Item 13. SB 540 Pathways – Support Letter Approval — Ava Community Energy Board of Directors, April 16, 2025

Staff Report Item 13
Staff Report Item 13
To: Ava Community Energy Authority
From: Todd Edmister, Sr. Director of Public Policy and Deputy General Counsel Dominic Faria, Senior Policy Coordinator
Subject: Seeking Board approval for supporting SB 540 (Pathways legislation) Date: April 16, 2025
________________________________________________________________ Summary/Recommendation
This Staff Report and accompanying presentation are intended to inform the Ava Board of Directors about SB 540 and the West-wide Pathways Initiative, and to seek approval to adopt a Resolution in support of SB 540 and authorizing the CEO to sign the attached Letter of Support.

Financial Impact
There is no cost associated with sending a letter of support but adoption of SB 540 could potentially result in operational savings for Ava in the future.

Analysis and Context
This item is being carried over from the prior, March 19, 2025 Board meeting. Please see the prior Staff Report on SB 540, attached hereto. Please also see a supplemental slide deck, also attached hereto, addressing questions arising at the March 19, 2025 Board meeting.

Staff Recommendation
Staff recommends that the Board authorize the CEO to sign the letter of support on behalf of Ava. Overall, SB 540 will have little to no immediate direct impact on Ava’s operations, but the potential reliability enhancements and operational savings Ava could achieve via a broader, independently governed regional energy market are significant. Even if the estimated expanded EDAM benefits are not fully realized, it is expected to at least be a marginal improvement over the status quo.

Staff Report Item 13
Attachments
A. Resolution
B. Power Point Presentation
C. Bill text
D. Item 17 Board Packet materials from March 19, 2025 Board meeting E. SB 540 Coalition Support Letter
F. SB 540 Coalition Oppose Letter
G. SB 540 Consumer Watchdog Oppose Letter
H. The Brattle Group Preliminary Day Ahead Market Impacts Study I. Stanford Woods Institute Grid Regionalization White Paper Attachment Staff Report Item 13A
RESOLUTION NO. R-2025-XX

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE AVA COMMUNITY ENERGY AUTHORITY SUPPORTING
CLAIFORNIA SENATE BILL 540 (2025)
WHEREAS Ava Community Energy Authority (“Ava”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, under the Joint Exercise of Powers Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of Ava and parties to the Joint Powers Agreement (“JPA”) in March of 2020. The city of Stockton was added as a member to Ava in September of 2022. The city of Lathrop was added as a member to Ava in October of 2023. San Joaquin County was added as a member to Ava in July 2024. On October 24, 2023, Ava legally adopted the name Ava Community Energy Authority, where it had previously used the name East Bay Community Energy Authority since its inception; WHEREAS, on February 20, 2025, California State Senators Josh Becker and Henry Stern introduced SB 540 as a critical step in advancing the West-wide Pathways Initiative by allowing the California Independent System Operator (CAISO) and California load serving entities to participate in an energy market governed by an independent regional organization (RO);
WHEREAS SB 540 and the Pathways proposal aims to lower energy bills, improve grid reliability, and reduce pollution while retaining control over California’s procurement, environmental, reliability, and other public policies; and WHEREAS Ava, as a load serving entity that serves energy demand within the CAISO grid, stands to benefit from the expected cost savings associated with transferring governance over the energy market from the CAISO to an independent RO.

NOW, THEREFORE, THE BOARD OF DIRECTORS OF AVA COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The Board of Directors hereby expresses its support for SB 540 and authorizes the CEO to sign the Letter of Support urging members of the California legislature to do the same.

ADOPTED AND APPROVED this 16th day of April, 2025.

Attachment Staff Report Item 13A
Jack Balch, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
SB 540 and the West-wide Pathways Initiative
Todd Edmister & Dominic Faria | April 16, 2025
Attachment Staff Report Item 13B
Summary
2 • Ava is being invited to join 40+ organizations – including many other California CCAs – in supporting California Senate Bill 540 (SB 540). • SB 540 enables California's participation in regional energy market overseen by an independent regional organization (RO) proposed by the Pathways Initiative
• Following extensive analysis, Ava staff recommends Board approval to sign onto the coalition letter supporting SB 540.
• The initial letter was sent to the CA Senate Energy, Utilities, and Communications Committee on March 7, 2025. Ava would be added to the letter for broader legislative outreach.

Attachment Staff Report Item 13B
The Current Electricity
Landscape
3 Attachment Staff Report Item 13B
4 Attachment Staff Report Item 13B
5 Attachment Staff Report Item 13B
The current California energy landscape
6 • California’s energy grid is operated and managed by the California Independent System Operator (CAISO), a public non-profit corporation created by state law. The CAISO has six main responsibilities:
• The CAISO is run by a five-member Board of Governors, each appointed by the Governor and confirmed by the state Senate.
• The California Public Utilities Commission (CPUC) is in charge of regulating investor-owned utilities (like PG&E) by approving rates and overseeing a range of other California policies and initiatives, including procurement and integrated resource planning, the renewable portfolio standard (RPS), resource adequacy (RA) planning, distributed energy resources, and more.
• The California Energy Commission (CEC) also oversees state energy policies related to renewable energy, energy efficiency, resource planning, energy project permitting, and others.

Transmission
Planning
Transmission
System
Operation
Balancing
Authority
Functions
Reliability
Coordination
Energy
Market Rules
Energy
Market
Operation
Attachment Staff Report Item 13B
Energy Markets
7 • California currently participates in the Western Energy Imbalance Market (WEIM), a regional market that enables participants to buy and sell power in real time. • The WEIM is operated by the CAISO and its rules are jointly governed by the CAISO Governing Board and the Western Energy Market (WEM) Governing Body, which has five members selected by a multi-state, multi-stakeholder nominating committee. • In addition to the CAISO, the WEIM has 21 participants from a variety of states and has been in operation since 2014.
• The CAISO plans to launch an Extended Day Ahead Market (EDAM) in 2026.

Energy
Market Rules
Energy
Market
Operation
Attachment Staff Report Item 13B
Why do we have a regional market?
8 • Coordinated electricity markets help customers save money, keep the lights on (avoid blackouts), and make the electric grid cleaner.
• The more connected California’s grid is to other states, the easier it is for everyone involved to share energy resources across a wider geographic footprint, which increases reliability and keeps generation costs low.
• Saves participants money by not needing to build duplicative sources of power in each state.
• Optimizes the integration of renewable resources, like solar and wind, to the grid. • When it’s sunny in CA and cloudy in other states… CA exports excess solar to its neighbors
• When it’s hot in CA and demand spikes… CA imports excess energy from other states, reducing its reliance on expensive and polluting peaker plants Attachment Staff Report Item 13B
WEIM Participants
• California ISO (2014)
• PacifiCorp (2014)
• NV Energy (2015)
• Arizona Public Service (2016)
• Puget Sound (2016)
• Portland General Electric (2017)
• Powerex (2018)
• Idaho Power Company (2018)
• Balancing Authority of Northern
California (2019)
• Seattle City Light (2020)
• Salt River Project (2020)
• Turlock Irrigation District (2021)
• Public Service Company of New
Mexico (2021)
9 • Los Angeles Department of
Water & Power (2021)
• NorthWestern Energy (2021)
• Tacoma Power (2022)
• Avista (2022)
• Tucson Electric Power (2022)
• Bonneville Power
Administration (2022)
• WAPA Desert Southwest
Region (2023)
• El Paso Electric (2023)
• Avangrid (2023)
• BHE Montana (planned entry
2026)
• Black Hills Power (planned
entry 2026)
Attachment Staff Report Item 13B
EDAM Commitments
10 Formal Commitments:
• PacifiCorp
• Portland General Electric
• Balancing Authority of Northern California (BANC)
Informal Commitments:
• LADWP
• BHE Montana
• Idaho Power
• NV Energy
• Public Service Company of New Mexico
• Arizona G&T Cooperatives (part of WAPA Desert
Southwest Region)
Attachment Staff Report Item 13B
Federal Energy Regulatory Commission (FERC)
11 • As an independent system operator responsible for transmitting electricity across state lines, the CAISO and its energy markets (WEIM and EDAM) are under FERC jurisdiction. • FERC is an independent federal agency responsible for regulating the interstate transmission of electricity, natural gas, and oil, to ensure "just and reasonable" rates and industry practices. (Sec. 205(a) of the Federal Power Act)
• FERC has five commissioners, each of which is appointed by the President and serves a five-year term. No more than three commissioners can belong to the same political party at one time.

Mark Christie (Chair)
R (Trump appointee)
Term Expires June 2025
Willie Phillips
D (Biden appointee)
Term Expires June 2026
David Rosner
D (Biden appointee)
Term Expires June 2027
Lindsay See
R (Biden appointee)
Term Expires June 2028
Judy Chang
D (Biden appointee)
Term Expires June 2029
Attachment Staff Report Item 13B
The Pathways Initiative
12 Attachment Staff Report Item 13B
What is the Pathways Initiative?
13 • The Pathways Initiative is a multi-state effort aimed at establishing a unified, independently governed wholesale electricity market that includes all states in the Western Interconnection, including California.
• Began in 2023 at the request of public utility and energy commissioners from California, Oregon, Washington, Arizona, and New Mexico with the intent of maximizing the benefits of coordinated wholesale electricity markets for customers across the entire Western U.S. • The Pathways Initiative Launch Committee was formed in October 2023 and is led by representatives from a variety of stakeholders, including state regulators, IOUs, public utilities, labor unions, non-utility load serving entities (CCAs), consumer advocates, and others. (See slide 16 for list of committee members)
• The Pathways proposal does not change existing grid operators or balancing authorities and does not change existing RA or RPS standards for any state involved.

Attachment Staff Report Item 13B
Why the need for an independent RO?
14 • Although the WEIM has been running successfully for the past 10+ years and the EDAM promises to expand on those successes, participants in other states are intent on joining a market that is not controlled by a single state (California). • In fact, some WEIM participants (e.g., Bonneville) are actively pursuing options to join a competing day-ahead market (Southwest Power Pool’s Markets+) explicitly because the EDAM’s governance would not be independent enough.
• If enough of these energy suppliers opt to leave the WEIM and forgo EDAM participation, it could make it more difficult and expensive for California to meet energy demand and reduce the market’s overall benefits.
• So, CA and other states that prefer to remain in the WEIM and participate in the EDAM are trying to form an independent RO to shift market governance away from CA, attracting/retaining more market participants, and ultimately maximizing market benefits.

Attachment Staff Report Item 13B
Pathways Initiative Timeline
15 July 2023: Letter to members of the Western Interstate Energy Board (WEIB) from public utility and energy commissioners from California, Oregon, Washington, Arizona, and New Mexico, urging the WEIB to support the creation of an independent regional market operator.

October 2023: A Pathways “Launch Committee” is formed and led by representatives from a variety of stakeholders, including state regulators, IOUs, public utilities, labor unions, non-utility load serving entities (CCAs), consumer advocates, public interest groups, and others.

Oct 2023-Nov 2024: Launch Committee members collaborate with outside stakeholders and other interested parties at public meetings and workshops to form basis of Pathways process and final proposal.

June 2024: Launch Committee approves and sends Step I Proposal to the CAISO Board and WEM Governing Body, which proposes to give WEM governing body primary decision-making authority in market-related matters once non-CAISO EDAM entities accounting for at least 70% of CAISO balancing area load have executed EDAM implementation agreements.

Attachment Staff Report Item 13B
Pathways Initiative Timeline (continued)
16 August 2024: CAISO Board and WEM Governing Body accept Step 1 Proposal.

November 2024: Launch Committee approved its Step 2 Final Proposal outlining a plan to form an independent RO responsible for overseeing an integrated WEIM and EDAM for all western states.

December 2024: Launch Committee approves Formation Committee roster responsible for doing the work to create and implement the RO in accordance with the Step 2 Final Proposal and Formation Committee approval. RO to be stood up by late 2027 / early 2028.

February 2025: SB 540 introduced in CA legislature to enable CAISO board to shift market governance responsibilities to a new RO no sooner than January 1, 2027.

Attachment Staff Report Item 13B
FERC Approved Pathways Step 1
17 • On April 2, 2025, FERC accepted CAISO's revised tariff filing allowing the WEM governing body to file separate tariff proposals if the two don't agree on a tariff change.

Attachment Staff Report Item 13B
Pathways Launch Committee: Who’s Involved?
CA IOU Transmission Owners:
• Scott Ranzal, Pacific Gas and
Electric
• Jeff Nelson, Southern California
Edison
18 Public Power and Coops:
• Josh Walter, Seattle City Light
• Connor Reiten, PNGC Power
• Jim Shetler, Balancing Authority of
Northern California
• Randy Howard, Northern California
Power Agency
• Alternate(s): Jon Olson, SMUD
Independent Power Producers:
• Scott Miller, Western Power Trading
Forum
• Jan Smutny-Jones, Independent
Energy Producers Association
• Lisa Tormoen Hickey, Interwest
Energy Alliance
• Alternate(s): Ben Fitch-Fleischmann, Interwest Energy Alliance; Spencer Gray, NIPPC
Large Commercial & Industrial
Customers:
• Kathleen Staks, Western
Freedom (Co-Chair)
• Alternate(s): Heidi Ratz, Clean
Energy Buyers Association
Labor:
• Marc Joseph, Coalition of
California Utility Employees and
the State Association of Electrical
Workers (IBEW)
Residential and Small Commercial
Customers:
• Michele Beck, Utah Office of
Consumer Services
• Linda Serizawa, California Public
Advocates Office
Power Marketing Administrations:
• Chrystal Dean, Western Area
Power Administration
• Alternate(s): Tina Ko, Western Area
Power Administration
Public Interest Organizations:
• Michael Colvin, Environmental
Defense Fund
• Alaine Ginocchio, representing
Western Resource Advocates
• Ben Otto, NW Energy Coalition
• Alternate(s): Mark Specht, Union of
Concerned Scientists
EIM Entities:
• Omaya Ahmad, Arizona Public
Service
• David Rubin, NV Energy
• Kerstin Rock, PacifiCorp
• Pam Sporborg, Portland General
Electric (Co-Chair)
• Alternate(s): Robert Eckenrod,
PacifiCorp
States/Provinces:
• Commissioner Milt Doumit,
Washington Utilities and
Transportation Commission
• Commissioner Kevin Thompson,
Arizona Corporation Commission
• President Alice Reynolds,
California Public Utilities
Commission
• Commissioner Letha Tawney,
Oregon Public Utilities
Commission (Alternate)
• Vice Chair Siva Gunda, California
Energy Commission (Alternate)
• Commissioner Pat O’Connell, New
Mexico Public Regulatory
Commission (Alternate)
Non-utility Load Serving Entities:
• Evelyn Kahl, California Community
Choice Association
• Alternate(s): Beth Vaughan,
California Community Choice
Association
Technology Providers:
• Brian Turner, Advanced Energy
United
Attachment Staff Report Item 13B
Pathways Step 2 Final Proposal: Key Provisions
20 • The RO would have full independent governance authority over market rules (Section 205 filing rights), with the CAISO maintaining its existing day-to-day operation of the market under a vendor contract with the RO.
• The RO Board of Directors would be comprised of seven members with a diverse range of qualifications and expertise. Members would be selected by a nominating committee comprised of a mix of stakeholder representatives, similar to how WEM Governing Body members are selected today.
• The RO’s articles of Incorporation, bylaws, and any other official policies and procedures will include language centering on public interest protections and articulate a corporate obligation to respect state authority to set procurement, environmental, reliability, and other public interest policies.
• A Stakeholders Representatives Committee (SRC) would be formed within the RO to serve as the primary body responsible for developing and proposing market policy changes to the RO Board. The SRC would be comprised of 21 seats across nine different stakeholder sectors.

Attachment Staff Report Item 13B
Pathways Step 2 Final Proposal: Key Provisions
(continued)
21 • A Public Policy Committee (PPC) would be formed with members of the RO Board to conduct outreach at key points in the stakeholder process to states, local power authorities, and federal power marketing administrations to collect input on potential impacts by any policy initiative. • A new independent Consumer Advocate Organization (CAO) would be formed and funded by the RO to facilitate engagement by each consumer advocate office authorized in state law, in the stakeholder process and other RO engagement opportunities. • An Office of Public Participation (OPP) would be created within the RO to provide information and education to members of the public about issues and initiatives at the RO, including facilitating engagement in those processes.
• The RO would be incorporated in Delaware as a 501(c)(3) non-profit but will do business in or near Folsom, CA to remain close to CAISO HQ.

Attachment Staff Report Item 13B
What is SPP Markets+?
22 • Southwest Power Pool (SPP) is an Arkansas-based Regional Transmission Organization (RTO) that provides wholesale energy market and transmission grid services for 14 states in the central U.S.
• SPP is planning to launch Markets+, a real-time and day-ahead market for Western states, starting in 2027. FERC approved SPP’s Markets+ plan in January 2025. • In March 2025, FERC also approved SPP’s plans to expand into the Western Interconnection by linking its existing RTO footprint to new participants in the western grid.
• In other words, SPP is planning to offer both transmission grid services AND wholesale energy market services for utilities and power suppliers in the West, beginning as soon as 2026.

Attachment Staff Report Item 13B
Markets+ Commitments
23 Formal and Informal: • Arizona Public Service • Bonneville Power Administration (draft decision 3/6/25)
• Chelan County Public Utility District
(Washington)
• El Paso Electric (Texas) • Grant County Public Utilities District (Washington)
• Powerex (a subsidiary of BC Hydro)
(British Columbia, Canada)
• Salt River Project (Arizona) • Tacoma Power (Washington) • Tucson Electric Power (Arizona) Attachment Staff Report Item 13B
SB 540
24 Attachment Staff Report Item 13B
What is SB 540?
25 • Introduced on Feb 20 in the CA Senate by Sens. Josh Becker (D-Menlo Park) and Henry Stern (D-Los Angeles). Sen. Becker is the Chair of the Senate Energy Committee, of which Sen. Stern is also a member.
• Establishes a process through which the CAISO and California utilities can participate in an energy market governed by an independent, west-wide RO as proposed by the Pathways Initiative.
• The bill was referred to the Senate Energy Committee and Senate Judiciary Committee.

It received minor amendments on March 24. A bill hearing has not yet been scheduled. • The bill is co-sponsored by the Coalition of California Utility Employees, State Association of Electrical Workers, Environmental Defense Fund, and Natural Resources Defense Council.

Attachment Staff Report Item 13B
What the bill does
26 In general: SB 540 would allow CAISO to transfer its existing governance of the western energy markets (WEIM and EDAM) to an RO starting in 2027 only if CAISO decides that the RO meets a set of specific statutory requirements (included on next two slides).

Establishes a process through which the CAISO would be able to join the RO-governed energy market:
• The bill adds a new section (345.6) to the PUC Code allowing the CAISO to use voluntary energy markets governed by an independent RO, subject to a set of specific requirements. • The CAISO must wait until at least January 1, 2027, to implement tariff modifications with FERC to operate the energy markets governed by the RO, and before doing so, must adopt a resolution (via a public meeting process) confirming that each of those requirements has been or will be adopted by the RO.

Includes a CAISO “backstop” and “ripcord” provision:
• The bill directs the CAISO to “maintain the necessary technical capability to operate energy markets” as a backstop to allow California market participants to withdraw from the RO-governed markets, in which case the CAISO would revert to providing separate market services for those entities.
• The bill also specifies that the PUC maintains its authority “to direct an electrical corporation to withdraw” from an RO-governed energy market “in response to federal action or any other significant change in market rules or operations detrimental to California consumers or California procurement, environmental, reliability, or other public interest policies.”
Attachment Staff Report Item 13B
What the bill does (continued)
27 Preserves CAISO reliability and renewables standards, and balancing authority area, functions, and responsibilities:
• The bill directs the CAISO to “continue its functions and responsibilities as a balancing authority as they existed before” the bill’s enactment, and to “maintain compliance with applicable reliability standards as developed, adopted, and enforced by” NERC, the WECC, and FERC. • The bill also clarifies that it does not change the CAISO’s responsibilities related to managing the transmission grid, planning for transmission expansion, or complying with the state’s integrated energy policy reporting and renewable portfolio standard program (Article 16 of the Public Utilities Code) and targets (Section 454.53).

Enables CAISO-RO vendor relationship:
• The bill allows the CAISO to act as a vendor, through a contract with the RO, “of market operation services, generation dispatch services, transmission operation services, transmission planning services, reliability coordination, balancing authority compliance or operation services, or other electrical system services.” Attachment Staff Report Item 13B
Why this bill is different from “regionalization”
28 • Past bills (AB 813 in 2018 and AB 538 in 2023) would have transitioned the CAISO and all of its functions to a full RTO to serve the entire region. This would have transferred California’s authority over the transmission system, balancing authority functions, and reliability coordination – in addition to market governance – to an independent regional operator.
• SB 540, on the other hand, only deals with market governance – in other words, who has the “right” to set market rules and to ask FERC to approve them. It leaves the CAISO firmly under state control and each of its five other functions untouched.

Transmission
Planning
Transmission
System
Operation
Balancing
Authority
Functions
Reliability
Coordination
Energy
Market Rules
Energy
Market
Operation
CAISO under
CA control
AB 813 / AB 538 would have
turned the CAISO into an RTO
Transmission
Planning
Transmission
System
Operation
Balancing
Authority
Functions
Reliability
Coordination
Energy
Market Rules
Energy
Market
Operation
RTO no longer
under sole CA
control
Attachment Staff Report Item 13B
Graphic courtesy of CalCCA 29
Attachment Staff Report Item 13B
RO Requirements (1-6)
30 1. The RO is a nonprofit corporation whose governing documents include a corporate obligation to respect the authority of each state that has a load-serving entity or balancing authority participating in the market to set its own procurement, environmental, reliability, and other public interest policies.

2. The RO’s governing board maintains a public policy committee consisting of members of the RO governing board that engages with states, local power authorities, and federal power marketing administrations about potential impacts to state, local, or federal policies before it approves a tariff change for filing at the Federal Energy Regulatory Commission.

3. The RO’s governing board maintains a relationship with and seeks input from a body of state regulators or similar body to receive the views of state regulators.

4. The RO makes funding available for a consumer advocate organization that represents the interests of one or more consumer advocate offices authorized in state law and facilitates engagement by those offices in the markets governed by the RO.

5. The RO maintains an office of public participation to provide information and education to members of the public about issues and initiatives at the RO, including facilitating engagement in those processes.

6. In addition to any independent market monitoring activity required by a FERC order, the RO maintains access to independent market analysis for the RO governing board on the impacts of market dynamics or rule changes to minimize overall costs to end-use consumers.

Attachment Staff Report Item 13B
RO Requirements (7-12)
31 7. Subject to appropriate confidentiality provisions, market data is available to the CPUC and the Public Advocate’s Office, and other states’ commissions and public advocate offices, to the same or greater extent as existed on December 31, 2024, for the markets governed by the CAISO.

8. There is a stakeholder process designed to provide nonbinding advice to the RO governing board.

9. The RO is obligated to conduct meetings and make decisions in an open process with transparent, documented rationales, and all meetings of the RO governing board are publicly noticed and, excluding executive sessions, are available to remote participants, recorded and posted on the RO’s internet website, open to the public, and subject to open record requirements.

10.The CAISO continues to operate the energy markets, subject to the market rules determined by the RO as accepted by the FERC.

11.The RO market rules continue to provide greenhouse gas emissions information and protocols sufficient to enable entities subject to the State Air Resources Board’s rules to demonstrate compliance.

12.The RO permits and provides a procedure for unilateral withdrawal by any participant with reasonable prior notice and without any further approvals.

Attachment Staff Report Item 13B
What the Bill Does NOT Do
32 • SB 540 does not change California’s existing procurement and reliability standards. It does not affect the state’s RPS or RA requirements and does not forfeit its authority over transmission planning, transmission cost allocation, or balancing authority functions. • It also does not immediately authorize the CAISO or utilities to enter a market governed by an independent RO. The CAISO must first demonstrate the RO meets certain statutory requirements before transferring control over market rules and cannot do so before January 1, 2027.
• The bill does not require funding for new infrastructure to operate the energy markets.

