Comments on Draft 2024-2025 Transmission Plan

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

ACP-California values CAISO’s efforts to advance the necessary reliability-driven projects in the 2024-25 Transmission Plan. Planning for future load growth is challenging and the set of projects recommended by CAISO seem to offer significant reliability reinforcements and appear to help ensure the CAISO grid will be better positioned to accommodate future load growth. Given the delays that are being experienced in bringing transmission upgrades online, it is important to move these projects forward for approval expeditiously.

2. Please provide your organization’s comments on Frequency Response.

No comments at this time. 

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

ACP-California appreciates that CAISO has added additional information, and sought to increase transparency, around how it is planning for and considering MIC Expansions, including through increased transparency on the deliverability reservations for long lead-time resources. It will be important, going forward, to continue to improve the information provided on MIC expansion requests and MIC-related deliverability reservations.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

ACP-California appreciates CAISO’s diligent work to identify the three policy-driven projects recommended for approval in the 2024-25 Draft Transmission Plan. As CAISO is aware, moving necessary projects forward for approval in a timely manner is imperative given the long delays that are being experienced in bringing transmission projects online and, therefore, in energizing new clean energy resources. In order for California to be positioned to achieve its goals and ensure reliability, it is critical to approve needed policy-driven upgrades, such as those recommended for approval in the 2024-25 Draft Transmission Plan.

5. Please provide your organization’s comments on the Economic Assessment.

No comment at this time. 

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

ACP-California greatly appreciates the significant efforts CAISO has put into the 2024-25 Draft Transmission Plan and the continued improvements to the information provided in the transmission planning process.  One notable enhancement to this year’s draft transmission plan is additional transparency regarding CAISO’s process for reserving deliverability for long lead-time resources, in line with direction provided to CAISO by the CPUC. The 2024-25 Draft Transmission Plan specifies the long lead-time resources in the base portfolio and the amount of deliverability that is being reserved for them. ACP-California supports CAISO continuing to provide this information and encourages additional information be added, such that stakeholders can also understand how much of the reserved deliverability may already be allocated to resources in the queue and how much is available for resources in future clusters. Continuing to improve and expand on the information provided on MIC/deliverability reservations and other topics will continue to provide stakeholders with value and we appreciate CAISO’ ongoing efforts on this front.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Alameda Municipal Power (AMP) is a major wholesale customer of PG&E, with thousands of customers on Alameda Island, and is supplied by PG&E’s North Oakland and South Oakland transmission systems. AMP provides the following comments on CAISO Draft 2024-25 Transmission Plan proposals for North and South Oakland.

1. AMP supports the addition of transmission capacity in the North Oakland and South Oakland areas. AMP encourages CAISO and PG&E to attempt to accelerate the completion of the projects prior to 2032, prioritizing the completion of the North Oakland Reinforcement project.
2. AMP notes that the Oakland Clean Energy Initiative (OCEI) project is assumed to be operational in the studies for the North Oakland area. AMP continues to have concerns related to insufficient transmission capacity for the North Oakland transmission system due to the increased load forecast, with the Oakland Power Plant unit #2 already retired and the other two Oakland units expected to retire at Station C, and the storage component of the OCEI Project not yet completed. AMP requests that the CAISO conduct a planning assessment of the North Oakland system to ensure that any NERC violations without the 36 MW battery storage component of the OCEI project are identified and proposed mitigations are considered. AMP requests that CAISO include the results of this evaluation in the Final 2024-2025 Transmission Plan.
3. With the completion of the North and South Oakland capacity increase projects, please confirm that
   1. AMP load transfers will no longer be required to support the transmission system.
   2. The Special Protection Scheme (SPS) currently in place at Station C will be removed.

Accordingly, please update the discussion of the “North Oakland Reinforcement Project,” in the Final 2024-2025 Transmission Plan, providing clarification on the lack of need for the AMP load transfer and the removal of the existing SPS at Station C.

4. AMP requests that CAISO and PG&E coordinate with AMP to minimize load transfers prior to completion of the upgrades (and during construction), including the use of the OCEI storage, if available, to mitigate potential AMP load transfers.

Thank you for the opportunity to provide input on the transmission plan.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The Bay Area Municipal Transmission group (BAMx)^[1] appreciates the opportunity to comment on the Draft 2024-2025 Transmission Plan (Draft Plan, hereafter), dated March 31, 2025. The comments and questions below also address the material presented at the CAISO Stakeholder meeting on April 15, 2025. BAMx recognizes the tremendous amount of work the CAISO staff has completed in this planning cycle. BAMx also believes the CAISO staff must allow a corresponding amount of time to engage the stakeholders to explain the staff’s work.

Support for the Ames Distribution – Palo Alto 115 kV line and South Bay Reinforcement Projects

BAMx supports the CAISO staff’s recommendation to approve projects that are justified based on the NERC and CAISO reliability planning criteria violations in the near to medium term, especially when they are determined as cost-effective solutions relative to all the alternative mitigation solutions. Two such examples in the Draft Plan are the Ames Distribution – Palo Alto 115 kV line and the South Bay Reinforcement Project.

The Draft Plan accurately classifies the Ames Distribution – Palo Alto 115 kV line as a new diverse source to serve increasing electric demand and mitigate a major vulnerability of a common transmission corridor outage interrupting the entire city of Palo Alto load.[2] This project will serve as a new diverse source that eliminates a major vulnerability of a common transmission corridor outage.

The South Bay Reinforcement project will address P1-P7 overloads in the San Jose area on the 115 kV system. As noted in the Draft Plan, these upgrades will support the 500 kV supply for the Bay Area, the San Jose B – NRS 230 kV line, and the addition of the Metcalf 500/230 kV Transformer Bank[3]. BAMx recommends that CAISO consider aligning the in-service date of this project with the San Jose B – NRS 230 kV line project of 2030 so that the full 1,000 MW DC injection into the San Jose area can be achieved.

Conditional Support for the Julian Hinds-Mirage 230 kV Advanced Reconductor Project

SCE submitted six (6) different advanced reconductor projects in the 2024-2025 TPP request window. The CAISO staff found only one of those projects needed for reliability purposes, i.e., the Julian Hinds-Mirage 230 kV Advanced Reconductor project. This upgrade is expected to be partially subsidized by the U.S. Department of Energy (DOE) GRIP grant funding awarded through the CHARGE 2T project.[4] BAMx support for this project is conditional on the partial DOE funding. Until there is clarity on the DOE funding, this project should not proceed, and the CAISO should rely on the continued use of the Blythe Energy RAS to address potential reliability issues.

Moraga 230/115 kV Transformer Bank Addition Project

BAMx previously submitted comments to CAISO on November 27, 2024, seeking clarification on whether dynamic bus series reactors were considered as a potential mitigation measure for the P2 and P6 contingency drivers of this project need. However, no clear response was provided. To ensure a comprehensive evaluation of mitigation options, BAMx requests confirmation from CAISO in the Final Plan on whether dynamic bus series reactors were assessed as a solution for addressing the P2 and P6 contingency issues.

