788 13,190 86
TABLE 4: Estimated wheel-through transfers in January 2022

GRAPH 4: Estimated wheel-through transfers in January 2022

Attachment E Page 20 of 178

BAA Net Export Net Import Wheel- Through
AZPS 34,347 85,813 104,934
BANC 2,935 117,374 98
CISO 517,910 159,037 107,781
IPCO 22,128 187,127 22,540
LADWP 15,884 157,688 48,040
NEVP 45,735 54,254 128,992
NWMT 10,313 20,056 886
PACE 209,609 61,687 40,513
PACW 80,557 37,680 95,559
PGE 62,800 33,131 19,702
PNM 24,331 38,924 119
PSEI 47,616 14,270 31,087
PWRX 7,092 74,587 4,223
SCL 11,669 29,212 7,901
SRP 61,596 83,064 1,223
TIDC 8,218 8,840 99
TABLE 5: Estimated wheel-through transfers in February 2022

Attachment E Page 21 of 178

GRAPH 5: Estimated wheel-through transfers in February 2022

BAA Net Export Net Import Wheel Through
AVA 43,306 46,901 2,440
AZPS 51,264 77,801 188,234
BANC 4,815 154,027 110
CISO 773,070 164,043 107,953
IPCO 24,629 173,774 60,889
LADWP 18,477 172,730 22,074
NEVP 60,343 65,802 212,265
NWMT 15,942 21,763 29,901
PACE 206,033 126,407 118,369
PACW 82,333 55,441 118,102
PGE 32,816 62,233 20,610
PNM 23,957 40,904 221
PSEI 39,620 33,649 38,812
Attachment E Page 22 of 178
PWRX 4,108 103,915 4,720
SCL 21,209 19,426 6,938
SRP 30,015 109,757 2,167
TIDC 7,085 11,521 163
TPWR 6,412 5,343 62
TABLE 6: Estimated wheel-through transfers in March 2022

GRAPH 6: Estimated wheel-through transfers in March 2022
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS
The Western EIM benefit calculation includes the economic benefits that can be attributed to
avoided renewable curtailment within the ISO footprint. If not for energy transfers facilitated by
the EIM, some renewable generation located within the ISO would have been curtailed via
either economic or exceptional dispatch. The total avoided renewable curtailment volume in
MWh for Q1 2022 was calculated to be 18,160 MWh (January) + 29,740 MWh (February) +
46,268 MWh (March) = 94,168 MWh total.
There are environmental benefits of avoided renewable curtailment as well. Under the
assumption that avoided renewable curtailments displace production from other resources at a
default emission rate of 0.428 metric tons CO2/MWh, avoided curtailments displaced an
Attachment E Page 23 of 178
estimated 40,304 metric tons of CO2 for Q1 2022. Avoided renewable curtailments also may
have contributed to an increased volume of renewable credits that would otherwise have been
unavailable. This report does not quantify the additional value in dollars associated with this
benefit. Total estimated reductions in the curtailment of renewable energy in the ISO footprint,
along with the associated reductions in CO2, are shown in Table 7.
Year Quarter MWh Eq. Tons CO2
1 8,860 3,792
2015 2 3,629 1,553
3 828 354
4 17,765 7,521
1 112,948 48,342
2016 2 158,806 67,969
3 33,094 14,164
4 23,390 10,011
1 52,651 22,535
2017 2 67,055 28,700
3 23,331 9,986
4 18,060 7,730
1 65,860 28,188
2018 2 129,128 55,267
3 19,032 8,146
4 23,425 10,026
1 52,254 22,365
2019 2 132,937 56,897
3 33,843 14,485
4 35,254 15,089
1 86,740 37,125
2020 2 147,514 63,136
3 37,548 16,071
4 39,956 17,101
2021 1 76,147 32,591
2 109,059 46,677
Attachment E Page 24 of 178
3 23,042 9,862
4 38,044 16,283
2022 1 94,168 40,304
Total 1,664,368 712,270

TABLE 7: Total reduction in curtailment of renewable energy and associated reductions in CO2
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS
The Western EIM facilitates procurement of flexible ramping capacity in the FMM to address
variability that may occur in the RTD. Because variability across different BAAs may happen in
opposite directions, the flexible ramping requirement for the entire EIM footprint can be less
than the sum of individual BAA’s requirements. This difference is known as flexible ramping
procurement diversity savings.
Starting in 2016, the ISO replaced the flexible ramping constraint with flexible ramping products
that provide both upward and downward ramping. The minimum and maximum flexible ramping
requirements for each BAA and for each direction are listed in Table 8.
Month BAA Direction Minimum
requirement
Maximum
requirement
AZPS up 21 251
January BANC up 8 120
CISO up 209 2,437
IPCO up 30 140
LADWP up 38 295
NEVP up 17 328
NWMT up 26 156
PACE up 146 612
PACW up 57 222
PGE up 64 212
PNM up 31 148
PSEI up 51 192
PWRX up 82 366
SCL up 7 45
SRP up 14 151
TIDC up 2 14
Attachment E Page 25 of 178
ALL EIM up 390 2,917
AZPS down 6 278
BANC down 5 85
CISO down 57 1,577
IPCO down 43 184
LADWP down 28 272
NEVP down 14 328
NWMT down 39 159
PACE down 120 484
PACW down 43 232
PGE down 23 217
PNM down 41 161
January PSEI down 35 200
PWRX down 72 339
SCL down 4 49
SRP down 16 207
TIDC down 0 16
ALL EIM down 221 2,021
AZPS up 19 261
February BANC up 9 120
CISO up 257 2,226
IPCO up 39 150
LADWP up 44 295
NEVP up 23 337
NWMT up 43 129
PACE up 112 463
PACW up 48 222
PGE up 43 212
PNM up 43 143
PSEI up 38 187
PWRX up 68 259
Attachment E Page 26 of 178
SCL up 8 44
SRP up 24 151
TIDC up 2 14
ALL EIM up 464 2,661
AZPS down 22 254
BANC down 5 81
CISO down 54 1,577

February
IPCO down 49 203
LADWP down 51 272
NEVP down 12 355
NWMT down 35 159
PACE down 124 484
PACW down 38 232
PGE down 34 230
PNM down 36 150
PSEI down 26 156
PWRX down 93 339
SCL down 5 49
SRP down 22 170
TIDC down 1 17
ALL EIM down 284 2,021

March

AVA up 17 91
AZPS up 32 286
BANC up 7 113
CISO up 281 2,120
IPCO up 34 159
LADWP up 37 315
NEVP up 26 337
NWMT up 26 115
PACE up 111 495
PACW up 47 222
Attachment E Page 27 of 178

March

PGE up 33 177
PNM up 28 177
PSEI up 43 162
PWRX up 67 319
SCL up 5 45
SRP up 24 169
TIDC up 2 14
TPWR up 3 29
ALL EIM up 459 2,710
AVA down 19 87
AZPS down 22 229
BANC down 5 88
CISO down 110 1,623
IPCO down 35 223
LADWP down 50 279
NEVP down 15 395
NWMT down 33 161
PACE down 142 470
PACW down 53 179
PGE down 40 219
PNM down 36 150
PSEI down 27 174
PWRX down 93 314
SCL down 4 49
SRP down 20 175
TIDC down 0 19
TPWR down 4 34
ALL EIM down 283 2,122
Table 8: Flexible ramping requirements
Attachment E Page 28 of 178
The flexible ramping procurement diversity savings for all the intervals averaged over the month
are shown in Table 9. The percentage savings is the average MW savings divided by the sum of
the individual BAA requirements.
January February March
Direction Up Down Up Down Up Down
Average MW saving 1,247 1,229 1,236 1,246 1,317 1,350
Sum of BAA requirements 2,487 2,148 2,364 2,217 2,488 2,370
Percentage savings 50% 57% 52% 56% 53% 57%
Table 9: Flexible ramping procurement diversity savings in Q1 2022
Flexible ramping capacity may be used in RTD to handle uncertainties in the future interval. The
RTD flexible ramping capacity is prorated to each BAA. Flexible ramping surplus MW is defined
as the awarded flexible ramping capacity in RTD minus its share, and the flexible ramping
surplus cost is defined as the flexible ramping surplus MW multiplied by the flexible ramping
EIM-wide marginal price. A positive flexible ramping surplus MW is the capacity that a BAA
provided to help other BAAs, and a negative flexible ramping surplus MW is the capacity that a
BAA received from other BAAs.
The EIM dispatch cost for a BAA with positive flexible ramping surplus MW is increased
because some capacities are used to help other BAAs. The flexible ramping surplus cost is
subtracted from the BAA’s EIM dispatch cost to reflect the true dispatch cost of a BAA. Please
see the Benefit Report Methodology for more details.

CONCLUSION
Using state-of-the-art technology to find and deliver low-cost energy to meet real-time demand,
the Western EIM demonstrates that utilities can realize financial and operational benefits
through increased coordination and optimization. In addition to these benefits, the Western EIM
provides significant environmental benefits through the reduction of renewable curtailments
during periods of oversupply.
Sharing resources across a larger geographic area reduces greenhouse gas emissions by using
renewable generation that otherwise would have been turned off. The quantified environmental
benefits from avoided curtailments of renewable generation from 2015 to-date reached 712,270
metric tons of CO2, roughly the equivalent of avoiding the emissions from 149,752 passenger
cars driven for one year.

Attachment E Page 29 of 178
APPENDIX 1: GLOSSARY OF ABBREVIATIONS

Abbreviation Description
APS Arizona Public Service
BAA Balancing Authority Area
BANC Balancing Authority of Northern California
CISO, ISO California ISO
EIM Energy Imbalance Market
FMM Fifteen Minute Market
GHG Greenhouse Gas
IPCO Idaho Power
MW Megawatt
MWh Megawatt-Hour
NVE NV Energy
PAC PacifiCorp
PACE PacifiCorp East
PACW PacifiCorp West
PGE Portland General Electric
PSE Puget Sound Energy
PWRX Powerex
RTD Real Time Dispatch
SCL Seattle City Light
SRP Salt River Project
TID Turlock Irrigation District

Attachment E Page 30 of 178

Western Energy Imbalance Market Benefits
Second Quarter 2022

July 29, 2022
Attachment E Page 31 of 178

CONTENTS

EXECUTIVE SUMMARY ........................................................................................................... 3
BACKGROUND ......................................................................................................................... 4
WEIM ECONOMIC BENEFITS IN Q2 2022 ............................................................................... 4
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION ................................................................... 5
INTER-REGIONAL TRANSFERS ............................................................................................................. 6
WHEEL-THROUGH TRANSFERS ......................................................................................................... 21
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS ....................................28
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS ..............................................29
CONCLUSION ..........................................................................................................................34
APPENDIX 1: GLOSSARY OF ABBREVIATIONS...................................................................36
Attachment E Page 32 of 178

EXECUTIVE SUMMARY
This report presents the benefits associated with
participation in the Western Energy Imbalance
Market (WEIM).
The measured benefits of participation in the WEIM
include cost savings, increased integration of
renewable energy, and improved operational
efficiencies including the reduction of
the need for real-time flexible reserves.
This analysis demonstrates the benefit of economic
dispatch in the real time market across a larger
WEIM footprint with diverse resources and geography.

Q2 2022 Gross Benefits by Participant
(millions $)
Arizona Public Service $10.14
Avista $5.16
BANC $68.09
BPA $4.36
California ISO $71.75
Idaho Power $8.44
LADWP $13.78
NV Energy $8.63
NorthWestern Energy $5.90
PacifiCorp $35.21
Portland General Electric $11.92
PNM $3.10
Puget Sound Energy $4.90
Powerex $4.66
Seattle City Light $2.90
Salt River Project $21.26
Tacoma Power $1.55
TEP $2.84
TID $2.85
Total $287.44
Gross benefits from WEIM since November 2014
$2.39 billion
ECONOMICAL
$287.44 M
Gross benefits realized due to more
efficient inter-and intra-regional
dispatch in the Fifteen-Minute
Market (FMM) and Real-Time
Dispatch (RTD)*

ENVIRONMENTAL
50,655
Metric tons of CO2** avoided
curtailments

OPERATIONAL
54%
Average reduction in flexibility
reserves across the footprint
2022
Q2 BENEFITS
Attachment E Page 33 of 178

*WEIM Quarterly Benefit Report Methodology: https://www.westerneim.com/Documents/EIM-BenefitMethodology.pdf.
**The GHG emission reduction reported is associated with the avoided curtailment only. The current market process and
counterfactual methodology cannot differentiate the GHG emissions resulting from serving ISO load via the EIM versus dispatch that
would have occurred external to the ISO without the WEIM. For more details, see
http://www.caiso.com/Documents/GreenhouseGasEmissionsTrackingReport-FrequentlyAskedQuestions.pdf
BACKGROUND
The Western EIM began financially binding operation on November 1, 2014 by optimizing
resources across the ISO and PacifiCorp Balancing Authority Areas (BAAs). NV Energy began
participating in December 2015, Arizona Public Service and Puget Sound Energy began
participating in October 2016, and Portland General Electric began participating in October
2017. Idaho Power and Powerex began participating in April 2018, and the Balancing Authority
of Northern California (BANC) began participating in April 2019. Seattle City Light and Salt River
Project began participating in April 2020.
In 2021, new balancing authorities began participating in the Western EIM, with the Turlock
Irrigation District (TID) in March 2021, the second phase of BANC in March 2021, and the Los
Angeles Department of Water and Power (LADWP) and Public Service Company of New
Mexico (PNM) in April 2021, followed by NorthWestern Energy (NWMT) starting in June 2021.
Avista Utilities (AVA) and Tacoma Power (TPWR), two utilities serving a combined 600,000
electric customers in the Pacific Northwest, became the newest members of the WEIM, with
both beginning their participation on March 2, 2022. On May 3, 2022, the Bonneville Power
Administration (BPA) and Tucson Electric Power (TEP) both Joined the WEIM.
The Western EIM footprint now includes portions of Arizona, California, Idaho, Montana,
Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, and extends to the border with
Canada.
WEIM ECONOMIC BENEFITS IN Q2 2022
Table 1 shows the estimated WEIM gross benefits by each region per month1. The monthly
savings presented show $93.66 million for April, $83.84 million for May, and $109.94 million for
June with a total estimated benefit of $287.44 million for this quarter2. This level of WEIM
benefits accrued from having additional WEIM areas participating in the market and economical
transfers displacing more expensive generation.
1 The WEIM benefits reported here are calculated based on available data. Intervals without complete data are
excluded in the calculation. The intervals excluded due to unavailable data are normally within a few percent
points of the total intervals.
2 For several quarterly estimates, CAISO benefits were calculated on a variation of the counterfactual
methodology. For CAISO only the logic had considered offline resources as part of the bid stack in the
counterfactual. In Q4 2021, CAISO identified some questionable results that drove persistent negative benefits
for CAISO when considering offline resources. Since Q4 2021, the benefit calculation for CAISO area follows
the same methodology applicable to all WEIM entities in which only online resources are used.
Attachment E Page 34 of 178
Region April May June Total
APS $3.69 $3.83 $2.62 $10.14
AVA $1.98 $1.72 $1.46 $5.16
BANC $4.71 $13.78 $49.60 $68.09
BPA $2.26 $2.10 $4.36
CISO $42.10 $14.56 $15.09 $71.75
IPCO $3.89 $2.78 $1.77 $8.44
LADWP $4.42 $5.30 $4.06 $13.78
NVE $2.49 $2.40 $3.74 $8.63
NWMT $2.50 $2.44 $0.96 $5.90
PAC $13.35 $15.43 $6.43 $35.21
PGE $3.60 $3.43 $4.89 $11.92
PNM $0.07 $1.26 $1.77 $3.10
PSE $1.79 $1.94 $1.17 $4.90
PWRX $0.64 $2.05 $1.97 $4.66
SCL $1.10 $1.00 $0.80 $2.90
SRP $5.95 $7.04 $8.27 $21.26
TPWR $0.40 $0.43 $0.72 $1.55
TEP $1.29 $1.55 $2.84
TID $0.98 $0.90 $0.97 $2.85
Total $93.66 $83.84 $109.94 $287.44
TABLE 1: Q2 2022 benefits in millions USD
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION
Since the start of the WEIM in November 2014, the cumulative economic benefits of the market
have totaled $2.39 billion. The quarterly benefits have grown over time as a result of the
participation of new BAAs, which results in benefits for both the individual BAA but also
compounds the benefits to adjacent BAAs through additional transfers. The ISO began
publishing quarterly WEIM benefit reports in April 2015.3
Graph 1 illustrates the gross economic benefits of the WEIM by quarter for each participating
BAA.
3 Prior reports are available at https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx
Attachment E Page 35 of 178

GRAPH 1: Cumulative economic benefits for each quarter by BAA
INTER-REGIONAL TRANSFERS
A significant contributor to EIM benefits is transfers across balancing areas, providing access to
lower cost supply, while factoring in the cost of compliance with greenhouse gas (GHG)
emissions regulations when energy is transferred into the ISO. As such, the transfer volumes
are a good indicator of a portion of the benefits attributed to the WEIM. Transfers can take place
in both the 15-Minute Market and Real-Time Dispatch (RTD).
Generally, transfer limits are based on transmission and interchange rights that participating
balancing authority areas make available to the WEIM, with the exception of the PacifiCorp
West (PACW) -ISO transfer limit and the Portland General Electric (PGE) -ISO transfer limit in
RTD. These RTD transfer capacities between PACW/PGE and the ISO are determined based
on the allocated dynamic transfer capability driven by system operating conditions. This report
does not quantify a BAA’s opportunity cost that the utility considered when using its transfer
rights for the EIM.
Table 2 provides the 15-minute and 5-minute WEIM transfer volumes with base schedule
transfers excluded. The WEIM entities submit inter-BAA transfers in their base schedules. The
benefits quantified in this report are only attributable to the transfers that occurred through the
WEIM. The benefits do not include any transfers attributed to transfers submitted in the base
schedules that are scheduled prior to the start of the EIM.
The transfer from BAA_x to BAA_y and the transfer from BAA_y to BAA_x are separately
reported. For example, if there is a 100 Megawatt-Hour (MWh) transfer during a 5-minute
interval, in addition to a base transfer from ISO to NVE, it will be reported as 100 MWh
Attachment E Page 36 of 178
from_BAA ISO to_BAA NEVP, and 0 MWh from_BAA NEVP to_BAA ISO in the opposite
direction. The 15-minute transfer volume is the result of optimization in the 15-minute market
using all bids and base schedules submitted into the WEIM. The 5-minute transfer volume is the
result of optimization using all bids and base schedules submitted into WEIM, based on unit
commitments determined in the 15-minute market optimization. The maximum transfer
capacities between WEIM entities are shown in Graph 2 below.