The CAISO will serve as a vendor to the new RO and retain the use of its current market operation personnel, technology, and hardware.
• Most importantly, neither SB 540 nor the Pathways Initiative hinders Ava’s efforts or ability to procure local clean energy or invest in local development.

Attachment Staff Report Item 13B
Who supports SB 540? • Advanced Energy United (AEU) • American Clean Power – California (ACP)
• California & Nevada State
Association of Electrical Worker
(IBEW)*
• California Community Choice
Association (CalCCA)
• California Environmental Voters • California State Pipe Trades Council
• Clean Energy Buyers Association
(CEBA)
• Coalition of California Utility
Employees (CCUE)*
• E2 Environmental Entrepreneurs • EDP Renewables • Environmental Defense Fund (EDF)*
• Independent Energy Producers
Association (IEPA)
• Leap • MCE
33 • Natural Resources Defense
Council (NRDC)*
• Pacific Gas & Electric • Pattern Energy • Peninsula Clean Energy • Rivian • San Diego Community Power • San Diego Gas & Electric • Sierra Nevada Brewing Co. • Silicon Valley Leadership Group (SVLG)
• Silicon Valley Clean Energy
(SVCE)
• Solar Energy Industries
Association (SEIA)
• Southern California Edison • Union of Concerned Scientists (UCS)
• Western Power Trading Forum
(WPTF)
• Western Resource Advocates
(WRA)
* Original cosponsor
Attachment Staff Report Item 13B
Who opposes SB 540?
Loretta Lynch,
Former CPUC
President
34 Attachment Staff Report Item 13B
Empirical Analysis
35 Attachment Staff Report Item 13B
Brattle Study
36 • Calculates the benefits, starting in 2032, for CA customers if additional utilities across the western U.S. participate in EDAM. Examines four different scenarios. • Benefits come from cost savings to customers due to efficiency gains, environmental benefits through lower emissions, and reliability benefits by making it easier to manage the grid during extreme weather events
Source: The Brattle Group: “Preliminary Day-Ahead Market Impacts Study” Attachment Staff Report Item 13B
Stanford Woods Study
37 • Evaluates shifts in Western generation/transmission under stressed grid conditions (e.g., extreme heat and drought), as a function of different levels of energy market integration . Uses CA’s September 2022 heat event as a benchmark.
• "The results from the case study show that expansion of an ISO/RTO footprint is one way to substantially lower risk of unserved energy for customers. Our simulations show, qualitatively, how creation of a multi-state market can reducerisk, and that the bigger the market, the greater the risk reduction achieved." Source: Stanford Woods Institute: “Grid Regionalization in the West” Attachment Staff Report Item 13B
Finding 1: Estimated Cost Savings
38 • Estimated cost savings: $182 million to $800 million reduction in annual California system costs, depending on size and extent of the market, compared to the status quo, starting in 2032. • Translates to roughly $7 million to $32 million in annual cost savings for Ava (assuming ~4% of CA’s load), or about $11 to $50 per customer per year (~642,000 customer accounts).

Source: The Brattle Group: “Preliminary Day-Ahead Market Impacts Study” Attachment Staff Report Item 13B
Finding 2: Enhanced Grid Reliability
39 • Enhanced grid reliability: Relieves strain on the electric grid during extreme heat events, reducing the number of hours the grid is strained by as much as 40% and reducing unserved load by more than half in the West-Wide ISO/RTO scenario.

Source: Stanford Woods Institute: “Grid Regionalization in the West” Attachment Staff Report Item 13B
Findings 3 & 4: Reduced Emissions and Optimized
Resource Use
40 • Reduced emissions: Decreases California’s fossil fuel generation by up to 31% and greenhouse gas emissions by up to 11.2%
• Optimized resource use: Reduces solar and wind energy curtailment by up to 10%, allowing California to export and import more excess renewable energy to and from other states.

Source: The Brattle Group: “Preliminary Day-Ahead Market Impacts Study” Attachment Staff Report Item 13B
FAQs
41 Attachment Staff Report Item 13B
Q: Why is SB 540 needed?
42 A: SB 540 would enable the CAISO and the entities within its balancing area to participate in the markets governed by the RO. Today, Public Utilities Code section 345.5 requires the CAISO to “manage” the transmission grid and related markets (WEIM and EDAM). Legislation is thus necessary to permit the CAISO and entities within its BAA to participate in markets “managed” by an independent RO. This structural change will help broaden the footprint for the Western market and maximize consumer benefits.

Since the WEIM and EDAM are governed by a corporation created by California law (the CAISO), other states don’t need to make any analogous changes to their laws in order for balancing authorities in their states to participate in the RO’s market.

Attachment Staff Report Item 13B
Q: Will participating in RO markets increase California’s risk of Federal interference with affordability, reliability, and climate goals? 43 A: The straightforward answer is no. Participating in the RO markets does not expose California participants to greater risk of federal interference.

Today, California’s Governor appoints the CAISO Board, which maintains authority to approve or reject market rule changes proposed by its staff or stakeholders and to seek approval from the FERC using a Section 205 filing. FERC, however, holds the ultimate authority to approve or reject market rules proposed by CAISO Board. In addition, FERC has the authority under the Federal Power Act to make generic rules governing wholesale market and transmission operations, and the CAISO may be required to internalize the mandated rules in its operations.

An independently governed RO will have the same relationship with FERC as the CAISO has today. FERC will continue to hold the same level of ultimate authority to approve or reject market rules proposed by RO Board, leaving California participants in the same position they face today. Like CAISO, the RO may also be required to internalize rules mandated through FERC’s rulemaking process. The only difference is that California would be one of several states with input in the RO tariff filing process, instead of having unilateral authority today.

Critically, however, California will maintain full control of all other energy policy. The CPUC and state law will continue to govern three central policy areas: retail rate design, resource preferences, and resource adequacy rules. California will also maintain its authority over other policies such as energy efficiency, building decarbonization, electric vehicles, net energy metering, distribution infrastructure, and grid safety. Finally, the California Air Resources Board will retain authority over carbon policy, to the extent federal policy changes do not preempt California’s goals and regulatory framework.

Attachment Staff Report Item 13B
Q: What happens if California takes no action or delays joining an independent RO?
44 A: While it is impossible to know with certainty what would happen, it is clear that California’s isolation would leave meaningful affordability, reliability, and climate benefits on the table, and the CAISO's existing market footprint would shrink.

The West is moving towards regional markets. But it may not go in California’s favor. CAISO’s neighboring areas are wary of joining the EDAM because the governance structure explicitly advantages California control rather than providing more of a shared governance approach.

Markets+ is in development and is gaining momentum with utilities and transmission owners.

Bonneville Power Administration, the Pacific Northwest’s largest provider of wholesale power and transmission owner, has already announced its intention to join Markets+ due to its view that the Pathways proposal does not create an RO that is sufficiently independent from CA.

If we don’t adjust the current California-centric nature of our expanding electricity markets now, we should expect large parts of the West to break off in favor of CAISO’s competitors. In the long run, this could render California’s electrical system more of an island, which would threaten reliability and lead to increased costs for customers.

Attachment Staff Report Item 13B
Q: Does California really need a regional market to keep the lights on?
45 A: California’s ability to efficiently buy and sell power during extreme weather events plays a critical role in avoiding blackouts and ensuring the resiliency of the energy grid. According to the CAISO, the WEIM was “an effective tool in helping to balance supply and demand in the wider Western footprint by enabling energy transfers across the region” and eliminating the need for widespread customer flex alerts during the July 2024 heat wave.1 But that doesn’t mean California is complacent. In fact, the state has brought online more than 11,000 MW of clean energy over the last three years. Battery storage capacity also grew from about 500 MW in 2020 to 11,200 MW in June 2024 in the CAISO balancing area.2 Importing electricity through the regional market is just one tool in the broader toolbox the state is using to meet rising demand.
1 CAISO. “Managing the July 2024 heat wave with our partners in California and the West”. July 15, 2024. https://www.caiso.com/about/news/energy-matters-blog/managing-the-july-2024-heat-wave-with-our-partners-in-california-and-the-west 2 CAISO’s 2023 Special Report on Battery Storage. July 16, 2024. https://www.caiso.com/documents/2023-special-report-on-battery-storage-jul-16- 2024.pdf
Attachment Staff Report Item 13B
Q: Does California’s (and by extension, Ava’s) participation in regional markets hinder its efforts to procure more local, clean energy sources?
46 A: No. California has been procuring clean energy from local (in-state) sources at a rapid pace, especially within the past decade (the WEIM was launched in 2014). This is largely thanks to state rules that govern what LSEs can count toward RPS requirements, none of which will change under SB 540.

In fact, the state has more wind and solar energy than it needs for many hours of the day, so much so that it is curtailing wind and solar generation at times when those resources aren’t being used. Joining a market governed by an RO would allow California to reduce curtailment and more easily sell that excess energy to other states.

Commonly, the biggest roadblocks to building both small- and utility-scale generation projects and bringing them online are related to lengthy permitting processes and interconnection queues, not the abundance of energy sources from other states.

The majority of electricity Ava provides its customers comes from direct power purchase agreements (PPAs) and are not purchased on the CAISO spot market. Neither SB 540’s passage nor the CAISO’s participation in a market governed by an independent RO would interfere with Ava’s plans or ability to contract for electricity from local, clean generation sources.

Attachment Staff Report Item 13B
Q: Will rates go up to pay for new transmission lines?
47 A: It’s unlikely that the rates California customers pay for transmission would experience any significant increase due to the CAISO’s participation in the RO market. Some new transmission lines or interties might have to be built in certain parts of the Western grid to better connect participants, but those costs will be socialized among customers of all participating balancing areas.

PG&E customers currently pay roughly 4 cents/kWh for transmission access charges (TAC),1 so it’s doubtful that the TAC would increase 3-5 cents (75% to 125%) just from connecting Wyoming wind, as some have claimed.
1 PG&E Electric Schedule E-1, Residential Services. February 26, 2025. https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC_SCHEDS_E-1.pdf Attachment Staff Report Item 13B
Q: Will participation in the RO markets bring coal imports into California?
48 A: No. California has worked hard to phase out coal, and moving to an RO model will not undermine these efforts. It is unlawful today for any retail electricity supplier in California to enter into a long-term contract for coal-produced electricity. Moreover, none of the CEC Study scenarios showed coal imports into California, and the continued growth of carbon-free resources in California will further mitigate any such risk.

Additionally, FERC does not possess any authority to direct the dispatch or procurement of specific resources.

FERC’s primary role is to regulate transmission rates and wholesale prices to ensure they are just and reasonable and nondiscriminatory. Any detrimental policy aimed at fossil fuels is more likely to come in the form of tax subsidies and DOE financial support for fossil resources, and such changes could affect the West regardless of which entity – the CAISO or RO – is making energy market rules.

Market forces also will reduce reliance on coal anywhere in the West. Generators bid their resources into the markets at or around the cost of fuel and variable operations and maintenance expenses. Resources such as wind and solar will displace fossil-fuel because, unlike a coal plant, no fuel is required to generate. The bid prices for these resources will beat coal prices and they will almost always be dispatched first by the market’s optimization model. Suppliers also must add to their bids GHG compliance costs, which further increases the price bid by a coal generator as compared to a GHG-free renewable generator. This mechanism is part of CAISO’s WEIM today, and part of the plan for EDAM through tariffs already approved by FERC.

Attachment Staff Report Item 13B
Q: Do the coal emissions produced by the Brattle model mean that SB 540 would cause higher GHG emissions in the WECC? 49 A: While both the Expanded EDAM and Split Market scenarios show higher GHG emissions across the WECC, higher emissions are not caused by the formation or operation of the RO. Instead, higher GHG emissions across the WECC is a function of the gas prices used in the model run by Brattle. Using gas prices that are higher than coal prices is likely to suggest coal emissions in most modeling scenarios until clean resources, which have no marginal production costs, can fully displace coal resources.

Both scenarios show an increase in WECC-wide emissions in absolute terms: the Brattle study shows a 2.1% rise in the West if California does nothing and allows a Split Market to develop, and 1.3% in the Expanded EDAM scenario – the scenario targeted by SB 540.

Regardless of the absolute values, what is important in this analysis are the relative results: both California and the WECC are better off with an Expanded Market than a Split Market when examining CO2 emissions impacts.

Attachment Staff Report Item 13B
Q: Today, Public Utilities Code Section 345.5 requires CAISO to prioritize CA consumer interests by minimizing costs, maximizing available energy resources, and protecting the public’s health and the environment. Does SB 540 eliminate these responsibilities? 50 A: No. These responsibilities remain in place for all CAISO functions except energy market management, including transmission planning, transmission system operation, balancing authority area management, and reliability coordination.

With respect to market management, the Pathways proposal builds several layers of public interest protections into the RO framework, going beyond the current protections in the existing CAISO processes, including that the RO protect the public interest and respect each state’s authority in its decision-making process, create a new Public Policy Committee of the RO Board to collect input about the potential for adverse impacts on a state or local policy, establish and fund a new Consumer Advocate Organization, among others.

Finally, SB 540 establishes a “ripcord” that California can pull if any of these safeguards fail.

Attachment Staff Report Item 13B
PUC Section 345.5
requirements:
51 SB 540 / Pathways
requirements:

1. Making the most efficient use of available
energy resources.

2. Reducing, to the extent possible, overall
economic cost to the state’s consumers.

3. Adhering to applicable state law intended to
protect the public’s health and the
environment.

4. Maximizing availability of existing electric
generation resources necessary to meet the
needs of the state’s electricity consumers.

5. Conducting internal operations in a manner
that minimizes cost impact on ratepayers.

6. Communicating with all balancing area
authorities in California in a manner that
supports electrical reliability.

1. Corporate obligation to respect the authority of each state to set its own procurement, environmental, reliability, and other public interest policies.

2. Maintain a public policy committee that engages with and collects input from states, local power authorities, and federal power marketing administrations.

3. Seeks input from a body of state regulators.

4. Makes funding available for a consumer advocate
organization and facilitates engagement by those offices.

5. Maintains an office of public participation.

6. Maintains access to independent market analysis for the RO governing board on the impacts of market dynamics or rule changes to minimize overall costs to end-use consumers.

7. Make market data available to the CPUC and the Public Advocate’s Office, and other states’ commissions and public advocate offices.

8. Maintain a stakeholder process designed to provide
nonbinding advice to the RO governing board.

9. An obligation to conduct meetings and make decisions in an open process with transparent, documented rationales.

10.Provide greenhouse gas emissions information sufficient to enable entities subject to CARB rules to demonstrate
compliance.

Attachment Staff Report Item 13B
Q: What happens if California later decides to exit the RO market?
52 A: The bill contemplates a three- part “ripcord” for California IOU BAAs to deploy if the RO adopts rules adverse to California’s climate goals or customer affordability, or for any other reason. SB 540:
• Reaffirms the CPUC’s existing authority to direct the IOUs to withdraw from the RO markets.
• Stipulates that California IOU BAAs can only participate in the RO markets if the RO adopts rules that allow unilateral withdrawal for any purpose subject to reasonable notice.
• Requires the CAISO to “stand ready” to resume day-ahead and real-time market governance if the CAISO/IOUs withdraw from the RO market. Approval to reinstate the tariff would, in the normal course, be required from FERC.

Attachment Staff Report Item 13B
Summary and Next Steps
53 • By enabling California to transfer authority over the regional energy markets to an RO, SB 540’s passage would be a key step forward in the process of advancing the Pathways proposal and achieving energy cost savings, and reliability and emissions benefits for California and Ava. • SB 540 will have a hearing in the Senate Energy, Utilities, and Communications Committee on April 21, 2025, and the Senate Judiciary Committee (date TBD). • The legislature will have until the end of the 2025 session (September 12) to pass SB 540, and then the Governor will have until October 12 to sign the bill into law. • Once SB 540 is signed into law, CAISO will have the power to decide whether to join the RO no earlier than January 1, 2027. Until then, the Pathways Formation Committee will work to stand up the RO by finalizing its governing rules and seating the initial seven-member board. • Staff recommendation: Ava should sign onto a coalition letter urging California legislators to support SB 540.

Attachment Staff Report Item 13B
AMENDED IN SENATE MARCH 24, 2025
SENATE BILL No. 540
Introduced by Senators Becker and Stern
February 20, 2025
An act to amend Section 337 of, to add Section 345.6 to, to repeal Section 352 of, and to repeal Article 4 (commencing with Section 355) of, Article 5 (commencing with Section 359) of, and Article 5.5 (commencing with Section 359.5) of, Chapter 2.3 of Part 1 of Division 1 of, the Public Utilities Code, relating to electricity. legislative counsel’s digest
SB 540, as amended, Becker. Independent System Operator:
independent regional organization.

Existing law provides for the establishment of an Independent System Operator (ISO) as a nonprofit public benefit corporation and requires the ISO to ensure efficient use and reliable operation of the electrical transmission grid consistent with achieving planning and operating reserve criteria no less stringent than those established by the Western Electricity Coordinating Council and the North American Electric Reliability Council. Existing law, the Clean Energy and Pollution Reduction Act of 2015, provides for the transformation of the ISO into a regional organization, with the approval of the Legislature, pursuant to a specified process. That process provides that modifications to the ISO’s governance structure, through changes to its bylaws or other corporate governance documents, will not become effective until the ISO, the Public Utilities Commission, the State Energy Resources Conservation and Development Commission, the State Air Resources Board (state board), the Governor, and the Legislature take specified actions on or before January 1, 2019.
98 Attachment Staff Report Item 13C
This bill would delete the above-described provisions providing for the transformation of the ISO into a regional organization. The bill would authorize the ISO and the electrical corporations that are participating transmission owners whose transmission systems are operated by the ISO, in lieu of the ISO managing related energy markets, as provided, to use voluntary energy markets governed by an independent regional organization, provided that specified requirements are satisfied. The bill would authorize the ISO, on or after January 1, 2027, to implement tariff modifications accepted by the Federal Energy Regulatory Commission to operate the energy markets whose rules are governed by an independent regional organization if the governing board of the ISO adopts a resolution, as specified, finding that each of the specified conditions have been, or will be, adopted by the independent regional organization. The bill would require the ISO to maintain the necessary technical capability to operate energy markets, as specified, and would require the ISO to continue its functions and responsibilities as a balancing authority, as provided.

Existing law requires the Power Exchange to provide an efficient competitive auction, open on a nondiscriminatory basis to all suppliers, that meets the loads of all exchange customers at efficient prices, and authorizes the Power Exchange governing board to form appropriate technical advisory committees composed of market and nonmarket participants to advise the governing board on relevant issues.

This bill would delete these provisions.

Vote: majority. Appropriation: no. Fiscal committee: yes.

State-mandated local program: no.

The people of the State of California do enact as follows:
line 1 SECTION 1. Section 337 of the Public Utilities Code is line 2 amended to read:
line 3 337. (a)  The Independent System Operator governing board line 4 shall comprise a five-member independent governing board of line 5 directors appointed by the Governor and subject to confirmation line 6 by the Senate. Any reference in this chapter or in any other line 7 provision of law to the Independent System Operator governing line 8 board means the independent governing board appointed under line 9 this subdivision.
line 10 (b) A member of the independent governing board appointed line 11 under subdivision (a) may not be affiliated with any actual or 98 SB 540 — 2 —
Attachment Staff Report Item 13C
line 1 potential participant in any market administered by the Independent line 2 System Operator.
line 3 (c) (1)  All appointments shall be for three-year terms. line 4 (2) There is no limit on the number of terms that may be served line 5 by any member.
line 6 (d) The Oversight Board shall require the articles of line 7 incorporation and bylaws of the Independent System Operator to line 8 be revised in accordance with this section, and shall make filings line 9 with the Federal Energy Regulatory Commission as the Oversight line 10 Board determines to be necessary.
line 11 (e) For purposes of the initial appointments to the Independent line 12 System Operator governing board, as provided in subdivision (a), line 13 the Governor shall appoint one member to a one-year term, two line 14 members to a two-year term, and two members to a three-year line 15 term.
line 16 SEC. 2. Section 345.6 is added to the Public Utilities Code, to line 17 read:
line 18 345.6. (a)  In lieu of the Independent System Operator line 19 managing related energy markets as provided in subdivision (b) line 20 of Section 345.5, the Independent System Operator and the line 21 electrical corporations that are participating transmission owners line 22 whose transmission systems are operated by the Independent line 23 System Operator may use voluntary energy markets governed by line 24 an independent regional organization if all of the following line 25 requirements are satisfied:
line 26 (1) The independent regional organization is a nonprofit line 27 corporation whose governance documents include a corporate line 28 obligation to respect the authority of each state that has a line 29 load-serving entity or balancing authority participating in the line 30 market to set its own procurement, environmental, reliability, and line 31 other public interest policies.
line 32 (2) The governing board of the independent regional line 33 organization maintains a public policy committee consisting of line 34 members of the governing board of the independent regional line 35 organization that engages with states, local power authorities, and line 36 federal power marketing administrations about potential impacts line 37 to state, local, or federal policies before it approves a tariff change line 38 for filing at the Federal Energy Regulatory Commission. line 39 (3) The governing board of the independent regional line 40 organization maintains a relationship with and seeks input from a 98 — 3 — SB 540
Attachment Staff Report Item 13C
line 1 body of state regulators or similar body to receive the views of line 2 state regulators.
line 3 (4) The independent regional organization makes funding line 4 available for a consumer advocate organization that represents the line 5 interests of one or more consumer advocate offices authorized in line 6 state law and facilitates engagement by those offices in the markets line 7 governed by the independent regional organization. line 8 (5) The independent regional organization maintains an office line 9 of public participation to provide information and education to line 10 members of the public about issues and initiatives at the line 11 independent regional organization, including facilitating line 12 engagement in those processes.
line 13 (6) In addition to any independent market monitoring activity line 14 required by a Federal Energy Regulatory Commission order, the line 15 independent regional organization maintains access to independent line 16 market analysis for the governing board of the independent regional line 17 organization on the impacts of market dynamics or rule changes line 18 to minimize overall costs to end-use consumers. line 19 (7) Subject to appropriate confidentiality provisions, market line 20 data is available to the commission and the Public Advocate’s line 21 Office, and other states’ commissions and public advocate offices, line 22 to the same or greater extent as existed on December 31, 2024, for line 23 the markets governed by the Independent System Operator. line 24 (8) There is a stakeholder process designed to provide line 25 nonbinding advice to the governing board of the independent line 26 regional organization.
line 27 (9) The independent regional organization is obligated to line 28 conduct meetings and make decisions in an open process with line 29 transparent, documented rationales, and all meetings of the line 30 governing board of the independent regional organization are line 31 publicly noticed and, excluding executive sessions, are available line 32 to remote participants, recorded and posted on the independent line 33 regional organization’s internet website, open to the public, and line 34 subject to open record requirements.
line 35 (10) The Independent System Operator continues to operate the line 36 energy markets, subject to the market rules determined by the line 37 independent regional organization as accepted by the Federal line 38 Energy Regulatory Commission.
line 39 (11) The market rules of the independent regional organization line 40 continue to provide greenhouse gas emissions information and 98 SB 540 — 4 —
Attachment Staff Report Item 13C
line 1 protocols sufficient to enable entities subject to the State Air line 2 Resources Board’s rules to demonstrate compliance. line 3 (12) The independent regional organization permits and provides line 4 a procedure for unilateral withdrawal by any participant with line 5 reasonable prior notice. notice and without any further approvals. line 6 (b) On or after January 1, 2027, the Independent System line 7 Operator may implement tariff modifications accepted by the line 8 Federal Energy Regulatory Commission to operate the energy line 9 markets whose rules are governed by an independent regional line 10 organization, as provided in subdivision (a), if the governing board line 11 of the Independent System Operator adopts a resolution finding line 12 that each of the requirements of paragraphs (1) through (12), line 13 inclusive, of subdivision (a) have been or will be adopted by the line 14 independent regional organization. The governing board of the line 15 Independent System Operator may adopt the resolution if the line 16 Independent System Operator satisfies all of the following line 17 requirements:
line 18 (1) The meeting is open to the public, available to remote line 19 participants, recorded, and posted on the Independent System line 20 Operator’s internet website.
line 21 (2) The Independent System Operator issues a notice of the line 22 meeting and proposed findings not less than 90 days before the line 23 meeting.
line 24 (3) The notice explains the basis for finding that each line 25 requirement of paragraphs (1) through (12), inclusive, of line 26 subdivision (a) will be met.
line 27 (4) The notice provides an opportunity for written comments line 28 on the proposed findings.
line 29 (5) The Independent System Operator issues written responses line 30 to any comments not less than 20 days before the meeting. line 31 (c) (1)  The Independent System Operator shall maintain the line 32 necessary technical capability to operate energy markets in a line 33 manner that enables California electrical corporations, local line 34 publicly owned electric utilities, and other applicable market line 35 participants to withdraw from the markets governed by the line 36 independent regional organization and instead the Independent line 37 System Operator would provide separate market services for those line 38 entities.
line 39 (2) This section does not modify the commission’s authority to line 40 direct an electrical corporation to withdraw from an energy market 98 — 5 — SB 540
Attachment Staff Report Item 13C
line 1 governed by an independent regional organization in response to line 2 federal action or any other significant change in market rules or line 3 operations detrimental to California consumers or California line 4 procurement, environmental, reliability, or other public interest line 5 policies.
line 6 (d) (1)  The Independent System Operator shall continue its line 7 functions and responsibilities as a balancing authority as they line 8 existed before enactment of this section, and maintain compliance line 9 with applicable reliability standards as developed, adopted, and line 10 enforced by the North American Electric Reliability Corporation, line 11 the Western Electricity Coordinating Council, or the Federal line 12 Energy Regulatory Commission.
line 13 (2) The Independent System Operator shall not change its line 14 balancing authority area from that which existed on December 31, line 15 2024, except as follows:
line 16 (A) Standard accretion of new transmission lines, substations, line 17 and other equipment by participating transmission owners. line 18 (B) The Independent System Operator may combine its line 19 balancing authority area with another California balancing authority line 20 if the combination is mutually agreed upon.
line 21 (C) The Independent System Operator may use its subscriber line 22 participating transmission owner tariff.
line 23 (3) This Except as provided in subdivision (a) with respect to line 24 managing energy markets as provided in this section, this section line 25 does not change the responsibilities of the Independent System line 26 Operator under Section 345.5, including managing the transmission line 27 grid, planning for transmission expansion, and complying with line 28 Section 25308 of the Public Resources Code.
line 29 (e) (1)  This section does not change any requirement related line 30 to the California Renewables Portfolio Standard Program as line 31 provided in Article 16 (commencing with Section 399.11). line 32 (2) This section does not change the policy of the state to reach line 33 specified targets by specified dates for supplying eligible renewable line 34 energy resources and zero-carbon resources as provided in line 35 subdivision (a) of Section 454.53.
line 36 (e)
line 37 (f) The Independent System Operator may act as a vendor, line 38 through a contract with the independent regional organization, of line 39 market operation services, generation dispatch services, line 40 transmission operation services, transmission planning services, 98 SB 540 — 6 —
Attachment Staff Report Item 13C
line 1 reliability coordination, balancing authority compliance or line 2 operation services, or other electrical system services. line 3 (f)
line 4 (g) For purposes of this section, the terms “balancing authority,” line 5 “balancing authority area,” and “California balancing authority” line 6 have the same meanings as provided in Section 399.12. line 7 SEC. 3. Section 352 of the Public Utilities Code is repealed. line 8 SEC. 4. Article 4 (commencing with Section 355) of Chapter line 9 2.3 of Part 1 of Division 1 of the Public Utilities Code is repealed. line 10 SEC. 5. Article 5 (commencing with Section 359) of Chapter line 11 2.3 of Part 1 of Division 1 of the Public Utilities Code is repealed. line 12 SEC. 6. Article 5.5 (commencing with Section 359.5) of line 13 Chapter 2.3 of Part 1 of Division 1 of the Public Utilities Code is line 14 repealed.