Need for Detailed Cost Information

BAMx appreciates the cost information provided by the CAISO for the Reliability and Policy-driven transmission projects recommended for approval. For three 230 kV (high side) bank addition projects recommended for approval, the estimated costs range from $40 million - $115 million[5]. While the bus work at any one of the three given substations can vary for a transformer addition, which could drastically impact the cost of a project, it would be useful for Stakeholders to be able to see the detailed cost information to understand truly why similar type transformers can range in costs from $40 million to $115 million. BAMx requests that CAISO provide the detailed cost information for the following bank addition projects recommended for approval:

• San Mateo 230/115 kV Transformer Bank Addition: $110 M
• Moraga 230/115 kV Transformer Bank Addition: $40 M
• Helm 230/70 kV Bank #2: $115 M

The Draft Plan identifies the need to replace the existing 40 kA-rated 500 kV GIS bus positions (numbers 1–3) with 60 kA-rated equivalent equipment at 500 kV GIS Serrano bus.[6] Given the scale and complexity of this GIS replacement project, the estimated cost is $183 million. Due to the significant financial investment required, BAMx would greatly benefit from a transparent breakdown of the cost components involved in this undertaking. To support an informed evaluation, BAMx requests that CAISO provide detailed cost information for the Serrano 500 kV SCD Mitigation.

[1] BAMx consists of City of Palo Alto Utilities and City of Santa Clara, Silicon Valley Power.

[2] Draft Plan, Appendix B, pp. B-142 - B-144, March 31, 2025

[3] See “South Bay Reinforcement Project”, pages 70-72, 2024-2025 Transmission Plan Draft, March 31, 2025

[4] See slides p. 42, 2024-2025 Transmission Planning Process: Draft Transmission Plan, April 15, 2025 stakeholder meeting.

[5] See Tables ES-1 & ES-2, pages 9-11, 2024-2025 Transmission Plan Draft, March 31, 2025

[6] See “Serrano 500 kV SCD Mitigation Project”, pages 50-51, 2024-2025 Transmission Plan Draft, March 31, 2025

2. Please provide your organization’s comments on Frequency Response.

During the Stakeholder meeting on April 15, 2025, CAISO clarified that the small-scale undamped frequency oscillations observed in the 2034 dynamics simulation frequency plots[1] stemmed from a generic dynamic model representing a localized future resource. BAMx concurs with CAISO’s overall system frequency observations and fully supports ongoing efforts to refine the dynamic models, ensuring more accurate responses for future resources. However, the Draft Plan does not explicitly address these small-scale undamped frequency oscillations. To enhance transparency and understanding, BAMx recommends that CAISO incorporate clarifying language explaining the origin of these oscillations and why they are deemed acceptable within the models presented in the Draft Report.

[1] See slides pp. 66, 68 & 69, 2024-2025 Transmission Planning Process: Draft Transmission Plan, April 15, 2025 stakeholder meeting.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comments at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Detailed cost estimates for the Helm 230/70 kV Bank #2 project recommended for approval

Please see the request for detailed cost estimates for this project in comments for item #1.

Deliverability Reservations for Long Lead-Time Resources

The CAISO has reserved deliverability for long lead-time generation resources to ensure that policy-driven transmission projects are used to deliver resources specified in resource plans.[1] The discussion during the April 15th stakeholder meeting highlighted a considerable amount of confusion among the stakeholders regarding the “downstream” impact of CAISO’s reservation of deliverability for long lead-time generation resources and its effects on other non-long lead-time resources. BAMx’s understanding is that the CAISO would approve policy-driven transmission to accommodate full capacity deliverability status (FCDS) resources assumed in the Baseline portfolio, which includes both the long lead-time and the non-long lead-time resource mix. Therefore, as long as the non-long lead time resource is represented in the Baseline portfolio, it would not be discriminated against any long lead-time resource for achieving FCDS based on the existing and potentially approved transmission infrastructure. For example, the 300 MW of solar and 529 MW of Li-Ion battery mapped at Eldorado would be treated similarly to the 1,500 MW of out-of-state (OOS) wind modeled at Eldorado to deliver them via existing and policy-driven transmission. We request the CAISO to confirm or clarify BAMx’s understanding of this topic in the Final Transmission Plan.

Support of the CAISO’s decision not to recommend policy-driven projects for the East of Pisgah Interconnection Area and GLW-VEA areas

BAMx commends CAISO for its comprehensive evaluation of multiple mitigation measures aimed at addressing the Eldorado–McCullough path constraint under on-peak conditions for the Base Portfolios. CAISO has identified four (4) potential transmission upgrades that could effectively mitigate the constraint.[2] At this stage, cost estimates have been provided for only one of the four proposed mitigation options, i.e., the Trout Canyon–Lugo 500 kV line. Additionally, this same network upgrade has been listed as a possible mitigation measure for the GLW-VEA constraint and the Lugo – Victorville 500 kV constraint. Given the evolving nature of these constraints and the resource portfolios, including the out-of-state wind, BAMx supports CAISO’s decision to maintain these mitigations as TBD to address the Eldorado–McCullough and GLW-VEA constraints in the current TPP cycle and further evaluate potential mitigation measures in future TPP cycles, ensuring a thorough and well-informed approach to addressing policy and deliverability challenges.

[1] Draft Plan, pp. 17-18, March 31, 2025

[2] Draft Plan, Appendix F, p. F-70, March 31, 2025

5. Please provide your organization’s comments on the Economic Assessment.

BAMx appreciates CAISO’s thorough economic evaluation across the 10- and 15-year planning horizons, which provides valuable insights into long-term transmission needs. As outlined in the Draft Plan, CAISO assessed the Pacific Transmission Expansion (PTE) project as a potential mitigation measure to address congestion within the LA Basin and across the Path 26 corridor. BAMx concurs with CAISO’s findings that, while the PTE project may offer partial relief for Path 26 congestion and other transmission constraints in the LA Basin area, its projected benefits do not sufficiently justify the overall cost of implementation[1].

Furthermore, during the CAISO Stakeholder meeting on April 15, 2025, CAISO reviewed the local capacity requirement (LCR) reduction benefit associated with the PTE project. BAMx agrees with CAISO’s conclusion that no identified alternatives provided sufficient economic justification to warrant an economically driven upgrade for Path 26 and LA Basin congestion mitigation at this time[2]. BAMx appreciates CAISO’s commitment to rigorous analysis and supports ongoing efforts to refine transmission planning approaches to ensure cost-effective, sustainable solutions

[1] See Table 4.9-1, page 144, 2024-2025 Transmission Plan Draft, March 31, 2025

[2] See slides pp. 112-113, 2024-2025 Transmission Planning Process: Draft Transmission Plan, April 15, 2025 Stakeholder Meeting.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

During the Stakeholder meeting on April 15, 2025, CAISO discussed the role of Grid Enhancing Technologies (GETs) in the development of corrective action plans to address overload issues. The suite of GETs evaluated included advanced conductors (with high-temperature, low-sag characteristics), dynamic line ratings, power flow controllers, and topology optimizations—all of which were considered as potential mitigation measures for multiple projects recommended for approval in the Draft Plan. However, the Draft Plan lacks clarity regarding the methodology used to evaluate these technologies and how they were assessed relative to various reliability and policy-driven transmission upgrades that have been proposed for approval. To ensure transparency and a comprehensive understanding of the evaluation process, BAMx requests that CAISO provide specific details on the assessment of GETs for the following proposed projects in the Final Plan.