Month

From BAA

To BAA
15min WEIM transfer
(15m – base)
5min WEIM transfer
(5m – base)
AVA CISO 0 0
April AVA IPCO 20,394 16,524
AVA NWMT 6,205 5,541
AVA PACW 10,480 12,791
AVA PGE 48 62
AVA PSEI 0 1
AVA SCL 2 1
AVA TPWR 2,909 3,389
AZPS CISO 106,535 70,984
AZPS LADWP 6,478 7,404
AZPS NEVP 8,905 16,269
AZPS PACE 31,007 36,001
AZPS PNM 18,144 15,167
AZPS SRP 44,298 47,638
BANC CISO 7,941 3,264
BANC TIDC 30 145
CISO AVA 87 20
CISO AZPS 69,708 73,122
CISO BANC 85,021 100,826
CISO LADWP 76,743 80,241
CISO NEVP 73,631 78,704
CISO PACW 0 8,331
Attachment E Page 37 of 178
CISO PGE 11,468 15,791
CISO PWRX 41,738 50,391
CISO SRP 173,251 176,313
CISO TIDC 11,060 12,811
IPCO AVA 27,722 33,028
IPCO NEVP 45,717 33,915
IPCO NWMT 2,648 3,081
IPCO PACE 19,505 14,309
IPCO PACW 30,365 40,626
IPCO PSEI 0 0
IPCO SCL 9,280 10,695
LADWP AZPS 2,428 3,116
LADWP CISO 92,685 66,908
LADWP NEVP 11,999 16,419
LADWP PACE 34,565 37,081
NEVP AZPS 3,021 3,101
NEVP CISO 75,594 53,435
NEVP IPCO 34,940 45,747
NEVP LADWP 19,953 23,871
NEVP PACE 10,672 12,977
NWMT AVA 21,314 26,256
NWMT IPCO 3,773 4,108
NWMT PACE 8,283 5,869
NWMT PACW 0 4
NWMT PGE 10 29
NWMT PSEI 20 33
NWMT TPWR 3,119 3,684
PACE AZPS 163,693 150,630
Attachment E Page 38 of 178
PACE IPCO 51,491 64,637
PACE LADWP 84,511 69,606
PACE NEVP 23,563 20,808
PACE NWMT 24,092 27,565
PACE PACW 32,675 41,067
PACE SRP 0 0
PACW AVA 8,656 9,452
PACW CISO 60,528 80,218
PACW IPCO 21,181 14,035
PACW NWMT 5 5
PACW PGE 39,297 45,740
PACW PSEI 30,125 32,468
PACW SCL 998 972
PGE AVA 0 61
April PGE CISO 30,727 29,991
PGE NWMT 34 29
PGE PACW 21,307 24,282
PGE PSEI 0 0
PGE SCL 1,067 996
PGE TPWR 2,843 2,905
PNM AZPS 28,441 36,596
PNM SRP 15,061 16,969
PSEI AVA 0 1
PSEI IPCO 0 0
PSEI NWMT 8 33
PSEI PACW 34,478 37,186
PSEI PGE 0 0
PSEI PWRX 5,578 6,972
Attachment E Page 39 of 178
PSEI SCL 12,480 11,398
PSEI TPWR 5,344 5,461
PWRX CISO 0 0
PWRX PSEI 21,825 21,249
SCL AVA 1 1
SCL IPCO 1,474 1,341
SCL PACW 920 1,112
SCL PGE 1,374 1,607
SCL PSEI 12,048 16,353
SRP AZPS 4,575 6,585
SRP CISO 49,283 40,892
SRP PACE 0 0
SRP PNM 1,580 1,225
TIDC BANC 74 148
TIDC CISO 14,826 12,010
TPWR AVA 2,038 1,631
TPWR NWMT 1,796 1,493
TPWR PGE 3,053 3,061
TPWR PSEI 10,632 10,722
May AVA BPAT 4,997 3,193
AVA CISO 321 320
AVA IPCO 12,634 12,924
AVA NWMT 20,196 14,720
AVA PACW 7,459 9,702
AVA PGE 0 27
AVA PSEI 0 0
AVA SCL 8 3
AVA TPWR 1,915 1,951
Attachment E Page 40 of 178
AZPS CISO 56,237 34,273
AZPS LADWP 526 1,364
May AZPS NEVP 1,175 2,596
AZPS PACE 29,605 38,059
AZPS PNM 42,248 34,449
AZPS SRP 94,492 90,578
AZPS TEPC 11,098 11,526
BANC BPAT 1,112 1,264
BANC CISO 7,397 6,010
BANC TIDC 33 76
BPAT AVA 3,264 2,655
BPAT BANC 45 171
BPAT CISO 9,105 13,408
BPAT IPCO 1,277 1,325
BPAT LADWP 1,928 818
BPAT NEVP 389 220
BPAT NWMT 8,458 4,973
BPAT PACW 3,747 1,938
BPAT PGE 15,217 10,544
BPAT PSEI 13,355 15,088
BPAT PWRX 13,404 2,790
BPAT SCL 964 1,242
BPAT TPWR 4,105 4,675
CISO AVA 0 0
CISO AZPS 108,931 119,324
CISO BANC 140,055 144,032
CISO BPAT 5,329 9,780
CISO LADWP 65,629 76,466
Attachment E Page 41 of 178
CISO NEVP 114,631 142,138
May CISO PACW 898 13,245
CISO PGE 13,869 35,171
CISO PWRX 103,222 116,329
CISO SRP 233,061 251,791
CISO TEPC 3,935 3,799
CISO TIDC 16,133 16,403
IPCO AVA 22,176 25,776
IPCO BPAT 4,252 1,603
IPCO NEVP 4,572 2,682
IPCO NWMT 4,814 5,912
IPCO PACE 62,009 39,574
IPCO PACW 27,098 32,785
IPCO PSEI 0 0
IPCO SCL 8,334 9,465
LADWP AZPS 2,322 3,093
LADWP BPAT 1,735 800
LADWP CISO 71,092 50,524
LADWP NEVP 15,764 21,057
LADWP PACE 28,235 32,900
LADWP TEPC 0 83
NEVP AZPS 9,672 8,583
NEVP BPAT 743 502
NEVP CISO 100,199 65,338
NEVP IPCO 18,269 20,665
NEVP LADWP 24,255 27,189
NEVP PACE 62,305 75,527
NWMT AVA 13,111 16,444
Attachment E Page 42 of 178
NWMT BPAT 8,236 5,871
May NWMT IPCO 2,319 3,858
NWMT PACE 18,733 13,988
NWMT PACW 0 1
NWMT PGE 31 16
NWMT PSEI 43 7
NWMT TPWR 1,679 2,136
PACE AZPS 188,726 166,512
PACE IPCO 59,360 86,462
PACE LADWP 107,420 95,825
PACE NEVP 95,324 73,337
PACE NWMT 24,644 28,147
PACE PACW 17,234 21,078
PACE SRP 0 0
PACE TEPC 2,868 1,649
PACW AVA 10,429 11,849
PACW BPAT 6,114 8,427
PACW CISO 40,522 74,582
PACW IPCO 41,422 36,860
PACW NWMT 1 1
PACW PGE 61,168 52,085
PACW PSEI 23,739 24,918
May PACW SCL 1,476 1,513
PGE AVA 24 28
PGE BPAT 10,097 9,760
PGE CISO 25,689 23,700
PGE NWMT 38 12
PGE PACW 18,473 26,855
Attachment E Page 43 of 178
PGE PSEI 0 2
PGE SCL 1,396 1,621
PGE TPWR 5,783 7,298
PNM AZPS 7,443 9,283
PNM SRP 3,717 3,799
PNM TEPC 19,551 19,898
PSEI AVA 0 0
PSEI BPAT 23,116 24,524
PSEI IPCO 0 0
PSEI NWMT 14 3
PSEI PACW 13,399 14,445
PSEI PGE 0 2
May PSEI PWRX 19,784 20,398
PSEI SCL 7,287 7,266
PSEI TPWR 5,988 6,051
PWRX BPAT 3,143 2,461
PWRX CISO 0 0
PWRX PSEI 9,627 9,607
SCL AVA 4 2
SCL BPAT 1,583 1,514
SCL IPCO 6,414 6,157
SCL PACW 502 652
SCL PGE 1,001 1,031
SCL PSEI 10,783 13,798
SRP AZPS 8,960 13,548
SRP CISO 35,923 32,898
SRP PACE 0 0
SRP PNM 777 1,096
Attachment E Page 44 of 178
SRP TEPC 80,131 91,726
May TEPC AZPS 250 72
TEPC CISO 13,630 2,924
TEPC LADWP 0 0
TEPC PACE 158 225
TEPC PNM 8,882 6,798
TEPC SRP 8,763 17,041
TIDC BANC 148 226
TIDC CISO 7,454 6,662
TPWR AVA 991 1,194
TPWR BPAT 5,938 5,746
TPWR NWMT 594 371
TPWR PGE 3,586 2,963
TPWR PSEI 6,116 7,682
June AVA BPAT 5,697 406
AVA CISO 0 0
AVA IPCO 19,387 9,691
AVA NWMT 8,671 8,888
AVA PACW 4,100 2,252
AVA PGE 0 0
AVA PSEI 0 0
AVA SCL 7 0
AVA TPWR 0 0
AZPS CISO 62,964 27,082
AZPS LADWP 20,883 18,279
AZPS NEVP 8,203 9,826
AZPS PACE 78,792 95,501
AZPS PNM 28,526 29,050
Attachment E Page 45 of 178
AZPS SRP 30,063 17,897
June AZPS TEPC 26,059 23,874
BANC BPAT 2,035 0
BANC CISO 6,626 9,577
BANC TIDC 161 309
BPAT AVA 5,927 3,735
BPAT BANC 136 0
BPAT CISO 970 2,042
BPAT IPCO 1,597 31
BPAT LADWP 2,748 0
BPAT NEVP 267 0
BPAT NWMT 25,521 3,725
BPAT PACW 9,990 3,840
BPAT PGE 26,200 16,429
BPAT PSEI 28,247 28,987
BPAT PWRX 13,371 0
BPAT SCL 5,389 4,838
BPAT TPWR 11,342 9,848
CISO AVA 0 0
CISO AZPS 95,766 117,824
CISO BANC 189,226 186,320
CISO BPAT 862 1,968
CISO LADWP 92,507 120,240
CISO NEVP 114,963 134,766
CISO PACW 5,909 48,873
CISO PGE 22,744 62,760
CISO PWRX 63,709 83,326
CISO SRP 205,170 240,137
Attachment E Page 46 of 178
CISO TEPC 2,011 2,538
June CISO TIDC 9,640 9,452
IPCO AVA 21,875 23,515
IPCO BPAT 1,411 0
IPCO NEVP 23,059 11,967
IPCO NWMT 4,394 7,790
IPCO PACE 25,922 15,769
IPCO PACW 37,118 19,512
IPCO PSEI 0 0
IPCO SCL 7,773 10,522
LADWP AZPS 3,850 5,604
LADWP BPAT 5,096 0
LADWP CISO 14,438 6,421
LADWP NEVP 13,680 17,035
LADWP PACE 13,217 12,022
LADWP TEPC 0 0
NEVP AZPS 6,668 7,636
NEVP BPAT 1,347 0
NEVP CISO 43,430 10,628
NEVP IPCO 70,804 77,974
NEVP LADWP 39,289 34,228
NEVP PACE 43,582 47,042
NWMT AVA 21,277 19,088
NWMT BPAT 6,028 625
NWMT IPCO 3,571 2,858
NWMT PACE 5,959 2,625
NWMT PACW 282 0
NWMT PGE 174 0
Attachment E Page 47 of 178
NWMT PSEI 77 0
NWMT TPWR 1,229 2,492
June PACE AZPS 74,780 55,992
PACE IPCO 57,496 62,736
PACE LADWP 49,749 51,623
PACE NEVP 39,964 22,428
PACE NWMT 30,729 27,130
PACE PACW 51,580 40,357
PACE SRP 0 0
PACE TEPC 1,536 1,103
PACW AVA 15,528 16,880
PACW BPAT 4,176 656
PACW CISO 7,124 21,286
PACW IPCO 14,579 13,248
PACW NWMT 0 0
PACW PGE 54,893 47,383
PACW PSEI 22,296 29,307
PACW SCL 1,680 2,024
PGE AVA 0 0
June PGE BPAT 9,824 14,726
PGE CISO 9,436 5,703
PGE NWMT 108 0
PGE PACW 19,654 18,578
PGE PSEI 3 0
PGE SCL 1,469 1,868
PGE TPWR 1,339 2,453
PNM AZPS 24,924 25,722
PNM SRP 4,149 2,826
Attachment E Page 48 of 178
PNM TEPC 25,169 24,931
June PSEI AVA 0 0
PSEI BPAT 9,819 13,642
PSEI IPCO 0 0
PSEI NWMT 17 0
PSEI PACW 11 0
PSEI PGE 1 0
PSEI PWRX 15,518 16,414
PSEI SCL 20,565 17,180
PSEI TPWR 6,136 6,662
PWRX BPAT 4,255 34
PWRX CISO 0 0
PWRX PSEI 12,295 12,347
SCL AVA 17 0
SCL BPAT 118 46
SCL IPCO 9,305 6,415
SCL PACW 1,098 798
SCL PGE 1,170 867
SCL PSEI 3,912 6,684
SRP AZPS 15,979 19,695
SRP CISO 50,824 38,195
SRP PACE 0 0
SRP PNM 947 1,651
SRP TEPC 65,964 77,789
TEPC AZPS 399 0
TEPC CISO 16,959 10,582
TEPC LADWP 0 0
TEPC PACE 864 1,578
Attachment E Page 49 of 178

TABLE 2: Energy transfers (MWh) in the FMM and RTD markets for Q2 2022

TEPC PNM 17,131 13,585
June TEPC SRP 12,777 10,796
TIDC BANC 203 0
TIDC CISO 12,951 14,046
TPWR AVA 0 0
TPWR BPAT 1,275 2,462
TPWR NWMT 2,957 1,689
TPWR PGE 2,372 1,449
TPWR PSEI 7,000 9,278
Attachment E Page 50 of 178

GRAPH 2: Estimated maximum transfer capacity
WHEEL-THROUGH TRANSFERS
As the footprint of the WEIM grows, wheel-through transfers may become more common. In
order to derive the wheel-through transfers for each WEIM BAA, the ISO uses the following
calculation for every real-time interval dispatch:

• Total import: summation of transfers above base transfers coming into the WEIM
BAA under analysis
• Total export: summation of all transfers above base transfers going out of the WEIM
BAA under analysis
• Net import: the maximum of zero or the difference between total imports and total
exports
Attachment E Page 51 of 178
• Net export: the maximum of zero or the difference between total exports and total
imports
• Wheel-through: the minimum of the WEIM transfers into (total import) or WEIM
transfer out (total export) of a BAA for a given interval

All wheel-through transfers are summed over both the month and the quarter.

Currently, a WEIM entity facilitating a wheel through receives no direct financial benefit for
facilitating the wheel; only the sink and source directly benefit. As part of the WEIM
Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel
through volumes to assess whether, after the addition of new WEIM entities, there is a potential
future need to pursue a market solution to address the equitable sharing of wheeling benefits.

The ISO will continue to track the volume of wheel-through transfers in the WEIM market in the
quarterly reports.

This volume reflects the total wheel-through transfers for each WEIM BAA, regardless of the
potential paths used to wheel through. The net imports and exports estimated in this section
reflect the overall volume of net imports and exports; in contrast, the imports and exports
provided in Table 2 reflect the gross transfers between two WEIM BAAs.

The metric is measured as energy in MWh for each month and the corresponding calendar
quarter, as shown in Tables 3 through 6 and Graphs 3 through 6.

BAA Net Export Net Import Wheel Through
AVA

62,566

151,797

39,821
AZPS

127,260

325,482

500,557
BANC

19,328

430,405

1,317
BPAT

93,752

70,440

39,571
CISO

2,160,868

441,541

372,362
IPCO

118,497

263,568

224,029
LADWP

84,341

418,433

188,721
NEVP

183,385

273,110

331,057
NWMT

40,364

71,478

69,628
PACE

824,667

198,626

284,023
PACW

248,054

142,851

277,458
Attachment E Page 52 of 178
PGE

88,154

214,303

82,713
PNM

113,932

76,929

26,093
PSEI

79,693

130,587

107,944
PWRX

16,732

267,654

28,967
SCL

32,420

55,646

25,956
SRP

169,868

720,349

155,433
TEPC

58,079

253,395

5,521
TIDC

32,509

38,613

583
TPWR

19,923

29,186

29,818

TABLE 3: Estimated wheel-through transfers in Q2 2022

GRAPH 3: Estimated wheel-through transfers in Q1 2022

BAA Net Export Net Import Wheel Through
AVA

22,848

54,990

15,462
AZPS

30,459

110,147

163,004
Attachment E Page 53 of 178
BANC

3,272

100,837

137
CISO

494,339

255,490

102,212
IPCO

46,954

57,693

88,700
LADWP

41,281

98,879

82,243
NEVP

55,128

82,111

84,004
NWMT

17,552

15,316

22,431
PACE

294,558

27,639

79,755
PACW

72,220

53,570

111,828
PGE

41,277

49,303

16,987
PNM

52,128

14,956

1,436
PSEI

29,559

49,335

31,492
PWRX

10,937

47,051

10,312
SCL

13,337

16,984

7,077
SRP

45,994

238,211

2,708
TIDC

12,011

12,809

147
TPWR

8,702

7,234

8,205

TABLE 4: Estimated wheel-through transfers in April 2022

Attachment E Page 54 of 178

GRAPH 4: Estimated wheel-through transfers in April 2022

BAA Net Export Net Import Wheel Through
AVA

29,449

44,558

13,391
AZPS

20,765

128,333

192,081
BANC

6,170

143,248

1,180
BPAT

32,468

48,067

27,379
CISO

769,360

151,522

159,118
IPCO

47,285

97,739

70,512
LADWP

25,667

118,873

82,789
NEVP

59,358

103,585

138,445
NWMT

13,868

25,684

28,454
PACE

332,732

60,441

140,277
PACW

114,734

24,756

95,945
PGE

36,218

68,781

33,058
Attachment E Page 55 of 178
PNM

21,064

30,427

11,916
PSEI

37,049

35,461

35,640
PWRX

2,802

130,251

9,266
SCL

14,237

12,194

8,916
SRP

45,112

269,052

94,156
TEPC

22,104

123,726

4,955
TIDC

6,752

16,343

135
TPWR

5,415

9,570

12,541

TABLE 5: Estimated wheel-through transfers in May 2022

GRAPH 5: Estimated wheel-through transfers in May 2022

BAA Net Export Net Import Wheel Through
AVA

10,269

52,249

10,968
Attachment E Page 56 of 178
AZPS

76,036

87,001

145,473
BANC

9,886

186,320

-
BPAT

61,283

22,373

12,192
CISO

897,170

34,529

111,033
IPCO

24,257

108,136

64,817
LADWP

17,394

200,681

23,689
NEVP

68,899

87,414

108,608
NWMT

8,944

30,478

18,743
PACE

197,378

110,546

63,991
PACW

61,100

64,525

69,685
PGE

10,660

96,220

32,669
PNM

40,739

31,545

12,741
PSEI

13,085

45,791

40,812
PWRX

2,992

90,351

9,389
SCL

4,846

26,468

9,964
SRP

78,761

213,086

58,569
TEPC

35,975

129,669

567
TIDC

13,745

9,460

300
TPWR

5,806

12,383

9,072

TABLE 6: Estimated wheel-through transfers in June 2022

Attachment E Page 57 of 178

GRAPH 6: Estimated wheel-through transfers in June 2022
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS
The WEIM benefit calculation includes the economic benefits that can be attributed to avoided
renewable curtailment within the ISO footprint. If not for energy transfers facilitated by the
WEIM, some renewable generation located within the ISO would have been curtailed via either
economic or exceptional dispatch. The total avoided renewable curtailment volume in MWh for
Q2 2022 was calculated to be 31,330 MWh (April) + 41,764 MWh (May) + 45,259 MWh (June) =
118,352 MWh total.
There are environmental benefits of avoided renewable curtailment as well. Under the
assumption that avoided renewable curtailments displace production from other resources at a
default emission rate of 0.428 metric tons CO2/MWh, avoided curtailments displaced an
estimated 50,655 metric tons of CO2 for Q2 2022. Avoided renewable curtailments also may
have contributed to an increased volume of renewable credits that would otherwise have been
unavailable. This report does not quantify the additional value in dollars associated with this
benefit. Total estimated reductions in the curtailment of renewable energy in the ISO footprint,
along with the associated reductions in CO2, are shown in Table 7.
Year Quarter MWh Eq. Tons CO2
1 8,860 3,792
2015 2 3,629 1,553
3 828 354
4 17,765 7,521
Attachment E Page 58 of 178
1 112,948 48,342
2016 2 158,806 67,969
3 33,094 14,164
4 23,390 10,011
1 52,651 22,535
2017 2 67,055 28,700
3 23,331 9,986
4 18,060 7,730
1 65,860 28,188
2018 2 129,128 55,267
3 19,032 8,146
4 23,425 10,026
1 52,254 22,365
2019 2 132,937 56,897
3 33,843 14,485
4 35,254 15,089
1 86,740 37,125
2020 2 147,514 63,136
3 37,548 16,071
4 39,956 17,101
2021 1 76,147 32,591
2 109,059 46,677
3 23,042 9,862
4 38,044 16,283
2022 1 94,168 40,304
2 118,352 50,655
Total 1,782,720 762,925