O
98 — 7 — SB 540
Attachment Staff Report Item 13C
Staff Report Item 17
To: Ava Community Energy Authority
From: Todd Edmister, Sr. Director of Public Policy and Deputy General Counsel Dominic Faria, Senior Policy Coordinator
Subject: Seeking Board approval for supporting SB 540 (Pathways legislation) Date: March 19, 2025
________________________________________________________________ Summary/Recommendation
This Staff Report and accompanying presentation are intended to inform the Ava Board of Directors about SB 540 and the West-wide Pathways Initiative, and to seek approval to adopt a Resolution in support of SB 540 and authorizing the CEO to sign the attached Letter of Support.

Financial Impact
There is no cost associated with sending a letter of support but adoption of SB 540 could potentially result in operational savings for Ava in the future.

Analysis and Context
California CCAs, including Ava, have been asked to sign a letter supporting California Senate Bill 540 (SB 540). The letter is being led and signed by a broad coalition of stakeholders, including CalCCA, Natural Resources Defense Council, American Clean Power, among others.

The letter will be sent to members of the legislature urging them to support the legislation.

What is SB 540? On February 20, state Senators Josh Becker (D-Menlo Park) and Henry Stern (D-Los Angeles) introduced SB 540, a bill that establishes a process through which the California Independent System Operator (CAISO) and California utilities can participate in an energy market governed by an independent, West-wide regional organization (RO) as proposed by the Pathways Initiative.

Attachment Staff Report Item 13D
Under current California law, the state’s energy market rules are governed by the CAISO Board of Governors, a five-member body whose members are appointed by the Governor and confirmed by the state Senate. The CAISO operates the Western Energy Imbalance Market (WEIM), a regional market that enables participants to buy and sell power in real time and plans to launch an Extended Day Ahead Market (EDAM) in 2026. The CAISO also oversees transmission planning, energy project selection, transmission system operation and cost allocation, balancing authority functions, reliability coordination, and energy market operations.

SB 540 would allow the CAISO to transfer its existing governance of the western energy markets to an RO starting in 2027, but only if the CAISO decides that the RO meets a set of specific statutory requirements. The bill does not alter the CAISO’s existing authority over transmission planning, balancing authority functions, or reliability and renewable portfolio standards. Instead, it would merely give the CAISO the authority to decide whether to transfer its existing governance over the energy market rules to the RO while retaining the remainder of its current authorities and functions.

Who is supporting and opposing the Pathways Initiative? SB 540 is co-sponsored by the Coalition of California Utility Employees, State Association of Electrical Workers, Environmental Defense Fund, and Natural Resources Defense Council. It is supported by a range of other utility, labor, developer, and environmental advocacy groups. Supporters within the CCA community include MCE, Silicon Valley Clean Energy and Peninsula Clean Energy. The CalCCA Board of Directors voted in February 2025 to support the legislation.

Opposition has come from Consumer Watchdog and former CPUC President Loretta Lynch.

What is the Pathways Initiative? The Pathways Initiative is a multi-state effort aimed at establishing a unified, independently governed wholesale electricity market that includes all states in the Western Interconnection, including California. The Pathways Initiative began in 2023 at the request of public utility and energy commissioners from California, Oregon, Washington, Arizona, and New Mexico with the intent of maximizing the benefits of coordinated wholesale electricity markets for customers across the entire Western U.S.

The Pathways Initiative Launch Committee was formed in October 2023 and is led by representatives from a variety of stakeholders, including state regulators, investor-owned utilities (IOUs), public utilities, labor unions, non-utility load serving entities (e.g., CCAs), consumer advocates, and others.

This past November, the Pathways Launch Committee approved its Step 2 Final Proposal outlining a plan to form an independent RO responsible for overseeing an integrated WEIM and EDAM for all western states, with the intent to take incremental steps toward ultimate governance and operational control of the market later down the line.

The Pathways Initiative is as notable for what it is not as for what it is. Unlike prior regionalization efforts that have failed to clear the California state legislature or garner requisite support from other states, the Pathways Initiative does not establish a full West-wide regional transmission organization (RTO) with authority over grid operation, capacity requirements, and transmission planning. The proposal does not change existing grid operators or balancing authorities and does not change existing resource adequacy or renewables standards for any Attachment Staff Report Item 13D
state involved. The RO that Pathways establishes is only limited to governance over regional energy market rules.

By enabling California to transfer authority over the regional energy markets to an RO, SB 540’s passage would be a key step forward in the process of advancing the Pathways proposal and achieving potential energy cost savings, and reliability and emissions benefits for California.

Possible RO benefits: Since it was established in 2014, the WEIM reports saving its 22 market participants a total of $6.62 billion. The WEIM states that it is using state-of-the-art technology to find and deliver the lowest-cost resources to meet immediate power needs and manage congestion on transmission lines to maintain grid reliability. The Pathways proposal aims to expand the benefits and cost savings of the WEIM and soon-to-launch EDAM by increasing coordination with and market participation from balancing authorities in other states.

Through an independent RO, market participants would be able to draw resources from a broader energy footprint and thus potentially increase overall reliability and efficiency. A study by The Brattle Group estimates that expanding the EDAM footprint would save California participants anywhere from $182 million to $800 million per year, depending on the size and extent of the regional market; and that market expansion would also reduce the state’s fossil fuel generation by up to 31% and wind and solar curtailment by up to 10%, resulting in a net reduction in statewide greenhouse gas emissions of up to 11.2%, according to the study.

Another study conducted by the Stanford Woods Institute estimates that an expanded regional energy market would substantially reduce the risks of unserved energy and rotating outages by as much as 40% during extreme stress conditions, such as summer heat waves. This analysis also estimates that unserved load would be more than cut in half during these scenarios, from 1901 GWh to 877 GWh.

Possible benefits to Ava: Based on CAISO’s latest WEIM benefits report, the WEIM saves LSEs within CAISO roughly $50 million per year. Ava serves approximately 4% of the CAISO balancing area’s load, meaning that WEIM saves Ava about $2 million per year under the current market arrangement.

Based on Brattle’s $182 million to $800 million system cost savings estimate, transferring market governance to an independent RO and subsequently expanding the EDAM could save Ava anywhere from $7 million to $32 million per year. Again, the actual cost savings Ava ends up realizing will depend on how many entities join the RO-governed EDAM, the overall size of the EDAM footprint, and how efficiently “seams” issues between an RO-Governed EDAM and adjacent markets are resolved. A larger EDAM footprint generally should lead to greater savings.

Concerns with the Pathways Initiative: Pathways Initiative opponents have raised concerns over California relinquishing to the federal government what remaining, energy crisis-era, control it has over the western energy market. This at a time and moment when an aggressively pro-fossil fuel administration has just taken power and is actively attempting to exert greater control over independent federal agencies, like the FERC.

Attachment Staff Report Item 13D
This is a very real concern. However, the loss of remaining state control over energy markets is balanced against the reality that the status quo will not hold anyway. SPP’s Markets+, a competing RTO proposal from the Southwest, is already courting commitments from power suppliers and balancing authorities across the West. Should any delays or failures occur in implementing the Pathways proposal, there is a risk that potential EDAM participants instead elect to join Markets+. The resulting supply-demand dynamic in the EDAM could provide less cost reduction than estimated, and in a worst-case scenario could lead to increased wholesale and retail energy prices.

In short, if California does not cede its already limited control over the CAISO markets, critical suppliers (e.g., Bonneville Power Authority and/or Powerex) will likely join competing markets, with a corresponding reduction in supply to California. At minimum, the Pathways Initiative will reduce the number of supplier “defections” from EIM, while at best, as outlined above, the Pathways Initiative expands the universe of available resources. Which leads to the Staff recommendation below.

Attachments
A. Resolution
B. SB 540 Letter of Support
C. Author’s Fact Sheet
D. Power Point Presentation
Attachment Staff Report Item 13D
RESOLUTION NO. R-2025-XX

A RESOLUTION OF THE BOARD OF DIRECTORS

NOW, THEREFORE, THE BOARD OF DIRECTORS OF AVA COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The Board of Directors hereby expresses its support for SB 540 and authorizes the CEO to sign the Letter of Support urging members of the California legislature to do the same.

ADOPTED AND APPROVED this 19th day of March, 2025.

Attachment Staff Report Item 13D

Jack Balch, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
Attachment Staff Report Item 13D
We are writing to express our strong support for SB 540. This bill provides the statutory authorization necessary to implement the Pathways Proposal, which would make electricity more affordable for California consumers while protecting California’s procurement, environmental, reliability, and other public interest policies.

Developed by a large and diverse set of stakeholders, the Proposal would create a new, independent regional organization that would be solely responsible for setting energy market rules. The California Independent System Operator (CAISO) would continue to operate the markets as it does today, as well as continuing its role in operating the transmission system, transmission system planning, and balancing authority functions. SB 540 ensures the expertise and infrastructure that the CAISO has built is maintained, further protecting investments in current energy markets.

Creating an independent organization responsible for energy market rules would enable more utilities across the West to participate in consolidated electricity markets, making electricity in California more affordable and reliable while also reducing emissions in California.

SB 540 Provides More Affordable Electricity
This legislation, and the consolidated electricity markets it enables, would provide much needed energy affordability benefits to Californians. A new analysis conducted for the California Energy Commission (CEC) determined a West-wide day-ahead market could produce nearly $800 million in annual cost savings for California customers. 1 SB 540 Improves Electric Reliability
The legislation would enhance the reliability of California’s power grid by enabling more efficient and coordinated management of energy supply and demand across the Western region. With better access to shared resources, grid operators will be better equipped to draw on a wider resource pool during peak demand periods, reduce the likelihood of blackouts, and support the resilience of the grid in the face of growing challenges such as extreme weather events and climate-driven disruptions.
2 SB 540 Increases Use of Clean Energy
A consolidated western energy market will maximize use of existing clean energy generation and enable a faster, more affordable clean energy future. SB 540 makes more clean energy available both in California and around the West by reducing curtailment (deliberately reducing output below what could have been produced), a growing problem for solar and wind power generators in California. The CEC study determined the expanded market would reduce wind 1 John Tsoukalis, et al., Brattle Group, “Preliminary Day-Ahead Market Impact Study: Impact of Market Footprints on California Customers” (Prepared for California Energy Commission, January 24, 2025). 2 See Tsoukalis, et al. and Michael Wara, et al., Stanford Climate & Energy Policy Program, “Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations”(Prepared for California Energy Commission, January 24, 2025).

Attachment Staff Report Item 13D
and solar curtailment by 10%. This improvement would reduce air pollution by displacing other less efficient emitting resources and enhance the financial foundation for clean energy investment and jobs by enabling California to use and sell more of its clean energy. 3 With 80% of energy customers in the West now served by utilities with net-zero carbon energy mandates, the demand for clean energy resources will continue to grow. Maximizing use of existing clean generation is the fastest, most affordable way to reduce emissions.

SB 540 Protects Consumers and California Energy Policy
SB 540 would permit CAISO and California investor-owned utilities to participate in the independently governed energy markets only if the new regional organization meets guardrails designed to protect consumers and ensure that California can continue to set its own procurement, environmental, reliability, and other public interest policies. These protections include:
● public interest protections in the corporate documents; ● specific roles and engagement with state regulators and consumer advocate offices including access to market data;
● transparent and accessible operations including an office of public participation; ● independent market analysis and monitoring to protect consumers; ● engagement with states, local power authorities, and federal power marketing agencies to evaluate potential impacts of proposed market rule and tariff changes to state, local, and federal policies; and
● retention of the right to withdraw from the energy markets governed by the new regional organization if participation were no longer in the interests of their customers.

The diverse set of signatories on this letter represent an unprecedented coalition of consumer advocates, organized labor, environmental advocates, clean energy developers, investor-owned utilities, public power, and large customers who strongly support SB 540. For all of the above reasons, we support this legislation and request your support. 3 John Tsoukalis, et al., Brattle Group, “Preliminary Day-Ahead Market Impact Study: Impact of Market Footprints on California Customers” (Prepared for California Energy Commission, January 24, 2025).

Attachment Staff Report Item 13D
SB 540 - Pathways Initiative

SUMMARY
SB 540 provides the California Independent
System Operator (CAISO) the authority
necessary to implement the Pathways Initiative
Proposal if it determines an independent regional
organization (RO) meets specific requirements.

The bill allows CAISO to tap into a wider
market of electricity resources which studies
have shown stand to provide significant benefits
to Californians including cost savings, enhanced
grid reliability, and reduced air pollution.

While prior attempts to create a wider regional
market have failed out of concerns that
California would lose control over its
environmental policies, SB 540 enables an
innovative approach that would secure the gains
of an expanded market while protecting
California’s ability to set and enforce its own
procurement, environmental, reliability, and
other public policies.

PROBLEM
For many years, California’s energy regulators
have explored how they could optimize
available energy supplies across other western
states to expand our energy markets and enable
an affordable, clean, and reliable grid.

Studies have shown that there are significant
benefits for California in an expanded energy
market. For example, a Stanford Woods Institute
(2024) study found that an expanded market
would relieve strain on the electric grid during
extreme heat events–in an expanded market
scenario the grid was strained 40% fewer hours.1
A study commissioned by the California Energy
Commission (CEC) found that under an
expanded market, California would save nearly
$800 million per year and gas generation would
fall by 31%, moving us closer to our 100% clean
1 Stanford Woods Institute: “Grid Regionalization in
the West”
energy goals while reducing air pollution.2
However, these benefits only materialize if
other states want to join the regional market, a
market they are wary of if it’s solely under
California’s control.

Several different proposals, that would reassure
other Western states of California’s willingness
to work jointly, have made their way before the
Legislature. Most recently, AB 538 (Holden,
2023) would have transformed CAISO into a
regional transmission organization (RTO).

However, these previous efforts have failed over
reasonable concerns about losing control of the
state’s critical public policies.

The Pathways Proposal offers a way to solve
these problems. Instead of creating an RTO, the
Pathways Proposal creates an RO that only
governs the market rules for energy markets
while retaining CAISO’s role as a
California-governed balancing authority so that
California and CAISO retain control over
procurement, environmental, reliability, and
other public policies.

CURRENT LAW
Existing law enables CAISO to, and instructs
how it will, manage the transmission grid and
related energy markets. It requires, among other
things, that CAISO manage those markets in a
manner that maximizes efficiency, reduces costs
to consumers, protects public health and the
environment, and ensures reliability. However,
additional authority is required in order for
CAISO and California utilities to use energy
markets overseen by an RO as proposed by the
Pathways Initiative.

THIS BILL
SB 540 enables the CAISO and California
utilities to participate in energy markets
governed by a separate, independent regional
2 Brattle: “Preliminary Day-Ahead Market Impacts
Study”
Last Updated 02/20/2025
Attachment Staff Report Item 13D
organization. If the RO meets specific criteria,
CAISO would be authorized to enact a
resolution allowing the RO’s rules to govern
CAISO’s energy markets. The CAISO would
continue to be the operator of the energy
markets.

SB 540 does not transfer authority for
transmission planning, transmission cost
allocation, balancing authority functions, or
reliability coordination–this authority would
remain with the existing CAISO board structure.

The bill also does not immediately authorize
utilities to enter a market governed by an RO,
CAISO must first demonstrate the RO meets a
number of statutory requirements before moving
control of the market rules to the RO including:
confirming that California regulatory agencies
and CAISO retain control over Renewables
Portfolio Standard requirements, climate policy,
other procurement requirements, transmission
planning, CAISO’s interconnection queue, and
resource adequacy requirements; requiring that
the RO provides a procedure for withdrawal
from the market, should it no longer benefit
California to participate; maintaining the
capability to operate its own market, should
California decide to withdraw from the RO;
ensuring the RO is obligated to make decisions
in an open process; making funding available
for consumer advocates to engage in the process,
and more.

The expanded market that SB 540 would enable
will save ratepayers money, improve grid
reliability, and reduce air pollution from power
plants in California by:
1) Optimizing the use of generation, storage and
transmission resources.
2) Securing California’s ability to export excess
renewables rather than curtailing them and
importing them from other states when
available.
3) Allowing California to draw upon a wider set
of Western renewable resources when our grid is
stressed.
4) Making less use of back-up diesel generators
and the oldest, dirtiest gas plants during system
peaks.

SB 540 will ensure that we reach our climate
goals in the most cost-effective and reliable
manner possible by tapping into a much wider
set of Western resources–lowering energy bills,
improving grid reliability, and reducing
pollution in front-line communities, while also
retaining control of our procurement,
environmental, reliability, and other public
policies.

SUPPORT
Coalition of California Utility Employees
(co-sponsor)
State Association of Electrical Workers
(co-sponsor)
Environmental Defense Fund (co-sponsor)
Natural Resources Defense Council (co-sponsor)
American Clean Power–California
California Community Choice Association
California Environmental Voters
Clean Energy Buyers Association
Pattern Energy
Peninsula Clean Energy

FOR MORE INFORMATION
Erika Romero
Policy Analyst
[email protected]
Last Updated 02/20/2025
Attachment Staff Report Item 13D
SB 540 and the West-wide Pathways Initiative
Todd Edmister & Dominic Faria | March 19, 2025
Attachment Staff Report Item 13D
Overview
2 1. What is SB 540?

2. What the bill does

3. What is the Pathways Initiative?

4. Potential benefits & concerns

5. Summary and next steps
Attachment Staff Report Item 13D
What is SB 540?
3 • Introduced Feb 20 in CA Senate by Sens. Josh Becker (D-Menlo Park) and Henry Stern (D-Los Angeles)
• Establishes a process through which the California Independent System Operator (CAISO) and California utilities can participate in an energy market governed by an independent, west-wide regional organization (RO) as proposed by the Pathways Initiative
• Co-sponsored by the Coalition of California Utility Employees, State Association of Electrical Workers, Environmental Defense Fund, and Natural Resources Defense Council
• The CalCCA Board of Directors voted in February 2025 to support the legislation Attachment Staff Report Item 13D
What the bill does
4 • California’s energy market rules are governed by the CAISO Board of Governors, a five-member body whose members are appointed by the Governor and confirmed by the state Senate • CAISO operates the Western Energy Imbalance Market (WEIM), a regional market that enables participants to buy and sell power in real time, and plans to launch an Extended Day Ahead Market (EDAM) in 2026. • SB 540 would allow CAISO to transfer its existing governance of the western energy markets (WEIM and EDAM) to an RO starting in 2027 only if CAISO decides that the RO meets a set of specific statutory requirements, including:
▪ The RO’s governing documents confirm that California regulatory agencies and CAISO will retain control over RPS and other procurement requirements, climate policy, transmission planning, CAISO’s interconnection queue, and RA requirements ▪ The RO makes decisions in an open, public process and establishes formal processes through which to engage with state regulators, policy experts, stakeholders, and the public ▪ The RO makes funding available for consumer advocates to engage in the process ▪ The CAISO continues to operate the energy markets, subject to the market rules determined by the RO ▪ The RO permits and provides a procedure for withdrawal by any participant • Allows CAISO to act as a vendor, through a contract with the RO, to provide market operations, generation dispatch, transmission, and reliability coordination services.

Attachment Staff Report Item 13D
Graphic courtesy of CalCCA
5 Attachment Staff Report Item 13D
What is the Pathways Initiative?
6 • The Pathways Initiative is a multi-state effort aimed at establishing a unified, independently governed wholesale electricity market that includes all states in the Western Interconnection, including California. It began in 2023 at the request of public utility and energy commissioners from California, Oregon, Washington, Arizona, and New Mexico with the intent of maximizing the benefits of coordinated wholesale electricity markets for customers across the entire Western U.S. • The Pathways Initiative Launch Committee was formed in October 2023 and is led by representatives from a variety of stakeholders, including state regulators, IOUs, public utilities, labor unions, non-utility load serving entities (CCAs), consumer advocates, and others. • This past November, the Pathways Launch Committee approved its Step 2 Final Proposal outlining a plan to form an independent RO responsible for overseeing an integrated WEIM and EDAM for all western states.
• The Pathways proposal does not change existing grid operators or balancing authorities and does not change existing RA or RPS standards for any state involved.