• Coronado Island Reliability Reinforcement Phase I;
• Coronado Island Reliability Reinforcement Phase II;
• Konocti-Eagle Rock 60 kV Reconductoring Project;
• San Miguel New 70 kV Line Project; and
• West Fresno 115 kV Voltage support project.

BAMx appreciates the opportunity to comment on the CAISO Draft 2024-25 Transmission Plan.  BAMx also appreciates the staff’s willingness to work with the stakeholders in the process to more fully develop it.  We hope to work with the CAISO staff to continue to improve the Transmission Planning Process.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The California Community Choice Association’s (CalCCA’s) comments on the 2024-2025 Draft Transmission Plan are included in Section 6, below.  

2. Please provide your organization’s comments on Frequency Response.

CalCCA has no comments at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

CalCCA has no comments at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

CalCCA has no comments at this time.

5. Please provide your organization’s comments on the Economic Assessment.

CalCCA has no comments at this time.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

(1)        Next Steps on the High Gas Retirement Sensitivity Should be Pursued to Identify the Most Cost-Effective and Feasible Mitigation Solutions

CalCCA applauds the California Independent System Operator’s (CAISO’s) for its diligent work on the 2024-2025 Draft Transmission Plan (the Transmission Plan). The Transmission Plan plays a significant role in meeting the state’s clean energy goals, ensuring grid reliability, and interconnecting new resources.

CalCCA greatly appreciates the CAISO conducting the high gas retirement sensitivity. It is critically important that the CAISO, the California Public Utilities Commission (CPUC), and all stakeholders understand resource and transmission needs under a scenario with significantly less gas usage.  The sensitivity study focuses on identifying transmission needs with the retirement of 5.4 GW of natural gas by 2034, and 12.3 GW of by 2039. The CAISO identifies increases in reliability constraints, resource deficiencies, and local capacity requirements in local areas with meaningfully high retirement portfolio scenarios. These results are informative because when these conditions arise, the result may be that without new resources in the local area or transmission to reduce the local constraint, resources that want to retire in the local area cannot due to a reliability need.

The next step, therefore, should be for the CAISO and the CPUC to evaluate mitigations to resolve the deficiencies that arise when emitting resources retire. Local reliability needs are responsible for retention of some of the most polluting generation in the state, undermining the state’s decarbonization and environmental justice goals. Addressing local reliability needs is a complex problem requiring coordination between CAISO and the CPUC to ensure the most cost-effective solution. There are two options to address a local reliability need: (1) having sufficient generation physically located within the local area; or (2) having sufficient transmission built to relieve the local area constraints and allow generation outside the local area to be delivered to the load within the local area. The decision of whether to mitigate through new local resources or new transmission requires an assessment of cost-effectiveness, and feasibility given land use considerations. This next step of evaluating mitigation options is necessary to support the fast-approaching Senate Bill 100[1] target of zero-carbon resources supplying 100 percent of electric retail sales to end-use customers by 2045. Robust upfront planning focused specifically on how to reliably phase out local carbon-emitting resources is crucial.

(2) Transparency on TPD Reservations and Downstream Impacts Should be Provided

CalCCA agrees with stakeholders that the CAISO should increase transparency in transmission plan deliverability (TPD) reservations and their downstream impacts. TPD reservations can result in interim deliverability constraints that affect project viability and deliverability allocations.

As recommended by Sonoma Clean Power Authority and Redwood Coast Energy Authority, CalCCA recommends that the CAISO:

• Provide substation-level mapping of all TPD reservations, including those tied to offshore wind, geothermal, and out-of-state resources;
• Indicate how much capacity has been reserved vs. allocated in each area;
• Clarify the implications on MIC and interconnection queue limitations in downstream substations; and
• Incorporate these transparency elements into the final transmission plan and stakeholder deliverables for the 2025–26 Transmission Planning Process.

[1]            Senate Bill 100 (SB 100) (De León, Chapter 312, Statutes of 2018): https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201720180SB100.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

CPUC Staff have no comments at this time on Reliability-driven Projects Recommended for Approval.

2. Please provide your organization’s comments on Frequency Response.

CPUC Staff have no comments at this time on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

CPUC Staff have no comments at this time on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Regarding the East of Pisgah Interconnection Area and the Lugo-Victorville 500 kV constraint area, CPUC staff appreciate the update in the draft Transmission Plan noting that CAISO will continue to evaluate both potential new transmission upgrades and alternative transmission solutions to address the deliverability issues identified in the studies.  

CPUC staff also appreciate and support the CAISO’s proposal in the draft Transmission Plan to not approve any upgrades for integrating the additional out-of-state resources from Wyoming and New Mexico beyond what can be delivered on the already approved and in-development new transmission lines, and the plan to pursue additional analysis and a special study of the various routes and combinations for out-of-state wind amounts. This is consistent with the CPUC requests in D.25-02-026.   We look forward to continued discussion and collaboration with CAISO staff as CPUC staff also pursue additional modeling analysis.

CPUC staff also appreciate the guidance in the draft Transmission Plan for reducing the amount of storage resources mapped in the Greater Bay and other areas, rather than triggering transmission upgrades.  We look forward to working with CAISO staff to identify alternative busbars for generic battery storage that would help minimize overall resource and transmission costs. 

5. Please provide your organization’s comments on the Economic Assessment.

CPUC Staff have no comments at this time on the Economic Assessment.
 

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Energy Division staff (CPUC Staff) of the California Public Utilities Commission (CPUC) develop and administer energy policy and programs to serve the public interest, advises the CPUC, and ensures compliance with CPUC decisions and statutory mandates. Staff provide objective and expert analyses that promote reliable, safe, and environmentally sound energy services at just and reasonable rates for the people of California.^[1]  Further, Staff advocate on behalf of California ratepayers at the Federal Energy Regulatory Commission (FERC), under whose jurisdiction CAISO’s transmission planning falls.

The CPUC’s Integrated Resource Planning (IRP) process is designed to ensure that load serving entities (LSEs) in the CPUC’s jurisdiction meet targets that allow the electricity sector to contribute to California’s economy-wide greenhouse gas (GHG) emissions reductions at least cost while maintaining electric service reliability and meeting other state policy goals. Accordingly, in addition to developing resource portfolios that result in electrical transmission upgrades through the CAISO’s TPP, the IRP process is crucial to meeting the electric sector’s clean energy goals established in SB 100 and SB 1020, and statewide emissions reductions goals established in AB 1279. 

Staff appreciate this opportunity to discuss affordability and cost containment measures in the 2024-2025 Draft Transmission Plan. Staff also appreciate CAISO’s efforts to collaborate with the CPUC on this comprehensive transmission analysis, which is essential to the state’s clean energy goals.

Cost Containment and Competitive Solicitations

Energy Division staff appreciate the CAISO’s efforts to open eligible projects to the competitive solicitation process. The trend has continued where a small number of competitive projects represent a significant portion of all project costs recommended for approval (see the table below). The two projects eligible for competitive solicitation in the 2024-2025 Draft Transmission Plan (i.e., new 500 kV and 230 kV lines in the South Bay area) make up approximately 19% of the total estimated costs, which is less than in recent years, but still significant.