TABLE 7: Total reduction in curtailment of renewable energy and associated reductions in CO2
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS
The WEIM facilitates procurement of flexible ramping capacity in the FMM to address variability
that may occur in the RTD. Because variability across different BAAs may happen in opposite
Attachment E Page 59 of 178
directions, the flexible ramping requirement for the entire WEIM footprint can be less than the
sum of individual BAA’s requirements. This difference is known as flexible ramping procurement
diversity savings.
Starting in 2016, the ISO replaced the flexible ramping constraint with flexible ramping products
that provide both upward and downward ramping. The minimum and maximum flexible ramping
requirements for each BAA and for each direction are listed in Table 8.
Month BAA Direction Minimum
requirement
Maximum
requirement
AVA up 21 91
April AZPS up 30 286
BANC up 7 113
CISO up 367 2,072
IPCO up 34 159
LADWP up 59 315
NEVP up 26 332
NWMT up 36 118
PACE up 116 516
PACW up 45 190
PGE up 33 177
PNM up 40 177
PSEI up 39 203
PWRX up 77 319
SCL up 5 45
SRP up 32 152
April TIDC up 2 14
TPWR up 3 29
ALL EIM up 471 2,759
AVA down 22 87
AZPS down 38 229
BANC down 5 88
CISO down 148 1,682
IPCO down 36 223
Attachment E Page 60 of 178
LADWP down 45 279
NEVP down 16 395
NWMT down 31 135
PACE down 116 470
PACW down 60 186
PGE down 62 219
PNM down 49 163
PSEI down 27 174
PWRX down 76 314
SCL down 3 38
SRP down 17 160
TIDC down 1 19
TPWR down 4 34
ALL EIM down 326 2,122
AVA up 21 84
May AZPS up 33 286
BANC up 7 113
BPAT up 85 236
CISO up 363 2,072
IPCO up 38 159
LADWP up 66 315
NEVP up 0 332
NWMT up 36 129
May PACE up 118 516
PACW up 49 190
PGE up 51 277
PNM up 40 149
PSEI up 41 203
PWRX up 71 319
SCL up 5 45
SRP up 25 169
Attachment E Page 61 of 178
TEPC up 37 135
TIDC up 0 14
TPWR up 4 25
ALL WEIM up 359 2,759
AVA down 33 84
AZPS down 38 229
BANC down 3 88
BPAT down 139 385
CISO down 142 1,682

May
IPCO down 61 223
LADWP down 51 279
NEVP down 0 395
NWMT down 38 135
PACE down 116 470
PACW down 55 221
PGE down 55 219
PNM down 40 163
PSEI down 36 174
PWRX down 59 314
SCL down 2 37
SRP down 15 143
TEPC down 33 149
TIDC down 1 19
TPWR down 3 19
ALL EIM down 337 2,122

June

AVA up 17 84
AZPS up 40 286
BANC up 7 113
BPAT up 64 407
CISO up 363 1,967
IPCO up 41 159
Attachment E Page 62 of 178

June

June
LADWP up 66 315
NEVP up 0 332
NWMT up 24 128
PACE up 135 516
PACW up 47 200
PGE up 48 177
PNM up 34 179
PSEI up 40 203
PWRX up 71 225
SCL up 5 45
SRP up 30 169
TEPC up 42 135
TIDC up 0 15
TPWR up 4 26
ALL WEIM up 358 2,560
AVA down 23 84
AZPS down 39 229
BANC down 3 88
BPAT down 139 402
CISO down 149 1,682
IPCO down 63 223
LADWP down 56 279
NEVP down 0 327
NWMT down 30 156
PACE down 129 470
PACW down 57 221
PGE down 65 219
PNM down 45 163
PSEI down 33 174
PWRX down 67 239
SCL down 2 34
Attachment E Page 63 of 178
SRP down 22 159
TEPC down 26 134
TIDC down 1 19
TPWR down 2 24
ALL WEIM down 342 2,122
Table 8: Flexible ramping requirements
The flexible ramping procurement diversity savings for all the intervals averaged over the month
are shown in Table 9. The percentage savings is the average MW savings divided by the sum of
the individual BAA requirements.
April May June
Direction Up Down Up Down Up Down
Average MW saving 1,387

1,397 1,676 1,428 1,747 1,504
Sum of BAA requirements 2,708 2,472 3,010 2,945 3,056 2,880
Percentage savings 51% 57% 56% 48% 57% 52%
Table 9: Flexible ramping procurement diversity savings in Q2 2022
Flexible ramping capacity may be used in RTD to handle uncertainties in the future interval. The
RTD flexible ramping capacity is prorated to each BAA. Flexible ramping surplus MW is defined
as the awarded flexible ramping capacity in RTD minus its share, and the flexible ramping
surplus cost is defined as the flexible ramping surplus MW multiplied by the flexible ramping
WEIM-wide marginal price. A positive flexible ramping surplus MW is the capacity that a BAA
provided to help other BAAs, and a negative flexible ramping surplus MW is the capacity that a
BAA received from other BAAs.
The EIM dispatch cost for a BAA with positive flexible ramping surplus MW is increased
because some capacities are used to help other BAAs. The flexible ramping surplus cost is
subtracted from the BAA’s WEIM dispatch cost to reflect the true dispatch cost of a BAA. Please
see the Benefit Report Methodology for more details.

CONCLUSION
Using state-of-the-art technology to find and deliver low-cost energy to meet real-time demand,
the WEIM demonstrates that utilities can realize financial and operational benefits through
increased coordination and optimization. In addition to these benefits, the WEIM provides
significant environmental benefits through the reduction of renewable curtailments during
periods of oversupply.
Attachment E Page 64 of 178
Sharing resources across a larger geographic area reduces greenhouse gas emissions by using
renewable generation that otherwise would have been turned off. The quantified environmental
benefits from avoided curtailments of renewable generation from 2015 to-date reached 762,925
metric tons of CO2, roughly the equivalent of avoiding the emissions from 160,402 passenger
cars driven for one year.

Attachment E Page 65 of 178
APPENDIX 1: GLOSSARY OF ABBREVIATIONS

Abbreviation Description
APS Arizona Public Service
AVA Avista Utilities
BAA Balancing Authority Area
BANC Balancing Authority of Northern California
BPA Bonneville Power Administration
CISO, ISO California ISO
EIM Energy Imbalance Market
FMM Fifteen Minute Market
GHG Greenhouse Gas
IPCO Idaho Power
LADWP Los Angeles Department of Water and Power
MW Megawatt
MWh Megawatt-Hour
NVE NV Energy
PAC PacifiCorp
PACE PacifiCorp East
PACW PacifiCorp West
PGE Portland General Electric
PSE Puget Sound Energy
PWRX Powerex
RTD Real Time Dispatch
SCL Seattle City Light
SRP Salt River Project
TEP Tucson Electric Power
TID Turlock Irrigation District
TPWR Tacoma Power
WEIM Western Energy Imbalance Market

Attachment E Page 66 of 178

Western Energy Imbalance Market Benefits
Third Quarter 2022

October 31, 2022
Attachment E Page 67 of 178

CONTENTS

EXECUTIVE SUMMARY ........................................................................................................... 3
BACKGROUND ......................................................................................................................... 4
WEIM ECONOMIC BENEFITS IN Q3 2022 ............................................................................... 4
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION ................................................................... 5
INTER-REGIONAL TRANSFERS ............................................................................................................. 6
WHEEL-THROUGH TRANSFERS ......................................................................................................... 22
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS ....................................30
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS ..............................................32
CONCLUSION ..........................................................................................................................37
APPENDIX 1: GLOSSARY OF ABBREVIATIONS...................................................................38
Attachment E Page 68 of 178

EXECUTIVE SUMMARY
This report presents the benefits associated with
participation in the Western Energy Imbalance
Market (WEIM).
The measured benefits of participation in the
WEIM include cost savings, increased integration
of renewable energy, and improved operational
efficiencies including the reduction of
the need for real-time flexible reserves.
This analysis demonstrates the benefit of
economic dispatch in the real time market across a larger
WEIM footprint with diverse resources and geography.

Q3 2022 Gross Benefits by Participant
(millions $)
Arizona Public Service $36.42
Avista $7.24
BANC $111.54
BPA $9.07
California ISO $65.99
Idaho Power $12.04
LADWP $25.79
NV Energy $62.38
NorthWestern Energy $6.84
PacifiCorp $84.54
Portland General Electric $19.64
PNM $16.63
Puget Sound Energy $7.59
Powerex $2.76
Seattle City Light $3.67
Salt River Project $19.28
Tacoma Power $3.84
TEP $26.88
TID $4.37
Total $526.51
Gross benefits from WEIM since November 2014
$2.91 billion
ECONOMICAL
$526.51 M
Gross benefits realized due to more
efficient inter-and intra-regional
dispatch in the Fifteen-Minute
Market (FMM) and Real-Time
Dispatch (RTD)*

ENVIRONMENTAL
18,176
Metric tons of CO2** avoided
curtailments

OPERATIONAL
61%
Average reduction in flexibility
reserves across the footprint
2022
Q3 BENEFITS
Attachment E Page 69 of 178

*WEIM Quarterly Benefit Report Methodology: https://www.westerneim.com/Documents/EIM-BenefitMethodology.pdf.
**The GHG emission reduction reported is associated with the avoided curtailment only. The current market process and
counterfactual methodology cannot differentiate the GHG emissions resulting from serving ISO load via the EIM versus dispatch that
would have occurred external to the ISO without the WEIM. For more details, see
http://www.caiso.com/Documents/GreenhouseGasEmissionsTrackingReport-FrequentlyAskedQuestions.pdf
BACKGROUND
The Western EIM began financially binding operation on November 1, 2014 by optimizing
resources across the ISO and PacifiCorp Balancing Authority Areas (BAAs). NV Energy began
participating in December 2015, Arizona Public Service and Puget Sound Energy began
participating in October 2016, and Portland General Electric began participating in October
2017. Idaho Power and Powerex began participating in April 2018, and the Balancing Authority
of Northern California (BANC) began participating in April 2019. Seattle City Light and Salt River
Project began participating in April 2020.
In 2021, new balancing authorities began participating in the Western EIM, with the Turlock
Irrigation District (TID) in March 2021, the second phase of BANC in March 2021, and the Los
Angeles Department of Water and Power (LADWP) and Public Service Company of New
Mexico (PNM) in April 2021, followed by NorthWestern Energy (NWMT) starting in June 2021.
Avista Utilities (AVA) and Tacoma Power (TPWR), two utilities serving a combined 600,000
electric customers in the Pacific Northwest, became the newest members of the WEIM, with
both beginning their participation on March 2, 2022. On May 3, 2022, the Bonneville Power
Administration (BPA) and Tucson Electric Power (TEP) both Joined the WEIM.
The Western EIM footprint now includes portions of Arizona, California, Idaho, Montana,
Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, and extends to the border with
Canada.
WEIM ECONOMIC BENEFITS IN Q3 2022
Table 1 shows the estimated WEIM gross benefits by each region per month1. The monthly
savings presented show $141.35 million for July, $175.44 million for August, and $209.72
million for September with a total estimated benefit of $526.51 million for this quarter2. This level
of WEIM benefits accrued from having additional WEIM areas participating in the market and
economical transfers displacing more expensive generation.
1 The WEIM benefits reported here are calculated based on available data. Intervals without complete data are
excluded in the calculation. The intervals excluded due to unavailable data are normally within a few percent
points of the total intervals.
2 For several quarterly estimates, CAISO benefits were calculated on a variation of the counterfactual
methodology. For CAISO only the logic had considered offline resources as part of the bid stack in the
counterfactual. In Q4 2021, CAISO identified some questionable results that drove persistent negative benefits
for CAISO when considering offline resources. Since Q4 2021, the benefit calculation for CAISO area follows
the same methodology applicable to all WEIM entities in which only online resources are used.
Attachment E Page 70 of 178
Region July August September Total
APS $3.59 $6.13 $26.70 $36.42
AVA $0.92 $2.33 $3.99 $7.24
BANC $51.75 $41.88 $17.91 $111.54
BPA $2.47 $1.81 $4.79 $9.07
CISO $26.84 $33.10 $6.05 $65.99
IPCO $2.41 $3.56 $6.07 $12.04
LADWP $2.74 $5.15 $17.90 $25.79
NVE $10.67 $20.42 $31.29 $62.38
NWMT $0.94 $2.86 $3.04 $6.84
PAC $19.83 $29.33 $35.38 $84.54
PGE $2.84 $6.37 $10.43 $19.64
PNM $2.70 $3.80 $10.13 $16.63
PSE $1.36 $2.63 $3.60 $7.59
PWRX $0.50 $0.70 $1.56 $2.76
SCL $0.99 $1.21 $1.47 $3.67
SRP $2.91 $4.79 $11.58 $19.28
TPWR $1.10 $1.48 $1.26 $3.84
TEP $6.19 $6.57 $14.12 $26.88
TID $0.60 $1.32 $2.45 $4.37
Total $141.35 $175.44 $209.72 $526.51
TABLE 1: Q3 2022 benefits in millions USD
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION
Since the start of the WEIM in November 2014, the cumulative economic benefits of the market
have totaled $2.91 billion. The quarterly benefits have grown over time as a result of the
participation of new BAAs, which results in benefits for both the individual BAA but also
compounds the benefits to adjacent BAAs through additional transfers. The ISO began
publishing quarterly WEIM benefit reports in April 2015.3
Graph 1 illustrates the gross economic benefits of the WEIM by quarter for each participating
BAA.
3 Prior reports are available at https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx
Attachment E Page 71 of 178

GRAPH 1: Cumulative economic benefits for each quarter by BAA
INTER-REGIONAL TRANSFERS
A significant contributor to EIM benefits is transfers across balancing areas, providing access to
lower cost supply, while factoring in the cost of compliance with greenhouse gas (GHG)
emissions regulations when energy is transferred into the ISO. As such, the transfer volumes
are a good indicator of a portion of the benefits attributed to the WEIM. Transfers can take place
in both the 15-Minute Market and Real-Time Dispatch (RTD).
Generally, transfer limits are based on transmission and interchange rights that participating
balancing authority areas make available to the WEIM, with the exception of the PacifiCorp
West (PACW) -ISO transfer limit and the Portland General Electric (PGE) -ISO transfer limit in
RTD. These RTD transfer capacities between PACW/PGE and the ISO are determined based
on the allocated dynamic transfer capability driven by system operating conditions. This report
does not quantify a BAA’s opportunity cost that the utility considered when using its transfer
rights for the EIM.
Table 2 provides the 15-minute and 5-minute WEIM transfer volumes with base schedule
transfers excluded. The WEIM entities submit inter-BAA transfers in their base schedules. The
benefits quantified in this report are only attributable to the transfers that occurred through the
WEIM. The benefits do not include any transfers attributed to transfers submitted in the base
schedules that are scheduled prior to the start of the EIM.
The transfer from BAA_x to BAA_y and the transfer from BAA_y to BAA_x are separately
reported. For example, if there is a 100 Megawatt-Hour (MWh) transfer during a 5-minute
interval, in addition to a base transfer from ISO to NVE, it will be reported as 100 MWh
from_BAA ISO to_BAA NEVP, and 0 MWh from_BAA NEVP to_BAA ISO in the opposite
Attachment E Page 72 of 178
direction. The 15-minute transfer volume is the result of optimization in the 15-minute market
using all bids and base schedules submitted into the WEIM. The 5-minute transfer volume is the
result of optimization using all bids and base schedules submitted into WEIM, based on unit
commitments determined in the 15-minute market optimization. The maximum transfer
capacities between WEIM entities are shown in Graph 2 below.

Month

From BAA

To BAA
15min WEIM transfer
(15m – base)
5min WEIM transfer
(5m – base)
AVA BPAT 4,287 2,169
July AVA CISO 0 0
AVA IPCO 9,467 8,216
AVA NWMT 7,071 6,723
AVA PACW 2,634 1,617
AVA PGE 23 0
AVA PSEI 0 0
AVA SCL 16 0
AVA TPWR 0 0
AZPS CISO 111,143 63,693
AZPS LADWP 9,350 7,932
AZPS NEVP 2,638 4,757
AZPS PACE 17,424 28,600
AZPS PNM 50,174 57,898
AZPS SRP 41,553 33,295
AZPS TEPC 42,246 47,294
BANC BPAT 0 0
BANC CISO 3,944 5,031
BANC TIDC 139 0
BPAT AVA 6,898 6,811
BPAT BANC 0 0
BPAT CISO 4,088 9,589
July BPAT IPCO 372 55
Attachment E Page 73 of 178
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 13,563 3,313
BPAT PACW 5,930 4,180
BPAT PGE 42,908 42,969
BPAT PSEI 8,809 13,022
BPAT PWRX 4,381 0
BPAT SCL 1,549 1,486
BPAT TPWR 6,350 9,643
CISO AVA 0 0
CISO AZPS 54,583 86,952
CISO BANC 181,272 182,290
CISO BPAT 1,458 2,114
CISO LADWP 36,070 50,833
CISO NEVP 37,916 59,924
CISO PACW 2,559 23,995
CISO PGE 5,239 23,912
CISO PWRX 35,629 49,711
CISO SRP 80,498 107,934
CISO TEPC 1,016 1,759
CISO TIDC 7,072 7,916
IPCO AVA 10,613 9,803
IPCO BPAT 2,124 130
IPCO NEVP 28,676 13,382
IPCO NWMT 1,615 1,755
IPCO PACE 5,734 2,170
IPCO PACW 19,482 14,540
July IPCO PSEI 0 0
Attachment E Page 74 of 178
IPCO SCL 4,782 5,510
LADWP AZPS 12,019 19,249
LADWP BPAT 0 0
LADWP CISO 97,069 67,308
LADWP NEVP 20,123 29,621
LADWP PACE 12,257 12,380
LADWP TEPC 0 0
NEVP AZPS 14,928 19,814
NEVP BPAT 0 0
NEVP CISO 166,873 96,719
NEVP IPCO 38,578 61,322
NEVP LADWP 37,726 39,438
NEVP PACE 21,017 22,867
NWMT AVA 25,660 32,558
NWMT BPAT 6,800 1,482
NWMT IPCO 6,893 5,565
NWMT PACE 2,161 1,411
NWMT PACW 121 0
NWMT PGE 78 0
NWMT PSEI 67 0
NWMT TPWR 0 0
PACE AZPS 138,901 113,551
PACE IPCO 69,102 79,540
PACE LADWP 143,300 135,756
PACE NEVP 68,744 47,347
PACE NWMT 33,804 37,153
PACE PACW 42,886 50,124
July PACE SRP 0 0
Attachment E Page 75 of 178
PACE TEPC 4,531 4,251
PACW AVA 6,925 6,146
PACW BPAT 5,421 1,831
PACW CISO 19,835 46,193
PACW IPCO 17,769 11,637
PACW NWMT 3 0
PACW PGE 44,907 48,842
PACW PSEI 15,553 17,562
PACW SCL 1,022 963
PGE AVA 0 0
PGE BPAT 17,891 20,275
PGE CISO 24,773 18,917
PGE NWMT 54 0
PGE PACW 22,315 24,145
PGE PSEI 0 0
PGE SCL 742 772
PGE TPWR 1 0
PNM AZPS 26,937 22,200
PNM SRP 1,511 1,186
PNM TEPC 27,932 25,573
PSEI AVA 0 0
PSEI BPAT 29,993 28,698
PSEI IPCO 0 0
PSEI NWMT 25 0
PSEI PACW 3 0
PSEI PGE 0 0
PSEI PWRX 16,808 17,224
July PSEI SCL 9,600 8,216
Attachment E Page 76 of 178
PSEI TPWR 11,218 12,442
PWRX BPAT 7,222 0
PWRX CISO 0 0
PWRX PSEI 10,170 10,621
SCL AVA 9 0
SCL BPAT 408 462
SCL IPCO 7,498 7,211
SCL PACW 1,252 1,362
SCL PGE 1,522 1,676
SCL PSEI 7,166 11,096
SRP AZPS 9,575 9,812
SRP CISO 63,151 54,223
SRP PACE 0 0
SRP PNM 295 459
SRP TEPC 49,231 56,964
TEPC AZPS 1,431 27
TEPC CISO 28,437 18,693
TEPC LADWP 0 0
TEPC PACE 654 247
TEPC PNM 11,791 11,266
TEPC SRP 4,234 4,914
TIDC BANC 84 0
TIDC CISO 14,925 13,664
TPWR AVA 0 0
TPWR BPAT 4,512 4,975
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 2,975 5,532
Attachment E Page 77 of 178
August AVA BPAT 4,749 3,178
AVA CISO 0 0
AVA IPCO 16,711 16,925
AVA NWMT 2,408 2,078
AVA PACW 1,489 1,755
AVA PGE 0 0
AVA PSEI 0 0
AVA SCL 12 0
AVA TPWR 46 80
AZPS CISO 164,404 114,804
AZPS LADWP 9,973 9,821
AZPS NEVP 7,196 10,283
AZPS PACE 15,325 12,656
AZPS PNM 23,748 21,788
AZPS SRP 34,289 28,488
AZPS TEPC 38,082 41,405
BANC BPAT 0 0
BANC CISO 9,661 6,010
BANC TIDC 59 0
BPAT AVA 5,576 4,395
BPAT BANC 0 0
BPAT CISO 5,429 11,676
BPAT IPCO 393 33
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 9,143 1,403
BPAT PACW 2,864 1,809
August BPAT PGE 25,385 23,619
Attachment E Page 78 of 178
BPAT PSEI 10,251 11,372
BPAT PWRX 4,757 55
BPAT SCL 1,838 1,335
BPAT TPWR 8,128 9,806
CISO AVA 0 0
CISO AZPS 8,805 17,526
CISO BANC 180,068 194,375
CISO BPAT 2,294 3,935
CISO LADWP 15,141 25,640
CISO NEVP 9,784 13,344
CISO PACW 2,157 17,615
CISO PGE 15,394 41,675
CISO PWRX 31,560 41,185
CISO SRP 28,511 46,236
CISO TEPC 824 813
CISO TIDC 5,648 6,896
IPCO AVA 17,111 13,070
IPCO BPAT 1,270 298
IPCO NEVP 62,095 48,046
IPCO NWMT 434 871
IPCO PACE 7,143 4,091
IPCO PACW 31,503 25,610
IPCO PSEI 0 0
IPCO SCL 11,840 11,144
LADWP AZPS 10,982 17,035
LADWP BPAT 0 0
LADWP CISO 129,042 97,849
August LADWP NEVP 20,189 26,589
Attachment E Page 79 of 178
LADWP PACE 17,333 19,364
LADWP TEPC 0 0
NEVP AZPS 12,237 16,914
NEVP BPAT 0 0
NEVP CISO 193,378 124,343
NEVP IPCO 31,439 31,988
NEVP LADWP 29,339 33,205
NEVP PACE 6,317 3,608
NWMT AVA 42,267 45,970
NWMT BPAT 6,399 3,154
NWMT IPCO 11,670 11,237
NWMT PACE 10,131 6,188
NWMT PACW 1 0
NWMT PGE 10 0
NWMT PSEI 0 0
NWMT TPWR 92 92
PACE AZPS 160,806 141,419
PACE IPCO 62,388 61,361
PACE LADWP 142,727 139,942
PACE NEVP 89,202 75,228
PACE NWMT 26,851 29,329
PACE PACW 83,914 83,431
PACE SRP 0 0
PACE TEPC 13,008 11,318
PACW AVA 4,441 4,831
PACW BPAT 3,556 1,130
PACW CISO 16,379 42,807
August PACW IPCO 15,977 9,724
Attachment E Page 80 of 178