Attachment Staff Report Item 13D
Potential Benefits
7 • Estimated cost savings: $182 million to $800 million reduction in annual California system costs, depending on size and extent of the market, compared to the status quo. Translates to roughly $7 million to $32 million in annual cost savings for Ava.
• Enhanced grid reliability: Relieves strain on the electric grid during extreme heat events, reducing the number of hours the grid is strained by as much as 40% and reducing unserved load by more than half in these scenarios.
• Reduced emissions: Decreases California’s fossil fuel generation by up to 31% and greenhouse gas emissions by up to 11.2%
• Optimized resource use: Reduces solar and wind energy curtailment by up to 10%, allowing California to export and import more excess renewable energy to and from other states. • Helps achieve state climate goals: California will maintain authority over its existing policies while being able to tap into a wider set of regional resources in a cost-effective and reliable manner Sources: Stanford Woods Institute: “Grid Regionalization in the West” and The Brattle Group: “Preliminary Day-Ahead Market Impacts Study” Attachment Staff Report Item 13D
Other Considerations
8 • Potential concern: Relinquishing CA control over energy market governance at a time when the administration is attempting to exert greater control over independent agencies, like FERC • Western entities electing to participate in a competing market: SPP's Markets+ is already courting commitments from power suppliers and balancing authorities across the West, limiting the possible benefits of EDAM
• Bottom line: Should any delays or failures occur in implementing the Pathways proposal, there is a risk that potential EDAM participants instead elect to join Markets+. If California does not cede its already limited control over the CAISO markets, critical suppliers will likely join competing markets, with a corresponding reduction in supply to California.

Attachment Staff Report Item 13D
Summary and Next Steps
9 • By enabling California to transfer authority over the regional energy markets to an RO, SB 540’s passage would be a key step forward in the process of advancing the Pathways proposal and achieving energy cost savings, and reliability and emissions benefits for California and Ava. • SB 540 will have a hearing in the Senate Energy, Utilities, and Communications Committee (date TBD)
• The legislature will have until the end of the 2025 session (September 12) to pass SB 540, and then the Governor will have until October 12 to sign the bill into law • Once SB 540 is signed into law, CAISO will have the power to decide whether to join the RO no earlier than January 1, 2027. Until then, the Pathways Formation Committee will work to stand up the RO by finalizing its governing rules and seating the initial seven-member board. • Staff recommendation: Ava should sign onto a coalition letter urging California legislators to support SB 540.

Attachment Staff Report Item 13D
SUPPORT – SB 540 (Becker and Stern) - as introduced, February 20, 2025 3/7/25 - Page 1 of 6
Attachment Staff Report Item 13E
SUPPORT – SB 540 (Becker and Stern) - as introduced, February 20, 2025 3/7/25 - Page 2 of 6
March 7, 2025
The Honorable Senator Becker
Chairman, Senate Utilities, Energy, and Communications Committee 1021 O Street, Suite 3350
Sacramento, CA 95814
RE: SUPPORT - SB 540 (Becker, Stern) – as introduced February 20, 2025 Dear Senator Becker,
We are writing to express our strong support for SB 540. This bill provides the statutory authorization necessary to implement the Pathways Proposal which would make electricity more affordable for California consumers while protecting California’s procurement, environmental, reliability, and other public interest policies.

SB 540 Improves Electric Reliability
The legislation would enhance the reliability of California’s power grid by enabling more efficient and coordinated management of energy supply and demand across the Western region. With better access to shared resources, grid operators will be better equipped to draw on a wider resource pool during peak demand periods, reduce the likelihood of blackouts, and support the 1 John Tsoukalis, et al., Brattle Group, “Preliminary Day-Ahead Market Impact Study: Impact of Market Footprints on California Customers” (Prepared for California Energy Commission, January 24, 2025).

Attachment Staff Report Item 13E
SUPPORT – SB 540 (Becker and Stern) - as introduced, February 20, 2025 3/7/25 - Page 3 of 6
resilience of the grid in the face of growing challenges such as extreme weather events and climate-driven disruptions.2

SB 540 Increases Use of Clean Energy
A consolidated western energy market will maximize use of existing clean energy generation and enable a faster, more affordable clean energy future. SB 540 makes more clean energy available both in California and around the West by reducing curtailment (deliberately reducing output below what could have been produced), a growing problem for solar and wind power generators in California. The CEC study determined the expanded market would reduce wind and solar curtailment by 10 percent. This improvement would reduce air pollution by displacing other less efficient emitting resources and enhance the financial foundation for clean energy investment and jobs by enabling California to use and sell more of its clean energy.3 With 80% of energy customers in the West now served by utilities with net-zero carbon energy mandates, the demand for clean energy resources will continue to grow. Maximizing use of existing clean generation is the fastest, most affordable way to reduce emissions.

The diverse set of signatories on this letter represent an unprecedented coalition of consumer advocates, organized labor, environmental advocates, clean energy developers, investor-owned 2 See Tsoukalis, et al. and Michael Wara, et al., Stanford Climate & Energy Policy Program, “Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations”(Prepared for California Energy Commission, January 24, 2025). 3 John Tsoukalis, et al., Brattle Group, “Preliminary Day-Ahead Market Impact Study: Impact of Market Footprints on California Customers” (Prepared for California Energy Commission, January 24, 2025).

Attachment Staff Report Item 13E
SUPPORT – SB 540 (Becker and Stern) - as introduced, February 20, 2025 3/7/25 - Page 4 of 6
utilities, public power, and large customers who strongly support SB 540. For all of the above reasons, we support this legislation and request your support.

Sincerely,
Advanced Energy United (AEU)
Amazon
American Clean Power – California (ACP)
CA & NV State Association of Electrical
Workers (IBEW)
CalCCA
California Chamber of Commerce
California Environmental Voters
California Large Energy Consumers
Association (CLECA)
California State Pipe Trades Council
Ceres
Clean Energy Buyers Association (CEBA)
Coalition of California Utility Employees
(CCUE)
E2 | Environmental Entrepreneurs
EDP Renewables
Environmental Defense Fund (EDF)
Google
Independent Energy Producers Association
(IEPA)
Leap
MCE Community Choice Energy
Microsoft
Mitsubishi Cement Corporation
Natural Resources Defense Council
(NRDC)
Pacific Steel Group (PSG)
Pattern Energy
Rivian
San Diego Community Power
Sierra Nevada Brewing Co.

Silicon Valley Leadership Group (SVLG)
Silicon Valley Clean Energy
Solar Energy Industries Association (SEIA)
Union of Concerned Scientists (UCS)
Western Freedom
Western Power Trading Forum (WPTF)
Western Resource Advocates (WRA)
Western States SMART Council
CC: Senator Henry Stern, Co-Author
Members, Senate Utilities, Energy, and Communications Committee Nidia Bautista, Chief Consultant
Kerry Yoshida, Republican Caucus Consultant
Attachment Staff Report Item 13E
SUPPORT – SB 540 (Becker and Stern) - as introduced, February 20, 2025 3/7/25 - Page 5 of 6
Edson Perez
Senior Principal
Advanced Energy United (AEU)
Nate Hill
Head of Energy Policy
Amazon
Alexander L. Jackson
Executive Director
American Clean Power – California (ACP)
John Doherty
Secretary/Treasurer
CA & NV State Association of Electrical
Workers (IBEW)
Beth Vaughan
Chief Executive Officer
CalCCA
Jonathan Kendrick
Policy Advocate
California Chamber of Commerce
Melissa Romero
Policy Advocacy Director
California Environmental Voters
Christian Lenci
Chair
California Large Energy Consumers
Association (CLECA)
Mike Hartley
Executive Director
California State Pipe Trades Council
Kelly Trombley
Director, State Policy, West
Ceres
Priya Barua
Senior Director of Market & Policy
Innovation
Clean Energy Buyers Association (CEBA)
Hunter Stern
Chair
Coalition of California Utility Employees
(CCUE)
Susan Nedell
Senior Western Advocate
E2 | Environmental Entrepreneurs
Jack Wadleigh
Regulatory Affairs and Market Development
Manager, Western Region
EDP Renewables
Katelyn Roedner Sutter
California State Director
Environmental Defense Fund (EDF)
Dylan Sullivan
Head of Energy Market Development, US-West
Google
Jan Smutny-Jones, Esq.

Chief Executive Officer, General Counsel
Independent Energy Producers Association
(IEPA)
Collin Smith
Regulatory Affairs Manager
Leap
Dawn Weisz
Chief Executive Officer
MCE Community Choice Energy
Robyn Hines
Sr. Director Government Affairs
Microsoft
Attachment Staff Report Item 13E
SUPPORT – SB 540 (Becker and Stern) - as introduced, February 20, 2025 3/7/25 - Page 6 of 6
Austin Marshall
President/C.O.O.

Mitsubishi Cement Corporation
Victoria Rome
CA Government Affairs Director
Natural Resources Defense Council
(NRDC)
Mark Olson
Vice President of Mill Operations
Pacific Steel Group (PSG)
Varner Seaman
Director of Government Affairs
Pattern Energy
Coley Girouard
Lead, Energy Market Enablement and Utility
Strategy
Rivian
Patrick Welch
Senior Legislative Manager
San Diego Community Power
Mandi McKay
Sustainability & Social Impact Officer
Sierra Nevada Brewing Co.

Monica V. Padilla
Chief Executive Officer
Silicon Valley Clean Energy
Laura Wilkinson
SVP, Strategy & External Affairs
Silicon Valley Leadership Group (SVLG)
Stephanie Doyle
California State Affairs Director
Solar Energy Industries Association (SEIA)
Daniel Barad
Western States Policy Manager
Union of Concerned Scientists (UCS)
Kathleen Staks
Executive Director
Western Freedom
Scott Miller
Executive Director
Western Power Trading Forum (WPTF)
Vijay Satyal
Deputy Director, Regional Markets and
Transmission
Western Resource Advocates (WRA)
Dion Abril
Executive Administrator
Western States SMART Council
Attachment Staff Report Item 13E

March 12, 2025
Re: Pathways (SB 540) Gives Trump’s FERC Power To Invalidate The Renewable Portfolio Standard And Other California Environmental Laws
Dear California Senator,
You will soon be asked to take a vote to hand the power over California environmental laws to the Federal Energy Regulatory Commission (FERC) at grave risk to California’s renewable portfolio standard (RPS) and other clean energy laws.

The sovereignty issues that have doomed the Western Regional Transmission Organization (RTO)/Pathways, and prevented it from becoming law, have not gone away, in fact they have become more perilous following the presidential election.

What has happened is the need for more power due to the inexhaustible hunger of data centers to power AI has caused some people to conveniently forget the Achilles heel of Pathways.

Pathways proponents claim that California needs more power and more renewable electricity, and that a Delaware corporation operating regional electricity markets will make that happen.

The problem is that the Delaware company will be entirely subject to FERC’s rules, a FERC with Donald Trump’s appointees on it, not California’s.

Changing California law and statutory requirements to allow a regional market operator that will be a Delaware corporation eliminates all the protections that ISO v. FERC provides California to require the market operator to follow California law and propose market rules that follow California law. (ISO v. FERC, 372 F.3d 396 (D.C. Cir. 2004).) California is now shielded from any challenge to its authority over the board of CA’s market operator, CAISO, because it is a California corporation. California cannot be forced to violate California’s environmental laws. That protection vanishes if California cedes its authority to a Delaware corporation that runs the regional market.

Under Pathways as envisioned in SB 540, the CAISO remains the transmission grid operator, but it will transfer its right to propose tariffs (the rules for how the markets and the transmission grid operate, called Section 205 filing rights) to a Delaware (DE) corporation, called a Regional Operator (RO). The Delaware RO will control all the tariffs dictating how all electricity markets operate AND how California runs its grid. California would give up its right to demand that its environmental, consumer and health safety laws be followed.

Attachment Staff Report Item 13G
• California’s laws (P.U.Code §345.5(b)) requiring CAISO to run CA’s electricity markets and California’s grid consistent with the interests of the people of CA and to minimize prices and maximize supply for CA consumers will be made inopera;ve. • Pathways allows the Trump Administra;on to require CA to buy coal-fired electricity. It will allow Trump to require CA (and the en_re regional market) to subsidize the purchase of coal-fired power throughout the West. If Trump requires coal subsidies in regional markets, as he promised and started to do in 2018, California will be required to buy and use electricity made from coal. • Pathways creates the risk that the DE regional corpora;on will block the development or expanded use of distributed energy resources in CA. The DE RO could file tariff rules that hurt CA’s development of distributed clean power, and instead promote coal, nuclear and fossil resources. The regional operator could require CA help pay for transmission lines in other states in the regional market that support coal and nuclear power plants or are costly and unneeded. In January 2025, PacifiCorp reneged on its promise to shut down its Utah coal plants. California could be required to subsidize their coal power instead of developing its own clean power. • Pathways risks invalida;ng CA’s landmark Renewable PorHolio Standard (RPS) laws: Any market par_cipant or prospec_ve market par_cipant, such as a coal plant owner, can challenge California’s RPS, which sets targets for California’s clean energy goals, as a viola_on of the Interstate Commerce Law and invalidate the RPS law.

Changing our California-only electricity market to a mul_-state market makes us vulnerable to lawsuits claiming that our RPS law violates interstate commerce. Even if all the u_li_es or states joining the regional market operator agreed that California laws, as well as policies, would remain effec_ve, any company could s_ll sue California to invalidate the RPS.

The California Senate Judiciary Committee analysis of a similar proposal from 2018 sums up the problems: “This change in governance would place control over California’s energy market in the hands of a Western states RTO heavily dominated by coal interests (the largest coal-producing states in the U.S.) and under the direction of the Trump administration. California’s policies for transitioning to renewable energy—and initiatives to develop distributed or decentralized energy resources—would be subject to review and revision by a market authority that is not interested in either.”
Bottom line, Pathway makes California more vulnerable to the Trump FERC and provides the best opportunity for Trump to hold California over a barrel or hurt our economy and consumers.

Attachment Staff Report Item 13G
If California’s renewal portfolio standard is invalidated, this is a vote you will be remembered for. It should not be taken lightly. Many of the generation of legislators who voted for electricity deregulation regretted it and it haunted many. Consumer Watchdog is calling on every Senator who votes for the Pathways plan to take a pledge to resign from public office if the renewable portfolio standard is invalidated under a legal challenge made because of Pathways. Had those deregulation legislators had to make a similar vow, California would have avoided a huge disaster.

Many of the same forces that advocated California’s deregulation law are aligned to enact Pathways. The IBEW unions, after dire warning about sovereignty issues in 2023, are now on board. This follows a huge boon to IBEW electricians nationally to staff data center and new contracts for the union from PacifiCorp, a principal backer of the Western grid. NRDC, another principal backer of the deregulation law, has been a driving force for Pathways. Ralph Cavanagh, an NRDC attorney, was the chief booster of the Western power trading market. He famously said in 1997, “Can you trust Enron? On stewardship issues and public benefit issues…the answer is, yes.”
Western power trading and arbitraging comes with its own risks that California has rightly steered away from after its deregulation disaster. Trump poses the ultimate challenge.

The question remains to you: “Can you trust Trump’s FERC with our environmental laws?” If the answer is no, you need to vote against Pathways. If you vote for it, you should do it soberly with a pledge to resign from public office if our environmental laws are invalidated. You are making a bet on California’s green energy future.

The electricity deregulation law passed unanimously under the same conspiracy of silence and self-interest that Pathways seems to be greased with. Consumer Watchdog sponsored a ballot measure in 1998 to do away with the worst parts of the deregulation effort, paying the stranded assets that wound up on our electricity bills for 30 years. Prop 9 failed because of utility opposition, but we were right about the impact of deregulation. Markets that are unfettered will eat the consumer and our environmental laws too.

Consumer Watchdog asked to participate in the Senate Energy Committee information hearing on Pathways on March 12th, but was denied a seat on a panel, despite being one of the only dissenting voices to the utility/Big Energy establishment. The backers of SB 540 don’t want you to know its real motto: “More Power For AI, Hell With Climate Change.” The so-called “guardrails” in the SB 540 proposal are not safeguards. Even if CAISO remains the balancing authority, the Delaware corporation will hold all the cards and possess the authority to make the rules for both the markets and the transmission grid, solely subject to FERC’s jurisdiction. The idea that a statement of corporate governance saying that the DE RO will respect California’s right to set policies will be binding on the RO or prevent market participants who want to challenge California’s environmental laws is laughable. Giving CAISO the power to pull the trigger in 2027 is only delaying the inevitable — CAISO and its free market appointees Attachment Staff Report Item 13G
are big backers of Pathways. And no exit ramp exists if this experiment goes bad – the new Regional Operator – with the Trump FERC -- will decide whether California can leave the new unproven system, and how much it will cost California consumers to end the failed experiment.

Moreover, Pathways is not needed to get California more power from the West. California already buys and sells electricity through the West without ceding power to a regional operator.

Be warned: Pathways may be the most dangerous vote you will ever take in the state Capitol.

Sincerely,
Jamie Court
President, Consumer Watchdog
(310) 874-9989
Attachment Staff Report Item 13G
January 24, 2025

PREPARED BY PREPARED FOR
John Tsoukalis
Kai Van Horn
Johannes Pfeifenberger
Evan Bennett
Alison Savage Brooks

IMPACT OF MARKET FOOTPRINTS ON CALIFORNIA CUSTOMERS
Preliminary Day-Ahead
Market Impacts Study
Attachment Staff Report Item 13H
brattle.com | 1
The benefits of EDAM
will depend on the size
and diversity of
members that join. A
larger and more
diverse EDAM
footprint will deliver
more benefits to
customers in
California.
 Regional markets deliver cost savings to customers due to efficiency gains, environmental benefits through lower emissions, and reliability benefits by making it easier to manage the grid during extreme weather events.
 This study calculates the benefits to CA customers if additional utilities across the western U.S. participate in EDAM.
 We study 2032 as a proxy for the first decade of market operations – We use resource assumptions from utility IRPs and the CAISO’s TPP – We build off the modeling efforts conducted for over a dozen utilities in the last two years
Overview of the Study and Drivers of Benefits
Attachment Staff Report Item 13H
brattle.com | 2
Market Dynamics and Expected Outcomes
• Lower emissions due to avoided curtailed energy displacing fossil generation.

Environmental Benefit
• Lower power costs for customers due to zero variable cost energy displacing higher variable cost energy. Customer Cost Savings
• Better investment environment for renewable projects. Customer Cost Savings Reduced Curtailment of
Wind and Solar due to
Increased Resource and
Load Diversity
• Reduced bilateral trading as markets trades become more profitable, lost bilateral trading margins. Customer Cost Increase
• Increased market congestion and transfer revenues. Customer Cost Savings Increased Trading
between Market
Members
• Shift from less efficient to more efficient resources, leading to production cost savings for customers. Customer Cost Savings
• Emissions potentially decline due to shift to more efficient generation.

Potential Environmental Benefit
• Better management of extreme weather events and unexpected grid challenges (e.g., outages). Reliability Benefit
• Reduced sale of short-term transmission service, as transmission is “donated” to the market (offset by EDAM TRR Settlement). Customer Cost Increase Larger and More
Diverse Pool
Transmission and
Generation Resources
Attachment Staff Report Item 13H
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
brattle.com | 3
To test the impacts for California DA market participation benefits of several potential DA market outcomes, we simulated four market footprints
Simulated Market Footprints
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline Case
(Approved EDAM Commitments)
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Expanded EDAM Case
(Maximum EDAM Potential)
Split Market Case
(Likely EDAM Entities w/ Markets+)
WEIS
SPP RTO West (co-optimizes w/ M+)
EDAM (also in WEIM)
Markets+ (DA & RT)
WEIM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline+ Case
(Likely EDAM Commitments)
Attachment Staff Report Item 13H
brattle.com | 4
CA Customer Benefits Increase with the Size of the EDAM Footprint AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline Case
(Approved EDAM Commitments)
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Expanded EDAM Case
(Maximum EDAM Potential)
WEIS
SPP RTO West
EDAM (also in WEIM)
WEIM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline+ Case
(Likely EDAM Commitments)
 These benefits are
incremental to the
benefits of the
formation of EDAM
with the Baseline
footprint of
committed entities
 Intermediate EDAM
footprints likely to
produce benefits
between the
Baseline+ and
Expanded EDAM
“bookend”
CA Total System Cost
($million per year) $4,511 $4,399 $3,721
Δ to Baseline $112 $790
Δ to Baseline+ $678
Expansion of EDAM footprint could produce over $500 million/year in market benefits to CA customers Attachment Staff Report Item 13H
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
brattle.com | 5
California Benefits from a Two Market Outcome
Split Market Case
(Likely EDAM Entities w/ Markets+)
(Assumes Relatively Efficient Seams)
WEIS
SPP RTO West
EDAM (also in WEIM)
Markets+ (DA & RT)
WEIM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv.

CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper
Great Plains
WAPA
CO/MO
WAPA
Lower CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Baseline+ Case
(Likely EDAM Commitments)
Two offsetting effects lead to a small gain for CA
customers in the Split Market case:
 CA customers experience a loss from utilities leaving the WEIM (~40% of load in WEIM today).
 CA customers benefit from increased access to low-cost resources in the M+ footprint due to elimination of seams in the WECC and increased DA trading at the market seam.

Several assumptions drive this result:
 A relatively efficient seam between M+ and EDAM (lower trading costs than bilateral trading in the Baseline cases).  Hourly modeled real-time trading at the seam fails to capture full loss from utilities leaving WEIM, which
optimizes on a sub-hourly level.
 M+ co-optimizes with RTO West, giving low-cost thermal resources in that region hurdle-free access major CA
import locations (e.g., Malin, PV).
 The Split Market case assumes ~60% of load in the WEIM today joins EDAM; assuming more of the WEIM leaves
would increase the loss to CA customers.

CA Total System
Cost ($million per year) $4,399 $4,217
Δ to Baseline+ $182
CA Benefits ~$500 million/year higher in the
Expanded EDAM Case (see previous slide)
Attachment Staff Report Item 13H
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The expansion of EDAM reduces gas generation and the curtailment of wind and solar in California, resulting in lower GHG emissions in the state.  …
GHG Emissions Impacts
-4,000
-3,000
-2,000
-1,000
0 1,000
2,000
Expanded EDAM Split Market
Wind
Solar
Other
Nuclear
Hydro
Geothermal
Gas-ST
Gas-CT
Gas-CC
Coal
GWh
California-Wide Generation
(Relative to Baseline+)
CA gas
generation
falls 31%
with an
expanded
EDAM
0 2,000
4,000
6,000
8,000
10,000
12,000
Baseline Baseline+ Expanded
EDAM
Split Market
GWh
Total California Curtailments by Case
Wind and solar
curtailments fall 10%
with an expanded EDAM
Change in CO2 Emissions
CA CO2
emissions fall

11.2% with an
expanded EDAM
CA CO2
emissions fall

3.5% in the Split
Market Case
Expanded
EDAM
Split
Market
WECC CO2
emissions rise

1.3% with an
expanded EDAM
WECC CO2
emissions fall

2.1% in the Split
Market Case
Attachment Staff Report Item 13H
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 It includes generators that are online and below maximum output  It excludes resources that are on planned or forced outage  Storage resources are further limited by their stored energy  We conservatively assume that hydro, wind, and solar provide no incremental supply cushion.

Market Supply Cushion Overview
Online
generator
Supply Cushion
Example
Available
supply cushion
Generator
energy dispatch
Pmax
Attachment Staff Report Item 13H
0 5,000
10,000
15,000
20,000
25,000
30,000
35,000
12:00
AM
2:00
AM
4:00
AM
6:00
AM
8:00
AM
10:00
AM
12:00
PM
2:00
PM
4:00
PM
6:00
PM
8:00
PM
10:00
PM
Coal Gas-CC Gas-CT Gas-Other Storage
brattle.com | 8
 The supply cushion is ~25,000 MW more in the
Extended EDAM case than the Split Market case.
 Higher supply cushion in midday hours when
storage is charging.
– The Expanded EDAM case has more storage in the
EDAM compared to the Split Market case, as well as a
higher average state-of-charge due to increased
renewables diversity in the larger footprint.