*Total costs were determined by the highest estimate (when applicable) of each project’s cost

**Percent was calculated using the figure from Column 4 and the highest estimate (when applicable) of all projects approved or recommended for approval in each Transmission Planning Year

With greater focus statewide on affordability issues related to utility rates, it is important that the CAISO encourages and considers, to the greatest extent possible, cost containment measures in its competitive solicitation process. While cost management is already a category considered in the selection process, it is increasingly important that those entities being awarded these typically large projects include financing methods, cost caps, and even ownership arrangements that lessen the burden on ratepayers where possible.

This suggestion is not only relevant in the context of current cost trends but is also consistent with Public Utilities Code § 345.5(b)(2), which directs CAISO to manage the transmission system in a manner consistent with, “Reducing, to the extent possible, overall economic cost to the state’s consumers.”

IRP Development of the Preferred System Plan Portfolio for 2024-2025 TPP

CPUC staff would also like to provide broad comments on the draft Transmission Plan. This annual TPP assessment by the CAISO utilized the “2023 Preferred System Plan” (PSP) portfolio of generation and storage resources that was adopted by the Commission in D.24-02-047.  It is based on modeling to optimize clean energy resource procurement and reflects a cost-effective system plan to reach aggressive GHG emissions targets, while ensuring reliability.

Specifically, this base portfolio included 76 GW of new installed capacity by 2039, beyond existing resources and resources already contracted or under development. If realized, this fleet would drive down greenhouse gas emissions by 28 million metric tons (MMT) compared to 2020 electric sector emissions in the CAISO area. This translates to a 58% reduction, on a practical trajectory to achieve a carbon-free CAISO grid by 2045. Notably, this portfolio was developed first with an aggregation of the individual Integrated Resource Plans (IRPs) of all Load Serving Entities (LSEs), reflecting the resource preferences of those LSEs through 2035.  Then, CPUC staff augmented the resources using modeling analysis to ensure reliability standards and GHG targets were met through 2035, and to extend the resource planning timeframe out to 2039. 

IRP Process Develops Least Cost Portfolio that Considers Expected Transmission Costs

As explained in CAISO’s presentation (slide 11) at the April 15, 2025 stakeholder meeting, the CPUC’s resource portfolio and the CEC’s demand assumptions are the key inputs driving the transmission infrastructure that CAISO staff has identified for development within the 2024-2025 Draft Transmission Plan. Importantly, the CPUC’s modeling that developed this base portfolio takes into account the capital costs of new resources, as well as any necessary new transmission infrastructure and the costs of reliably operating the grid. Thus, the CAISO’s analysis and the resulting identification of transmission projects needed to accommodate this rapid build-out of clean energy resources represent a cost-effective path toward the achievement of the state’s goals by 2045. 

IRP Process Contributes to Efficient Transmission Build-out

This draft Transmission Plan identifies need for 28 reliability-driven transmission projects; the Draft Transmission Plan explains that “the increased rate of load growth in the most recent load forecast associated with building and other electrification, data-center growth, and transportation electrification results in significant reliability-driven needs in this year’s transmission plan.”

This draft Transmission Plan identifies only three policy-driven transmission projects, with an estimated $289.5 million cost. Last year’s 2023-2024 Transmission Plan included seven policy-driven projects totaling $4.9 billion (including North Coast offshore wind-related transmission).  The 2022-2023 Transmission Plan included 21 policy-driven projects with an estimated total cost of $5.53 billion.

This significant reduction in policy-driven projects in this draft Transmission Plan compared to previous TPP cycles is a result of the consistency in the development and mapping of future resource portfolios in recent years.

We note that the base portfolios that were analyzed over the past three TPP cycles are fairly similar, using similar policy targets and load assumptions, and reflect the potential for increased electrification occurring in other sectors of California’s economy. Thus, as could reasonably be expected, CAISO’s previously approved upgrades in the 2022-2023 and 2023-2024 TPP cycles meet the transmission needs in many locations for resources in the portfolio that was used as the base case for this 2024-2025 TPP.  The Commission (in D.23-02-040) encouraged getting this kind of a “head start” on needed transmission projects wherever possible, noting the longer development lead times for major transmission projects. 

This unique coordination between state agencies and the CAISO is further demonstrated by the CPUC’s busbar mapping methodology, which has been developed with considerable stakeholder input.  Busbar mapping helps to minimize overall costs to ratepayers by the mapping of expected resources by the working group of CPUC, CAISO, and CEC staff to areas with current or future transmission capacity, as identified by the CAISO’s TPP. 

We note that future TPP cycles may well result in identification of more policy-related transmission needs.  The point we emphasize here is that a less rigorous process for planning resources would likely result in inefficiencies, such as transmission that is not linked closely with the IRP-identified resources that best meet the state’s goals. CPUC staff will continue to work with CAISO staff to continually improve this rational, integrated way to build out the necessary renewable electricity infrastructure that will power California’s economy in the coming decades. 

Summarizing Comments

Overall, CPUC staff greatly appreciates CAISO’s efforts to produce this comprehensive transmission analysis, which is extremely important for reliability while achieving the state’s clean energy goals. We support this 2024-2025 Draft Transmission Plan in which the CAISO has identified the transmission buildout currently needed to reliably integrate the resource mix that will keep the state on the optimal and most cost-effective pathway to meet established state goals.

[1] More information about the CPUC Energy Division is available at: https://www.cpuc.ca.gov/about-cpuc/divisions/energy-division

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) provides these comments on the California Independent System Operator’s (CAISO) 2024-2025 Transmission Planning Process – Draft Transmission Plan and stakeholder meeting on April 15, 2025.  Cal Advocates is an independent ratepayer advocate with a mandate to obtain the lowest possible rates for utility services, consistent with reliable and safe service levels and the state’s environmental goals.[1]

1. Cal Advocates Recommends CAISO and its Participating Transmission Owners Provide Itemized Project Cost Estimates and the Length of Proposed New and Reconductored Lines for All Proposed Projects.  

At the April 15, 2025 Draft 2024-2025 Transmission Plan stakeholder meeting,  CAISO and the Participating Transmission Owners (PTOs) did not provide information on the cost for individual project components or consistently provide the length of new and reconductored lines.[2]  These deficiencies obscure the cost of individual project scope items.  Without this information, it is difficult for stakeholders to compare the proposed project descriptions to PTO cost benchmarks to confirm whether the project costs estimates are reasonable.

For example, for large multi-part projects like the Pacific Gas and Electric Company’s (PG&E) North Oakland Reinforcement Project, which has an estimated cost range of $564 - $1,167 million,^[3] it is unclear what share of the cost is attributed to each individual component.  Thus, a cross-comparison of the individual elements of this project is not possible.[4]  Similarly, one cannot confirm if the Southern California Edison Company (SCE) Serrano 500 kV (kilovolt) Short Circuit Duty Mitigation project costs are just and reasonable using the SCE’s per unit cost guide.  This is because SCE’s description lacks an itemized list of upgrades.[5]  Also, the San Diego Gas & Electric Company (SDG&E) Downtown Reliability Reinforcement project was not described in sufficient detail to estimate costs using SDG&E’s per unit cost guide.[6]  These discrepancies appear to indicate that there are project scope items that are not captured in the Draft Plan descriptions.