PACW NWMT 0 0
PACW PGE 80,891 81,312
PACW PSEI 25,966 24,939
PACW SCL 1,914 1,712
PGE AVA 3 0
PGE BPAT 35,848 41,276
PGE CISO 20,442 17,829
PGE NWMT 79 0
PGE PACW 27,376 27,204
PGE PSEI 0 0
PGE SCL 1,559 1,385
PGE TPWR 0 0
PNM AZPS 37,441 33,201
PNM SRP 6,152 3,763
PNM TEPC 45,943 41,436
PSEI AVA 0 0
PSEI BPAT 30,712 33,488
PSEI IPCO 0 0
PSEI NWMT 1 0
PSEI PACW 73 79
PSEI PGE 0 0
August PSEI PWRX 6,749 8,380
PSEI SCL 20,398 18,122
PSEI TPWR 12,970 15,651
PWRX BPAT 7,231 583
PWRX CISO 0 0
PWRX PSEI 19,494 19,059
SCL AVA 3 0
Attachment E Page 81 of 178
SCL BPAT 545 782
SCL IPCO 5,395 5,730
SCL PACW 809 998
SCL PGE 932 1,139
SCL PSEI 4,629 6,210
SRP AZPS 20,286 20,549
SRP CISO 71,162 57,540
SRP PACE 0 0
SRP PNM 53 114
SRP TEPC 46,543 57,784
TEPC AZPS 387 0
TEPC CISO 29,147 21,185
TEPC LADWP 0 0
TEPC PACE 10 117
TEPC PNM 4,341 4,973
TEPC SRP 5,086 3,392
TIDC BANC 266 0
TIDC CISO 20,930 18,151
TPWR AVA 77 6
TPWR BPAT 5,670 6,957
TPWR NWMT 0 0
TPWR PGE 209 131
TPWR PSEI 4,755 5,025
September AVA BPAT 18,123 14,394
AVA CISO 0 0
AVA IPCO 14,896 13,290
AVA NWMT 2,030 1,354
AVA PACW 1,944 1,400
Attachment E Page 82 of 178
AVA PGE 0 0
AVA PSEI 0 0
AVA SCL 16 0
AVA TPWR 0 0
AZPS CISO 234,246 177,401
AZPS LADWP 8,326 7,989
AZPS NEVP 2,241 4,389
AZPS PACE 7,104 9,205
AZPS PNM 9,952 7,659
AZPS SRP 22,526 18,355
September AZPS TEPC 18,388 18,700
BANC BPAT 0 0
BANC CISO 11,799 7,632
BANC TIDC 552 0
BPAT AVA 4,455 2,362
BPAT BANC 0 0
BPAT CISO 12,375 21,295
BPAT IPCO 567 0
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 7,547 304
BPAT PACW 2,971 2,139
BPAT PGE 16,957 12,621
BPAT PSEI 12,719 12,944
BPAT PWRX 4,143 81
BPAT SCL 2,295 1,885
BPAT TPWR 10,946 13,156
CISO AVA 0 0
Attachment E Page 83 of 178
CISO AZPS 11,956 16,177
CISO BANC 143,077 149,790
CISO BPAT 5,351 10,692
CISO LADWP 16,402 22,901
CISO NEVP 10,777 11,392
CISO PACW 3,230 16,696
CISO PGE 23,217 47,448
CISO PWRX 229,900 249,969
CISO SRP 47,912 56,189
CISO TEPC 416 844
September CISO TIDC 9,065 9,707
IPCO AVA 31,064 26,177
IPCO BPAT 1,290 221
IPCO NEVP 70,187 52,886
IPCO NWMT 410 608
IPCO PACE 3,251 818
IPCO PACW 33,522 29,507
IPCO PSEI 0 0
IPCO SCL 13,054 12,379
LADWP AZPS 3,177 3,905
LADWP BPAT 0 0
LADWP CISO 149,927 122,421
LADWP NEVP 5,265 7,184
LADWP PACE 24,443 27,507
LADWP TEPC 0 0
NEVP AZPS 6,718 7,215
NEVP BPAT 0 0
September NEVP CISO 305,456 228,955
Attachment E Page 84 of 178

NEVP IPCO 26,060 24,227
NEVP LADWP 43,986 51,704
NEVP PACE 5,765 6,771
NWMT AVA 40,759 41,672
NWMT BPAT 13,608 10,591
NWMT IPCO 10,801 10,932
NWMT PACE 5,765 2,340
NWMT PACW 74 0
NWMT PGE 84 0
NWMT PSEI 82 0
NWMT TPWR 0 0
PACE AZPS 141,534 127,193
PACE IPCO 148,341 151,578
PACE LADWP 116,789 109,709
PACE NEVP 122,613 107,518
PACE NWMT 32,296 31,501
PACE PACW 82,690 96,101
PACE SRP 0 0
PACE TEPC 11,498 10,424
PACW AVA 1,626 2,035
PACW BPAT 6,384 3,608
PACW CISO 33,666 71,934
PACW IPCO 13,402 6,459
PACW NWMT 5 0
PACW PGE 84,844 87,308
PACW PSEI 30,665 29,379
PACW SCL 1,922 1,812
September PGE AVA 2 0
Attachment E Page 85 of 178
PGE BPAT 37,426 42,258
PGE CISO 26,559 24,204
PGE NWMT 64 0
PGE PACW 19,576 17,835
PGE PSEI 0 0
PGE SCL 1,551 1,556
PGE TPWR 0 0
PNM AZPS 52,812 53,044
PNM SRP 15,002 11,113
PNM TEPC 38,111 36,732
PSEI AVA 0 0
PSEI BPAT 31,606 33,574
PSEI IPCO 0 0
PSEI NWMT 1 0
PSEI PACW 2 0
PSEI PGE 0 0
PSEI PWRX 17,690 18,331
PSEI SCL 10,638 8,578
PSEI TPWR 8,836 10,706
PWRX BPAT 4,025 0
PWRX CISO 0 0
PWRX PSEI 7,260 7,661
SCL AVA 16 0
SCL BPAT 1,378 2,707
SCL IPCO 3,048 2,942
SCL PACW 584 673
SCL PGE 905 978
September SCL PSEI 10,624 14,678
Attachment E Page 86 of 178

TABLE 2: Energy transfers (MWh) in the FMM and RTD markets for Q3 2022

SRP AZPS 8,100 8,178
SRP CISO 141,472 128,941
SRP PACE 0 0
SRP PNM 14 11
SRP TEPC 29,538 36,782
TEPC AZPS 595 100
TEPC CISO 73,757 62,516
TEPC LADWP 0 0
TEPC PACE 23 198
TEPC PNM 5,895 4,557
TEPC SRP 7,907 5,482
TIDC BANC 300 134
TIDC CISO 14,726 12,930
TPWR AVA 0 0
TPWR BPAT 7,326 7,937
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 8,310 9,591
Attachment E Page 87 of 178

GRAPH 2: Estimated maximum transfer capacity
WHEEL-THROUGH TRANSFERS
As the footprint of the WEIM grows, wheel-through transfers may become more common. In
order to derive the wheel-through transfers for each WEIM BAA, the ISO uses the following
calculation for every real-time interval dispatch:

• Total import: summation of transfers above base transfers coming into the WEIM
BAA under analysis
Attachment E Page 88 of 178
• Total export: summation of all transfers above base transfers going out of the WEIM
BAA under analysis
• Net import: the maximum of zero or the difference between total imports and total
exports
• Net export: the maximum of zero or the difference between total exports and total
imports
• Wheel-through: the minimum of the WEIM transfers into (total import) or WEIM
transfer out (total export) of a BAA for a given interval

All wheel-through transfers are summed over both the month and the quarter.

Currently, a WEIM entity facilitating a wheel through receives no direct financial benefit for
facilitating the wheel; only the sink and source directly benefit. As part of the WEIM
Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel
through volumes to assess whether, after the addition of new WEIM entities, there is a potential
future need to pursue a market solution to address the equitable sharing of wheeling benefits.

The ISO will continue to track the volume of wheel-through transfers in the WEIM market in the
quarterly reports.

This volume reflects the total wheel-through transfers for each WEIM BAA, regardless of the
potential paths used to wheel through. The net imports and exports estimated in this section
reflect the overall volume of net imports and exports; in contrast, the imports and exports
provided in Table 2 reflect the gross transfers between two WEIM BAAs.

The metric is measured as energy in MWh for each month and the corresponding calendar
quarter, as shown in Tables 3 through 6 and Graphs 3 through 6.

BAA Net Export Net Import Wheel Through
AVA

43,479

166,138

29,698
AZPS

259,011

266,659

467,402
BANC

18,674

526,589

-
BPAT

123,665

183,208

99,692
CISO

915,264

1,081,334

683,121
IPCO

65,844

312,802

207,171
LADWP

168,958

353,418

281,453
NEVP

451,416

194,216

317,674
NWMT

94,441

37,640

78,752
Attachment E Page 89 of 178
PACE

1,513,934

41,793

129,841
PACW

177,993

107,545

335,268
PGE

99,617

275,591

138,039
PNM

193,620

74,094

34,629
PSEI

119,444

104,643

94,047
PWRX

16,901

363,914

21,023
SCL

30,482

48,693

28,161
SRP

345,373

234,363

85,983
TEPC

125,449

379,861

12,217
TIDC

44,879

24,518

-
TPWR

11,158

42,580

28,996

TABLE 3: Estimated wheel-through transfers in Q3 2022

GRAPH 3: Estimated wheel-through transfers in Q3 2022

Attachment E Page 90 of 178
BAA Net Export Net Import Wheel Through
AVA

22,848

54,990

15,462
AZPS

30,459

110,147

163,004
BANC

3,272

100,837

137
CISO

494,339

255,490

102,212
IPCO

46,954

57,693

88,700
LADWP

41,281

98,879

82,243
NEVP

55,128

82,111

84,004
NWMT

17,552

15,316

22,431
PACE

294,558

27,639

79,755
PACW

72,220

53,570

111,828
PGE

41,277

49,303

16,987
PNM

52,128

14,956

1,436
PSEI

29,559

49,335

31,492
PWRX

10,937

47,051

10,312
SCL

13,337

16,984

7,077
SRP

45,994

238,211

2,708
TIDC

12,011

12,809

147
TPWR

8,702

7,234

8,205

BAA Net Export Net Import Wheel Through
AVA

14,129

50,723

4,595
AZPS

75,394

103,532

168,074
BANC

5,031

182,290

-
BPAT

67,084

38,154

23,983
Attachment E Page 91 of 178
CISO

436,627

233,317

160,714
IPCO

13,671

139,927

33,619
LADWP

40,727

146,128

87,831
NEVP

142,209

57,080

97,950
NWMT

13,629

21,556

27,388
PACE

430,188

30,141

37,533
PACW

56,045

42,834

77,129
PGE

25,325

78,614

38,784
PNM

33,020

53,684

15,940
PSEI

35,966

27,218

30,615
PWRX

5,968

62,283

4,653
SCL

14,612

9,752

7,195
SRP

87,160

113,030

34,298
TEPC

34,826

135,520

320
TIDC

13,664

7,916

-
TPWR

2,601

14,179

7,906

TABLE 4: Estimated wheel-through transfers in July 2022

Attachment E Page 92 of 178

GRAPH 4: Estimated wheel-through transfers in July 2022
BAA Net Export Net Import Wheel Through
AVA

14,248

58,505

9,767
AZPS

83,439

90,836

155,808
BANC

6,010

194,375

-
BPAT

30,932

60,211

34,570
CISO

211,845

314,800

197,394
IPCO

32,987

66,855

70,143
LADWP

48,708

96,479

112,129
NEVP

129,850

93,282

80,208
NWMT

42,524

9,565

24,116
PACE

492,409

4,493

49,620
PACW

51,125

35,080

123,420
PGE

35,381

95,563

52,312
PNM

64,522

12,996

13,879
Attachment E Page 93 of 178
PSEI

43,875

34,759

31,846
PWRX

10,145

40,123

9,497
SCL

5,851

24,690

9,008
SRP

111,866

57,760

24,120
TEPC

26,811

149,901

2,856
TIDC

18,151

6,896

-
TPWR

3,532

17,041

8,587

TABLE 5: Estimated wheel-through transfers in August 2022

GRAPH 5: Estimated wheel-through transfers in August 2022
BAA Net Export Net Import Wheel Through
AVA

15,102

56,910

15,336
AZPS

100,178

72,291

143,520
BANC

7,632

149,924

-
Attachment E Page 94 of 178
BPAT

25,648

84,843

41,139
CISO

266,792

533,217

325,013
IPCO

19,186

106,019

103,409
LADWP

79,524

110,811

81,493
NEVP

179,357

43,854

139,516
NWMT

38,288

6,519

27,248
PACE

591,336

7,159

42,688
PACW

70,822

29,631

134,719
PGE

38,911

101,414

46,942
PNM

96,078

7,415

4,811
PSEI

39,603

42,666

31,587
PWRX

788

261,509

6,873
SCL

10,019

14,251

11,959
SRP

146,347

63,574

27,565
TEPC

63,811

94,440

9,041
TIDC

13,064

9,707

-
TPWR

5,025

11,359

12,503

TABLE 6: Estimated wheel-through transfers in September 2022

Attachment E Page 95 of 178

GRAPH 6: Estimated wheel-through transfers in September 2022
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS
The WEIM benefit calculation includes the economic benefits that can be attributed to avoided
renewable curtailment within the ISO footprint. If not for energy transfers facilitated by the
WEIM, some renewable generation located within the ISO would have been curtailed via either
economic or exceptional dispatch. The total avoided renewable curtailment volume in MWh for
Q3 2022 was calculated to be 20,691 MWh (July) + 9,471 MWh (August) + 12,306 MWh
(September) = 42,468 MWh total.
There are environmental benefits of avoided renewable curtailment as well. Under the
assumption that avoided renewable curtailments displace production from other resources at a
default emission rate of 0.428 metric tons CO2/MWh, avoided curtailments displaced an
estimated 18,176 metric tons of CO2 for Q3 2022. Avoided renewable curtailments also may
have contributed to an increased volume of renewable credits that would otherwise have been
unavailable. This report does not quantify the additional value in dollars associated with this
benefit. Total estimated reductions in the curtailment of renewable energy in the ISO footprint,
along with the associated reductions in CO2, are shown in Table 7.
Year Quarter MWh Eq. Tons CO2
1 8,860 3,792
2015 2 3,629 1,553
3 828 354
4 17,765 7,521
Attachment E Page 96 of 178
1 112,948 48,342
2016 2 158,806 67,969
3 33,094 14,164
4 23,390 10,011
1 52,651 22,535
2017 2 67,055 28,700
3 23,331 9,986
4 18,060 7,730
1 65,860 28,188
2018 2 129,128 55,267
3 19,032 8,146
4 23,425 10,026
1 52,254 22,365
2019 2 132,937 56,897
3 33,843 14,485
4 35,254 15,089
1 86,740 37,125
2020 2 147,514 63,136
3 37,548 16,071
4 39,956 17,101
2021 1 76,147 32,591
2 109,059 46,677
3 23,042 9,862
4 38,044 16,283
2022 1 94,168 40,304
2 118,352 50,655
3 42,468 18,176
Total 1,825,188 781,101

TABLE 7: Total reduction in curtailment of renewable energy and associated reductions in CO2
Attachment E Page 97 of 178
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS
The WEIM facilitates procurement of flexible ramping capacity in the FMM to address
variability that may occur in the RTD. Because variability across different BAAs may happen in
opposite directions, the flexible ramping requirement for the entire WEIM footprint can be less
than the sum of individual BAA’s requirements. This difference is known as flexible ramping
procurement diversity savings.
Starting in 2016, the ISO replaced the flexible ramping constraint with flexible ramping products
that provide both upward and downward ramping. The minimum and maximum flexible ramping
requirements for each BAA and for each direction are listed in Table 8.
Month BAA Direction Minimum
requirement
Maximum
requirement
AVA up 14 71
July AZPS up 51 318
BANC up 4 147
BPAT up 102 460
CISO up 443 2,453
IPCO up 76 216
LADWP up 65 456
NEVP up 72 370
NWMT up 17 128
PACE up 108 592
PACW up 50 189
PGE up 56 223
PNM up 35 200
PSEI up 42 199
PWRX up 48 235
SCL up 4 34
SRP up 42 262
TEPC up 52 132
TIDC up 2 15
TPWR up 3 17
ALL EIM up 558 2,624
AVA down 20 78
Attachment E Page 98 of 178
AZPS down 30 390
BANC down 2 154
BPAT down 138 402
July CISO down 108 1,322
IPCO down 52 301
LADWP down 59 289
NEVP down 50 360
NWMT down 44 171
PACE down 111 652
PACW down 59 208
PGE down 55 286
PNM down 37 182
PSEI down 31 198
PWRX down 67 246
SCL down 1 28
SRP down 37 175
TEPC down 30 110
TIDC down 2 23
TPWR down 3 24
ALL EIM down 370 1,852
AVA up 16 65
August AZPS up 46 344
BANC up 10 82
BPAT up 109 460
CISO up 355 2,608
IPCO up 60 216
LADWP up 47 415
NEVP up 63 423
NWMT up 19 111
PACE up 132 592
PACW up 42 186
Attachment E Page 99 of 178
PGE up 60 223
PNM up 40 200
PSEI up 28 161
PWRX up 61 223
August SCL up 4 41
SRP up 58 262
TEPC up 44 129
TIDC up 2 15
TPWR up 2 15
ALL WEIM up 636 2,713
AVA down 22 71
AZPS down 42 390
BANC down 2 154
BPAT down 127 401
CISO down 167 1,003