Expanding the EDAM footprint Increases Supply Cushion
Expanded EDAM Case minus Split Market Case
Day-Ahead Market Supply Cushion
Average by Hour of Day and Capacity Type
MW
Added Supply Cushion Due
to Expanded EDAM
Focusing on the 10 tightest hours of the year, the
supply cushion in the EDAM is 20,000 MW larger
in the Expanded EDAM case than in the Split
Market case (27.8% of load vs. 24% of load)
Attachment Staff Report Item 13H
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 Overstated Bilateral Market Efficiency: our simulation of bilateral markets is more efficient than reality – Hourly model fails to captures the benefit of real-time markets to economically and reliability manage energy imbalances through sub-hourly re-dispatch and energy exchange across market members. – The model assumes all balancing authorities have optimal security-constrained unit-commitment and dispatch (SCUC and SCED) in both DA and RT, making the simulated dispatch more optimal than reality. – Inefficient utilization of transmission by bilateral trades is not fully modeled, understating the extent M+ and EDAM will be able to make better use of all physically and contractually available transmission. – Transmission outages are not modeled, which would magnify the benefit of SCED-based congestion management in EDAM and M+ compared to the bilateral markets.
 Normalized loads and fuel prices: the model uses weather-normalized loads and averaged monthly natural gas prices without daily volatility
– Challenging market conditions (beyond the included heat wave and cold snap), such during as the 2022 gas price spikes or 2024 MLK Day cold snap, will magnify benefits from a regional market. Illustrated by the WEIM experience of much higher benefits during those events.
– The Base Case does not reflect the limited liquidity of bilateral market during challenging market conditions Estimated Benefits are Conservatively Low
Attachment Staff Report Item 13H
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The four cases simulated provide significant insight on the impact of market expansion for CA and raise questions for future analyses to address. – Simulate a “Status Quo” case without any EDAM footprint, which would allow us to calculate the benefit of EDAM forming relative to just the WEIM.
– The Expanded EDAM and Split Market cases represent two approximate bookends, we could test intermediate footprints with different combinations of utilities joining EDAM or Markets+. – The level of coordination that will be achieved between the two markets is unknown. Future sensitivities could explore the impact to CA customers of different forms coordination and co-optimization across market seams. – Sub-hourly modeling could be used to calculate the benefit of 15-minute and 5-minute optimization conducted by the WEIM for CA customers and WEIM/EDAM members.
– Weather-relative load, thermal resource outages, and renewable production; daily gas price volatility Brainstorming Possible Further Analysis
Attachment Staff Report Item 13H
Appendix A:

Modeling Assumptions and
Detailed Results
Attachment Staff Report Item 13H
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 Long-term transmission rights, contracted resources (and transmission encumbrances), generation additions, transmission additions, renewable diversity and forecast errors, and market design detail/implementation  Study participants have helped refine our model by performing full reviews of relevant modeling assumptions for their systems, including transmission rights & costs, load forecasts, fuel prices, generation mix & costs, etc. – Study participants include the Balancing Authority of Northern California, El Paso Electric, Idaho Power, LA Department of Power and Water, NV Energy, Portland General Electric, PacifiCorp, Public Service Company of New Mexico, Sacramento Municipal Utility District, and other utilities, transmission owners and independent power producers – Several of these reviewers were able to provide details relevant to the CA system, including input from CAISO and others Timeline of the Brattle Team’s Western Markets Studies
Pre-2022 Studies 2022 EDAM Study 2023-24 EDAM-M+ Studies 2022 EDAM Benefits Study
We produced an updated
assessment of EDAM benefits for
five study participants, building on
the work done for the 2019 EDAM
feasibility study:
• BANC, Idaho Power, LADWP,
PacifiCorp, SMUD
Comparative EDAM-M+ Studies
We further refined our 2022 EDAM
benefits study model with input
from study participants and the
Markets+ design documents to
conduct benefits studies for several
additional utilities , including:
• Portland General Electric, NV
Energy, Public Service New Mexico,
El Paso Electric, and others
Western Market Studies
• EDAM Feasibility Study
• SPP RTO Expansion Study
• CAISO EIM GHG Structure Study
• Xcel Colorado WEIS/WEIM Study
• WEIS and SPP Integration Study
• Mountain West RTO Study
• CA SB350 Study
1 2 3
CEC Pathways Study
We leveraged our work and
modeling enhancements from all
prior studies to assess the value of a
nearly-WECC-wide day-ahead
market (i.e., an EDAM with a large
footprint) compared to an outcome
with two competing day-ahead
markets in the WECC (i.e., split
between EDAM and Markets+).
4 This Study
Attachment Staff Report Item 13H
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Multi-Functional Simulation of WECC
 Physical grid with ~20k buses, ~25k lines and
~5k generators represented as DC power flow
 38 Balancing Authority Areas (BAAs) and
contract paths
 WECC reserve sharing groups
 Diverse state clean energy policies
 Major trading hubs (e.g., Mid-C, Malin, PV, FC)
 Bilateral (long-term) transmission rights
 Renewable diversity, day-ahead forecast
uncertainty, real-time operations
 CAISO, SPP RTO West, Markets+, EDAM, WEIM,
& WEIS footprints
Markets/RTO
Functions &
Configurations
Reserve
Sharing
Clean Energy
Policies
BAA
Functions
Bilateral
Contract
Paths and
Transmission
Rights
Physical
Flows and
Constraints
We employ multi-layer simulations to
represent the various physical, policy, and
operational facets of the WECC
Attachment Staff Report Item 13H
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 Model developed in PSO/Enelytix, which contains state-of-the-art features – Simultaneously optimizes contract path and physical constraints – Models bilateral, day-ahead, and real-time markets (including uncertainty) sequentially through multiple solution cycles – Co-optimizes storage resources with other resources in unit-commitment and dispatch – Detailed ancillary service and operating reserve modeling (including reserve sharing) and co-optimization of ancillary services with energy  The study year is 2032, which aims to reflect the first decade of markets operations, representing an intermediate year that captures known changes in resource mix and transmission infrastructure  Model includes two extreme weather events based on a historic cold snap and a historic heat wave – These events are modeled as single weeks in which we increase modeled loads (peak and energy) and gas prices, including gas price volatility beyond typical weather-normalized values to reflect the increased strain on the system and the ability of markets for addressing such strain – Capturing non-weather-normal impacts is becoming increasingly important due to the increasing frequency of severe weather events  Detailed modeling of EDAM and Markets+ specific GHG rules which helps capture transfers into GHG pricing states – This includes the limits each market will place on sales to balancing authorities that price GHG emissions and the unit-type GHG cost representations instead of generic GHG charges
– We also model BPA’s status as an asset-controlling supplier for CA and WA, reflecting their lower cost to sell power into those zones Key Model Features
Attachment Staff Report Item 13H
brattle.com | 15
California-Wide Day-Ahead Market Expansion Benefits
Summary of California-Wide System Costs & Revenues by Case ($ Million per year)
Note: Bilateral trading revenues refers to short-term bilateral trading of energy.  Under our Expanded EDAM scenario, California benefits from the wider market footprint to expand trading and
reduce internal generation, resulting in $678 million lower net total system costs compared to the Baseline+ case:
– Adjusted production cost savings of $366 million from 3,200 GWh of reduced gas generation, lower purchase costs, and increased sales prices – Total trading and congestion revenues increase $182 million – Short-term wheeling revenues decline of $82 million as almost all of California’s trading partners join EDAM
 Under our Split Market scenario, California similarly reduces internal generation and increases trading, but to a lesser extent, resulting in $182 million in lower net total system costs compared to the Baseline+ case:
– Adjusted production cost savings of $200 million from 1,200 GWh of reduced gas generation and slightly increased average sales prices – Relatively static trading gains and congestion revenues as trading modestly shifts between bilateral and EDAM trading.
– Short-term wheeling revenues decline $23 million as some bilateral trading dries up with the creation of Markets+
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $5,172 $4,952 $4,585 $4,752
Production Cost $1,744 $1,440 $1,258 $1,370
Purchases Cost $3,674 $3,907 $3,968 $3,805
Sales Revenue (subtracted from costs) $246 $395 $640 $423 Short-Term Wheeling Revenues $227 $108 $25 $84
Bilateral Trading Revenues $199 $157 $23 $106
WEIM Congestion Revenues $66 $73 $55 $42
EDAM Congestion and Transfer Revenues $170 $204 $538 $292 EDAM Transfer Revenue $85 $105 $255 $112
EDAM Congestion Revenue $84 $99 $283 $179
Net TRR Settlement $0 $6 $112 $6
Total System Production Cost and Market Revenues $4,511 $4,399 $3,721 $4,217 Benefit Relative to Baseline $112 $790 $294
Benefit % of Baseline Production Cost and Market Revenues 2% 18% 7% Benefit Relative to Baseline+ $678 $182
Benefit % of Baseline+ Production Cost and Market Revenues 15% 4% Attachment Staff Report Item 13H
Metric
Adjusted Production
Cost (APC)
We anticipate the large majority of APC benefits would flow to customers. The timing will depend on provision in the PPAs:
• Flow through provisions in PPAs would see benefits passed through to customers. • Over the longer-term this could happen through the renegotiation of PPAs. • Reduced curtailments will impact future renewable PPAs. • Our study does not estimate any feedback effects this may have on RA prices.

Short-term wheeling
revenue
Most of the impact flows through to customers, since changes in these revenues will impact transmission access charges.

Market congestion
revenues
A large share of benefit flow to customers:
• EDAM Transfer Revenues are allocated to measured demand, which is mostly load. • EDAM Congestion Revenues are placed in the CRR Balancing Account. We have not analyzed the portion that will flow to customers, which will depend on the efficiency of CRR auctions in returning revenues to load-serving entities.

Bilateral trading
revenues
Customers would benefit from revenues on trades executed by load-serving entities, but potentially not from those executed by third-parties or generators.

Emissions Emissions reductions generally benefit all CA residents, but there may be distributional impacts depending on the geography of emitting generation changes.

Supply cushion Reliability benefits flows to customers and CA residents. brattle.com | 16
Interpretation of Benefits in CAISO
Attachment Staff Report Item 13H
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 344,267 342,584 -1,683 $4.18 $3.67 -$0.51 1,439,851 1,257,800 -$182,051 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 66,003 69,998 3,995 $53.81 $52.15 -$1.66 3,551,652 3,650,703 $99,051 Real-Time Market [5] 9,085 8,472 -613 $39.08 $37.43 -$1.65 355,030 317,101 -$37,928 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 80,650 83,113 2,463 $2.26 $4.82 $2.56 182,145 400,738 $218,593 Real-Time Market [8] 9,867 9,104 -763 $21.57 $26.33 $4.76 212,791 239,689 $26,898 Total Cost (Negative Difference = Benefit) [9] 328,837 328,837 0 $15.06 $13.94 -$1.11 4,951,597 4,585,177 -$366,419 % Change in APC -7.4%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost. brattle.com | 17
 (1) $182 million/yr reduction in production costs as California generation declines on the net by ~1,700 GWh (~3,200 GWh lower gas generation offset by ~1,500 GWh more renewables and other generation)  (2) $61 million/yr increase in purchase costs as California purchases about 4,000 GWh more in the day-ahead to substitute for lower internal gas generation, offset by lower real-time purchases  (3) $245 million/yr increase in sales revenue as California sells about 2,500 GWh more in the day-ahead and does so at an average price about $2.5/MWh higher than in Baseline+ California Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
California-Wide Adjusted Production Cost
Attachment Staff Report Item 13H
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 344,267 342,887 -1,379 $4.18 $4.00 -$0.19 1,439,851 1,370,114 -$69,737 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 66,003 67,264 1,261 $53.81 $52.02 -$1.79 3,551,652 3,499,355 -$52,297 Real-Time Market [5] 9,085 7,984 -1,100 $39.08 $38.29 -$0.79 355,030 305,747 -$49,283 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 80,650 80,751 100 $2.26 $2.67 $0.41 182,145 215,481 $33,336 Real-Time Market [8] 9,867 8,549 -1,319 $21.57 $24.29 $2.72 212,791 207,646 -$5,145 Total Cost (Negative Difference = Benefit) [9] 328,837 328,837 0 $15.06 $14.45 -$0.61 4,951,597 4,752,089 -$199,507 % Change in APC -4.0%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost. brattle.com | 18
 (1) $70 million/yr reduction in production cost as California gas generation falls ~1,200 GWh (non-gas generation falls also, with renewable curtailments increasing ~200 GWh)  (2) $100 million/yr reduction in purchase costs despite modestly higher overall purchase volumes due to lower purchase prices in day ahead and lower real-time purchases and prices  (3) $28 million/yr in increased sales revenue due to higher day-ahead sales prices and higher real-time sales prices offsetting lower real-time volumes, drive in part by the breakup of the WEIM California Adjusted Production Cost in the Split Market Case (1)
(2)
(3)
California Adjusted Production Cost
Attachment Staff Report Item 13H
brattle.com | 19
Gas Generation in California
MMT CO2
Pastoria
La Paloma
Walnut Creek
Sunrise
Tracy
Select Plant-Specific CO2 Emissions by Case
In the Expanded EDAM case, gas generation
in California declines by 31% relative to the
Baseline+ Case.
 Emissions from some of the larger gas plants in
California fall across the board, but dramatically
more in the Expanded EDAM case.
 The decline in gas generation in the Expanded
EDAM case is broadly consistent across all areas of
California.

Attachment Staff Report Item 13H
0 20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
Baseline Baseline+ Expanded
EDAM
Split Market
GWh
brattle.com | 20
 Total trade volumes increase 26 GWh (21%) for California from Baseline+ to the Expanded EDAM case
 Market transactions (EDAM + WEIM) make up 81% of all California trading in Baseline+ and 99% in the Expanded EDAM case
– Remaining bilateral transactions are with CFE in Mexico – Baseline market transactions are 65% of California trades – Split market case market transactions are 79% of California trade, as some seam trading returns with the PNW and Desert SW
 From Baseline+ to the Expanded EDAM case, California is mainly increasing trading with the Desert Southwest and Pacific Northwest California Trading Volume by Case
Total California Trading
by Trade Type
EDAM
WEIM
Block
Short-Term Bilateral
Note: Trade totals only include short-term and market trading. Long-term resource contracts are not included in these totals. Short-term bilateral trades include EDAM-Markets+ seam trades.

Attachment Staff Report Item 13H
0 50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
Baseline Baseline+ Expanded
EDAM
Split Market
GWh
brattle.com | 21
 Markets+ transactions between the Southwest and PNW require trading across several entities compared to more direct connections in a WECC-wide market like the Expanded EDAM case – For example, a trade from AZPS to BPAT in the Markets+ footprint requires power transacting several times across the M+ and RTO West entities in the Rocky Mountains
– In the Expanded EDAM case, AZPS could trade more directly via Nevada or California into the PNW
 Market transactions (EDAM or Markets+) are the highest share of trades in the Expanded EDAM case (93% of all WECC trading vs. 77% in the Split Market case)
– Remaining hourly and block trades between the markets (i.e., seam transactions) account for the majority of non-market trades
WECC-Wide Trading Volume by Case
Total WECC-Wide Trading
by Trade Type
EDAM
WEIM
Block
Short-Term Bilateral
Markets+ RT
Markets+ DA
Note: Trade totals only include short-term and market trading. Long-term resource contracts are not included in these totals. Short-term bilateral trades include EDAM-Markets+ seam trades.

Attachment Staff Report Item 13H
brattle.com | 22
 Hydro entities in the Pacific Northwest export 7 TWh
more to California, mostly in the morning and
evening
 California exports 20 TWh more to the Desert
Southwest and imports 15 TWh more, exchanging
renewables and efficient gas
 Trading with existing EDAM entities in the center of
the WECC declines about 10 TWh
– Idaho Power, NV Energy, and PacifiCorp increase direct trades with entities in the Pacific Northwest, Rocky Mountains, and Desert Southwest at the same time trades decease with
California
California Trading Changes: Baseline+ to Expanded EDAM
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy
Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains

WAPA CO/MO
WAPA Lower
CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Expanded EDAM Case
(Maximum EDAM Potential)
+35 TWh
with DSW
+8 TWh
with PNW
-10 TWh
with Existing
EDAM
Baseline+
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains

WAPA CO/MO
WAPA Lower
CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Attachment Staff Report Item 13H
brattle.com | 23
 Hydro entities in the Pacific Northwest export about
the same to California, but California exports about 1.5 TWh less to the PNW
 California exports 6 TWh less to the Desert Southwest and imports 7 TWh less, reducing trading in both
directions
 Trading with existing EDAM entities in the center of
the WECC increases about 5 TWh
 Trading between EDAM entities within California also
increases about 3 TWh
California Trading Changes: Baseline+ to Split Market
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy
Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains

WAPA CO/MO
WAPA Lower
CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Split Market Case
(Likely EDAM Entities w/ Markets+)
-13 TWh
with DSW
-1 TWh
with PNW
+5 TWh
with Existing
EDAM
Baseline+
AZPS
SRP
PNM
BCHA/
Powerex AESO
BPA
PSEI
TPWR
NV Energy Public Serv. CO
EPE
NWMT
PacifiCorp West Idaho Power
CHPD
WAPA Upper Great
Plains

WAPA CO/MO
WAPA Lower
CO

CFE TEPC
PacifiCorp East
SCL
AVA
PGE
GCPD
DOPD
Attachment Staff Report Item 13H
Appendix B:

Individual BAA Benefits
Attachment Staff Report Item 13H
brattle.com | 25
 CAISO sees an APC benefits in both cases, though about $136 million more in EDAM
 Short-term wheeling revenues fall more in the
Expanded EDAM case, declining $22 million from
Baseline+ to Split Market compared to the EDAM decline
of $60 million
 Total trading revenues increase $134 million in the
EDAM case compared to just $3 million in the Split
Market case
Individual BA Benefits: CAISO
Summary of CAISO System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $4,642 $4,441 $4,115 $4,250
Short-Term Wheeling Revenues $171 $85 $25 $63
Trading Revenues
Bilateral Trading Revenues $111 $88 $23 $61
WEIM Congestion Revenues $47 $55 $41 $31
EDAM Congestion and Transfer Revenues $146 $185 $398 $238 EDAM Transfer Revenue $113 $112 $228 $123
EDAM Congestion Revenue $33 $72 $170 $115
Net TRR Settlement $9 $80 $9
Total System Production Cost and Market Revenues $4,167 $4,019 $3,548 $3,848 Benefit Relative to Baseline $148 $619 $319
Benefit % of Baseline Production Cost and Market Revenues 4% 15% 8% Benefit Relative to Baseline+ $471 $171
Benefit % of Baseline+ Production Cost and Market Revenues 12% 4% Attachment Staff Report Item 13H
brattle.com | 26
 (1) $112 million/yr reduction in production costs as CAISO generation declines on the net by ~1000 GWh (~2,000 GWh lower gas generation offset by ~1,000 GWh more renewables and other generation)  (2) $40 million/yr increase in purchase costs as CAISO purchases about 2,900 GWh more in the day-ahead to offset declining gas generation  (3) $250 million/yr increase in sales revenue as CAISO sells about 2,400 GWh more in the day-ahead and does so at an average price about $3.0/MWh higher than in Baseline+ CAISO Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
CAISO Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 295,759 294,762 -996 $4.17 $3.81 -$0.37 1,234,372 1,121,700 -$112,672 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 53,447 56,344 2,897 $56.04 $54.23 -$1.81 2,995,068 3,055,363 $60,295 Real-Time Market [5] 6,488 6,488 0 $41.38 $38.27 -$3.11 268,462 248,274 -$20,188 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 73,205 75,653 2,448 -$0.60 $2.44 $3.03 -43,575 184,255 $227,830 Real-Time Market [8] 6,054 5,506 -547 $16.65 $22.93 $6.28 100,804 126,274 $25,470 Total Cost (Negative Difference = Benefit) [9] 276,435 276,435 0 $16.06 $14.89 -$1.18 4,440,673 4,114,808 -$325,865 % Change in APC -7.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 27
 (1) $55 million/yr decrease in production cost due to gas generation falling by ~930 GWh (non-gas generation also declines, with renewable curtailments increasing ~260 GWh)  (2) $67 million/yr decrease in purchase cost despite higher purchase volumes as the remaining EDAM market generation mix is renewable heavy
 (3) $58 million/yr increase in sales revenue as volumes and average sales prices increase slightly due to opportunities to sell into EDAM and Markets+
CAISO Adjusted Production Cost in the Split Market Case (1)
(2)
(3)
CAISO Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 295,759 294,501 -1,258 $4.17 $4.01 -$0.17 1,234,372 1,179,767 -$54,605 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 53,447 54,741 1,294 $56.04 $53.94 -$2.09 2,995,068 2,952,969 -$42,099 Real-Time Market [5] 6,488 6,181 -307 $41.38 $39.34 -$2.04 268,462 243,149 -$25,312 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 73,205 73,593 388 -$0.60 $0.20 $0.79 -43,575 14,409 $57,984 Real-Time Market [8] 6,054 5,395 -659 $16.65 $20.59 $3.94 100,804 111,097 $10,293 Total Cost (Negative Difference = Benefit) [9] 276,435 276,435 0 $16.06 $15.38 -$0.69 4,440,673 4,250,380 -$190,292 % Change in APC -4.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 28
 LDWP sees an APC benefits in both cases, $38 million
in EDAM and $18 million in the Split Market case
 Short-term wheeling revenues decline most in the
Expanded EDAM case, falling $13 million
 Total trading revenues increase $24 million in the
Expanded EDAM case compared to just $6 million in
the Split Market case
Individual BA Benefits: LDWP
Summary of LDWP System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $371 $354 $328 $336
Short-Term Wheeling Revenues $38 $13 $0 $6
Trading Revenues
Bilateral Trading Revenues $40 $39 $0 $17
WEIM Congestion Revenues $7 $9 $4 $5
EDAM Congestion and Transfer Revenues $17 $13 $81 $46
EDAM Transfer Revenue -$25 -$6 $17 -$8
EDAM Congestion Revenue $42 $19 $64 $54
Net TRR Settlement -$2 $26 -$2
Total System Production Cost and Market Revenues $269 $281 $216 $263 Benefit Relative to Baseline -$13 $53 $6
Benefit % of Baseline Production Cost and Market Revenues -5% 20% 2% Benefit Relative to Baseline+ $66 $18
Benefit % of Baseline+ Production Cost and Market Revenues 23% 6% Attachment Staff Report Item 13H
brattle.com | 29
 (1) $8.5 million/yr reduction in production costs as LDWP generation declines on the net by ~3 GWh (~120 GWh lower gas generation offset by ~117 GWh more renewables and other generation)  (2) $14 million/yr decrease in purchase costs due to reduced average cost of purchasing in the EDAM market by about $2/MWh
 (3) $3 million/yr increase in sales revenue as LDWP sells about 7 GWh more in the day-ahead and does so at an average price about $2.7/MWh higher than in Baseline+ LDWP Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
LDWP Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 21,157 21,154 -3 $1.29 $0.89 -$0.40 27,272 18,764 -$8,508 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 7,928 7,955 27 $46.43 $44.59 -$1.84 368,108 354,708 -$13,400 Real-Time Market [5] 431 412 -19 $27.01 $27.84 $0.83 11,642 11,466 -$176 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,067 1,074 7 -$7.72 -$5.01 $2.71 -8,237 -5,383 $2,854 Real-Time Market [8] 2,179 2,177 -2 $28.10 $28.72 $0.62 61,232 62,528 $1,296 Total Cost (Negative Difference = Benefit) [9] 26,270 26,270 0 $13.48 $12.48 -$1.00 354,027 327,793 -$26,235 % Change in APC -7.4%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 30
 (1) $0.3 million/yr decrease in production cost due to ~10 GWh of reduced gas generation (non-gas generation increases by ~40 GWh)
 (2) $14 million/yr reduction in purchase costs as the remaining EDAM market is very renewable heavy renewable heavy
 (3) $1 million/yr increase in sales revenue as volumes and average sales prices increase slightly due to opportunities to sell into EDAM and Markets+
LDWP Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
LDWP Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 21,157 21,204 47 $1.29 $1.27 -$0.02 27,272 27,004 -$269 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 7,928 7,952 24 $46.43 $44.53 -$1.91 368,108 354,077 -$14,031 Real-Time Market [5] 431 407 -24 $27.01 $27.97 $0.96 11,642 11,379 -$263 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,067 1,083 15 -$7.72 -$6.36 $1.36 -8,237 -6,886 $1,351 Real-Time Market [8] 2,179 2,210 32 $28.10 $28.56 $0.46 61,232 63,137 $1,905 Total Cost (Negative Difference = Benefit) [9] 26,270 26,270 0 $13.48 $12.80 -$0.68 354,027 336,209 -$17,819 % Change in APC -5.0%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 31
 BANC’s adjusted production cost remains about the
same in all three cases
 Short-term wheeling revenues decline $4 million in
EDAM
 Total trading revenues increase $10 million in the
Expanded EDAM case but decline $2 million in the Split
Market case
 BANC benefits and results are not inclusive of SMUD,
which is reported separately
Individual BA Benefits: BANC
Summary of BANC System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $56 $57 $56 $59
Short-Term Wheeling Revenues $5 $4 $0 $4
Trading Revenues
Bilateral Trading Revenues $15 $10 $0 $8
WEIM Congestion Revenues $2 $1 $0 $1
EDAM Congestion and Transfer Revenues $0 $1 $21 $1
EDAM Transfer Revenue -$6 -$5 -$6 -$5
EDAM Congestion Revenue $7 $6 $27 $6
Net TRR Settlement -$1 $3 -$1
Total System Production Cost and Market Revenues $34 $42 $31 $46 Benefit Relative to Baseline -$8 $2 -$12
Benefit % of Baseline Production Cost and Market Revenues -23% 7% -36% Benefit Relative to Baseline+ $10 -$4
Benefit % of Baseline+ Production Cost and Market Revenues 24% -11% Attachment Staff Report Item 13H
brattle.com | 32
 (1) $17 million/yr reduction in production costs as BANC generation declines on the net by ~260 GWh (~325 GWh lower gas generation offset by ~64 GWh more renewables and other generation)  (2) $5 million/yr increase in purchase costs as BANC purchases about 140 GWh more in the day-ahead to offset declining gas generation and make additional market sales  (3) $11 million/yr decrease in sales revenue due to ~$5/MWh decrease in day ahead market prices received
BANC Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
BANC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 6,206 5,944 -262 $12.63 $10.28 -$2.35 78,379 61,077 -$17,302 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 689 834 144 $44.22 $46.49 $2.27 30,483 38,755 $8,271 Real-Time Market [5] 303 247 -56 $42.32 $37.52 -$4.80 12,824 9,270 -$3,554 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,201 927 -274 $46.64 $41.74 -$4.90 56,015 38,684 -$17,331 Real-Time Market [8] 193 293 100 $42.69 $50.17 $7.48 8,224 14,704 $6,479 Total Cost (Negative Difference = Benefit) [9] 5,804 5,804 0 $9.90 $9.60 -$0.30 57,447 55,713 -$1,733 % Change in APC -3.0%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 33
 (1) $11 million/yr reduction in production cost due to ~200 GWh decreased gas generation(non-gas generation falls also, with renewable curtailments increasing ~14 GWh), but does not offset revenue loss  (2) $3 million/yr increase in purchase costs despite falling real time prices because of increased day ahead purchases
 (3) $10 million/yr decrease in sales revenue as day-ahead sales volumes decrease and real-time volumes only increase by ~12 GWh
BANC Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
BANC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 6,206 5,994 -212 $12.63 $11.24 -$1.39 78,379 67,376 -$11,002 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 689 776 86 $44.22 $44.47 $0.25 30,483 34,497 $4,014 Real-Time Market [5] 303 288 -15 $42.32 $39.35 -$2.96 12,824 11,352 -$1,471 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 1,201 1,049 -152 $46.64 $42.57 -$4.07 56,015 44,653 -$11,361 Real-Time Market [8] 193 204 12 $42.69 $46.60 $3.91 8,224 9,530 $1,306 Total Cost (Negative Difference = Benefit) [9] 5,804 5,804 0 $9.90 $10.17 $0.28 57,447 59,043 $1,596 % Change in APC 2.8%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 34
 SMUD adjusted production cost remains about the
same in all three cases, but declines slightly more in
the Split Market case
 Total trading revenues decline $6 million in the
Expanded EDAM case but increase $1 million in the
Split Market case due to increased internal California
trading
Individual BA Benefits: SMUD
Summary of SMUD System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $74 $73 $72 $70
Short-Term Wheeling Revenues $0 $0 $0 $0
Trading Revenues
Bilateral Trading Revenues $16 $15 $0 $15
WEIM Congestion Revenues $4 $4 $4 $4
EDAM Congestion and Transfer Revenues $6 $6 $15 $7
EDAM Transfer Revenue $3 $4 $11 $3
EDAM Congestion Revenue $3 $2 $5 $4
Net TRR Settlement -$1 -$6 -$1
Total System Production Cost and Market Revenues $48 $49 $58 $45 Benefit Relative to Baseline -$1 -$11 $2
Benefit % of Baseline Production Cost and Market Revenues -3% -22% 5% Benefit Relative to Baseline+ -$9 $4
Benefit % of Baseline+ Production Cost and Market Revenues -18% 8% Attachment Staff Report Item 13H
brattle.com | 35
 (1) $0.1 million/yr increase in production costs as SMUD generation increases by ~100 GWh, mostly from renewables and geothermal
 (2) $3 million/yr increase in purchase costs as SMUD purchases about 60 GWh more in the day-ahead  (3) $4 million/yr increase in sales revenue as SMUD sells about 200 GWh more in the day-ahead and does so at an average price about $0.1/MWh higher than in Baseline+ SMUD Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
SMUD Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 12,180 12,289 109 $0.82 $0.83 $0.00 10,044 10,179 $135 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 2,022 2,081 59 $50.40 $51.49 $1.10 101,888 107,144 $5,256 Real-Time Market [5] 861 802 -59 $41.24 $41.52 $0.28 35,520 33,317 -$2,203 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 2,101 2,283 182 $25.26 $25.38 $0.12 53,069 57,934 $4,866 Real-Time Market [8] 707 634 -73 $30.67 $33.22 $2.55 21,679 21,053 -$626 Total Cost (Negative Difference = Benefit) [9] 12,255 12,255 0 $5.93 $5.85 -$0.09 72,704 71,652 -$1,052 % Change in APC -1.4%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 36
 (1) $13 million/yr increase in production cost due to a reduction of ~6 GWh of generation  (2) $4 million/yr decrease in purchases cost because of slight reductions in price and volume in the day-ahead and real-time markets
 (3) $2 million/yr reduction in sales revenues due to a $1.3/MWh drop in day-ahead prices and ~50 GWh fewer sales in the real-time market
SMUD Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
SMUD Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 12,180 12,174 -6 $0.82 $0.83 $0.00 10,044 10,056 $13 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 2,022 2,015 -7 $50.40 $49.16 -$1.24 101,888 99,068 -$2,820 Real-Time Market [5] 861 855 -6 $41.24 $39.91 -$1.33 35,520 34,121 -$1,399 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 2,101 2,128 28 $25.26 $23.98 -$1.28 53,069 51,040 -$2,029 Real-Time Market [8] 707 660 -47 $30.67 $33.15 $2.48 21,679 21,875 $195 Total Cost (Negative Difference = Benefit) [9] 12,255 12,255 0 $5.93 $5.74 -$0.19 72,704 70,330 -$2,373 % Change in APC -3.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 37
 IID’s adjusted production cost doesn’t change in the
Expanded EDAM case, but increases $9 million in the
Split Market case
 Short-term wheeling revenues decline $6 million in
EDAM and increase $6 million in the Split Market case
 Total trading revenues increase $13 million in the
Expanded EDAM case but decline $3 million in the Split
Market case
Individual BA Benefits: IID
Summary of IID System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost -$83 -$85 -$85 -$74
Short-Term Wheeling Revenues $13 $5 $0 $11
Trading Revenues
Bilateral Trading Revenues $15 $4 $0 $4
WEIM Congestion Revenues $6 $3 $5 $0
EDAM Congestion and Transfer Revenues $0 $0 $15 $0
EDAM Transfer Revenue $0 $0 $6 $0
EDAM Congestion Revenue $0 $0 $9 $0
Net TRR Settlement $11
Total System Production Cost and Market Revenues -$116 -$97 -$115 -$89 Benefit Relative to Baseline -$19 -$1 -$27
Benefit % of Baseline Production Cost and Market Revenues 16% -1% -23% Benefit Relative to Baseline+ $18 -$9
Benefit % of Baseline+ Production Cost and Market Revenues 18% -9% Attachment Staff Report Item 13H
brattle.com | 38
 (1) $0.2 million/yr reduction in production costs as IID generation increases by ~45 GWh, all from renewable and other non-gas generation
 (2) $5 million/yr decrease in purchase costs as IID purchases about 100 GWh more in the day-ahead and reduces sales in the real time market
 (3) $5 million/yr decrease in sales revenue as BANC reduces sales volume by ~240 GWh in the real time market despite increased prices
IID Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
IID Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 7,301 7,346 45 $5.81 $5.79 -$0.01 42,401 42,551 $150 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 478 635 157 -$3.09 -$2.87 $0.22 -1,477 -1,823 -$345 Real-Time Market [5] 858 520 -338 $21.90 $28.14 $6.24 18,778 14,631 -$4,147 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 3,068 3,176 108 $40.50 $39.44 -$1.07 124,249 125,245 $997 Real-Time Market [8] 733 489 -244 $28.17 $29.96 $1.79 20,645 14,640 -$6,005 Total Cost (Negative Difference = Benefit) [9] 4,837 4,837 0 -$17.61 -$17.48 $0.14 -85,191 -84,525 $666 % Change in APC -0.8%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
brattle.com | 39
 (1) $0.3 million/yr increase in production cost due to limited shifts in production and prices  (2) $20 million/yr decrease in purchases cost as the remaining EDAM market is very renewable heavy, resulting in a $12/MWh decrease in day-ahead prices
 (3) $31 million/yr decrease in sales revenue as IID reduces sales by ~840 GWh across day-ahead and real-time markets
IID Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
IID Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 7,301 7,399 98 $5.81 $5.77 -$0.04 42,401 42,674 $273 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 478 247 -231 -$3.09 -$14.68 -$11.59 -1,477 -3,623 -$2,146 Real-Time Market [5] 858 155 -703 $21.90 $2.70 -$19.20 18,778 418 -$18,361 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 3,068 2,893 -175 $40.50 $38.70 -$1.80 124,249 111,976 -$12,273 Real-Time Market [8] 733 71 -662 $28.17 $19.58 -$8.59 20,645 1,385 -$19,260 Total Cost (Negative Difference = Benefit) [9] 4,837 4,837 0 -$17.61 -$15.28 $2.34 -85,191 -73,892 $11,299 % Change in APC -13.3%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
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 TIDC’s adjusted production cost declines $12
million in the Expanded EDAM case but just $2
million in the Split Market case
 Total trading revenues increase $6 million in the
Expanded EDAM case and don’t change in the
Split Market case
Individual BA Benefits: TIDC
Summary of TIDC System
Costs by Case ($ Millions)
Baseline Baseline+ Expanded EDAM Split Market
Adjusted Production Cost $112 $112 $100 $110
Short-Term Wheeling Revenues $0 $0 $0 $0
Trading Revenues
Bilateral Trading Revenues $1 $1 $0 $1
WEIM Congestion Revenues $1 $0 $0 $0
EDAM Congestion and Transfer Revenues $0 $0 $7 $0
EDAM Transfer Revenue $0 $0 -$2 $0
EDAM Congestion Revenue $0 $0 $8 $0
Net TRR Settlement -$2
Total System Production Cost and Market Revenues $110 $111 $95 $109 Benefit Relative to Baseline -$2 $15 $1
Benefit % of Baseline Production Cost and Market Revenues -1% 14% 1% Benefit Relative to Baseline+ $17 $2
Benefit % of Baseline+ Production Cost and Market Revenues 15% 2% Attachment Staff Report Item 13H
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 (1) $44 million/yr reduction in production costs as TIDC’s gas generation declines by ~575 GWh  (2) $30 million/yr increase in purchase costs as TIDC purchases about 710 GWh more in the day-ahead to offset declining gas generation
 (3) $0.4 million/yr decrease in sales revenue and reduces day ahead sales given the large price drop of $59/MWh in the day ahead market
TIDC Adjusted Production Cost in the EDAM Case
(1)
(2)
(3)
TIDC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ EDAM Difference Baseline+ EDAM Difference Baseline+ EDAM Difference Production Cost (+) [1] 1,664 1,089 -575 $28.48 $3.24 -$25.24 47,383 3,529 -$43,854 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 1,439 2,150 711 $40.01 $44.91 $4.90 57,582 96,556 $38,974 Real-Time Market [5] 144 2 -141 $54.34 $67.78 $13.44 7,804 144 -$7,660 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 9 0 -8 $73.37 $14.18 -$59.19 625 3 -$623 Real-Time Market [8] 3 6 3 $71.28 $88.53 $17.25 207 490 $283 Total Cost (Negative Difference = Benefit) [9] 3,235 3,235 0 $34.60 $30.83 -$3.77 111,937 99,736 -$12,201 % Change in APC -10.9%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
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 (1) $4 million/yr decrease in production cost due to ~50 GWh reduction of gas generation (TIDC does not have renewable generation)
 (2) $2 million/yr increase in purchases cost because of ~94 GWh of increased purchases to compensate for gas generation reduction
 (3) $0.1 million/yr increase in sales revenue caused by increases in real-time revenues despite a $2.9/MWh decrease in day-ahead prices
TIDC Adjusted Production Cost in the Split Market Case
(1)
(2)
(3)
TIDC Adjusted Production Cost
GWh $/MWh Total ($1000s/Year)
Cost Components Baseline+ Split Market Difference Baseline+ Split Market Difference Baseline+ Split Market Difference Production Cost (+) [1] 1,664 1,617 -47 $28.48 $26.74 -$1.74 47,383 43,237 -$4,147 Purchases Cost (+) [3]
Day-Ahead Market + Bilateral [4] 1,439 1,533 94 $40.01 $40.68 $0.67 57,582 62,366 $4,785 Real-Time Market [5] 144 98 -46 $54.34 $54.32 -$0.02 7,804 5,328 -$2,476 Sales Revenue (Negative = Cost) (-) [6]
Day-Ahead Market + Bilateral [7] 9 4 -4 $73.37 $70.47 -$2.90 625 289 -$336 Real-Time Market [8] 3 9 6 $71.28 $72.23 $0.95 207 622 $416 Total Cost (Negative Difference = Benefit) [9] 3,235 3,235 0 $34.60 $34.01 -$0.59 111,937 110,019 -$1,918 % Change in APC -1.7%
Note: Total production cost is calculated as the sum of [1] + [2] + [3] - [6] as sales are revenues, not costs.A positive $ amount in sales is a benefit to the entity, while a positive in purchases is a cost.

Curtailment cost/PTC value only shows the change in cost of curtailments are a price of $30/MWh for a curtailment.

Attachment Staff Report Item 13H
Appendix C:

Description of Benefit Metrics
Attachment Staff Report Item 13H
The APC is calculated for the BAU cases and the market cases to determine the market related reductions in APC
 By using the generation price of the exporter and load price of the importer for sales revenues and purchase costs, the APC metric does not capture wheeling revenues and the remaining portion of the value of the trade to the counterparties (see next slide) Benefit Metric: Adjusted Production Cost
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Adjusted Production Cost (APC) is a standard metric used to capture the direct variable energy-related costs from a customer impact perspective Attachment Staff Report Item 13H
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 Wheeling Revenues: collected by the exporting BAAs based on OATT rates  Trading Gains: buyer and seller split 50/50 the trading margin (and congestion revenues in EIM/EDAM) Benefit Metrics: Wheeling Revenues, Trading Gains
A sells
50 MWh A to B
Internal
Gen Price
$30/MWh
B
Internal
Load Price
$50/MWh
The APC metric only uses area-internal prices for purchase cost and sales revenues, which does not capture part of the value:
• A receives $30×50MWh=$1,500 in APC sales revenues
• B pays $50×50MWh=$2,500 in APC purchase costs
 $1,000 of trading value not captured in APC metric
Trading value = $20/MWh Δprice x 50 MWh = $1000
• Exporter A receives wheeling revenues: $8/MWhx50MWh = $400 • Remaining $600 trading gain split 50/50: both A and B receive $300 $8/MWh
Wheeling Charge
Attachment Staff Report Item 13H
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Illustration of Markets+ Congestion Revenues
BA2
(importer)
Avg. Gen Cost = fuel
+ variable O&M
Gen LMP = Sales revenue
to BA generators
Load LMP = Purchase cost
to serve load
Avg. Gen Cost
Gen LMP
Load LMP
Markets+ congestion revenues are
rolled together and estimated
based on BA load and gen LMPs:
• The BAA is assumed to own all rights
on congested paths within their BAA,
unless we have information on third-party contracts.
• Similarly, unless we have information
on third-party contracts, we assume
congestion between market
members is owned 50/50 by the two
BAAs
• Congestion/Transfer Revenue
Payment (split 50/50) = MW x (Load
LMP2 – Gen LMP1)
Attachment Staff Report Item 13H
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BA1
(exporter)
BA2
(importer)
Avg. Gen Cost = fuel
+ variable O&M
Gen LMP = Sales revenue
to BA generators
Load LMP = Purchase cost
to serve load
Avg. Gen Cost
Gen LMP
Load LMP
EDAM congestion and transfer
revenues estimated based on
individual tieline LMPs:
• Congestion Payment (to exporter)
= MW x (Tie LMP1 – Gen LMP1)
• Congestion Payment (to importer)
= MW x (Load LMP2 – Tie LMP2)
• Transfer Payment (split 50/50)
= MW x (Tie LMP2 – Tie LMP1)
Tieline LMP2-LMP1
Transfer payments
Attachment Staff Report Item 13H
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Illustration of Congestion/Transfer Revenues vs. APC
captured in APC.
o The $20 difference between the seller and buyer is the congestion and transfer revenue. o $5/MWh of congestion revenue is allocated to the seller ($30 on their side of the intertie less $25 internal gen price) o $8/MWh of congestion revenue is allocated to the buyer ($45 internal load price less $37 on their side of the intertie) o $7/MWh of transfer revenue is split 50/50 between the buyer and seller ($37 on the buyer side of the intertie less $30 on the seller side)
G L
$25 $45
Tiepoint
$30 $37
Exporting BAA Importing BAA
100 MW 100 MW
Sales revenue of
export reflected
in APC = $2,500
$5/MWh Congestion
Revenues = $500
$8/MWh Congestion
Revenues = $800
$7/MWh Transfer
Revenues = $700
(50/50 split between BAAs)
Purchase cost of
import reflected
in APC = $4,500
$20/MWh Value of Transaction not Captured in APC = $2,000 Attachment Staff Report Item 13H
Appendix D:

Overview of Power System
Optimizer (PSO)
Attachment Staff Report Item 13H
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Key Modeling Assumption Sources
Assumption Category California Rest of WECC
Resource Mix • CAISO resource mix assumptions reflect the 2023- 2024 CAISO TPP portfolio
• LADWP and BANC/SMUD provided resource mix
assumptions directly during the 2022
• Participant updates for El Paso Electric, Idaho Power, NV Energy, Portland General Electric, PacifiCorp, Public
Service Company of New Mexico
• Recent IRP updates for Arizona Public Service, Tucson Electric Power, Avista, and Puget Sound Energy
Load • CAISO load assumptions are based on the 2022 IEPR mid baseline load forecast
• LADWP and BANC/SMUD provided resource mix
assumptions
GHG Prices • GHG prices are based on the CEC’s 2022 mid case, with the modeled CA & WA price in 2032 at ~$64/metric ton • We assume the WA and CA carbon markets are linked by 2032 Natural Gas Prices • Gas prices were provided by the study participants in prior iterations of EDAM/Markets+ studies.

Transmission • Participant updates for specific projects, and addition of interregional projects anticipated to be online by 2032, including SunZia, SWIP-N, TransWest Express, Cross-Tie, Greenlink North & West, B2H, Gateway Projects • Enforced physical limits include WECC-rated paths and specific constraints identified by pariticpants • Contract path limits based on public data and participant input and enforced for all BA-to-BA connections Attachment Staff Report Item 13H
Utilized the Polaris Power System Optimizer (PSO), an advanced market simulation model  Nodal mixed-integer model representing each load and generator bus in the WECC  Licensed through Enelytix
 Detailed operating reserve and ancillary service product definition  Detailed representation of the transmission system (both physical power flows and contract paths)  Sub-hourly granularity (but used hourly simulations due to limited data availability)  Designed for multiple commitment and dispatch cycles (e.g., DA and RT) with different levels of foresight
 EDAM feasibility study assumptions updated to reflect the most recent utility resource plans and forecasts of system conditions and costs
PSO is uniquely suited to simulate bilateral trading, joint dispatch, imbalance markets, and RTOs, reflecting multiple stages of system operator decision making
Overview of Modeling Approach
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We utilize the WECC ADS nodal production cost model as a starting point imported into Power System Optimizer (PSO), as refined during the EDAM feasibility study and follow-on engagements
Attachment Staff Report Item 13H
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PSO simulates multiple independent decision cycles to capture day-ahead vs. real-time unit commitment and dispatch
Independent Simulation of Multiple Time Horizons
Independent real-time decision cycle
used to simulate DA vs. RT, including
forecast errors for wind and solar
Real Time Cycle
DA Bilateral
Markets
 DA block trades on
long-term
transmission rights
and incremental
transmission
D-1 (am)
Day-Ahead
Market
Intra-Day
Markets
EIM
(RT Balancing)
• CAISO, EDAM, and
RTO market clearing
• Hourly intertie trading
• Hourly trading with
long-term
transmission rights
• Hourly bilateral
trades on remaining
transmission
• WEIM/WEIS/RTO
trading of economic
energy
• Remaining Tx
released for

WEIM/WEIS
• RT balancing in BAAs
D-1 (~noon) D-1 (pm-D) D
Unit Commitment Cycle Economic Dispatch Cycle
Decision cycles capture bilateral trading, market
clearing, BAA functions in DA and RT, and market cycles (EDAM “GHG reference” pass, EDAM market, and EIM)
Independent real-time decision cycle
used to simulation
EIM functions
Attachment Staff Report Item 13H
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 Intra-day trading: the model simulates market activity through one-hour optimization horizons. Trading is assumed to utilize unused transmission, represented as the difference between their day-ahead trading volume and the total contract path limits.

No unit re-commitment is allowed due to the non-firm nature of the transactions. Changes to generation availability, such as forced outages, which were not “visible” during the day-ahead cycle become visible during this cycle.
 Real-Time Cycle: this cycle simulates the operation of the real-time imbalance markets, such as through EIM transactions. In this cycle, the model can re-optimize dispatch levels and unit commitment decisions for fast-start thermal resources (based on the assumption that the real-time market design allows for unit re-commitment). Deviations from day-ahead forecasts (due to uncertainty) need to be balanced in real-time.

The model setup for wholesale market simulation effort contains several cycles to simulate unit commitment and dispatch decisions in three different timeframes and within different market structures. For example, cycles simulated can include are:

These cycles can take on different assumptions, depending on market structure. In a bilateral setting, all are set up to analyze utility-specific unit commitment and dispatch decisions, with each of them including hurdle rates and transmission fees that limit the amount of economic transactions that can take place between the utilities. In EIM and EDAM+EIM scenarios, all of the cycles are set up to simulate market-wide optimization of unit commitment and dispatch, including the EDAM “reference pass” cycle. In the EDAM case, there would be no hurdle rates between EDAM participants in any of the cycles, allowing the model to optimize both unit commitment and dispatch in the market footprint on both a day-ahead and real-time basis.