Federal Energy Regulatory Commission (FERC) Orders No. 890 and the proceeding transmission planning Order No. 1000-A affirm that transmission providers must provide sufficient details in their regional transmission planning process to allow one to replicate the results of the planning study.[7]^,[8] 

To comply with the FERC Order No. 890 and 1000-A’s openness and transparency transmission planning principles, Cal Advocates recommends that CAISO include the costs for each component of proposed projects and the approximate length of new transmission lines or reconducted lines for every proposed project in CAISO’s Draft 2024-2025 Transmission Plan. 

2. Cal Advocates Recommends CAISO and PG&E Clarify the Cost Assumptions Used for the San Jose B NRS 230 kV Line.

The San Jose B NRS[9] 230 kV line project involves installing a new line in a densely urban area and for this reason would likely involve a new substation and line undergrounding.  The cost range for this project seems low at $500 to $700 million if it involves a new line and substation as well as line undergrounding in an urban area.  The project description did not include a detailed project scope or cost information for the proposed project components.  The Commission should require CAISO and PG&E provide confirmation of whether the project scope includes installing a new substation and undergrounding the new line, and cost estimates for these two project components.

3. Cal Advocates Recommends CAISO Continue to Study the Greater Bay Area 500 kV Transmission Reinforcement Project to Confirm it is Cost-Effective.

The Greater Bay Area project involves building a new line from the Maning to Metcalf substations in a new utility right-of-way.  Cal Advocates recommends that CAISO determine if the proposed Greater Bay Area project cost can be reduced through an alternative design that utilizes an existing utility right-of-way versus the proposed new line in a new utility right-of-way.[10]  In the interest of transparency, Cal Advocates also requests CAISO and Pacific Gas and Electric Company (PG&E) provide the project’s impact on the local capacity requirement (LCR).  Notably, while CAISO mentioned that the project would have LCR benefits, it did not share the results of its LCR impact analysis.[11]  Since this project is intended to address an expected need in the 15–20-year timeframe, CAISO and PG&E have ample time to confirm the proposed project is the least cost best fit solution. 

4. Cal Advocates Recommends PG&E Explain Why its Proposed Moraga 230/115 kV Transformer Bank Addition project is Significantly Less Than the Proposed San Mateo 230/115 kV and Metcalf Substation 500/230 kV Transformer Bank Addition projects.

The scopes for PG&E’s three transformer bank addition projects are nearly the same, but the Moraga transformer project has an estimated cost that is significantly less than the others proposed:[12] the Metcalf Transformer project cost estimate, at the high range, is $182 million, the San Mateo Transformer project cost estimate is $110 million, and the Moraga Transformer project cost estimate is $40 million.[13]  Cal Advocates recommends that PG&E explain why there is such a significant cost discrepancy between these proposed transformer bank projects.

5. Cal Advocates Recommends SCE Confirm the Net Costs of the Julian Hinds-Mirage 230 kV Advanced Reconductor Project.

It appears the Department of Energy will subsidize a portion of the total project cost of the Julian Hinds-Mirage 230 kV Advanced Reconductor Project.[14]  However, CAISO and SCE did not provide the remaining project cost that would be assigned to California ratepayers.  This information should be provided to determine the total impact of the Transmission Plan projects on ratepayers’ transmission access charge.

6. Cal Advocates Recommends that CAISO and Its PTOs Provide More Complete Per Unit Cost Guide.

Cal Advocates discovered gaps and inconsistencies in the PTOs per unit cost guides when analyzing the cost estimates of the proposed projects.  To explain, while SDG&E’s Coronado Island Reliability Reinforcement Phase 1 and Phase II projects include building new lines and reconductoring existing lines underwater, neither of these cost estimates are available in SDG&E’s Per Unit Cost Guide.  This was confirmed in the April 15, 2025 stakeholder meeting.[15]

SCE also did not provide an estimate for line reconductoring in its per unit cost guide.  This prevents Cal Advocates from determining whether the costs of reconductoring projects are just and reasonable, such as SCE’s Julian Hinds-Mirage 230 kV Advanced Reconductor project.  

[1] Cal. Pub. Util. Code, § 309.5.

[2] 2024-2025 Transmission Plan Process: Draft Transmission Plan (Presentation), April 15, 2025.

[3] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at pp.62-63. The North Oakland Reinforcement Project would rebuilding the two Sobrante-Grizzly-Claremont #1 and #2 115 kV lines into four lines, two of which would connect to Oakland D and Oakland L Substations through new underground (UG) cable sections; reroute the Moraga-Oakland X #4 line to connect to Oakland C via a new UG cable section; convert Oakland C to Gas-Insulated Switchgear (GIS); and replace the Oakland C-Oakland X UG cable with a larger size cable.

[4] PG&E Draft 2025 Per Unit Cost Gude, April 02, 2025. Calculations made using assumptions from PG&E Draft 2025 Per Unit Cost Guide, available https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/Participating-transmission-owner-per-unit-costs-2025.

[5] 2024-2025 Transmission Plan Process: Draft Transmission Plan (Presentation), April 15, 2025, Slide 43.

[6] For Example, the Vine Substation expansion portion of the project estimated at $385 to $475 million is significantly higher than the per unit cost guide indicates.  For Reference, Vine Substation Expansion components: Loop TL23029 Old Town – Mission into Vine substation ($13,641,000) and install a 230/69 kV 350 MVA bank ($12,998,000), totaling $26,639,000. The Draft TPP estimated $385,000,000 to $475,000,000. Cost estimates are taken from SDG&E’s Per Unit Cost Guide for Complete Loop-in Substation and New 230/69 kV Transformer Bank. Per Unit Cost Guide available at https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/Participating-transmission-owner-per-unit-costs-2025.

[7] Order No. 890, FERC Stats. & Regs. ¶ 31, 241 item 471 at pp. 269-270.

[8]  Order No. 1000-A, FERC Stats. & Regs. ¶ 61,132, item 281 at p. 211.

[9] NRS is the name of an existing substation in San Jose.

[10] 2024-2025 Transmission Plan Process: Draft Transmission Plan (Presentation), April 15, 2025, at Slides 34.

[11] California ISO 2024-2025 Transmission Planning Process Update Meeting, April 15, 2025, Customized Energy Solutions, at p. 10.

[12] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at pp.45, 62 and 68.

[13] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at pp.45, 62 and 68.

[14] 2024-2025 Transmission Plan Process: Draft Transmission Plan (Presentation), April 15, 2025, CAISO at Slide 42.