IPCO down 40 214
LADWP down 72 289
NEVP down 23 360
NWMT down 44 171
PACE down 164 652
PACW down 52 203
PGE down 39 257
PNM down 37 182
PSEI down 29 198
PWRX down 57 246
SCL down 0 24
SRP down 34 169
TEPC down 40 110
TIDC down 2 26
TPWR down 3 19
ALL EIM down 261 1,569
Attachment E Page 100 of 178

September

AVA up 18 95
AZPS up 54 315
BANC up 8 76
BPAT up 82 481
CISO up 371 2,758
IPCO up 47 213
LADWP up 61 390
NEVP up 54 410
NWMT up 17 111
PACE up 108 651
PACW up 34 130
PGE up 60 259
PNM up 40 194
PSEI up 28 147
PWRX up 62 247
SCL up 4 41
SRP up 46 296
TEPC up 34 221
TIDC up 2 19
TPWR up 2 15
ALL WEIM up 636 2,510
AVA down 18 113
AZPS down 41 385
BANC down 9 134
BPAT down 120 639
CISO down 135 1,145
IPCO down 40 170
LADWP down 62 364
NEVP down 31 471
NWMT down 40 168
PACE down 111 689
Attachment E Page 101 of 178

September

PACW down 33 160
PGE down 38 185
PNM down 38 229
PSEI down 26 213
PWRX down 57 307
SCL down 2 26
SRP down 25 544
TEPC down 37 215
TIDC down 3 32
TPWR down 3 18
ALL WEIM down 226 1,645
Table 8: Flexible ramping requirements
The flexible ramping procurement diversity savings for all the intervals averaged over the month
are shown in Table 9. The percentage savings is the average MW savings divided by the sum of
the individual BAA requirements.
July August September
Direction Up Down Up Down Up Down
Average MW saving 1,909

1,912 1,886 1,917 1,708 1,928
Sum of BAA requirements 3,336 2,877 3,356 2,954 3,175 2,934
Percentage savings 57% 66% 56% 65% 54% 66%
Table 9: Flexible ramping procurement diversity savings in Q3 2022
Flexible ramping capacity may be used in RTD to handle uncertainties in the future interval. The
RTD flexible ramping capacity is prorated to each BAA. Flexible ramping surplus MW is defined
as the awarded flexible ramping capacity in RTD minus its share, and the flexible ramping
surplus cost is defined as the flexible ramping surplus MW multiplied by the flexible ramping
WEIM-wide marginal price. A positive flexible ramping surplus MW is the capacity that a BAA
provided to help other BAAs, and a negative flexible ramping surplus MW is the capacity that a
BAA received from other BAAs.
The EIM dispatch cost for a BAA with positive flexible ramping surplus MW is increased
because some capacities are used to help other BAAs. The flexible ramping surplus cost is
subtracted from the BAA’s WEIM dispatch cost to reflect the true dispatch cost of a BAA. Please
see the Benefit Report Methodology for more details.
Attachment E Page 102 of 178

CONCLUSION
Using state-of-the-art technology to find and deliver low-cost energy to meet real-time demand,
the WEIM demonstrates that utilities can realize financial and operational benefits through
increased coordination and optimization. In addition to these benefits, the WEIM provides
significant environmental benefits through the reduction of renewable curtailments during
periods of oversupply.
Sharing resources across a larger geographic area reduces greenhouse gas emissions by using
renewable generation that otherwise would have been turned off. The quantified environmental
benefits from avoided curtailments of renewable generation from 2015 to-date reached 781,101
metric tons of CO2, roughly the equivalent of avoiding the emissions from 164,223 passenger
cars driven for one year.

Attachment E Page 103 of 178
APPENDIX 1: GLOSSARY OF ABBREVIATIONS

Abbreviation Description
APS Arizona Public Service
AVA Avista Utilities
BAA Balancing Authority Area
BANC Balancing Authority of Northern California
BPA Bonneville Power Administration
CISO, ISO California ISO
EIM Energy Imbalance Market
FMM Fifteen Minute Market
GHG Greenhouse Gas
IPCO Idaho Power
LADWP Los Angeles Department of Water and Power
MW Megawatt
MWh Megawatt-Hour
NVE NV Energy
PAC PacifiCorp
PACE PacifiCorp East
PACW PacifiCorp West
PGE Portland General Electric
PSE Puget Sound Energy
PWRX Powerex
RTD Real Time Dispatch
SCL Seattle City Light
SRP Salt River Project
TEP Tucson Electric Power
TID Turlock Irrigation District
TPWR Tacoma Power
WEIM Western Energy Imbalance Market

Attachment E Page 104 of 178

Western Energy Imbalance Market Benefits
Fourth Quarter 2022

January 30, 2023
Attachment E Page 105 of 178

CONTENTS

EXECUTIVE SUMMARY ........................................................................................................... 3
BACKGROUND ......................................................................................................................... 4
WEIM ECONOMIC BENEFITS IN Q4 2022 ............................................................................... 4
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION ................................................................... 5
INTER-REGIONAL TRANSFERS ............................................................................................................. 6
WHEEL-THROUGH TRANSFERS ......................................................................................................... 22
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS ....................................29
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS ..............................................31
CONCLUSION ..........................................................................................................................36
APPENDIX 1: GLOSSARY OF ABBREVIATIONS...................................................................37
Attachment E Page 106 of 178

EXECUTIVE SUMMARY
This report presents the benefits associated with
participation in the Western Energy Imbalance
Market (WEIM).
The measured benefits of participation in the WEIM
include cost savings, increased integration of
renewable energy, and improved operational
efficiencies including the reduction of
the need for real-time flexible reserves.
This analysis demonstrates the benefit of economic
dispatch in the real time market across a larger
WEIM footprint with diverse resources and geography.

Q4 2022 Gross Benefits by Participant
(millions $)
Arizona Public Service $34.87
Avista $9.73
BANC $83.44
BPA $12.96
California ISO $88.53
Idaho Power $17.18
LADWP $25.17
NV Energy $42.33
NorthWestern Energy $12.95
PacifiCorp $53.87
Portland General Electric $21.11
PNM $11.55
Puget Sound Energy $14.81
Powerex $3.45
Seattle City Light $4.71
Salt River Project $31.04
Tacoma Power $4.07
TEP $11.21
TID $2.31
Total $485.29
Gross benefits from WEIM since November 2014
$3.40 billion
ECONOMICAL
$485.29 M
Gross benefits realized due to more
efficient inter-and intra-regional
dispatch in the Fifteen-Minute
Market (FMM) and Real-Time
Dispatch (RTD)*

ENVIRONMENTAL
10,960
Metric tons of CO2** avoided
curtailments

OPERATIONAL
58%
Average reduction in flexibility
reserves across the footprint
2022
Q4 BENEFITS
Attachment E Page 107 of 178

*WEIM Quarterly Benefit Report Methodology: https://www.westerneim.com/Documents/EIM-BenefitMethodology.pdf.
**The GHG emission reduction reported is associated with the avoided curtailment only. The current market process and
counterfactual methodology cannot differentiate the GHG emissions resulting from serving ISO load via the EIM versus dispatch that
would have occurred external to the ISO without the WEIM. For more details, see
http://www.caiso.com/Documents/GreenhouseGasEmissionsTrackingReport-FrequentlyAskedQuestions.pdf
BACKGROUND
The Western EIM began financially binding operation on November 1, 2014 by optimizing
resources across the ISO and PacifiCorp Balancing Authority Areas (BAAs). NV Energy began
participating in December 2015, Arizona Public Service and Puget Sound Energy began
participating in October 2016, and Portland General Electric began participating in October
2017. Idaho Power and Powerex began participating in April 2018, and the Balancing Authority
of Northern California (BANC) began participating in April 2019. Seattle City Light and Salt River
Project began participating in April 2020.
In 2021, new balancing authorities began participating in the Western EIM, with the Turlock
Irrigation District (TID) in March 2021, the second phase of BANC in March 2021, and the Los
Angeles Department of Water and Power (LADWP) and Public Service Company of New
Mexico (PNM) in April 2021, followed by NorthWestern Energy (NWMT) starting in June 2021.
Avista Utilities (AVA) and Tacoma Power (TPWR), two utilities serving a combined 600,000
electric customers in the Pacific Northwest, became the newest members of the WEIM, with
both beginning their participation on March 2, 2022. On May 3, 2022, the Bonneville Power
Administration (BPA) and Tucson Electric Power (TEP) both Joined the WEIM.
The Western EIM footprint now includes portions of Arizona, California, Idaho, Montana,
Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, and extends to the border with
Canada.
WEIM ECONOMIC BENEFITS IN Q4 2022
Table 1 shows the estimated WEIM gross benefits by each region per month1. The monthly
savings presented show $99.25 million for October, $129.34 million for November, and $256.70
million for December with a total estimated benefit of $485.29 million for this quarter2. This level
of WEIM benefits accrued from having additional WEIM areas participating in the market and
economical transfers displacing more expensive generation.
1 The WEIM benefits reported here are calculated based on available data. Intervals without complete data are
excluded in the calculation. The intervals excluded due to unavailable data are normally within a few percent
points of the total intervals.
2 For several quarterly estimates, CAISO benefits were calculated on a variation of the counterfactual
methodology. For CAISO only the logic had considered offline resources as part of the bid stack in the
counterfactual. In Q4 2021, CAISO identified some questionable results that drove persistent negative benefits
for CAISO when considering offline resources. Since Q4 2021, the benefit calculation for CAISO area follows
the same methodology applicable to all WEIM entities in which only online resources are used.
Attachment E Page 108 of 178
Region October November December Total
APS $4.68 $3.32 $26.87 $34.87
AVA $1.60 $2.43 $5.70 $9.73
BANC $13.91 $24.57 $44.96 $83.44
BPA $2.15 $2.24 $8.57 $12.96
CISO $26.39 $40.63 $21.51 $88.53
IPCO $3.92 $4.00 $9.26 $17.18
LADWP $3.72 $6.74 $14.71 $25.17
NVE $7.38 $9.69 $25.26 $42.33
NWMT $2.83 $1.68 $8.44 $12.95
PAC $12.40 $10.85 $30.62 $53.87
PGE $3.73 $4.67 $12.71 $21.11
PNM $2.19 $2.50 $6.86 $11.55
PSE $2.11 $2.60 $10.10 $14.81
PWRX $0.52 $0.18 $2.75 $3.45
SCL $0.97 $1.07 $2.67 $4.71
SRP $6.63 $8.51 $15.90 $31.04
TPWR $0.59 $0.95 $2.53 $4.07
TEP $3.01 $1.90 $6.30 $11.21
TID $0.52 $0.81 $0.98 $2.31
Total $99.25 $129.34 $256.70 $485.29
TABLE 1: Q4 2022 benefits in millions USD
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION
Since the start of the WEIM in November 2014, the cumulative economic benefits of the market
have totaled $3.40 billion. The quarterly benefits have grown over time as a result of the
participation of new BAAs, which results in benefits for both the individual BAA but also
compounds the benefits to adjacent BAAs through additional transfers. The ISO began
publishing quarterly WEIM benefit reports in April 2015.3
Graph 1 illustrates the gross economic benefits of the WEIM by quarter for each participating
BAA.
3 Prior reports are available at https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx
Attachment E Page 109 of 178

GRAPH 1: Cumulative economic benefits for each quarter by BAA
INTER-REGIONAL TRANSFERS
A significant contributor to EIM benefits is transfers across balancing areas, providing access to
lower cost supply, while factoring in the cost of compliance with greenhouse gas (GHG)
emissions regulations when energy is transferred into the ISO. As such, the transfer volumes
are a good indicator of a portion of the benefits attributed to the WEIM. Transfers can take place
in both the 15-Minute Market and Real-Time Dispatch (RTD).
Generally, transfer limits are based on transmission and interchange rights that participating
balancing authority areas make available to the WEIM, with the exception of the PacifiCorp
West (PACW) -ISO transfer limit and the Portland General Electric (PGE) -ISO transfer limit in
RTD. These RTD transfer capacities between PACW/PGE and the ISO are determined based
on the allocated dynamic transfer capability driven by system operating conditions. This report
does not quantify a BAA’s opportunity cost that the utility considered when using its transfer
rights for the EIM.
Table 2 provides the 15-minute and 5-minute WEIM transfer volumes with base schedule
transfers excluded. The WEIM entities submit inter-BAA transfers in their base schedules. The
benefits quantified in this report are only attributable to the transfers that occurred through the
WEIM. The benefits do not include any transfers attributed to transfers submitted in the base
schedules that are scheduled prior to the start of the EIM.
The transfer from BAA_x to BAA_y and the transfer from BAA_y to BAA_x are separately
reported. For example, if there is a 100 Megawatt-Hour (MWh) transfer during a 5-minute
interval, in addition to a base transfer from ISO to NVE, it will be reported as 100 MWh
from_BAA ISO to_BAA NEVP, and 0 MWh from_BAA NEVP to_BAA ISO in the opposite
Attachment E Page 110 of 178
direction. The 15-minute transfer volume is the result of optimization in the 15-minute market
using all bids and base schedules submitted into the WEIM. The 5-minute transfer volume is the
result of optimization using all bids and base schedules submitted into WEIM, based on unit
commitments determined in the 15-minute market optimization. The maximum transfer
capacities between WEIM entities are shown in Graph 2 below.

Month

From BAA

To BAA
15min WEIM transfer
(15m – base)
5min WEIM transfer
(5m – base)
AVA BPAT 15,158 12,587
October AVA CISO 0 0
AVA IPCO 26,459 30,539
AVA NWMT 1,270 1,446
AVA PACW 1,320 1,715
AVA PGE 0 0
AVA PSEI 48 0
AVA SCL 3 0
AVA TPWR 0 0
AZPS CISO 192,466 157,183
AZPS LADWP 21,821 24,761
AZPS NEVP 4,788 7,232
AZPS PACE 18,644 12,065
AZPS PNM 7,838 11,773
AZPS SRP 6,054 4,026
AZPS TEPC 14,440 16,207
BANC BPAT 0 0
BANC CISO 975 2,168
BANC TIDC 32 0
BPAT AVA 7,866 9,835
BPAT BANC 0 0
BPAT CISO 22,265 28,438
BPAT IPCO 1,871 0
Attachment E Page 111 of 178
October BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 5,158 3,882
BPAT PACW 1,618 2,544
BPAT PGE 18,376 19,890
BPAT PSEI 15,371 13,882
BPAT PWRX 3,154 116
BPAT SCL 2,308 2,148
BPAT TPWR 7,834 8,742
CISO AVA 0 0
CISO AZPS 10,968 10,765
CISO BANC 176,979 181,497
CISO BPAT 29,414 37,685
CISO LADWP 32,588 41,322
CISO NEVP 7,163 9,378
CISO PACW 3,856 23,974
CISO PGE 19,121 32,229
CISO PWRX 182,958 202,784
CISO SRP 39,021 47,568
CISO TEPC 0 50
CISO TIDC 2,904 3,495
IPCO AVA 18,149 15,602
IPCO BPAT 1,447 24
IPCO NEVP 17,199 15,814
IPCO NWMT 129 329
IPCO PACE 3,919 2,623
IPCO PACW 19,330 16,217
October IPCO PSEI 0 0
Attachment E Page 112 of 178
IPCO SCL 3,050 2,414
October LADWP AZPS 1,020 783
LADWP BPAT 0 0
LADWP CISO 72,253 60,516
LADWP NEVP 13,252 14,137
LADWP PACE 36,626 40,015
LADWP TEPC 0 0
NEVP AZPS 2,331 2,585
NEVP BPAT 0 0
NEVP CISO 151,640 113,102
NEVP IPCO 80,489 71,536
NEVP LADWP 51,010 56,748
NEVP PACE 9,150 5,830
NWMT AVA 17,794 16,950
NWMT BPAT 16,143 11,477
NWMT IPCO 26,879 29,525
NWMT PACE 10,900 6,778
NWMT PACW 46 0
NWMT PGE 2 0
NWMT PSEI 0 0
NWMT TPWR 1,668 1,410
PACE AZPS 60,262 64,728
PACE IPCO 116,013 124,712
PACE LADWP 38,487 33,775
PACE NEVP 58,737 55,391
PACE NWMT 12,863 10,755
PACE PACW 29,618 25,279
October PACE SRP 0 0
Attachment E Page 113 of 178
PACE TEPC 702 2,084
October PACW AVA 2,440 2,992
PACW BPAT 6,910 6,058
PACW CISO 41,606 59,413
PACW IPCO 15,321 19,077
PACW NWMT 0 0
PACW PGE 38,473 33,653
PACW PSEI 23,217 20,909
PACW SCL 1,460 1,189
PGE AVA 0 0
PGE BPAT 40,539 38,923
PGE CISO 18,375 16,560
PGE NWMT 0 0
PGE PACW 19,409 31,612
PGE PSEI 0 0
PGE SCL 1,402 1,059
PGE TPWR 1,834 1,837
PNM AZPS 50,316 42,351
PNM SRP 1,609 1,431
PNM TEPC 24,024 22,571
PSEI AVA 0 0
PSEI BPAT 14,148 19,217
PSEI IPCO 0 0
PSEI NWMT 2 0
PSEI PACW 0 0
PSEI PGE 0 0
PSEI PWRX 18,178 18,857
October PSEI SCL 8,355 7,596
Attachment E Page 114 of 178
PSEI TPWR 6,452 11,381
October PWRX BPAT 3,299 218
PWRX CISO 0 0
PWRX PSEI 8,918 10,556
SCL AVA 0 0
SCL BPAT 1,138 2,710
SCL IPCO 1,775 2,887
SCL PACW 669 1,147
SCL PGE 831 1,382
SCL PSEI 5,400 10,023
SRP AZPS 7,000 8,635
SRP CISO 169,609 159,863
SRP PACE 0 0
SRP PNM 92 189
SRP TEPC 31,310 38,448
TEPC AZPS 649 0
TEPC CISO 46,986 42,114
TEPC LADWP 0 0
TEPC PACE 7 27
TEPC PNM 5,722 5,558
TEPC SRP 2,796 2,212
TIDC BANC 36 0
TIDC CISO 19,733 18,321
TPWR AVA 0 0
TPWR BPAT 8,764 12,810
TPWR NWMT 670 1,113
TPWR PGE 607 1,156
TPWR PSEI 10,490 9,840
Attachment E Page 115 of 178
November AVA BPAT 9,872 9,792
AVA CISO 0 0
AVA IPCO 27,850 24,185
AVA NWMT 5,106 5,780
AVA PACW 2,175 2,744
AVA PGE 48 0
AVA PSEI 0 0
AVA SCL 0 0
AVA TPWR 0 0
AZPS CISO 169,811 123,910
AZPS LADWP 17,593 13,016
AZPS NEVP 9,297 11,454
AZPS PACE 25,509 23,635
AZPS PNM 18,378 24,773
AZPS SRP 5,415 4,088
AZPS TEPC 3,491 3,962
BANC BPAT 0 0
BANC CISO 405 233
BANC TIDC 25 0
BPAT AVA 8,159 6,366
BPAT BANC 0 0
BPAT CISO 9,885 16,776
BPAT IPCO 2,127 0
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 9,659 4,329
BPAT PACW 4,465 5,948
November BPAT PGE 22,607 20,730
Attachment E Page 116 of 178
BPAT PSEI 13,237 13,088
November BPAT PWRX 4,764 0
BPAT SCL 2,841 2,101
BPAT TPWR 11,212 12,518
CISO AVA 0 0
CISO AZPS 17,159 20,078
CISO BANC 234,883 238,370
CISO BPAT 18,391 24,670
CISO LADWP 22,495 26,855
CISO NEVP 17,012 20,969
CISO PACW 18,738 38,561
CISO PGE 22,570 37,719
CISO PWRX 116,263 128,587
CISO SRP 26,378 33,224
CISO TEPC 0 0
CISO TIDC 3,407 3,462
IPCO AVA 14,643 14,186
IPCO BPAT 1,816 0
IPCO NEVP 38,862 22,356
IPCO NWMT 534 1,004
IPCO PACE 3,679 2,057
IPCO PACW 11,779 17,466
IPCO PSEI 0 0
IPCO SCL 5,841 5,584
LADWP AZPS 1,470 1,894
LADWP BPAT 0 0
LADWP CISO 101,230 92,703
November LADWP NEVP 15,365 19,462
Attachment E Page 117 of 178
LADWP PACE 20,870 23,045
November LADWP TEPC 0 0
NEVP AZPS 1,685 3,980
NEVP BPAT 0 0
NEVP CISO 172,364 121,695
NEVP IPCO 39,730 38,318
NEVP LADWP 20,804 26,069
NEVP PACE 18,659 16,759
NWMT AVA 13,472 13,343
NWMT BPAT 10,242 6,741
NWMT IPCO 13,944 13,045
NWMT PACE 12,126 6,640
NWMT PACW 5 0
NWMT PGE 12 0
NWMT PSEI 28 0
NWMT TPWR 0 0
PACE AZPS 62,929 66,771
PACE IPCO 75,414 73,707
PACE LADWP 23,204 21,709
PACE NEVP 86,307 75,628
PACE NWMT 12,517 15,086
PACE PACW 24,706 25,635
PACE SRP 0 0
PACE TEPC 267 770
PACW AVA 6,109 6,452
PACW BPAT 9,244 6,035
PACW CISO 64,046 92,137
November PACW IPCO 19,534 23,428
Attachment E Page 118 of 178