Simulating Several Wholesale Market Cycles in PSO
Attachment Staff Report Item 13H
Types of Trades and Transmission Reservations Modelled
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Unscheduled/unsold Transmission
EIM Trades
Total Transmission Capability (TTC)
Block Trades on ETCs
Block Trades on Incremental
Transmission
Hourly Bilateral Trades on ETCs
Hourly Bilateral Trades on Incremental
Transmission
Hourly EDAM, CAISO DA Intertie Trades
The model simulates the use of different
types of contract-path transmission
reservations for bilateral trading in DA and RT
• Existing long-term transmission contracts (ETCs) and
incrementally purchased transmission
• Total reservations on each contract path is limited by the total transfer capability (TTC)
• Trades are structured as blocks or hourly
• Bilateral trades between BAAs, at major hubs, or
across CAISO interties
• Account for renewable diversity and day-ahead
forecast uncertainty vs. real-time operations
• Unscheduled transfer capability released for EIM
trades in real-time
Attachment Staff Report Item 13H
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Nodal Simulations Based on Physical Transmission
WECC-Defined Paths Modeled
Limits on the physical transmission
system include all the paths defined in
WECC Path Rating Catalogue
• Additional transmission paths to represent
congestion internal to each BA
• Limits on all paths and constraints reflect
updates provided by the study participants
75 Attachment Staff Report Item 13H
Power System Optimizer (PSO), developed by Polaris Systems Optimization, Inc. is a state-of-the-art market and production cost modeling tool that simulates least-cost security-constrained unit commitment and economic dispatch with a full nodal representation of the transmission system, similar to actual RTO and ISO market operations. Such nodal market modeling is a commonly used method for assessing the operational benefits of wholesale market reforms (e.g., JDAs, EIMs, RTOs).

PSO can be used to test system operations under varying assumptions, including but not limited to: generation and transmission additions or retirements, de- pancaked transmission and scheduling charges, changes in fuel costs, novel environmental and clean energy regulations, alternative reliability criteria, and jointly-optimized generating unit commitment and dispatch. PSO can report hourly or sub-hourly energy prices at every bus, generation output for each unit, flows over all transmission facilities, and regional ancillary service prices, among other results. Comparing these results among multiple modeled scenarios reveals the impacts of the study assumptions on the relevant operational metrics (e.g. power production, emissions, fuel consumption, or production costs). Results can be aggregated on a unit, state, utility, or regional level.

PSO has important advantages over traditional production cost models, which are designed primarily to model dispatchable thermal generation and to focus on wholesale energy markets only. The model can capture the effects of increasing system variability due to large penetrations of non-dispatchable, intermittent renewable resources on thermal unit commitment, dispatch, and deployment of operating reserves. PSO simultaneously optimizes energy and multiple ancillary services markets on an hourly or sub-hourly timeframe.
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Attachment Staff Report Item 13H
GRID REGIONALIZATION IN THE WEST:

RELIABILITY BENEFITS FROM INCREASED

COOPERATION IN ELECTRICITY MARKETS

AND OPERATIONS
August 2024 By Mareldi Ahumada-Paras, Michael Mastrandrea, and Michael Wara Attachment Staff Report Item 13I
Photo credit above: Andrew Peacock, iStock. Photo credit cover: vencavolrab, iStock Acknowledgements
This work was supported by grant EF-G-2023-62324 from the Energy Foundation. The analysis was conducted using Energy Exemplar’s PLEXOS energy modeling software. The authors benefited from and gratefully acknowledge discussions with Elliot Mainzer, Xiaobo Wang, Matt Freedman, Hannes Pfeifenberger, and John Tsoukalis. The material presented in this whitepaper reflects the analysis and opinions of the authors only.

Authors
Mareldi Ahumada-Paras, postdoctoral scholar, Energy, Science and Engineering Department, Stanford Doerr School of Sustainability, and Climate and Energy Policy Program, Stanford Woods Institute for the Environment.

Michael Mastrandrea, Senior Research Scholar and Research Director, Climate and Energy Policy Program, Stanford Woods Institute for the Environment.

Michael Wara, Director, Climate and Energy Policy Program and Senior Research Scholar, Stanford Woods Institute for the Environment
GIS / Data Visualization Consultant
Monica Moritsch
DOI: https://doi.org/10.25740/hv369wc0301
External Reviewers
Kathleen Staks (Western Freedom). Jan Smutny-Jones (IEPA). Mark Rothleder (CAISO) Attachment Staff Report Item 13I

TABLE OF CONTENTS
Executive Summary....................................................................................................................... 1 Introduction .................................................................................................................................. 3 Background: Planning and Operations in the Western Interconnection ........................................ 5 Responding to Challenges in Planning and Operations......................................................................................... 6 Case Study: A simulation of the Western Interconnection for one month of operation under stress conditions ................................................................................................................ 9 Model and Study Design ................................................................................................................................... 11 Simulation Results............................................................................................................................................ 15 Conclusions................................................................................................................................... 18 List of Abbreviations ..................................................................................................................... 20 Appendix A: Balancing Authorities .............................................................................................. 21

LIST OF TABLES
Table 1. Stress Levels.................................................................................................................... 14 Table 2. Monthly System Wide Risk and Unserved Energy ............................................................ 16 Table 3. Balancing Authorities; participation in current market structures and simulated case studies.................................................................................................................. 21

LIST OF FIGURES
Figure 1. Stress event during Sep 2022 heat wave in CAISO territory. .......................................... 10 Figure 2. 34 simulated BAs in the WECC. (Note: CAISO is subdivided into its 3 IOUs and VEA) ..... 11 Figure 3. Geographic cases........................................................................................................... 12 Figure 4. Example of load at the 3 stress levels and reported (Example: CAISO BAs) ................... 14 Figure 5. Available Capacity Margin (%) for baseline. ................................................................... 15 Figure 6. Monthly System Wide Risk and Unserved Energy........................................................... 17 Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations i Attachment Staff Report Item 13I
Photo credit: BSPC, iStock.

Attachment Staff Report Item 13I

EXECUTIVE SUMMARY
In recent years, parts of the U.S. electricity grid have experienced increasing impacts from weather and climate-related extreme events that have disrupted system operations, triggered emergency responses, and motivated stakeholders to make substantial changes to planning strategies. In the West, extreme heat events combined with severe drought that limits availability of hydropower have proven particularly challenging for grid operators to manage.

Balancing Authorities (BA) are the entities responsible for ensuring electricity supply and demand balance – that is, bulk power system (BPS) reliability – within their service territory of the grid. Each BA can meet their needs by either dispatching generating units within their footprint, establishing forward contracts, or trading energy with neighboring BAs by participating in wholesale markets. In the western grid, called the Western Interconnection, all BAs at times use and to varying degrees rely on electricity imports to meet their demand primarily due to operating system efficiency and the economic benefits of participating in wholesale markets. However, when the system is most stressed because of extreme weather events that span across a large area, availability of resources in wholesale markets may be compromised, thus reducing access to imports and increasing the risk of not meeting demand. In such situations, operators in each BA make decisions based on imperfect information and rely on best practices and operator experience to overcome challenges in real-time. This uncertainty in the system poses a higher risk of failing to meet reliability and security standards and potentially leads to local or widespread power outages. As operations have evolved throughout the growth and structural evolution of the electrical grid, so have the responsibilities and organizational structures that define each BA. In today’s BPS operations, the most comprehensive structure is a regional transmission organization (RTO) having oversight of centralized unit commitment, economic dispatch, coordinating over a larger, multi-utility footprint and planning transmission system expansion. Naming conventions have also varied with time; we refer to an Independent System Operator (ISO) and an RTO as the overarching terms for cooperation areas comprised of multiple BAs. For the purposes of this study, we refer to ISO/RTO as entities that maintain operational and planning responsibilities within their region, without specifying a particular structure or governance framework. The latter falls outside the scope of this work and requires the ongoing consideration of decision makers who must balance multiple policy priorities.

This study evaluates shifts in utilization of generation, imports, and exports as we assign different cooperation regions in the West. We do this to illustrate the potential benefits to operations and reliability - under stressed grid conditions created by extreme heat and drought - of expansion and adaptation of existing markets, like the Extended Day-Ahead Market (EDAM), into a larger ISO/RTO. EDAM is a day-ahead market proposed by a number of western BAs and recently approved by the Federal Energy Regulatory Commission (FERC) as a component of the California ISO’s (CAISO) tariff. EDAM will become operational across its initial footprint in 2026. Several recent analyses have evaluated the potential economic benefits of increased cooperation among western BAs, but none have focused on the potential reliability impacts to date. These studies have generally shown real but modest economic benefits from a shift to organized regional electricity markets with larger footprints.

Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 1 Attachment Staff Report Item 13I
Simulating reliability impacts with power system optimization models is challenging because these models assume perfect information to optimize dispatch across all western BAs and optimization across the entire Western Interconnection footprint. In other words, they behave as if an RTO exists, with some limited economic frictions. In the real world, especially during stress events, system operations can divert substantially from the optimal outcome due to incomplete information, risk aversion by individual BAs, and other factors. Because of this challenge in simulating stress conditions using these models, we interpret our results as illustrative and directional rather than a precise estimate of the reliability benefits of a larger, ISO/RTO footprint.

Despite these challenges, we show that growing the footprint of an organized market for electricity in the West has the potential to substantially reduce risks to reliability under extreme heat scenarios derived from the September 2022 California heat event. Our case study of simulated extreme stress conditions shows a 40% decrease (from 25% down to 15%) in West-wide hours at risk following expansion from an ISO/RTO with a footprint similar to EDAM to the entire Western Interconnection. Simulated unserved energy is also more than cut in half (from 1901 to 877 GWh).

In other words, by creating and expanding an ISO/RTO beyond the current EDAM members (detailed in appendix A), our work suggests that western BAs can substantially reduce the risks of unserved energy and rotating outages. This work thus complements earlier work on economic benefits of a western ISO/RTO and adds an additional dimension to the ongoing stakeholder efforts to broaden and enhance coordination of electricity operations in the West. Further studies and analysis are needed in order to fully understand all the potential benefits and costs of creating an ISO/ RTO that spans across multiple states in the West.

Our results also lend an additional dimension of support for the reforms being undertaken to create a more equitable and independent governance structure for the EDAM and the Western Energy Imbalance Market (WEIM) via changes to the CAISO tariff, as well as the West-Wide Governance Pathways Initiative Phase I and Phase II efforts. Given the growing impacts of climate change on extreme heat events that translate directly into grid stress events, our results also indicate the value to all parties of greater integration that can only result from shared and equitable governance structures that facilitate greater sharing of resources. Our work is intended to motivate those efforts by providing a more complete picture of potential benefits to energy market regionalization that should be balanced against potential risks of such shared governance.

Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 2 Attachment Staff Report Item 13I

INTRODUCTION
The electric grid is a true marvel of human ingenuity, perseverance and care – the largest single machine that humans have ever created. Ingenuity was required to create it. Perseverance to keep it operating as reliably as it does in the United States. And care to ensure that reliable operations are also safe and affordable. All three are needed now, to ensure that reliability is maintained as we transition from a grid primarily fueled by fossil fuels to one that is heavily reliant on renewable resources, while we also contend with the rising impacts of climate-related extremes including wildfires and extreme heat. Operation and planning of the electrical grid have adapted, and continue to adapt, to meet present day needs, given that electricity is essential to a safe and prosperous modern society.

In recent years, parts of the Western Interconnection have experienced extreme events (particularly heat events) that have stressed system operations, triggered emergency responses and prompted stakeholders to make substantial changes to planning strategies. In 2020, a west-wide heat event resulted in rotating outages on August 14th and 15th in CAISO’s territory. In 2021, drought conditions exacerbated the Bootleg fire in Oregon and disrupted transmission lines, hindering the energy interchange capacity between Oregon and California during periods of extreme heat.

And in 2022, high temperatures created a record peak load of 52,061 MW in CAISO footprint. This peak load broke records from the early 2000s that most thought would never again be approached in California because of the massive growth in rooftop solar, which reduces peak demand for grid supplied energy. The CAISO grid was stressed to the point of the Governor’s Office of Emergency Services calling upon the population via text message to decrease their consumption in order to avoid outages.1
Once again, in Summer 2024, high temperatures in addition to intensified drought conditions2
made Pacific Northwest system operators run the system at stress conditions.

Due to such challenges, and the expectation that they are likely to intensify in the future as the western US climate becomes hotter and drier, stakeholders across the Western Interconnection are responding by proposing initiatives that would consolidate efforts and modify markets, planning, and operations in different regions with the overall goal of increased cooperation and collaboration in meeting electricity demands across the West. This kind of regional cooperation has long been a hallmark of western electricity planning, despite the large number of entities in the region responsible for system planning and operations. But increased coordination in the West is now more beneficial than ever. In addition, transmission investments and expansion, critical for unlocking the potential value expected through the Inflation Reduction Act,3
will need to be planned across boundaries, requiring additional cooperation in both planning and cost allocation. The Western Electricity Coordinating Council (WECC) in its most recent Western Assessment of Resource Adequacy (WARA) recommends that the Western Interconnection evaluate resource and transmission adequacy in a coordinated fashion through comprehensive wide-area system planning.4 1 California Governor’s Office of Emergency Services. 2022. https://news.caloes.ca.gov/state-officials-sent-cell-phone-alerts-to-protect-public-safety-amidst-ongoing-record-heat-energy-grid-shortfalls/ 2 National Integrated Drought Information System. 2023. https://www.drought.gov/news/summer-2023-review-look-back-drought-across-us-10-maps-2023-09-21 3 Jenkins, J.D., Farbes, J., Jones, R., Patankar, N., Schivley, G., “Electricity Transmission is Key to Unlock the Full Potential of the Inflation Reduction Act,” REPEAT Project, Princeton, NJ, September 2022. DOI: 10.5281/zenodo.7106176 4 WECC. (2023). 2023 “Western Assessment of Resource Adequacy”.

Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 3 Attachment Staff Report Item 13I
Recognition of these challenges has led to increased efforts to coordinate between BAs in their Resource Adequacy (RA) and transmission planning and in their operations. One such example is the Western Power Pool (WPP)’s coordinated planning for future load growth and weather impacts on resource availability their Western Resource Adequacy Program (WRAP).5
The design of WRAP is intended to leverage the existing bilateral market structure in the West to develop a resource adequacy construct in which participants who are short of necessary supply can call on the resources of other participants who have surplus supply under extreme conditions.

In addition, and central to the motivation for this work are two proposals currently under development. (1) A multi-state stakeholder-led effort called the West-Wide Governance Pathways Initiative 6 , initiated by regulators from
five western states. This proposal seeks to create a new, west-wide, independently governed regional organization that oversees operation and evolution of the WEIM and EDAM, and potentially other grid services. Because an independent governance structure has the potential to attract additional participation to EDAM, this initiative proposes to reduce reliability risk across a wider footprint and be financially beneficial to its participants.7 (2) A regional effort,
led by Southwest Power Pool (SPP), an existing RTO located mostly in the Eastern Interconnection8 , that intends to
offer a competitive wholesale market called Markets+, and is proposing the expansion of a Western RTO9 that would
operate alongside SPP’s footprint in the Eastern Interconnection.

While other work has assessed the economic benefits of EDAM and Markets+ proposals in terms of reduced operational and consumer costs under normal operating conditions, it often has not focused on benefits from reliability improvements during extreme weather or challenging operational conditions. Here, we present analysis that illustrates the potential reliability benefits that could be achieved by greater cooperation across the Western Interconnection under stress conditions. We argue that such reliability benefits to people and communities in the West are at least as important as the economic benefits to electricity market participants.

Maintaining a reliable and sufficient electricity supply is not merely economically beneficial, failure to do so can and does have life threatening consequences. Hundreds died during winter storm Uri when the grid failed in Texas. With increasing system uncertainty, a larger footprint with greater resource diversity and operating flexibility can help to manage reliability risks across different regions in the West. In addition, a major disruption to BPS operations in the West is likely, fairly or not, to be blamed on the growing role of variable renewable generation – wind and solar – in western electricity supply. Such an event, were it to occur, might have widespread policy implications in other jurisdictions that have adopted or are considering adoption of renewable energy policies like California’s and other western states.
5 WRAP. 2023. https://www.westernpowerpool.org/private-media/documents/WPP_WRAP_Interoperability_with_Markets_June_2023.pdf 6 West-Wide Governance Pathways Initiative. 2024. https://www.caiso.com/Documents/West-Wide-Governance-Pathway-Initiative-Overview.pdf 7 Energy and Environmental Economics (E3). 2023. Western Markets Exploratory Group: Western Day Ahead Market Production Cost Impact Study. 8 Southwest Power Pool. 2022. https://www.spp.org/media/1979/spp-markets-plus-proposal.pdf 9 Southwest Power Pool: RTO Expansion. 2021. https://www.spp.org/western-services/rto-expansion/ Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 4 Attachment Staff Report Item 13I
BACKGROUND: PLANNING AND OPERATIONS IN

THE WESTERN INTERCONNECTION
The continental US contains three primary physical electricity grids, the Western Interconnection, the Eastern Interconnection and ERCOT in Texas. The Western Interconnection stretches from the West Coast into the Great Plains and from Western Canada to Baja California. It operates under the purview of WECC, which sets and enforces reliability and security standards for the region, FERC, which regulates transmission planning, investment and inter-state electricity markets, and numerous State utility commissions, which regulate many aspects of utility planning and investment. In addition, the North American Electric Reliability Corporation (NERC) tasked CAISO and SPP as the two reliability coordinators (RC)10 in the West to assure the system complies with standards and security constraints.

Today, in the Western Interconnection, 37 BAs11 with widely varying governance are charged with assuring that demand for electricity within their geographies is instantaneously matched with supply of energy from electric generators. They keep the system in balance and manage the flows of electricity with neighboring BAs, since all of the Western interconnection’s BAs have long relied on regional power exchanges to meet local demand.12 This system balance is critical to the safe and reliable operation of the grid because at least for now, there is not widespread capacity to store electricity and so if demand and supply drift out of balance, voltage and current will also vary in ways that will cause the system to fragment and can lead to bulk power system outages like the multi-day blackout that occurred in 2003 in the Eastern Interconnection.

Beyond single-utility BAs, there are ISO and RTOs, which operate the transmission system through competitive wholesale electricity markets but do not own infrastructure such as generating units or transmission lines. The ISO structure is one that is designed to operate a certain region of the grid using an approach known as an organized wholesale market that generally consists of competitive auctions to determine which power plants provide services needed to assure grid reliability and wholesale electricity provision. An RTO, beyond an ISO’s responsibilities, is also tasked with planning transmission upgrades and expansion in order to avoid line congestion during operation and assure there is enough interchange capacity in the system. In today’s bulk power system operation and planning, an RTO is the most comprehensive regional governance structure since it has oversight of all phases including interstate transmission planning, in some cases, capacity expansion aligned with resource adequacy compliance within its footprint, and finally centralized unit commitment and economic dispatch. CAISO, while called an ISO for historical reasons, fills many of the roles of an RTO for the three large investor-owned utilities (IOUs) in California and a few smaller entities. Importantly for this discussion, it does not oversee power capacity expansion and resource adequacy in California or in any of the multi-state markets it currently operates or plans to operate. The rest of the entities that play the role of BAs in the Western Interconnection that are not part of an ISO/RTO structure are either traditionally 10 NERC. https://www.nerc.com/pa/rrm/bpsa/Pages/RCs.aspx 11 The Western Interconnection consists of 37 balancing authorities: 34 in the United States, 2 in Canada, and 1 in Mexico. https://www.eia.gov/todayinenergy/detail.php?id=27152#
12 WECC. Western Assessment of Resource Adequacy. November 2022.

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operated utilities13 that own generation, transmission, and distribution within their service territory or are Federal Power Marketing Administrations that own generation and transmission systems, providing wholesale power to other utilities.

All BAs, regardless of their structure, must ensure adequate planning for future electricity demand. In such planning, BAs conduct RA studies, develop transmission planning processes and incorporate state and federal policies such that their operation in future years will meet reliability requirements set by WECC and also be compliant with other policy goals such as Integrated Resource Plans (IRP) or Renewable Portfolio Standards (RPS). This planning can be challenging in that it requires consideration of the lengthy timelines for electric grid upgrades and generation and transmission expansions, including the planning, cost allocation, permitting, construction, and commissioning.

In operation, each BA procures the necessary resources to meet their load mainly through long-term contracts with generators within their territory and interchange of energy with their neighbors through forward contracts to purchase energy (sometimes referred to as bilateral contracts). In addition, in the West there are currently two regional energy imbalance markets: WEIM operated by the CAISO and the Western Energy Imbalance Service (WEIS) operated by SPP. Both markets facilitate trading of real time energy surpluses and deficits between BAs across the West.

Energy Imbalance Markets are thus a means of trading excess energy after local needs within a BA have been met.

Studies14 and experience in the WEIM have shown that energy imbalance markets provide economic, reliability and environmental benefits to their participants.15 Finally, CAISO’s EDAM, a day-ahead market proposed by a number of western BAs and recently approved by FERC as a component of CAISO’s tariff, is intended to extend the benefits demonstrated by the WEIM to a day-ahead market. SPP’s Markets+, another day-ahead market under development, is also intended to integrate day-ahead and real-time unit commitment and dispatch.

Responding to Challenges in Planning and Operations
BAs across the West have faced increasing challenges in recent years in ensuring that they have sufficient resources to meet electricity demand, particularly during stress conditions. Electricity grid planning and operation are contending with three key challenges.
(1) Demand and resource availability are becoming harder to predict. Projections based on historic averages no longer accurately represent the impacts of climate change on electricity consumer behavior, as well as the effects of weather variations on both demand and resource availability. Buildout of distributed energy resources (rooftop solar, home energy storage, etc.) and electrification efforts (heat pumps, etc.) are key drivers in the increased variability of demand side forecasts. Climate change is leading to intensifying extremes, both in frequency and magnitude and in the breadth of impacted areas, leading to increased peak and net-peak demands across the West. The Government 13 Vertically integrated monopolies are responsible for generating, transmitting, and distributing electricity to their customers. 14 Extended Day-Ahead Market Participation Benefits Study prepared by The Brattle Group, Inc. https://www.brattle.com/wp-content/uploads/2024/01/Extended-Day-Ahead-Market-Participation-Benefits-Study.pdf 15 In CAISO, for example, energy procurement by utility-owned generation and forward contracts usually sums to be between 45-97% of the total need. The remaining 3-55% is acquired through wholesale markets coordinated in the day-ahead market (DA) accounting for roughly 95% of transactions and the real time (RT) or imbalance market that trades the remaining 5% to account for the mismatch in forecast and actual demand.

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Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 6 Attachment Staff Report Item 13I
Accountability Office (GAO) suggests that FERC should act to introduce adequate and updated standards to account for the impacts of climate change.16 In addition, the Summer Stack Analysis for 2022-202617 published by the California Energy Commission (CEC) in July 2022 concluded that ‘grid reliability risks will persist through 2030 under the increased demand conditions experienced in 2020 and 2022 because of continued higher growth in electricity demand. These risks are compounded by the risk of coincident fires impacting generation and electricity imports to California .’ One of the key drivers of uncertainty in load growth is the proliferation of data centers. Some grid planners forecast that data center expansion could more than double load growth. (2) The electric generating mix is in rapid transition. There is rapid growth of renewable capacity, like wind and solar, combined with retirement of thermal capacity, like coal. Also, short-term and long-term energy storage additions are creating new operating and planning strategies and capabilities for meeting demand in some jurisdictions. Planning has historically been driven by the peak demand hour in predominantly thermal dispatchable systems, where the system is at its highest strain, but in a high-renewables system, strain is dictated by a host of parameters, requiring a broader range of seasons, load levels and resource dispatch to be considered. (3) The current patchwork of state and federal clean energy goals adds complexity in that each state has different incentives that influence operation and planning differently as well as having different levels of ambition and approaches to climate policy. In the Western Interconnection, these differences are particularly large, spanning from states with goals to fully decarbonize their electricity systems to states that hope to preserve the economic wellbeing of their coal mining industries and the power plants that purchase their output.