[15] Based on the SDG&E Per Unity Cost Guide the Coronado Island Reliability Reinforcement Phase I reconductor project cost is (~1.5 miles) x (8,640,000 $/mile) = $12,960,000, and the  Coronado Island Reliability Reinforcement Phase II reconductor project cost is (~3 miles) x (2,700,000 $/mile) = $8,100,000. In contrast, the draft 2024-2025 Transmission Plan estimated Phase 1 costs at $42,000,000 and Phase 2 costs at $66,000,000. For the estimates, distance was estimated between substations and per unit costs are for a new transmission line of high complexity (Phase I) and reconductoring a transmission line of high complexity (Phase II). Per Unit Cost Guide available at: https://www.caiso.com/library/current-cost-guides.  Thus, If Cal Advocates uses SDG&E’s “high complexity estimates” for new transmission lines and reconductoring, the estimated costs are still significantly lower than the cost estimates provided in the draft Transmission Plan

2. Please provide your organization’s comments on Frequency Response.

Cal Advocates has no comments on the Frequency Response study results at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

Cal Advocates has no comments on the Maximum Import Capability Expansion requests at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

The project descriptions for the proposed policy projects that involve reconductoring do not confirm whether PG&E will use advanced or traditional conductors for the projects.  Advanced conductors can carry higher power loads (50-100% more) with reduced thermal sag, improved efficiency, and greater resilience compared to traditional conductors.[1]  Cal Advocates requests CAISO evaluate the impact of using advanced conductors for the proposed reconductoring projects because this technology could be a better investment for the state’s long-term needs.  FERC Order No. 1920 also requires transmission providers to more fully consider alternative transmission technologies such as advanced conductors for meeting long-term transmission needs.[2]

[1] Incorporating GETs and HPC into Transmission Planning under FERC Order 1920, The Brattle Group, April 2025 at p. 11.

[2] Order No. 1920, FERC Stats. & Regs. ¶ 61,068, item 8 at p. 13.

5. Please provide your organization’s comments on the Economic Assessment.

Cal Advocates has no comments on the Economic Assessment study results at this time.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Recommendations for Data Center Driven Projects

There are five PG&E projects in the 2024-2025 Transmission Plan that are proposed in part to address the new data center load. These projects are: (1) the South Oakland Reinforcement,[1] (2) Greater Bay Area 500 kV Transmission Reinforcement,[2] (3) Metcalf 500/230 kV Transmission Bank Addition,[3] (4) San Jose B-NRS 230 kV Line[4] and (5) the Ames Distribution – Palo Alto 115 kV Transmission Line projects.[5]  The total costs for these projects is significant and ranges from $908 million to $1,416 million.[6]  The discussion on these projects in the 2024-2025 TPP did not confirm whether demand response or energy efficiency were considered to reduce the expected new data center load during critical need hours.  In 2013 CAISO committed to considering whether preferred resources, such as energy efficiency, demand response, renewable generation and energy storage, could mitigate or offset the need for new transmission.[7]   Cal Advocates recommends CAISO determine whether the scope of the projects mentioned could be reduced if the expected new data centers were incentivized to participate in demand response programs or to implement the range of possible energy efficiency upgrades.

If the expected data centers participated in demand response programs, they would be incentivized to power down or rely on their own energy storage systems that provide backup power during critical need hours.  Data centers’ energy storage systems could also rely on CAISO’s excess midday solar energy supply.  Energy efficiency upgrades could also reduce data center load needs through new technologies including plant cooling technologies.  Data centers could also reduce their load needs by co-locating with generation or connecting to a microgrid.[8]^,[9]  These options were identified as data center load shifting strategies that could reduce data center load when the grid is constrained at the February 26, 2025 California Energy Commission’s workshop on California’s Economic Outlook.[10]

Recommendations for the Consideration of Dynamic Line Rating technologies for new lines and upgrade to existing lines in the Transmission Plan

Cal Advocates notes that none of the proposed line upgrades or new lines project descriptions in the 2024-2025 Draft Transmission Plan include a Dynamic Line Rating (DLR) technology.  FERC Order No. 1920 requires transmission planners to consider DLR technologies when evaluating new regional transmission lines or upgrades to existing transmission lines.[11]  DLR technologies can enhance the capacity of existing and new lines by providing real time information on transmission line conditions.  Energinet in Denmark reported that after installing DLR technologies, it observed an increase in overhead line capacity 90% of the time.[12] 

DLRs can also aid in responding to power shut-off events by helping to identify available transmission capacity on surrounding lines to deliver power.

Cal Advocates recommends the CAISO PTOs pilot DLR technologies in combination with the proposed projects in areas where there are significant public safety power shut-off events.

[1] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at p. 65.

[2] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at p. 67.

[3] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at p. 68.

[4] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at p. 69.

[5] CAISO 2024-2025 Transmission Plan - Draft, March 31, 2024 at p. 74.

[6] CAISO 2024-2025 Transmission Plan Process: Draft Transmission Plan (Presentation), April 15, 2025, at Slides 29 and 32-35.

[7] Consideration of Alternatives to Transmission or conventional generation to address local needs in the transmission planning process ( Paper), CAISO, September 4, 2013 at p. 7. http://www.caiso.com/Documents/Paper-Non-ConventionalAlternatives-2013-

2014TransmissionPlanningProcess.pdf

[8] https://www.microgridknowledge.com/data-center-microgrids/article/33038792/microgrids-help-create-data-centers-that-dont-break-the-grid-or-the-environment

[9] https://www.microgridknowledge.com /data-center-microgrids/article/55019485/how-power-hungry-data-centers-and-large-industries-are-turning-to-microgrids-on-and-off-grid

[10] IEPR Commissioner Workshop on California’s Economic Outlook recording at 4:21 – to 4:48.

[11] Order No. 1920, FERC Stats. & Regs. ¶ 61,068, item 1198 at p. 856.

[12] https://www.smart-energy.com/industry-sectors/energy-grid-management/energinets-dynamic-line-rating-improves-overhead-capacity-by-up-to-30/ 

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Cal Western has no comments on reliability - driven project recommended for approval

2. Please provide your organization’s comments on Frequency Response.

Cal Western has no comments on frequency response

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

Cal Western has not comment on maximum capacity expansion requests

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Cal Western has no comments on policy-driven projects recommended for approval

5. Please provide your organization’s comments on the Economic Assessment.

California Western Grid Comments on California ISO

2024-2025 TPP Draft Transmission Plan

April 29. 2025

California Western Grid Development LLC (“Cal Western”) appreciates the opportunity to submit comments on the March 31, 2025, CAISO 2024-25 TPP Draft Transmission Plan (Draft Plan) and the April 15, 2025, Stakeholder Meeting.

We appreciate all the work CAISO staff has done to create the Draft Plan and are grateful that the Draft Plan includes critical information and analysis Cal Western requested in CWGs December 20, 2024, TPP Comments. Specifically, CAISO has included critical production cost modelling estimates of fossil plant utilization in the 2034 and 2039 base resource portfolios, provided transparency on  the assumed cost of Local RA and System RA CAISO used in its economic studies and created a sensitivity for economic evaluation of the Pacific Transmission Energy Project (PTEP) that assumes Gas Plants are the marginal local RA resource for the LA Basin and utility scale batteries as the marginal system RA Resource.

Cal Western has four specific requests related to the CAISO Economic Assessment:

1. Cal Western urges CAISO to share with stakeholders critical fossil generation-related assumptions and gas plant utilization findings in all future TPP cycles. Especially the costs CAISO assumes for Local RA and System RA, the gas plant utilization for the system and transmission constrained local areas derived from production cost modelling of CPUC resource portfolios.  CWG also urges CAISO to continue to evaluate capacity benefits in transmission constrained local areas assuming gas plants are the source of local RA and new utility scale batteries are the source of system RA

CAISO should also update its cost assumptions for continued operation of gas plants in local areas.  In recent years the market price of RA procurement in local areas has far exceeded ‘cost of the owning and maintaining’ estimate by the CPUC and CEC at least partly owing to growing market power of generators in local areas.  CAISO should work with CPUC and CEC to determine if ‘market price paid’ for local RA capacity is a better estimate than ‘cost of owning and operating’.