PACW NWMT 7 0
November PACW PGE 33,945 31,961
PACW PSEI 19,253 18,488
PACW SCL 1,479 1,248
PGE AVA 0 0
PGE BPAT 36,874 37,663
PGE CISO 44,156 41,706
PGE NWMT 22 0
PGE PACW 19,603 31,002
PGE PSEI 0 0
PGE SCL 1,420 1,244
PGE TPWR 0 0
PNM AZPS 51,866 39,582
PNM SRP 1,545 1,342
PNM TEPC 15,852 16,442
PSEI AVA 7 0
PSEI BPAT 15,156 17,988
PSEI IPCO 0 0
PSEI NWMT 40 0
PSEI PACW 13,153 16,071
PSEI PGE 0 0
November PSEI PWRX 11,824 11,395
PSEI SCL 12,130 10,341
PSEI TPWR 8,472 11,446
PWRX BPAT 5,169 0
PWRX CISO 0 0
PWRX PSEI 15,870 16,888
SCL AVA 0 0
Attachment E Page 119 of 178
SCL BPAT 1,904 2,695
November SCL IPCO 4,640 4,581
SCL PACW 666 980
SCL PGE 805 1,158
SCL PSEI 5,586 8,341
SRP AZPS 24,218 24,520
SRP CISO 178,030 154,174
SRP PACE 0 0
SRP PNM 1,109 1,248
SRP TEPC 22,138 28,468
TEPC AZPS 269 0
TEPC CISO 24,735 19,095
TEPC LADWP 0 0
TEPC PACE 54 385
TEPC PNM 10,725 10,931
TEPC SRP 28,475 22,127
TIDC BANC 17 0
TIDC CISO 18,516 17,906
TPWR AVA 0 0
TPWR BPAT 9,018 11,092
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 10,053 10,147
December AVA BPAT 16,513 16,892
AVA CISO 354 361
AVA IPCO 20,615 15,885
AVA NWMT 8,675 3,211
AVA PACW 2,182 1,879
Attachment E Page 120 of 178
AVA PGE 0 0
AVA PSEI 50 0
AVA SCL 0 0
AVA TPWR 0 0
AZPS CISO 217,909 187,535
AZPS LADWP 40,012 42,673
AZPS NEVP 21,042 22,865
AZPS PACE 73,138 72,884
AZPS PNM 57,843 37,746
AZPS SRP 5,860 3,921
December AZPS TEPC 7,254 6,300
BANC BPAT 0 0
BANC CISO 360 295
BANC TIDC 33 0
BPAT AVA 21,382 14,912
BPAT BANC 0 0
BPAT CISO 18,784 23,780
BPAT IPCO 3,299 297
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 14,272 3,753
BPAT PACW 3,807 4,382
BPAT PGE 16,120 16,001
BPAT PSEI 17,181 15,102
BPAT PWRX 6,119 0
BPAT SCL 6,427 6,174
BPAT TPWR 11,931 12,834
CISO AVA 50 49
Attachment E Page 121 of 178
CISO AZPS 10,910 13,784
December CISO BANC 243,805 245,309
CISO BPAT 31,124 38,622
CISO LADWP 18,592 22,935
CISO NEVP 47,868 49,634
CISO PACW 24,801 54,705
CISO PGE 35,322 55,003
CISO PWRX 67,544 76,385
CISO SRP 6,169 10,517
CISO TEPC 0 16
December CISO TIDC 7,962 7,231
IPCO AVA 30,665 30,978
IPCO BPAT 713 0
IPCO NEVP 34,077 23,009
IPCO NWMT 395 1,472
IPCO PACE 16,019 6,920
IPCO PACW 41,591 27,917
IPCO PSEI 0 0
IPCO SCL 10,017 9,044
LADWP AZPS 6,205 6,437
LADWP BPAT 0 0
LADWP CISO 86,038 76,740
LADWP NEVP 28,959 34,065
LADWP PACE 27,482 24,068
LADWP TEPC 0 0
NEVP AZPS 5,931 7,783
NEVP BPAT 0 0
December NEVP CISO 126,215 92,655
Attachment E Page 122 of 178

NEVP IPCO 74,249 63,113
December NEVP LADWP 16,409 16,169
NEVP PACE 32,771 23,723
NWMT AVA 29,257 32,584
NWMT BPAT 9,227 7,194
NWMT IPCO 16,759 16,697
NWMT PACE 26,611 9,625
NWMT PACW 44 0
NWMT PGE 45 0
NWMT PSEI 355 0
NWMT TPWR 0 0
PACE AZPS 34,112 23,767
PACE IPCO 60,699 60,112
PACE LADWP 21,211 24,983
PACE NEVP 86,163 75,891
PACE NWMT 12,889 19,264
PACE PACW 24,651 24,279
PACE SRP 0 0
PACE TEPC 573 306
PACW AVA 5,636 4,509
PACW BPAT 14,823 12,052
PACW CISO 46,461 66,361
PACW IPCO 20,463 21,587
PACW NWMT 3 0
PACW PGE 40,592 37,467
PACW PSEI 23,009 21,643
PACW SCL 1,597 1,456
December PGE AVA 0 0
Attachment E Page 123 of 178
PGE BPAT 42,026 42,746
December PGE CISO 43,528 41,651
PGE NWMT 298 0
PGE PACW 12,010 20,839
PGE PSEI 0 0
PGE SCL 1,605 1,450
PGE TPWR 0 0
PNM AZPS 63,186 78,499
PNM SRP 2,494 2,653
PNM TEPC 18,123 20,165
PSEI AVA 2 0
PSEI BPAT 17,207 17,624
PSEI IPCO 0 0
PSEI NWMT 132 0
PSEI PACW 12,207 14,049
PSEI PGE 0 0
PSEI PWRX 6,210 6,361
PSEI SCL 16,491 16,172
PSEI TPWR 5,473 6,745
PWRX BPAT 9,262 0
PWRX CISO 0 0
PWRX PSEI 19,063 19,179
SCL AVA 0 0
SCL BPAT 2,506 2,789
SCL IPCO 4,734 5,644
SCL PACW 603 806
SCL PGE 792 988
December SCL PSEI 6,638 8,276
Attachment E Page 124 of 178

TABLE 2: Energy transfers (MWh) in the FMM and RTD markets for Q4 2022

SRP AZPS 31,010 27,353
December SRP CISO 112,006 103,851
SRP PACE 0 0
SRP PNM 3 3
SRP TEPC 26,398 26,296
TEPC AZPS 416 188
TEPC CISO 72,158 68,914
TEPC LADWP 547 640
TEPC PACE 1,332 887
TEPC PNM 18,980 12,548
TEPC SRP 8,538 9,468
TIDC BANC 122 0
TIDC CISO 8,770 8,897
TPWR AVA 0 0
TPWR BPAT 12,015 13,298
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 17,779 17,616
Attachment E Page 125 of 178

GRAPH 2: Estimated maximum transfer capacity
WHEEL-THROUGH TRANSFERS
As the footprint of the WEIM grows, wheel-through transfers may become more common. In
order to derive the wheel-through transfers for each WEIM BAA, the ISO uses the following
calculation for every real-time interval dispatch:

• Total import: summation of transfers above base transfers coming into the WEIM
BAA under analysis
Attachment E Page 126 of 178
• Total export: summation of all transfers above base transfers going out of the WEIM
BAA under analysis
• Net import: the maximum of zero or the difference between total imports and total
exports
• Net export: the maximum of zero or the difference between total exports and total
imports
• Wheel-through: the minimum of the WEIM transfers into (total import) or WEIM
transfer out (total export) of a BAA for a given interval

All wheel-through transfers are summed over both the month and the quarter.

Currently, a WEIM entity facilitating a wheel through receives no direct financial benefit for
facilitating the wheel; only the sink and source directly benefit. As part of the WEIM
Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel
through volumes to assess whether, after the addition of new WEIM entities, there is a potential
future need to pursue a market solution to address the equitable sharing of wheeling benefits.

The ISO will continue to track the volume of wheel-through transfers in the WEIM market in the
quarterly reports.

This volume reflects the total wheel-through transfers for each WEIM BAA, regardless of the
potential paths used to wheel through. The net imports and exports estimated in this section
reflect the overall volume of net imports and exports; in contrast, the imports and exports
provided in Table 2 reflect the gross transfers between two WEIM BAAs.

The metric is measured as energy in MWh for each month and the corresponding calendar
quarter, as shown in Tables 3 through 6 and Graphs 3 through 6.

BAA Net Export Net Import Wheel Through
AVA

76,406

118,148

50,611
AZPS

450,985

83,461

361,025
BANC

2,697

665,176

-
BPAT

106,572

247,609

161,995
CISO

834,232

1,105,856

903,198
IPCO

61,352

485,208

153,667
LADWP

260,650

218,438

133,216
NEVP

368,747

165,967

291,319
NWMT

127,090

26,505

44,920
Attachment E Page 127 of 178
PACE

677,683

131,016

146,951
PACW

195,076

96,713

293,040
PGE

183,493

164,535

124,801
PNM

200,941

80,674

24,095
PSEI

115,928

144,662

69,316
PWRX

23,028

420,672

23,813
SCL

31,497

46,312

22,908
SRP

505,405

74,935

67,643
TEPC

183,825

170,815

11,269
TIDC

45,124

14,187

-
TPWR

31,920

21,761

45,153

TABLE 3: Estimated wheel-through transfers in Q4 2022

GRAPH 3: Estimated wheel-through transfers in Q4 2022

Attachment E Page 128 of 178
BAA Net Export Net Import Wheel Through
AVA

28,087

27,179

18,200
AZPS

131,719

28,320

101,527
BANC

2,168

181,497

-
BPAT

35,475

87,708

54,002
CISO

301,772

368,703

288,975
IPCO

9,475

234,727

43,549
LADWP

67,890

109,045

47,561
NEVP

173,265

25,418

76,536
NWMT

52,954

4,340

13,186
PACE

264,269

14,882

52,457
PACW

60,473

19,671

82,818
PGE

54,798

53,116

35,194
PNM

62,616

13,783

3,737
PSEI

32,766

40,925

24,286
PWRX

1,809

212,792

8,965
SCL

13,725

9,984

4,423
SRP

188,884

36,986

18,251
TEPC

48,947

78,396

964
TIDC

18,321

3,495

-
TPWR

8,878

7,329

16,041

TABLE 4: Estimated wheel-through transfers in October 2022

Attachment E Page 129 of 178

GRAPH 4: Estimated wheel-through transfers in October 2022

BAA Net Export Net Import Wheel Through
AVA

30,282

28,128

12,218
AZPS

83,298

35,284

121,541
BANC

233

238,370

-
BPAT

34,377

69,198

47,478
CISO

284,906

392,748

287,587
IPCO

19,904

134,514

42,749
LADWP

99,728

50,273

37,376
NEVP

109,099

52,146

97,723
NWMT

26,794

13,225

12,974
PACE

243,821

37,035

35,485
PACW

65,859

24,518

113,890
PGE

65,789

45,741

45,827
PNM

51,010

30,596

6,356
Attachment E Page 130 of 178
PSEI

43,754

43,463

23,488
PWRX

8,116

131,210

8,771
SCL

10,059

12,822

7,696
SRP

173,991

26,363

34,419
TEPC

52,114

49,217

425
TIDC

17,906

3,462

-
TPWR

7,478

10,203

13,761
TABLE 5: Estimated wheel-through transfers in November 2022

GRAPH 5: Estimated wheel-through transfers in November 2022

BAA Net Export Net Import Wheel Through
AVA

18,037

62,841

20,192
Attachment E Page 131 of 178
AZPS

235,968

19,857

137,956
BANC

295

245,309

-
BPAT

36,720

90,703

60,515
CISO

247,554

344,404

326,636
IPCO

31,972

115,968

67,369
LADWP

93,031

59,120

48,279
NEVP

86,383

88,403

117,061
NWMT

47,342

8,940

18,759
PACE

169,592

79,098

59,009
PACW

68,744

52,524

96,332
PGE

62,906

65,678

43,781
PNM

87,315

36,295

14,001
PSEI

39,409

60,275

21,541
PWRX

13,102

76,669

6,076
SCL

7,713

23,507

10,790
SRP

142,530

11,586

14,973
TEPC

82,764

43,202

9,881
TIDC

8,897

7,231

-
TPWR

15,564

4,229

15,351

TABLE 6: Estimated wheel-through transfers in December 2022

Attachment E Page 132 of 178

GRAPH 6: Estimated wheel-through transfers in December 2022
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS
The WEIM benefit calculation includes the economic benefits that can be attributed to avoided
renewable curtailment within the ISO footprint. If not for energy transfers facilitated by the
WEIM, some renewable generation located within the ISO would have been curtailed via either
economic or exceptional dispatch. The total avoided renewable curtailment volume in MWh for
Q4 2022 was calculated to be 10,571 MWh (October) + 9,270 MWh (November) + 5,767 MWh
(December) = 25,609 MWh total.
There are environmental benefits of avoided renewable curtailment as well. Under the
assumption that avoided renewable curtailments displace production from other resources at a
default emission rate of 0.428 metric tons CO2/MWh, avoided curtailments displaced an
estimated 10,960 metric tons of CO2 for Q4 2022. Avoided renewable curtailments also may
have contributed to an increased volume of renewable credits that would otherwise have been
unavailable. This report does not quantify the additional value in dollars associated with this
benefit. Total estimated reductions in the curtailment of renewable energy in the ISO footprint,
along with the associated reductions in CO2, are shown in Table 7.
Year Quarter MWh Eq. Tons CO2
1 8,860 3,792
2015 2 3,629 1,553
3 828 354
4 17,765 7,521
Attachment E Page 133 of 178
1 112,948 48,342
2016 2 158,806 67,969
3 33,094 14,164
4 23,390 10,011
1 52,651 22,535
2017 2 67,055 28,700
3 23,331 9,986
4 18,060 7,730
1 65,860 28,188
2018 2 129,128 55,267
3 19,032 8,146
4 23,425 10,026
1 52,254 22,365
2019 2 132,937 56,897
3 33,843 14,485
4 35,254 15,089
1 86,740 37,125
2020 2 147,514 63,136
3 37,548 16,071
4 39,956 17,101
2021 1 76,147 32,591
2 109,059 46,677
3 23,042 9,862
4 38,044 16,283
2022 1 94,168 40,304
2 118,352 50,655
3 42,468 18,176
4 25,609 10,960
Total 1,850,797 792,061

TABLE 7: Total reduction in curtailment of renewable energy and associated reductions in CO2
Attachment E Page 134 of 178
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS
The WEIM facilitates procurement of flexible ramping capacity in the FMM to address
variability that may occur in the RTD. Because variability across different BAAs may happen in
opposite directions, the flexible ramping requirement for the entire WEIM footprint can be less
than the sum of individual BAA’s requirements. This difference is known as flexible ramping
procurement diversity savings.
Starting in 2016, the ISO replaced the flexible ramping constraint with flexible ramping products
that provide both upward and downward ramping. The minimum and maximum flexible ramping
requirements for each BAA and for each direction are listed in Table 8.
Month BAA Direction Minimum
requirement
Maximum
requirement
AVA up 0 95
October AZPS up 0 328
BANC up 0 76
BPAT up 0 401
CISO up 0 2,768
IPCO up 0 253
LADWP up 0 361
NEVP up 0 410
NWMT up 0 111
PACE up 0 506
PACW up 0 123
PGE up 0 191
PNM up 0 169
PSEI up 0 166
PWRX up 0 247
SCL up 0 41
SRP up 0 302
TEPC up 0 220
TIDC up 0 19
TPWR up 0 15
ALL EIM up 0 2,583
AVA down 0 113
Attachment E Page 135 of 178
AZPS down 0 444
BANC down 0 134
BPAT down 0 581
October CISO down 0 1,145
IPCO down 0 198
LADWP down 0 357
NEVP down 0 471
NWMT down 0 150
PACE down 0 613
PACW down 0 157
PGE down 0 185
PNM down 0 218
PSEI down 0 137
PWRX down 0 307
SCL down 0 26
SRP down 0 519
TEPC down 0 176
TIDC down 0 25
TPWR down 0 18
ALL EIM down 0 1,593
AVA up 15 87
November AZPS up 48 328
BANC up 7 76
BPAT up 47 371
CISO up 321 2,758
IPCO up 29 253
LADWP up 41 361
NEVP up 24 463
NWMT up 4 127
PACE up 100 447
PACW up 36 178
Attachment E Page 136 of 178
PGE up 35 190
PNM up 44 141
PSEI up 30 167
PWRX up 70 310
November SCL up 3 30
SRP up 27 302
TEPC up 43 220
TIDC up 2 19
TPWR up 2 19
ALL WEIM up 491 2,684
AVA down 7 103
AZPS down 36 369
BANC down 4 140
BPAT down 72 639
CISO down 192 1,250

IPCO down 46 198
LADWP down 52 285
NEVP down 21 471
NWMT down 30 126
PACE down 176 538
PACW down 27 139
PGE down 31 230
PNM down 38 218
PSEI down 32 137
PWRX down 79 340
SCL down 3 28
SRP down 30 344
TEPC down 22 167
TIDC down 2 25
TPWR down 3 24
ALL EIM down 308 1,989
Attachment E Page 137 of 178

December

AVA up 17 81
AZPS up 56 300
BANC up 8 83
BPAT up 54 386
CISO up 313 2,337
IPCO up 34 189
LADWP up 40 393
NEVP up 20 463
NWMT up 25 127
PACE up 115 460
PACW up 48 174
PGE up 48 200
PNM up 44 155
PSEI up 39 167
PWRX up 85 294
SCL up 5 31
SRP up 29 280
TEPC up 60 220
TIDC up 2 19
TPWR up 4 19
ALL WEIM up 455 2,771
AVA down 17 86
AZPS down 26 246
BANC down 6 82
BPAT down 98 639
CISO down 153 1,332
IPCO down 42 194
LADWP down 43 262
NEVP down 22 408
NWMT down 42 124
PACE down 165 501
Attachment E Page 138 of 178

December

PACW down 27 143
PGE down 28 204
PNM down 37 141
PSEI down 35 153
PWRX down 56 345
SCL down 5 28
SRP down 22 344
TEPC down 26 165
TIDC down 1 17
TPWR down 3 24
ALL WEIM down 319 2,175
Table 8: Flexible ramping requirements
The flexible ramping procurement diversity savings for all the intervals averaged over the month
are shown in Table 9. The percentage savings is the average MW savings divided by the sum of
the individual BAA requirements.
October November December
Direction Up Down Up Down Up Down
Average MW saving 1,517

1,720 1,551 1,603 1,617 1,606
Sum of BAA requirements 2,908 2,657 2,866 2,622 3,056 2,632
Percentage savings 52% 65% 54% 61% 53% 61%
Table 9: Flexible ramping procurement diversity savings in Q4 2022
Flexible ramping capacity may be used in RTD to handle uncertainties in the future interval. The
RTD flexible ramping capacity is prorated to each BAA. Flexible ramping surplus MW is defined
as the awarded flexible ramping capacity in RTD minus its share, and the flexible ramping
surplus cost is defined as the flexible ramping surplus MW multiplied by the flexible ramping
WEIM-wide marginal price. A positive flexible ramping surplus MW is the capacity that a BAA
provided to help other BAAs, and a negative flexible ramping surplus MW is the capacity that a
BAA received from other BAAs.
The EIM dispatch cost for a BAA with positive flexible ramping surplus MW is increased
because some capacities are used to help other BAAs. The flexible ramping surplus cost is
subtracted from the BAA’s WEIM dispatch cost to reflect the true dispatch cost of a BAA. Please
see the Benefit Report Methodology for more details.
Attachment E Page 139 of 178
CONCLUSION
Using state-of-the-art technology to find and deliver low-cost energy to meet real-time demand,
the WEIM demonstrates that utilities can realize financial and operational benefits through
increased coordination and optimization. In addition to these benefits, the WEIM provides
significant environmental benefits through the reduction of renewable curtailments during
periods of oversupply.
Sharing resources across a larger geographic area reduces greenhouse gas emissions by using
renewable generation that otherwise would have been turned off. The quantified environmental
benefits from avoided curtailments of renewable generation from 2015 to-date reached 792,061
metric tons of CO2, roughly the equivalent of avoiding the emissions from 166,527 passenger
cars driven for one year.