Since the 2020 and 2022 California heat events, the CEC and the California Public Utilities Commission (CPUC), have been required (as directed by SB 846) to provide reliability planning assessments, develop risk scenarios and update their operation and planning protocols. These efforts led to new interim transmission service and market scheduling priorities implemented in the summer of 2021, with a more durable approach implemented in 2024 that better recognizes the contracted supply, available transmission and resource adequacy relationships. The CEC and CPUC are also in the process of developing climate-informed load forecasting approaches that take account of climate change impacts on extreme conditions in the West.

In the Western Interconnection, all BAs operate with interchange of electricity; system efficiency, economic benefits of participating in wholesale markets, and ultimately the need to assure that supply is sufficient to meet demand dictate times when a BA becomes a net exporter or net importer. However, when the system is most stressed in the presence of extreme weather events that span across a large footprint, availability of resources in wholesale markets may be compromised, thus reducing imports and increasing the risk of not meeting demand. In such situations, operators in each BA make decisions based on imperfect information and have to rely on best practices and operator experience to overcome challenges in real-time. This uncertainty in the system poses a higher risk of failing to meet reliability and security standards and potentially leads to local or widespread power outages. 16 GAO. (2021, Mar 05). U.S. Government Accountability Office. Retrieved from https://www.gao.gov/products/gao-21-346 17 https://www.energy.ca.gov/publications/2021/2022-summer-stack-analysis-update Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 7 Attachment Staff Report Item 13I
The key operational advantage of ISO/RTO organized wholesale markets is to create day-ahead and real time transparency into the availability, price, and deliverability of energy resources across a multi-utility footprint.

Coordination and optimization of operations under stress conditions within an ISO/RTO footprint is accomplished via computer algorithms that solve for the complex problem of meeting demand across the footprint at least cost using available supplies. This approach allows for greater visibility into which resources are actually available and what an optimal dispatch of resources is under stress conditions. By contrast, a more fragmented system of smaller BAs with incomplete information and optimization protocols focused on their BA rather than the region may lead to suboptimal decisions both in the day-ahead and the real time operational time frames. Particularly when resources are short, this visibility of available resources across a footprint can be helpful to maintaining reliability for bulk power system operations. Two states, Colorado and Nevada have requirements for their investor-owned utilities to join an RTO in the near future.18
In the next section, we evaluate how this shift – from a more fragmented structure of many smaller BAs that each meet supply-demand balance according to their regional or state/local resource adequacy requirements along with bilateral contracting – compares to an approach with a progressively larger cooperation footprint. 18 Colorado S.B.072 and Nevada S.B.448.

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CASE STUDY: A SIMULATION OF THE WESTERN

INTERCONNECTION FOR ONE MONTH OF

OPERATION UNDER STRESS CONDITIONS
This study evaluates shifts in grid operations, the utilization of generation, imports, and exports, as we assign different ISO/RTO footprints in the West. We do this to evaluate the potential benefits to operational reliability under grid stress conditions created by extreme heat through creation and expansion of a western ISO/RTO. We benchmark our simulated stress conditions to the conditions experienced in September 2022 in California, when CAISO recorded record peak demand. Figure 1 (top panel) shows total CAISO grid demand (blue), net generation (yellow) from generating units that are managed by a BA or whose operations are visible to a BA, and total interchange (black) with neighboring BAs on the record peak demand day of September 6, 2022 and surrounding days. To avoid losses, CAISO imported energy, on balance, from neighboring BAs to make up the difference between net generation and total demand. Figure 1 (bottom panel) shows the decomposition of energy interchange with neighboring BAs, showing that there were still exports during periods of high demand.

The stress conditions set in the case study that follows are derived from the extreme conditions experienced during this event, but with stress levels sustained throughout a month-long operating horizon. We acknowledge that a month-long, widespread event is unlikely, yet the intention behind this study is to provide insight into a worst-case scenario and how different levels of cooperation might fare against such a stressor. We run a simulation of the entire Western Interconnection during one month of operation at three different levels of compounding stresses. Each stress scenario is then modeled under three cases representing different levels of operational integration and cooperation in the Western Interconnection.

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Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 9 Attachment Staff Report Item 13I
Figure 1. Stress event during Sep 2022 heat wave in CAISO (referred as CISO in the figure) territory.

Total Interchange: negative interchange values indicate net inflows, and positive interchange values indicate net outflows. The top graph shows the total demand, the generation and the total interchange. The bottom graph shows the distribution of energy interchange with neighboring BAs. -12,000
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Simulating reliability impacts with power system optimization models is challenging because these models generally assume perfect information to optimize dispatch across all western BAs. In the real world, especially during stress events, system operations can diverge substantially from the optimal outcome due to incomplete information, risk aversion by individual BAs, and other factors. Because of this challenge in simulating stress conditions, we interpret our results as illustrative and directional rather than a precise estimate of the reliability benefits of a multi-state ISO/ RTO. Nevertheless, we show that growing the footprint of an ISO/RTO in the West has the potential to substantially reduce risks to reliability under extreme heat scenarios derived from the September 2022 California heat event. In other words, by expanding organized wholesale markets beyond the current EDAM partners, our work suggests that western BAs can reduce the risks of unserved energy and rolling blackouts. This work thus complements earlier work on economic benefits and adds an additional dimension to the ongoing cooperation regarding improved coordination of electricity operations in the West.

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Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 10 Attachment Staff Report Item 13I
Model and Study Design
All simulations are done using Energy Exemplar’s PLEXOS CloudUI services and their 2024 WECC Zonal dataset.19 This study is done using a zonal model that runs a production cost optimization to dispatch resources to meet demand in each zone, given physical and financial constraints for emissions, generators, fuels, transmission lines and wheeling rates. Fuel supply for all resources is assumed available, including predetermined wind, solar and hydro profiles. This model’s representation of the Western Interconnection is divided into 34 BAs, shown in Figure 2. Note that CAISO, even though it is a single BA, in this model, is subdivided into its 4 subregions20. We recognize and acknowledge the limitations of using a zonal rather than a nodal model for evaluating grid operations. Zonal models cannot be relied upon for precise quantification of changes to operations. However, in this case, because of the intent to provide insight into the reliability impacts of progressively larger organized wholesale markets rather than to precisely quantify these benefits, we believe use of a zonal model is both adequate and appropriate.

Figure 2. 34 simulated BAs in the WECC.21 (Note: CAISO is subdivided into its 3 IOUs and VEA) To assess reliability and energy interchange, we divide the Western Interconnection into different operating subregions in the three geographic cases we model, as follows (see also Figure 3). The subregions in cases 1 and 2 are considered operating islands, cutting any energy transactions at the seams. We understand this assumption is an extreme condition that would assume inability to rely on neighboring BAs outside the subregion and disregards the already existing market participation in wholesale markets or long-term contracts. This assumption is intended to 19 Energy Exemplar. (2024). 2024 PLEXOS WECC Zonal Release Notes; Energy Exemplar’s 2024 PLEXOS WECC Zonal dataset; The case studies were run using PLEXOS Engine Version 10.0 R04, virtual machine 32 Core – 256 GB RAM – 1200 GB Disk. 20 CAISO participating utilities and boundaries. https://westerngrid.net/wcea/wp-content/uploads/2016/07/governance-figure1-CAISO-util.png 21 The boundaries and shapes are an approximation the actual footprints and are only used for illustration purposes modified from WECC 2017 map. https://www.wecc.org/Administrative/Balancing_Authorities_JAN17.pdf Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 11 Attachment Staff Report Item 13I
simulate an operational fragmentation that represents the increased value of information about available resources and willingness to trade resources between regions during stress events. We are intentionally maximizing the frictions in the system during an extreme event to highlight how cooperation enhances reliability. But we emphasize that our assumptions mean that our results should be interpreted as directional and illustrative rather than as precise estimates.

Case 1. Region A (blue) is an ISO/RTO footprint based on the members of the EDAM operated by CAISO. Region B (orange) represents the rest of the Western Interconnection.

Case 2. Region A (blue) adds most of the Pacific Northwest to this ISO/RTO footprint. This addition includes various BAs currently in the WPP, some of which are already active participants in WEIM. It also includes some BAs that have indicated a preference for participation in the Markets+ day-ahead market under development by SPP. Region B (orange) represents the rest of Western Interconnection encompassing Arizona, New Mexico, Colorado, and parts of Wyoming and Montana.

Case 3. West-wide ISO/RTO, with no subregions. Imports and exports have no restrictions other than the zonal transmission constraints. This footprint is the 2024 PLEXOS WECC Zonal dataset system modeled without modifications.

For cases 1 and 2, each BA is either in subregion A or B, detailed in Appendix A. Note that the cases do not represent the EDAM and other markets precisely but are rather an approximation of the possible participation of BAs in a future ISO/RTO. The intention of our study is thus to illustrate how growth of regional cooperation is likely to impact risks to reliability under stress conditions, but not to quantify the exact benefits.

Figure 3. Geographic cases.

Case 1 and 2 are divided into two subregions: A (blue) and B (orange). Case 3 is represented as a single West-wide ISO/RTO.

CASE 1 CASE 2 CASE 3 West-wide ISO/RTO
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Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 12 Attachment Staff Report Item 13I
These (sub)regions operate like single entities composed of the sum of the generation, load and resources of the BAs that comprise them. We limit the interchange of electricity at the seams of each subregion, such that regions can only satisfy their demand with their internal resources, without imports across these seams. Disallowing energy exchange between subregions is a scenario considered in the WECC’s WARA,22 where the whole West is divided into 5 subregions and analyzed separately including a ‘no imports’ case study. Although this imposition is an extreme assumption that disregards bilateral contracts that do exist across these seams and diverges from normal operations, during stress events, as mentioned previously, energy imports and exports especially among BAs that are not in the same wholesale power pool become scarce, especially under stress conditions. We acknowledge that the strictness of these assumptions in particular shows a worst-case and improbable scenario and could be further relaxed by incorporating historical bilateral contracts.

The model also does not simulate the many daily decisions made by operators with imperfect information. The optimization also does not include market structures, bilateral contracts or storage charge/discharge algorithms for arbitrage. Given this framework, modifying the geographic footprint of a subregion will ultimately impact coordination among BAs in operations and when addressing reliability and resource adequacy challenges under stress conditions.

The stress levels, detailed in Table 1, are set to represent compounding effects including climate-related extreme events (heatwaves, wildfires, drought) and load growth. Stress level 1 (baseline) focuses on September 2022 load data, as it is intended to benchmark against the stress event experienced in California in that month. For stress levels 2 and 3, similar to the Summer Stack Analysis for 2022-202623 proposed by CEC, we increase loads in each BA by 15% and 40% above baseline as a proxy for stress as shown in Figure 4. Interconnection between BAs are transmission lines based on historical five-year running average energy flows, and there are no builds of new generation units or retirement of units. Drought conditions are based on historical data created from the lowest available hydro year in the WECC over the past 22 years. Generator outages are based on historical 2022 outages reported by EIA.
22 Western Assessment of Resource Adequacy. 2022. https://www.wecc.org/wecc-document/5436 23 https://www.energy.ca.gov/publications/2021/2022-summer-stack-analysis-update Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 13 Attachment Staff Report Item 13I
Table 1. Stress Levels
Case Demand Other conditions
Stress level 1 baseline Drought year, Generator outages Stress level 2 15% above baseline Drought year, Generator outages Stress level 3 40% above baseline Drought year, Generator outages Stress level 1 (Baseline) is a construct from 2024 WECC Zonal PLEXOS dataset which is based on historical and forecasted profiles from the 2032 Anchor Data Set (ADS) along with EIA, FERC-714 filings and other resources. The information for baseline load, generation and the simulation as a whole is taken from the month of September 2022 as represented in the dataset used.

Stress level 2 stresses the system to 15% above the baseline case, a standard capacity reserve margin.

Stress level 3 stresses the system to 40% above baseline, representing demand behavior similar to but somewhat higher than the increase in demand during the Sep 2022 heatwave event in California, shown in Figure 4.

Figure 4. Example of load at the 3 stress levels and reported (Example: CAISO BAs) 0 10,000
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Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 14 Attachment Staff Report Item 13I
Simulation Results
As a starting point to provide context for the results that follow, Figure 5 shows the available generating capacity margin (%) for each BA as represented in the model, expressed as a function of generating capacity vs. peak load.

Available generating capacity in a given BA is the sum of all generators, including operating constraints, capacity factor, ratings, and resource availability.

Available Capacity Margin (%) = 100 X
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The higher (darker green) values indicate BAs where generating capacity exceeds peak load. Values lower than 100% suggest that BAs must rely on imports from other BAs to satisfy their peak demand. This shows the baseline operations in our model; real available capacity, especially during a stress event, may differ from what is modeled.

Figure 5. Available Capacity Margin (%) for baseline
As described above, we run a simulation of the entire Western Interconnection during one month of operation for each of our three geographic cases representing different levels of cooperation and three stress scenarios representing different levels of stress. Table 2 presents three summary metrics for each geographic case and stress scenario. The first two are also presented in Figure 6.

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1. Hours at Risk (%): The percentage of hours during the simulation month when the system is at or above a “risk threshold” indicating system stress. The risk threshold is determined by the value of lost load (VoLL), a value embedded in the model’s dataset24 and used without modification, in this case 550 $/MWh for all BAs.

2. Unserved Energy (%): The percentage of hours during the simulation month in which there was unserved energy (USE). USE indicates a loss of load event—demand at the zonal level (BAs) that was not provided by available generation or transmission resources. Reasons for this include a shortfall in generation locally and in neighboring BAs, loss of transmission availability, or prices above VoLL.

3. Unserved Energy (GWh): The magnitude of USE across the system during the simulation month, in Gigawatt hours.

Table 2. Monthly System Wide Risk and Unserved Energy
Monthly System-Wide Risk and Unserved Energy
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15% Stress 1.30% 0.64% 22.5 0% 0% 0 0.54% 0% 0
40% Stress 24.93% 7.55% 1,901 18.13% 4.18% 1,243 15.46% 2.92% 877 These results illustrate the benefits of expanding cooperation across the Western Interconnection. With 15% stress being imposed on the whole system, the difference in hours at risk and USE across different footprints is less evident, as each (sub)region largely has enough capacity to overcome a level of stress comparable to running the system at the reserve margins. Notably, the 2022 event indicated that these reserve margins may not reflect the full scope of potential peak demand. Under an increased stress level of 40%, however, the benefits of cooperation and expanded energy interchange possibilities are clearer. We observe a major decrease (from 25% to 15%) in systemwide hours at risk following expansion of an ISO/RTO from the EDAM footprint to the entire Western Interconnection. Simulated USE is also more than cut in half (from 1901 to 877 GWh). As discussed previously, a month-long, widespread 40% stress event is unlikely, yet the intention behind this study is to provide insight into how different levels of cooperation might fare against such an extreme stressor.
24 Energy Exemplar’s 2024 PLEXOS WECC Zonal dataset
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Figure 6. Monthly System Wide Risk and Unserved Energy
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System-level results tell one part of the story; but not all BAs bear the same level of risk. Even within the same cooperating (sub)regions, different BAs have different availability of generation resources and transmission capacity connecting to other neighbors, as well as different resource mixes. Some rely on fossil fuels as their bulk generating fleet, while others are more reliant on renewable resources. These embedded characteristics differentiate each BA’s ability to reduce risk and prevent unserved energy.

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CONCLUSIONS
This study provides insight into the electricity reliability benefits of greater market and operational integration and coordination in the Western Interconnection. We show that larger footprints for a single ISO/RTO create larger reliability benefits during extreme events. Since these events are increasingly likely due to climate change and the evolution of both energy supply and demand in western BAs, the value of cooperation is greater today and in the future than in the past. Restructuring electricity markets, grid operations, and grid planning into a single West-wide ISO/RTO requires careful study and resolution of multiple issues, including governance, cost allocation, stakeholder participation, and incorporation of state policy goals. Our focus here is on reliability and we defer to other studies for the evaluation of other benefits and risks.

Simulating reliability impacts with power system optimization models is challenging because these models assume perfect information to optimize dispatch and constant frictions in trading energy between BAs even though the reality in wholesale markets is that information is imperfect and frictions can increase dramatically during stress events. In other words, the models behave as if an ISO/RTO exists, with some limited economic frictions, but in the real world, especially during stress events, system operations can divert substantially from the optimal outcome. As a result of this modelling challenge, we are cautious in interpreting our results and view them as illustrative and directional rather than a precise estimate of the reliability benefits of a larger, regional day-ahead market and operational structure.

Nevertheless, we show that growing the footprint of an ISO/RTO in the West has the potential to substantially reduce risks to reliability under extreme heat scenarios. By expanding an ISO/RTO framework beyond the current EDAM footprint, our work suggests that western BAs can substantially reduce the risks of rotating outages. This work thus complements earlier work on economic benefits and adds an additional dimension to the ongoing efforts to increase integration of electricity operations in the West.

Outside the scope of our work, but complimentary to it, is the need for a probabilistic analysis to show the current and future likelihood of system wide high intensity/long duration stress events under various climate change scenarios. Work of this nature is underway for California, conducted by the CEC. Further study examining the full complement of western BAs is crucial to understanding the full scope of the problem both today and as the West gets hotter and drier. The greatest challenges for the Western Interconnection occur when multiple areas experience extreme heat simultaneously and so are unable to rely on each other for normal and especially increased levels of energy imports. As illustrated in our case study, these challenges are most pronounced in the context of lower hydro availability due to drought, also a feature of recent experience as well as climate change projections.

Day-ahead and real-time markets are crucial mechanisms that allow BAs to match supply and demand within their territory but current approaches to handling extreme events that impact multiple BAs have real limitations. When extraordinary events impact a BA’s generating capacity and their trading neighbors suffer the same impact, a reliance on imports to avoid rolling blackouts is put in jeopardy. The results from the case study show that expansion of an ISO/RTO footprint is one way to substantially lower risk of unserved energy for customers. Our simulations show, qualitatively, how creation of a multi-state market can reduce risk, and that the bigger the market, the greater the risk reduction achieved. There are also other ways to reduce these risks and we would be the first to emphasize that all avenues for preserving bulk power system reliability in the face of the current challenges should be pursued.

Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 18 Attachment Staff Report Item 13I
States in the Western Interconnection are at the forefront of the energy transition. Large changes to systems as complex as the integrated yet massively distributed machine we call the Western Interconnection will always create some degree of risk. The West and in particular California play an important role in demonstrating that a high renewables, low emissions, and high reliability grid is achievable. In addition to the normal reasons for ensuring bulk power system reliability, policymakers should take all feasible steps to ensure that problems with reliability do not occur because such problems, unlike in Texas after winter storm Uri, are likely to be blamed on renewables. If such a western outage were to occur, this narrative would be likely to slow national and global progress towards zero carbon resources, even if the fault is misattributed.

In the end, the decision to pursue key changes to governance or markets, operations and planning that are beyond the scope of this work – especially a fully independent governance structure for a multi-state ISO/RTO – needs to be made by policymakers after considering a wide array of benefits and risks. This paper has shown that the benefits extend beyond simply economic ones – redistributing gains and losses between particular stakeholders in particular BAs – and extend to the reliability of the bulk power system in the West. That is not terribly surprising given that the physical system we inherit was built with deep cooperation and integration in order to assure reliability. Deepening that decades long collaboration by further integration of market structures and operations allows us to reduce risk of failure as we transition to a hotter, drier, but lower carbon future. This can’t be the only consideration in discussions around creation of an ISO/RTO, but it is a consideration that should be central to the ongoing discussions and decisions of energy policymakers.

Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 19 Attachment Staff Report Item 13I

LIST OF ABBREVIATIONS
ADS Anchor Data Set
BA Balancing Authority
BPS Bulk Power System
CAISO California Independent System Operator
CEC California Energy Commission
CPUC California Public Utilities Commission
EDAM Extended Day-Ahead Market
ERCOT Electric Reliability Council of Texas
FERC Federal Energy Regulatory Commission
GAO Government Accountability Office
GWh Gigawatt hour
IOU Investor-Owned Utilities
ISO Independent System Operator
NERC North American Electric Reliability Corporation
RTO Regional Transmission Organization
SPP Southwest Power Pool
USE Unserved Energy
VoLL Value of Lost Load
WECC Western Electricity Coordinating Council
WEIM Western Energy Imbalance Market
WEIS Western Energy Imbalance Service
WPP Western Power Pool
WRAP Western Resource Adequacy Program
Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 20 Attachment Staff Report Item 13I
APPENDIX A: BALANCING AUTHORITIES
Table 3. Balancing Authorities; participation in current market structures and simulated case studies
Markets Case Studies
Balancing Authority Abrev WEIM WEIS EDAM Markets + Case 1 Case 2 Case 3 Alberta Electric System Operator AESO B A A
Avista Corporation AVA X B A A
Arizona Public Service Company AZPS X X B B A
Balancing Authority of Northern California BANC X X A A A Bonneville Power Administration – Transmission BPAT X X B A A British Columbia Hydro Authority (Powerex) BCHA X B A A PUD No. 1 of Chelan County CHPD X B A A
PUD No. 1 of Douglas County DOPD B A A
El Paso Electric Company EPE X B B A
PUD No. 2 of Grant County GCPD X B A A
Idaho Power Company IPCO X X A A A
Imperial Irrigation District IID A A A
Los Angeles Department of Water and Power LDWP X X A A A Comision Federal de Electricidad CFE A A A
Nevada Power Company NEVP X A A A
NorthWestern Energy NWMT X B A A
PacifiCorp East PACE X X A A A
PacifiCorp West PACW X X A A A
Pacific Gas & Electric Company PGAE X X A A A
Portland General Electric Company PGE X X A A A
Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 21 Attachment Staff Report Item 13I
Markets Case Studies
Balancing Authority Abrev WEIM WEIS EDAM Markets + Case 1 Case 2 Case 3 Public Service Company of Colorado PSCO X B B A
Public Service Company of New Mexico PNM X B B A
Puget Sound Energy PSEI X X B A A
Salt River Project SRP X X B B A
Southern California Edison SCE X X A A A
San Diego Gas & Electric Company SDGE X X A A A
Seattle City Light SCL X B A A
City of Tacoma, Department of Public Utilities TPWR X X B A A Turlock Irrigation District TIDC X X A A A
Tucson Electric Power Company TEPC X X B B A
Valley Electric Association VEA X X A A A
Western Area Power Administration,
Colorado-Missouri Region WACM X B B A
Western Area Power Administration,
Lower Colorado Region WALC X X B B A
Western Area Power Administration,
Upper Great Plains West WAUW X B B A
Stanford Climate and Energy Policy Program
Grid Regionalization in the West: Reliability Benefits from Increased Cooperation in Electricity Markets and Operations 22 Attachment Staff Report Item 13I
Photo credit: Brenda Kean, iStock.

Attachment Staff Report Item 13I
For more information visit:
woods.stanford.edu
Stanford Woods Institute for the Environment
Stanford University
Jerry Yang & Akiko Yamazaki
Environment & Energy Building
473 Via Ortega, MC 4205
Stanford, CA 94305
[email protected]
This report was produced by the Climate and Energy Policy Program (CEPP) within the Stanford Woods Institute for the Environment. CEPP operates at the interface of policy analysis, academic research and education, with a focus on informing decision making on climate and energy law and regulation. For more information visit:
https://woods.stanford.edu/climate-and-energy-policy-program The Stanford Woods Institute for the Environment is part of the Stanford Doerr School of Sustainability.

Attachment Staff Report Item 13I

Ava Community Energy Board of DirectorsApril 16, 2025

Ava Community Energy Board of Directors
April 16, 2025