2. Work more closely with CPUC Staff to assist in developing resource plans for the 2025-26 TPP and all future IRP / TPP cycles that meet emission targets and legislative requirements.  The CPUC RESOLVE and SERVM models do not produce reliable forecasts of gas utilization[1] and emissions and those CPUC models are not capable of forecasting gas utilization in transmission constrained local areas[2].   As a result, the CPUC Base Portfolio is intended to substantially reduce gas use, however, the failure of CPUC’s model to accurately forecast gas usage and failure to recognize local transmission constraints that prevent other resources from replacing gas use is causing the CPUC  to dramatically under-estimate  resulting gas use and failing to comply with Senate Bill 887 requirements to substantially reduce gas use in transmission constrained local areas by 2035.[3]  

Based on its Resolve model, the CPUC estimated that the base case in its 2024-2025 resource portfolios transmitted by CPUC Decision 24-02-047 was intended to produce “significant reductions (of approximately 70 percent) in natural gas plant utilization within the CAISO area by 2035 and further reductions (of approximately 90 percent) over the full 15-year planning.”^[4]

The CPUC resource portfolios recently transmitted to CAISO for use in the CAISO 2025-26 TPP again relied on the CPUC RESOLVE model to claim those portfolios meet emission targets and comply with State mandates.  The CAISO production cost modeling is likely to show the proposed 2025-26 TPP resource portfolios will fail to meet emission targets. This is all the more serious given the 10 years or more lead time for new transmission needed to deliver new clean resources and remove the local transmission constraints by the SB 887 2035 deadline.

The CAISO PLEXOS model has the granularity to forecast gas utilization in transmission constrained areas and is a more accurate forecasting tool for system wide emissions for each CPUC resource portfolio. CAISO modelling capabilities must be made available to CPUC to assist the CPUC in producing resource portfolios that specify gas utilization targets and meet legislative requirements of SB 887, SB 350 and SB 100.  This cooperation should start immediately as the CPUC has transmitted its Base Portfolio to CAISO for the 2025-26 TPP.

While there is not time for wholesale revision of the CPUC resource portfolios for the 2025-26 TPP,  CWG urges creative inter-agency solutions that allow the CAISO to get started on no regrets long lead time transmission solutions, especially transmission needed to comply with SB 887 in transmission constrained local areas such as the LA Basin and Fresno where SB 887 has placed priority due to poor air quality.[5]

3. Expand the list of benefits that are included in CAISO TEAM cost benefit analysis.  At a minimum all transmission and non-transmission alternatives should include credit for reduction criteria pollutants (Nox, Sox, PM2.5), credit for reducing impacts on underserved communities, credit for reducing curtailment of solar and wind generation in both CAISO and throughout the WECC. Cal Western urges CAISO to begin by expanding the list of benefits in its cost benefit analysis in the 2024-25 TPP Draft Report and all future TPP cycles.

4. Western urges the CAISO to improve its calculation of ISO ratepayers’ production benefits which are currently defined as: (ISO Net Payment of the pre-upgrade case) – (ISO Net Payment of the post-upgrade case)

It appears the CAISO calculation of ‘ISO Net Payment’ assumes all payments CAISO receives come out of generator profits and none of those payments are recovered from ratepayers as LSE’s pass the cost of power purchase agreements on to ratepayers. It also appears the CAISO assumes that payments it receives from LSEs or scheduling coordinators for congestion relief and in Congestion Revenue Right (CRR) auctions are not passed on to ratepayers.  CWG questions this assumption.

Just because CAISO receives a payment from generators or scheduling coordinators and credits it back to CAISO ratepayers does not mean the ratepayers enjoy that cost reduction on their total electricity bill.  CAISO must reconsider how it calculates those benefits, fully mindful of the fact that many of the ‘net payment’ revenues the CAISO receives are passed on to and recovered from ratepayers in rate recovery mechanisms at the CPUC. The approach CAISO uses undervalues congestion relief that new transmission solutions provide.

CWG urges CAISO to improve its calculation of ‘net payment’ revenues in this 2024-25 TPP and all future TPP cycles.

Thank you for the opportunity to submit these comments for your consideration.

Respectfully submitted on behalf of Cal Western.

By Marty Walicki

Managing Member

(240) 277-8968                                                                                                           April 29, 2025.

[1] For example, CPUC Decision D.24-02-047 transmitting portfolios to CAISO for the 2024-25 TPP estimated the gas plant utilization for the 2034 base resource portfolio would be 18,080 GWh.  CAISO PLEXOS model showed gas utilization for the same portfolio would be 36,542 GWh. 

[2] According to CPUC Decision 24-02-047:

“Conducting locational analysis within the context of IRP is difficult, because much of our analysis historically has been focused at the system level. The CAISO, however, has the ability to do much more granular and detailed analysis of local reliability needs. Therefore, we find it prudent to ask the CAISO to conduct this sensitivity analysis for the 2024-2025 TPP.” atPage 79

[3] Senate Bill 887 (2022) established the need for California state agencies to “provide resource projections that, combined with transmission capacity expansions, are expected to substantially reduce, no later than 2035, the need to rely on nonpreferred resources in local capacity areas.” Cal. Pub. Util. Code § 454.57(e)(4)(A).

[4] D.24-02-047 at 71.

[5] For example, the CPUC could request CAISO estimate gas plant utilization results for transmission constrained local areas using the CPUC 2025-26 TPP base resource portfolio.  The CPUC could further request that if CASIO PLEXOS results show CPUC gas plant utilization targets are not met CAISO should identify a plan of service for the local area that meets CPUC targets. The plan of service could optimize a combination of new  transmission and local storage and CAISO could approve in the 2025-26 TPP any needed long lead time transmission solutions into transmission constrained local areas that reduce gas plant usage significantly by 2035 as required by SB 887. 

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Cal Western has no addtional comments

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

The draft plan does not fulfill the CPUC’s request to plan transmission for the 5.2 GW of in-state wind energy included in the base portfolio in its Decision 24-02-047 (issued on February 15, 2024).  CAISO must consider the FCDS capacity that has already been allocated and ensure that additional capacity is being planned as needed to accommodate the wind resources in the CPUC’s portfolio.

CalWEA is primarily concerned with the SCE Northern and SDG&E study areas where wind development interest is currently the strongest. (Development interest is also strong in far Northeast California outside of the CAISO balancing area; however, in its most recent decision for the 2025-2026 TPP, the CPUC asks CAISO to study, but not yet plan for, transmission in this area.[1])

In the SCE Northern study area, the CPUC requested CAISO to plan for 564 MW of FCDS wind. Of this, 100 MW at Whirlwind has already been awarded FCDS.  For the remaining 464 MW, however, Windhub is fully subscribed, and Whirlwind and Antelope will be fully subscribed after QC 15.  Therefore, to fulfill the CPUC’s request, CAISO must plan for 464 MW as indicated on Map 3.5-14.  Alternatively, CAISO could plan for this wind capacity at Windhub, as CalWEA recommended in its November 27, 2024 comments.[2]

Similarly, in the SDG&E study area, the CPUC requested that CAISO plan for 1,325 MW of FCDS wind.  Of this, 300 MW of wind has been awarded FCDS.  For the balance of 1,025 MW, however, the area is fully subscribed; therefore, CAISO should plan for that additional 1,025 MW of capacity to fulfill the CPUC’s request.