Attachment E Page 140 of 178
APPENDIX 1: GLOSSARY OF ABBREVIATIONS

Abbreviation Description
APS Arizona Public Service
AVA Avista Utilities
BAA Balancing Authority Area
BANC Balancing Authority of Northern California
BPA Bonneville Power Administration
CISO, ISO California ISO
EIM Energy Imbalance Market
FMM Fifteen Minute Market
GHG Greenhouse Gas
IPCO Idaho Power
LADWP Los Angeles Department of Water and Power
MW Megawatt
MWh Megawatt-Hour
NVE NV Energy
PAC PacifiCorp
PACE PacifiCorp East
PACW PacifiCorp West
PGE Portland General Electric
PSE Puget Sound Energy
PWRX Powerex
RTD Real Time Dispatch
SCL Seattle City Light
SRP Salt River Project
TEP Tucson Electric Power
TID Turlock Irrigation District
TPWR Tacoma Power
WEIM Western Energy Imbalance Market

Attachment E Page 141 of 178

Western Energy Imbalance Market Benefits
Fisrt Quarter 2023

April 27, 2023
Attachment E Page 142 of 178

CONTENTS

EXECUTIVE SUMMARY ........................................................................................................... 3
BACKGROUND ......................................................................................................................... 4
WEIM ECONOMIC BENEFITS IN Q1 2023 ............................................................................... 4
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION ................................................................... 5
INTER-REGIONAL TRANSFERS ............................................................................................................. 6
WHEEL-THROUGH TRANSFERS ......................................................................................................... 23
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS ....................................30
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS ..............................................31
CONCLUSION ..........................................................................................................................36
APPENDIX 1: GLOSSARY OF ABBREVIATIONS...................................................................37
Attachment E Page 143 of 178

EXECUTIVE SUMMARY
This report presents the benefits associated with
participation in the Western Energy Imbalance
Market (WEIM).
The measured benefits of participation in the WEIM
include cost savings, increased integration of
renewable energy, and improved operational
efficiencies including the reduction of
the need for real-time flexible reserves.
This analysis demonstrates the benefit of economic
dispatch in the real time market across a larger
WEIM footprint with diverse resources and geography.

Q1 2023 Gross Benefits by Participant
(millions $)
Arizona Public Service $26.53
Avista $6.38
BANC $44.85
BPA $11.83
California ISO $67.86
Idaho Power $13.32
LADWP $30.84
NV Energy $47.38
NorthWestern Energy $12.60
PacifiCorp $70.31
Portland General Electric $21.75
PNM $22.45
Puget Sound Energy $15.37
Powerex $16.80
Seattle City Light $4.21
Salt River Project $31.39
Tacoma Power $6.55
TEP $10.39
TID $3.01
Total $463.82
Gross benefits from WEIM since November 2014
$3.86 billion
ECONOMICAL
$463.82 M
Gross benefits realized due to more
efficient inter-and intra-regional
dispatch in the Fifteen-Minute
Market (FMM) and Real-Time
Dispatch (RTD)*

ENVIRONMENTAL
22,685
Metric tons of CO2** avoided
curtailments

OPERATIONAL
50%
Average reduction in flexibility
reserves across the footprint
2023
Q1 BENEFITS
Attachment E Page 144 of 178

*WEIM Quarterly Benefit Report Methodology: https://www.westerneim.com/Documents/EIM-BenefitMethodology.pdf.
**The GHG emission reduction reported is associated with the avoided curtailment only. The current market process and
counterfactual methodology cannot differentiate the GHG emissions resulting from serving ISO load via the EIM versus dispatch that
would have occurred external to the ISO without the WEIM. For more details, see
http://www.caiso.com/Documents/GreenhouseGasEmissionsTrackingReport-FrequentlyAskedQuestions.pdf
BACKGROUND
The Western EIM began financially binding operation on November 1, 2014 by optimizing
resources across the ISO and PacifiCorp Balancing Authority Areas (BAAs). NV Energy began
participating in December 2015, Arizona Public Service and Puget Sound Energy began
participating in October 2016, and Portland General Electric began participating in October
2017. Idaho Power and Powerex began participating in April 2018, and the Balancing Authority
of Northern California (BANC) began participating in April 2019. Seattle City Light and Salt River
Project began participating in April 2020.
In 2021, new balancing authorities began participating in the Western EIM, with the Turlock
Irrigation District (TID) in March 2021, the second phase of BANC in March 2021, and the Los
Angeles Department of Water and Power (LADWP) and Public Service Company of New
Mexico (PNM) in April 2021, followed by NorthWestern Energy (NWMT) starting in June 2021.
Avista Utilities (AVA) and Tacoma Power (TPWR), two utilities serving a combined 600,000
electric customers in the Pacific Northwest, became the newest members of the WEIM, with
both beginning their participation on March 2, 2022. On May 3, 2022, the Bonneville Power
Administration (BPA) and Tucson Electric Power (TEP) both Joined the WEIM.
The Western EIM footprint now includes portions of Arizona, California, Idaho, Montana,
Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, and extends to the border with
Canada.
WEIM ECONOMIC BENEFITS IN Q1 2023
Table 1 shows the estimated WEIM gross benefits by each region per month1. The monthly
savings presented show $188.96 million for January, $127.41 million for February, and $147.45
million for March with a total estimated benefit of $463.82 million for this quarter2. This level of
WEIM benefits accrued from having additional WEIM areas participating in the market and
economical transfers displacing more expensive generation.
1 The WEIM benefits reported here are calculated based on available data. Intervals without complete data are
excluded in the calculation. The intervals excluded due to unavailable data are normally within a few percent
points of the total intervals.
2 For several quarterly estimates, CAISO benefits were calculated on a variation of the counterfactual
methodology. For CAISO only the logic had considered offline resources as part of the bid stack in the
counterfactual. In Q4 2021, CAISO identified some questionable results that drove persistent negative benefits
for CAISO when considering offline resources. Since Q4 2021, the benefit calculation for CAISO area follows
the same methodology applicable to all WEIM entities in which only online resources are used.
Attachment E Page 145 of 178
Region January February March Total
APS $11.57 $7.26 $7.70 $26.53
AVA $2.84 $1.65 $1.89 $6.38
BANC $18.56 $20.88 $5.41 $44.85
BPA $4.57 $4.20 $3.06 $11.83
CISO $22.41 $17.64 $27.81 $67.86
IPCO $6.32 $3.33 $3.67 $13.32
LADWP $11.78 $10.19 $8.87 $30.84
NVE $17.95 $8.35 $21.08 $47.38
NWMT $8.07 $2.60 $1.93 $12.60
PAC $33.24 $14.83 $22.24 $70.31
PGE $9.29 $6.51 $5.95 $21.75
PNM $10.28 $5.06 $7.11 $22.45
PSE $7.33 $3.47 $4.57 $15.37
PWRX $2.15 $7.73 $6.92 $16.80
SCL $1.74 $1.05 $1.42 $4.21
SRP $12.40 $9.00 $9.99 $31.39
TPWR $3.25 $1.23 $2.07 $6.55
TEP $4.18 $1.68 $4.53 $10.39
TID $1.03 $0.75 $1.23 $3.01
Total $188.96 $127.41 $147.45 $463.82
TABLE 1: Q1 2023 benefits in millions USD
CUMULATIVE ECONOMIC BENEFITS SINCE INCEPTION
Since the start of the WEIM in November 2014, the cumulative economic benefits of the market
have totaled $3.86 billion. The quarterly benefits have grown over time as a result of the
participation of new BAAs, which results in benefits for both the individual BAA but also
compounds the benefits to adjacent BAAs through additional transfers. The ISO began
publishing quarterly WEIM benefit reports in April 2015.3
Graph 1 illustrates the gross economic benefits of the WEIM by quarter for each participating
BAA.
3 Prior reports are available at https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx
Attachment E Page 146 of 178

GRAPH 1: Cumulative economic benefits for each quarter by BAA
INTER-REGIONAL TRANSFERS
A significant contributor to EIM benefits is transfers across balancing areas, providing access to
lower cost supply, while factoring in the cost of compliance with greenhouse gas (GHG)
emissions regulations when energy is transferred into the ISO. As such, the transfer volumes
are a good indicator of a portion of the benefits attributed to the WEIM. Transfers can take place
in both the 15-Minute Market and Real-Time Dispatch (RTD).
Generally, transfer limits are based on transmission and interchange rights that participating
balancing authority areas make available to the WEIM, with the exception of the PacifiCorp
West (PACW) -ISO transfer limit and the Portland General Electric (PGE) -ISO transfer limit in
RTD. These RTD transfer capacities between PACW/PGE and the ISO are determined based
on the allocated dynamic transfer capability driven by system operating conditions. This report
does not quantify a BAA’s opportunity cost that the utility considered when using its transfer
rights for the EIM.
Table 2 provides the 15-minute and 5-minute WEIM transfer volumes with base schedule
transfers excluded. The WEIM entities submit inter-BAA transfers in their base schedules. The
benefits quantified in this report are only attributable to the transfers that occurred through the
WEIM. The benefits do not include any transfers attributed to transfers submitted in the base
schedules that are scheduled prior to the start of the EIM.
The transfer from BAA_x to BAA_y and the transfer from BAA_y to BAA_x are separately
reported. For example, if there is a 100 Megawatt-Hour (MWh) transfer during a 5-minute
interval, in addition to a base transfer from ISO to NVE, it will be reported as 100 MWh
from_BAA ISO to_BAA NEVP, and 0 MWh from_BAA NEVP to_BAA ISO in the opposite
Attachment E Page 147 of 178
direction. The 15-minute transfer volume is the result of optimization in the 15-minute market
using all bids and base schedules submitted into the WEIM. The 5-minute transfer volume is the
result of optimization using all bids and base schedules submitted into WEIM, based on unit
commitments determined in the 15-minute market optimization. The maximum transfer
capacities between WEIM entities are shown in Graph 2 below.

Month

From BAA

To BAA
15min WEIM transfer
(15m – base)
5min WEIM transfer
(5m – base)
AVA BPAT 14,447 12,743
January AVA CISO 0 0
AVA IPCO 25,928 22,418
AVA NWMT 3,527 2,075
AVA PACW 8,338 9,885
AVA PGE 0 0
AVA PSEI 0 0
AVA SCL 0 0
AVA TPWR 0 0
AZPS CISO 239,844 188,035
AZPS LADWP 54,635 54,691
AZPS NEVP 14,963 15,504
AZPS PACE 35,647 38,963
AZPS PNM 5,920 2,973
AZPS SRP 2,800 2,312
AZPS TEPC 5,524 1,721
BANC BPAT 0 0
BANC CISO 5,730 5,948
BANC TIDC 29 0
BPAT AVA 9,832 9,473
BPAT BANC 0 0
BPAT CISO 26,238 33,920
BPAT IPCO 9,644 271
Attachment E Page 148 of 178
January BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 16,374 2,157
BPAT PACW 5,710 5,451
BPAT PGE 27,517 29,698
BPAT PSEI 14,731 14,954
BPAT PWRX 3,413 0
BPAT SCL 3,419 3,355
BPAT TPWR 7,335 8,831
CISO AVA 0 0
CISO AZPS 13,475 17,544
CISO BANC 101,677 105,617
CISO BPAT 23,062 26,574
CISO LADWP 49,505 56,542
CISO NEVP 18,639 20,381
CISO PACW 15,177 34,803
CISO PGE 35,840 53,953
CISO PWRX 154,650 171,000
CISO SRP 2,381 4,371
CISO TEPC 0 0
CISO TIDC 4,468 4,804
IPCO AVA 18,399 19,962
IPCO BPAT 426 166
IPCO NEVP 50,872 42,378
IPCO NWMT 218 565
IPCO PACE 39,298 18,343
IPCO PACW 30,297 31,398
January IPCO PSEI 0 0
Attachment E Page 149 of 178
IPCO SCL 9,620 8,790
January LADWP AZPS 169 289
LADWP BPAT 0 0
LADWP CISO 36,044 30,065
LADWP NEVP 10,247 11,522
LADWP PACE 18,160 19,136
LADWP TEPC 0 0
NEVP AZPS 250 844
NEVP BPAT 0 0
NEVP CISO 175,550 131,046
NEVP IPCO 49,907 49,266
NEVP LADWP 36,279 37,424
NEVP PACE 14,755 12,031
NWMT AVA 30,886 31,569
NWMT BPAT 9,417 8,840
NWMT IPCO 22,211 22,310
NWMT PACE 22,893 13,364
NWMT PACW 0 0
NWMT PGE 71 0
NWMT PSEI 285 0
NWMT TPWR 0 0
PACE AZPS 57,485 51,918
PACE IPCO 61,980 64,413
PACE LADWP 20,362 23,037
PACE NEVP 64,559 58,882
PACE NWMT 10,358 13,373
PACE PACW 40,489 39,802
January PACE SRP 0 0
Attachment E Page 150 of 178
PACE TEPC 55 302
January PACW AVA 6,464 5,835
PACW BPAT 5,869 5,212
PACW CISO 57,547 89,428
PACW IPCO 19,341 18,889
PACW NWMT 2 0
PACW PGE 64,408 64,217
PACW PSEI 20,751 19,480
PACW SCL 1,402 1,248
PGE AVA 0 0
PGE BPAT 28,931 31,304
PGE CISO 29,499 28,293
PGE NWMT 165 0
PGE PACW 14,299 18,163
PGE PSEI 0 0
PGE SCL 1,241 1,141
PGE TPWR 0 0
PNM AZPS 113,667 119,571
PNM SRP 498 465
PNM TEPC 15,512 17,130
PSEI AVA 0 0
PSEI BPAT 25,093 31,195
PSEI IPCO 0 0
PSEI NWMT 136 0
PSEI PACW 11,026 13,840
PSEI PGE 0 0
PSEI PWRX 13,662 15,620
January PSEI SCL 13,531 11,598
Attachment E Page 151 of 178
PSEI TPWR 407 570
January PWRX BPAT 18,442 0
PWRX CISO 0 0
PWRX PSEI 14,029 14,617
SCL AVA 0 0
SCL BPAT 1,139 1,906
SCL IPCO 3,741 4,651
SCL PACW 516 774
SCL PGE 789 1,094
SCL PSEI 5,235 8,650
SRP AZPS 49,716 50,770
SRP CISO 117,888 110,109
SRP PACE 0 0
SRP PNM 0 0
SRP TEPC 5,623 7,555
TEPC AZPS 812 40
TEPC CISO 62,756 61,758
TEPC LADWP 137 162
TEPC PACE 840 876
TEPC PNM 14,631 15,096
TEPC SRP 10,235 9,133
TIDC BANC 184 190
TIDC CISO 17,941 17,086
TPWR AVA 0 0
TPWR BPAT 11,559 12,150
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 23,512 23,880
Attachment E Page 152 of 178
February AVA BPAT 5,279 3,457
AVA CISO 0 0
AVA IPCO 30,101 26,908
AVA NWMT 8,116 7,304
AVA PACW 5,404 5,719
AVA PGE 0 0
AVA PSEI 0 0
AVA SCL 0 0
AVA TPWR 0 0
AZPS CISO 121,604 89,140
AZPS LADWP 29,838 26,510
AZPS NEVP 27,657 25,294
AZPS PACE 128,447 130,889
AZPS PNM 9,649 9,443
AZPS SRP 1,545 1,483
AZPS TEPC 2,310 2,350
BANC BPAT 0 0
BANC CISO 1,189 682
BANC TIDC 77 0
BPAT AVA 10,013 8,934
BPAT BANC 0 0
BPAT CISO 16,204 24,965
BPAT IPCO 13,746 7,826
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 18,506 8,124
BPAT PACW 8,771 6,464
February BPAT PGE 29,445 29,808
Attachment E Page 153 of 178
BPAT PSEI 22,973 24,062
February BPAT PWRX 4,877 0
BPAT SCL 5,075 4,840
BPAT TPWR 11,241 13,604
CISO AVA 0 0
CISO AZPS 42,390 39,061
CISO BANC 169,164 175,480
CISO BPAT 26,038 28,530
CISO LADWP 45,705 50,036
CISO NEVP 68,821 56,244
CISO PACW 22,574 55,675
CISO PGE 62,842 89,377
CISO PWRX 304,096 326,115
CISO SRP 31,532 30,711
CISO TEPC 0 0
CISO TIDC 6,530 7,114
IPCO AVA 22,331 26,192
IPCO BPAT 1,540 779
IPCO NEVP 23,409 14,186
IPCO NWMT 191 738
IPCO PACE 15,762 8,421
IPCO PACW 28,915 21,610
IPCO PSEI 0 0
IPCO SCL 7,578 7,099
LADWP AZPS 1,083 1,949
LADWP BPAT 0 0
LADWP CISO 18,190 14,640
February LADWP NEVP 10,565 10,472
Attachment E Page 154 of 178
LADWP PACE 19,162 16,736
February LADWP TEPC 0 0
NEVP AZPS 829 2,108
NEVP BPAT 0 0
NEVP CISO 70,252 44,499
NEVP IPCO 77,369 67,803
NEVP LADWP 30,651 34,471
NEVP PACE 100,091 87,196
NWMT AVA 12,646 12,559
NWMT BPAT 2,857 775
NWMT IPCO 19,350 18,526
NWMT PACE 29,657 25,144
NWMT PACW 0 0
NWMT PGE 0 0
NWMT PSEI 195 0
NWMT TPWR 0 0
PACE AZPS 32,910 27,943
PACE IPCO 39,841 33,920
PACE LADWP 10,562 10,073
PACE NEVP 16,583 14,061
PACE NWMT 7,867 6,093
PACE PACW 26,877 17,452
PACE SRP 0 0
PACE TEPC 0 0
PACW AVA 7,496 8,647
PACW BPAT 2,345 1,680
PACW CISO 33,658 46,692
February PACW IPCO 22,740 28,416
Attachment E Page 155 of 178

PACW NWMT 0 0
February PACW PGE 45,848 42,930
PACW PSEI 20,930 20,019
PACW SCL 1,425 1,319
PGE AVA 0 0
PGE BPAT 22,706 23,755
PGE CISO 25,404 23,302
PGE NWMT 0 0
PGE PACW 25,456 28,718
PGE PSEI 0 0
PGE SCL 1,341 1,289
PGE TPWR 0 0
PNM AZPS 90,489 91,889
PNM SRP 1,128 1,556
PNM TEPC 14,685 16,367
PSEI AVA 0 0
PSEI BPAT 24,244 26,069
PSEI IPCO 0 0
PSEI NWMT 314 0
PSEI PACW 19 0
PSEI PGE 0 0
PSEI PWRX 22,045 22,782
PSEI SCL 19,703 17,653
PSEI TPWR 4,953 5,785
PWRX BPAT 16,060 0
PWRX CISO 0 0
PWRX PSEI 7,676 7,094
February SCL AVA 0 0
Attachment E Page 156 of 178
SCL BPAT 504 601
February SCL IPCO 6,078 6,984
SCL PACW 821 1,002
SCL PGE 831 1,059
SCL PSEI 4,878 6,181
SRP AZPS 38,548 45,286
SRP CISO 174,867 161,834
SRP PACE 0 0
SRP PNM 23 5
SRP TEPC 24,646 24,850
TEPC AZPS 1,800 683
TEPC CISO 29,966 26,352
TEPC LADWP 152 272
TEPC PACE 371 121
TEPC PNM 10,702 7,802
TEPC SRP 31,790 30,468
TIDC BANC 12 0
TIDC CISO 17,975 16,672
TPWR AVA 0 0
TPWR BPAT 5,585 6,249
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 12,520 13,643
March AVA BPAT 9,088 5,439
AVA CISO 0 0
AVA IPCO 15,021 10,702
AVA NWMT 19,795 18,901
AVA PACW 5,058 5,192
Attachment E Page 157 of 178
AVA PGE 0 0
March AVA PSEI 0 0
AVA SCL 18 0
AVA TPWR 0 0
AZPS CISO 94,839 72,171
AZPS LADWP 23,695 31,347
AZPS NEVP 47,626 41,500
AZPS PACE 157,262 161,848
AZPS PNM 15,947 17,827
AZPS SRP 4,154 3,967
AZPS TEPC 3,646 4,856
BANC BPAT 0 0
BANC CISO 44,574 36,068
BANC TIDC 3,432 2,735
BPAT AVA 11,325 10,021
BPAT BANC 0 0
BPAT CISO 17,197 22,876
BPAT IPCO 14,535 4,749
BPAT LADWP 0 0
BPAT NEVP 0 0
BPAT NWMT 17,054 12,962
BPAT PACW 4,837 3,257
BPAT PGE 24,718 22,672
BPAT PSEI 15,618 20,547
BPAT PWRX 4,923 0
BPAT SCL 4,745 4,992
BPAT TPWR 10,188 13,112
March CISO AVA 0 0
Attachment E Page 158 of 178
CISO AZPS 41,759 30,917
March CISO BANC 43,639 57,361
CISO BPAT 31,944 35,760
CISO LADWP 50,554 51,085
CISO NEVP 83,463 66,098
CISO PACW 12,786 41,442
CISO PGE 49,531 71,815
CISO PWRX 320,642 338,692
CISO SRP 57,800 54,009
CISO TEPC 0 0
CISO TIDC 13,747 14,714
IPCO AVA 30,978 32,600
IPCO BPAT 6,070 6,616
IPCO NEVP 27,095 16,084
IPCO NWMT 1,024 1,548
IPCO PACE 56,934 50,980
IPCO PACW 40,885 30,879
IPCO PSEI 5,331 4,233
IPCO SCL 9,549 8,271
LADWP AZPS 2,818 4,747
LADWP BPAT 0 0
LADWP CISO 37,042 26,249
LADWP NEVP 23,056 22,861
LADWP PACE 29,943 34,177
LADWP TEPC 0 0
NEVP AZPS 3,215 5,454
NEVP BPAT 0 0
March NEVP CISO 62,375 46,255
Attachment E Page 159 of 178

NEVP IPCO 57,556 49,906
March NEVP LADWP 19,634 19,823
NEVP PACE 212,357 186,860
NWMT AVA 10,554 9,244
NWMT BPAT 5,717 3,668
NWMT IPCO 6,618 5,441
NWMT PACE 43,856 41,416
NWMT PACW 0 0
NWMT PGE 1 0
NWMT PSEI 110 0
NWMT TPWR 0 0
PACE AZPS 18,149 12,804
PACE IPCO 31,322 32,991
PACE LADWP 7,604 4,718
PACE NEVP 5,031 3,178
PACE NWMT 6,576 4,985
PACE PACW 31,300 24,028
PACE SRP 0 0
PACE TEPC 0 0
PACW AVA 6,192 6,250
PACW BPAT 6,379 4,744
PACW CISO 17,710 37,856
PACW IPCO 16,380 15,076
PACW NWMT 0 0
PACW PGE 65,927 56,243
PACW PSEI 40,077 37,812
PACW SCL 1,724 1,375
March PGE AVA 0 0
Attachment E Page 160 of 178
PGE BPAT 41,815 29,998
March PGE CISO 17,578 15,852
PGE NWMT 1 0
PGE PACW 10,172 16,529
PGE PSEI 2,480 2,995
PGE SCL 1,306 1,242
PGE TPWR 0 0
PNM AZPS 114,933 125,827
PNM SRP 803 852
PNM TEPC 13,343 12,707
PSEI AVA 0 0
PSEI BPAT 33,095 26,767
PSEI IPCO 2,931 2,478
PSEI NWMT 97 0
PSEI PACW 5,289 6,876
PSEI PGE 1,040 1,124
PSEI PWRX 23,355 26,297
PSEI SCL 23,516 21,716
PSEI TPWR 7,682 7,104
PWRX BPAT 16,390 0
PWRX CISO 0 0
PWRX PSEI 7,650 6,979
SCL AVA 7 0
SCL BPAT 856 846
SCL IPCO 5,394 5,905
SCL PACW 359 522
SCL PGE 721 814
March SCL PSEI 3,440 4,061
Attachment E Page 161 of 178

TABLE 2: Energy transfers (MWh) in the FMM and RTD markets for Q1 2023

SRP AZPS 53,332 52,849
March SRP CISO 136,422 125,198
SRP PACE 0 0
SRP PNM 58 91
SRP TEPC 25,779 23,480
TEPC AZPS 2,770 2,511
TEPC CISO 65,489 67,012
TEPC LADWP 0 0
TEPC PACE 5,869 4,703
TEPC PNM 21,855 16,460
TEPC SRP 24,516 21,236
TIDC BANC 4,589 5,538
TIDC CISO 19,037 15,510
TPWR AVA 0 0
TPWR BPAT 6,029 4,742
TPWR NWMT 0 0
TPWR PGE 0 0
TPWR PSEI 6,198 7,767
Attachment E Page 162 of 178

GRAPH 2: WEIM transfer
Attachment E Page 163 of 178
WHEEL-THROUGH TRANSFERS
As the footprint of the WEIM grows, wheel-through transfers may become more common. In
order to derive the wheel-through transfers for each WEIM BAA, the ISO uses the following
calculation for every real-time interval dispatch:

• Total import: summation of transfers above base transfers coming into the WEIM
BAA under analysis
• Total export: summation of all transfers above base transfers going out of the WEIM
BAA under analysis
• Net import: the maximum of zero or the difference between total imports and total
exports
• Net export: the maximum of zero or the difference between total exports and total
imports
• Wheel-through: the minimum of the WEIM transfers into (total import) or WEIM
transfer out (total export) of a BAA for a given interval

All wheel-through transfers are summed over both the month and the quarter.

Currently, a WEIM entity facilitating a wheel through receives no direct financial benefit for
facilitating the wheel; only the sink and source directly benefit. As part of the WEIM
Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel
through volumes to assess whether, after the addition of new WEIM entities, there is a potential
future need to pursue a market solution to address the equitable sharing of wheeling benefits.

The ISO will continue to track the volume of wheel-through transfers in the WEIM market in the
quarterly reports.

This volume reflects the total wheel-through transfers for each WEIM BAA, regardless of the
potential paths used to wheel through. The net imports and exports estimated in this section
reflect the overall volume of net imports and exports; in contrast, the imports and exports
provided in Table 2 reflect the gross transfers between two WEIM BAAs.

The metric is measured as energy in MWh for each month and the corresponding calendar
quarter, as shown in Tables 3 through 6 and Graphs 3 through 6.

BAA Net Export Net Import Wheel Through
AVA

89,033

139,575

41,711
AZPS

335,627

97,806

587,198
BANC

45,406

344,159

27
BPAT

163,219

151,860

188,705
Attachment E Page 164 of 178
CISO

1,354,826

848,513

760,999
IPCO

134,840

282,849

217,001
LADWP

116,399

323,748

76,443
NEVP

478,330

121,989

296,657
NWMT

138,434

24,401

54,423
PACE

307,605

714,838

136,367
PACW

198,530

104,643

314,838
PGE

103,768

345,990

118,814
PNM

350,796

34,129

35,569
PSEI

143,862

143,365

93,611
PWRX

9,974

881,791

18,715
SCL

24,259

75,138

20,791
SRP

510,350

68,884

91,678
TEPC

253,452

100,086

11,232
TIDC

54,996

29,366

-

TABLE 3: Estimated wheel-through transfers in Q1 2023

Attachment E Page 165 of 178

GRAPH 3: Estimated wheel-through transfers in Q1 2023

BAA Net Export Net Import Wheel Through
AVA

31,563

51,280

15,559
AZPS

104,474

41,250

199,725
BANC

5,948

105,806

-
BPAT

44,031

66,013

64,078
CISO

250,023

450,123

245,565
IPCO

54,962

115,578

66,641
LADWP

28,738

139,583

32,273
NEVP

136,668

54,724

93,943
NWMT

63,081

5,166

13,003
PACE

208,253

59,238

43,474
PACW

81,578

31,385

122,731
Attachment E Page 166 of 178
PGE

37,956

108,018

40,945
PNM

125,036

5,939

12,130
PSEI

44,148

52,906

28,675
PWRX

5,951

177,954

8,665
SCL

9,611

18,669

7,464
SRP

160,003

7,850

8,432
TEPC

82,788

22,430

4,278
TIDC

17,276

4,804

-
TPWR

27,342

714

8,688

TABLE 4: Estimated wheel-through transfers in January 2023

GRAPH 4: Estimated wheel-through transfers in January 2023

Attachment E Page 167 of 178
BAA Net Export Net Import Wheel Through
AVA

32,236

45,181

11,152
AZPS

111,287

35,097

173,822
BANC

682

175,480

-
BPAT

68,437

31,704

60,190
CISO

582,404

172,838

275,940
IPCO

25,221

136,577

53,806
LADWP

28,307

105,874

15,489
NEVP

152,045

36,225

84,033
NWMT

43,070

8,325

13,934
PACE

72,930

231,896

36,612
PACW

49,803

36,741

99,900
PGE

34,474

120,584

42,590
PNM

102,484

9,921

7,329
PSEI

45,624

44,335

26,665
PWRX

2,650

344,454

4,444
SCL

7,714

24,087

8,114
SRP

186,532

18,775

45,443
TEPC

65,427

43,296

271
TIDC

16,672

7,114

-
TPWR

8,439

7,936

11,453
TABLE 5: Estimated wheel-through transfers in February 2023

Attachment E Page 168 of 178

GRAPH 5: Estimated wheel-through transfers in February 2023

BAA Net Export Net Import Wheel Through
AVA

25,234

43,115

15,000
AZPS

119,866

21,459

213,651
BANC

38,775

62,872

27
BPAT

50,751

54,143

64,437
CISO

522,398

225,552

239,494
IPCO

54,657

30,694

96,554
LADWP

59,353

78,291

28,681
NEVP

189,617

31,040

118,681
NWMT

32,284

10,909

27,486
PACE

26,422

423,704

56,281
PACW

67,148

36,517

92,207
PGE

31,338

117,388

35,279
Attachment E Page 169 of 178
PNM

123,276

18,268

16,109
PSEI

54,090

46,125

38,271
PWRX

1,373

359,383

5,606
SCL

6,934

32,383

5,214
SRP

163,815

42,260

37,803
TEPC

105,237

34,359

6,684
TIDC

21,048

17,449

-
TPWR

4,982

12,689

7,526

TABLE 6: Estimated wheel-through transfers in March 2023

GRAPH 6: Estimated wheel-through transfers in March 2023

Attachment E Page 170 of 178
REDUCED RENEWABLE CURTAILMENT AND GHG REDUCTIONS
The WEIM benefit calculation includes the economic benefits that can be attributed to
avoided renewable curtailment within the ISO footprint. If not for energy transfers facilitated by
the WEIM, some renewable generation located within the ISO would have been curtailed via
either economic or exceptional dispatch. The total avoided renewable curtailment volume in
MWh for Q1 2023 was calculated to be 8,283 MWh (January) + 21,976 MWh (February) +
22,743 MWh (March) = 53,002 MWh total.
There are environmental benefits of avoided renewable curtailment as well. Under the
assumption that avoided renewable curtailments displace production from other resources at a
default emission rate of 0.428 metric tons CO2/MWh, avoided curtailments displaced an
estimated 22,685 metric tons of CO2 for Q1 2023. Avoided renewable curtailments also may
have contributed to an increased volume of renewable credits that would otherwise have been
unavailable. This report does not quantify the additional value in dollars associated with this
benefit. Total estimated reductions in the curtailment of renewable energy in the ISO footprint,
along with the associated reductions in CO2, are shown in Table 7.
Year Quarter MWh Eq. Tons CO2
1 8,860 3,792
2015 2 3,629 1,553
3 828 354
4 17,765 7,521
1 112,948 48,342
2016 2 158,806 67,969
3 33,094 14,164
4 23,390 10,011
1 52,651 22,535
2017 2 67,055 28,700
3 23,331 9,986
4 18,060 7,730
1 65,860 28,188
2018 2 129,128 55,267
3 19,032 8,146
4 23,425 10,026
1 52,254 22,365
2019 2 132,937 56,897
Attachment E Page 171 of 178
3 33,843 14,485
4 35,254 15,089
1 86,740 37,125
2020 2 147,514 63,136
3 37,548 16,071
4 39,956 17,101
2021 1 76,147 32,591
2 109,059 46,677
3 23,042 9,862
4 38,044 16,283
2022 1 94,168 40,304
2 118,352 50,655
3 42,468 18,176
4 25,609 10,960
2023 1 53,002 22,685
Total 1,903,799 814,746

TABLE 7: Total reduction in curtailment of renewable energy and associated reductions in CO2
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS
The WEIM facilitates procurement of flexible ramping capacity in the FMM to address variability
that may occur in the RTD. Because variability across different BAAs may happen in opposite
directions, the flexible ramping requirement for the entire WEIM footprint can be less than the
sum of individual BAA’s requirements. This difference is known as flexible ramping procurement
diversity savings.
Starting in 2016, the ISO replaced the flexible ramping constraint with flexible ramping products
that provide both upward and downward ramping. The minimum and maximum flexible ramping
requirements for each BAA and for each direction are listed in Table 8.
Month BAA Direction Minimum
requirement
Maximum
requirement
AVA up 22 81
January AZPS up 49 284
BANC up 10 96
BPAT up 82 371
Attachment E Page 172 of 178

CISO up 248 2,337
IPCO up 36 189
LADWP up 30 393
NEVP up 20 446
NWMT up 22 127
PACE up 90 460
PACW up 49 174
PGE up 51 200
PNM up 39 155
PSEI up 74 167
PWRX up 78 294
SCL up 7 31
SRP up 17 201
TEPC up 66 193
TIDC up 2 17
TPWR up 3 19
ALL EIM up 315 2,771
AVA down 11 92
AZPS down 23 231
January BANC down 6 152
BPAT down 141 639
CISO down 187 1,332
IPCO down 36 194
LADWP down 38 297
NEVP down 24 414
NWMT down 41 124
PACE down 176 461
PACW down 34 163
PGE down 28 204
PNM down 41 141
PSEI down 52 153
Attachment E Page 173 of 178
PWRX down 69 356
SCL down 4 28
SRP down 20 181
TEPC down 0 165
TIDC down 1 17
TPWR down 2 24
ALL EIM down 279 2,175
AVA up 20 81
February AZPS up 39 284
BANC up 8 102
BPAT up 87 435
CISO up 259 2,303
IPCO up 44 175
LADWP up 49 393
NEVP up 26 463
NWMT up 32 124
PACE up 103 525
PACW up 51 174
PGE up 35 200
February PNM up 39 155
PSEI up 67 167
PWRX up 79 369
SCL up 6 31
SRP up 27 267
TEPC up 64 200
TIDC up 2 20
TPWR up 23 19
ALL WEIM up 395 2,771
AVA down 14 103
AZPS down 31 383
BANC down 9 152
Attachment E Page 174 of 178
BPAT down 163 639
CISO down 220 1,332

IPCO down 52 194
LADWP down 68 307
NEVP down 32 414
NWMT down 36 132
PACE down 139 451
PACW down 50 163
PGE down 45 204
PNM down 59 146
PSEI down 74 153
PWRX down 66 356
SCL down 7 28
SRP down 23 400
TEPC down 39 134
TIDC down 1 17
TPWR down 2 25
ALL EIM down 438 2,175

March

AVA up 23 81
AZPS up 44 300
BANC up 7 102
BPAT up 76 435
CISO up 266 2,323
IPCO up 45 189
LADWP up 51 393
NEVP up 24 463
NWMT up 46 127
PACE up 103 525
PACW up 49 174
PGE up 59 200
PNM up 50 155
Attachment E Page 175 of 178

March

PSEI up 67 167
PWRX up 79 377
SCL up 6 31
SRP up 35 280
TEPC up 62 263
TIDC up 2 20
TPWR up 2 19
ALL WEIM up 385 2,771
AVA down 15 94
AZPS down 18 383
BANC down 5 152
BPAT down 109 639
CISO down 220 1,332
IPCO down 52 194
LADWP down 41 307
NEVP down 12 414
NWMT down 9 132
PACE down 96 451
PACW down 22 163
PGE down 24 204
PNM down 36 155
PSEI down 10 153
PWRX down 46 356
SCL down 5 28
SRP down 28 400
TEPC down 19 129
TIDC down 0 19
TPWR down 2 25
ALL WEIM down 1,718 2,175
Table 8: Flexible ramping requirements
Attachment E Page 176 of 178
The flexible ramping procurement diversity savings for all the intervals averaged over the month
are shown in Table 9. The percentage savings is the average MW savings divided by the sum of
the individual BAA requirements.
January February March
Direction Up Down Up Down Up Down
Average MW saving 1,655

1,657 1,698 1,484 2,470 951
Sum of BAA requirements 2,983 2,714 2,982 3,013 4,985 3,113
Percentage savings 55% 61% 57% 49% 50% 31%
Table 9: Flexible ramping procurement diversity savings in Q1 2023
Flexible ramping capacity may be used in RTD to handle uncertainties in the future interval. The
RTD flexible ramping capacity is prorated to each BAA. Flexible ramping surplus MW is defined
as the awarded flexible ramping capacity in RTD minus its share, and the flexible ramping
surplus cost is defined as the flexible ramping surplus MW multiplied by the flexible ramping
WEIM-wide marginal price. A positive flexible ramping surplus MW is the capacity that a BAA
provided to help other BAAs, and a negative flexible ramping surplus MW is the capacity that a
BAA received from other BAAs.
The EIM dispatch cost for a BAA with positive flexible ramping surplus MW is increased
because some capacities are used to help other BAAs. The flexible ramping surplus cost is
subtracted from the BAA’s WEIM dispatch cost to reflect the true dispatch cost of a BAA. Please
see the Benefit Report Methodology for more details.
CONCLUSION
Using state-of-the-art technology to find and deliver low-cost energy to meet real-time demand,
the WEIM demonstrates that utilities can realize financial and operational benefits through
increased coordination and optimization. In addition to these benefits, the WEIM provides
significant environmental benefits through the reduction of renewable curtailments during
periods of oversupply.
Sharing resources across a larger geographic area reduces greenhouse gas emissions by using
renewable generation that otherwise would have been turned off. The quantified environmental
benefits from avoided curtailments of renewable generation from 2015 to-date reached 814,746
metric tons of CO2, roughly the equivalent of avoiding the emissions from 171,297 passenger
cars driven for one year.

Attachment E Page 177 of 178
APPENDIX 1: GLOSSARY OF ABBREVIATIONS

Abbreviation Description
APS Arizona Public Service
AVA Avista Utilities
BAA Balancing Authority Area
BANC Balancing Authority of Northern California
BPA Bonneville Power Administration
CISO, ISO California ISO
EIM Energy Imbalance Market
FMM Fifteen Minute Market
GHG Greenhouse Gas
IPCO Idaho Power
LADWP Los Angeles Department of Water and Power
MW Megawatt
MWh Megawatt-Hour
NVE NV Energy
PAC PacifiCorp
PACE PacifiCorp East
PACW PacifiCorp West
PGE Portland General Electric
PSE Puget Sound Energy
PWRX Powerex
RTD Real Time Dispatch
SCL Seattle City Light
SRP Salt River Project
TEP Tucson Electric Power
TID Turlock Irrigation District
TPWR Tacoma Power
WEIM Western Energy Imbalance Market

Attachment E Page 178 of 178