Further, CAISO should provide consistency with the CPUC’s request in its recent decision adopting a portfolio for the 2025-2026 TPP by reserving this additional FCDS capacity for wind energy.  CAISO indicated its desire to act consistently with this recent CPUC decision on p. 105 regarding planning for Wyoming wind capacity.

[1] CPUC D. 25-02-026 (February 20, 2025) at p. 59.

[2] CalWEA recommended as follows:  Development of cost-effective and IRP-planned resources in the SCE Northern Area, and specifically in the Tehachapi wind resource area, has been hampered by near-zero TPD capacity for that area as well as the CAISO-imposed Windhub Substation export limit under the extreme system event criteria – potential blackout condition due to simultaneous loss of both 500kV lines from Windhub. CalWEA’s studies show that the addition of a 230kV double-circuit transmission line using high-capacity double-bundle conductors from the Windhub 230kV bus to the Vincent 230kV bus would obviate the need for the export capacity limit out of the Windhub substation.  Further, when combined with a low-cost fix (<$20M) to eliminate the ground clearance limitation for the Antelope Vincent 500kV line, this 230kV line upgrade would add more than 3,000 MW of TPD capacity to the Tehachapi wind resource area at Windhub, Whirlwind, and/or Antelope Substations. More than double that amount of solar and wind capacity is included in the 2024-25 CPUC portfolio as well as the CPUC’s draft 2025-26 portfolio.  Thus, CalWEA strongly recommends that CAISO consider approving the Windhub-to-Vincent 230kV line and addressing the ground clearance limitation for the Antelope Vincent 500kV line as part of its 2024-25 TPP.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

No Comment

2. Please provide your organization’s comments on Frequency Response.

No Comment

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No Comment

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Regarding the policy-driven upgrade on the Eagle Rock – Fulton – Silverado 115kV line, we have two main areas of questions and comments:

1. Modeling of Delayed Projects in Geyser Area
   1. During the meeting, ISO staff confirmed that the previously approved “Clear Lake 60kV System Reinforcement” project was modeled as part of this study. While the project was originally approved in 2009, it has been deferred for over a decade and now has a COD of 2030. According to the latest Transmission Development Forum report, the project has yet to begin construction.
   2. Our questions and concerns are as follows:
      1. Does CAISO consider it appropriate to model projects that have been delayed for over a decade with no visible progress?
      2. The prolonged delay of this project leaves existing congestion and operational issues unresolved, which may persist or worsen in the near term. How does CAISO account for this in its evaluation, and how can stakeholders be assured that newly proposed upgrades won’t overlook more urgent or severe needs?
      3. Would CAISO consider establishing criteria to conditionally include—or exclude—such long-delayed projects in its studies, especially when their implementation remains uncertain?
      4. Has CAISO considered developing mechanisms or enforcement authority to help ensure that approved projects proceed on schedule?
2. Generation Dispatch Conditions in the Geysers Region
   1. What assumptions were made regarding existing and future generation in the PG&E Geysers region? Specifically:
      1. When modeling the deliverability of new generation, are existing units in the region dispatched down to accommodate new output?
      2. If so, is there a defined dispatch priority or methodology used to determine which units are curtailed?
      3. How does CAISO ensure that the modeling reflects realistic operational scenarios for both existing and future resources in the area?

5. Please provide your organization’s comments on the Economic Assessment.

No Comment

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

No Comment

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The City of Palo Alto Utilities (CPAU) appreciates the opportunity to comment on the CAISO Draft 2024-2025 Transmission Plan (“Draft Plan,” hereafter). The comments and questions below address the material presented at the CAISO Stakeholder meeting on April 15, 2025, and the 2024-25 TPP draft report posted on March 31, 2025.  CPAU acknowledges and appreciates the significant efforts of the CAISO staff and PG&E staff to develop this comprehensive report. 

CPAU Strongly Supports CAISO Recommendation to Approve the “Ames Distribution – Palo Alto 115 kV transmission line” Project

The CAISO “Draft Plan” accurately classifies the “Ames Distribution – Palo Alto 115 kV transmission line” (“Project”, hereafter) project as a new diverse source to serve increasing CPAU electric demand and mitigate a major vulnerability of a common transmission corridor outage interrupting the entire City of Palo Alto territory.¹ CPAU is interconnected to the CAISO control grid with Pacific Gas and Electric (PG&E) at the Palo Alto Switching Station and served via three PG&E 115 kV lines from Ravenswood and Cooley Landing Substations. The three lines share a common corridor that is comprised of two double-circuit tower lines south of Ravenswood. This common corridor, shared between all three 115 kV lines serving CPAU, is a major vulnerability concern due to its close proximity to the end of the City of Palo Alto Airport, a bustling general aviation airport. The CAISO reliability assessment identified P6 and P7 NERC category contingencies that result in thermal overloads on the Ravenswood - Palo Alto #1 and #2, and the Cooley Landing-Palo Alto 115 kV lines, starting in the 2034 baseline scenario.² The Project mitigates these NERC and CAISO planning criteria violations on the 115kV lines. The CAISO found the Project to be the most cost-effective mitigation solution among the other alternatives it considered.³

CPAU strongly supports the CAISO’s recommendation⁴ that the Board approve the Project that would be built, owned, and financed by PG&E.

CPAU’s Load Continues to Grow at a Dramatic Rate, and CEC and CPAU Expect Significant Load Growth Over the Next Several Years

The CAISO correctly identified the anticipated demand increase and reliability issues in the adjacent system as one of the key drivers in its recommendation for the Project. CPAU’s load is expected to grow considerably in the next several years, primarily driven by data centers and multifamily housing developments. CPAU has worked closely with the California Energy Commission (CEC) staff to incorporate CPAU’s demand forecast in the 2024 Integrated Energy Policy Report (IEPR), which the CEC formally approved on January 21, 2025. This demand forecast is even higher than the forecast assumed in the current planning cycle, as data center load has come earlier and faster than estimated.

CPAU Requests that CAISO Expedite the Project’s In-Service Date

CPAU understands the Project could be completed in three to five years.  However, the CAISO’s Draft Plan explains that the later May 2034 estimated in-service date is due to an existing and different PG&E “maintenance project” that needs to be completed first.⁵  As described above, with CPAU’s rapid load growth, reliability vulnerability, and CAISO-identified reliability violations will remain unaddressed for many years. CPAU urges the CAISO to modify the estimated in-service year to 2030. CPAU is committed to collaborating closely with the CAISO and PG&E to explore options to parallel track and expedite the Project and the “maintenance project.

¹ See “Ames Distribution – Palo Alto 115 kV transmission line” project, pages 74-75, Draft Plan, March 31, 2025

² Draft Plan, Appendix B, p. B-142.

³ Reliability Assessment Recommendations –PG&E Area Draft 2024-2025 Transmission Plan, 2024-2025 Transmission Planning Process Stakeholder Meeting, April 15, 2025 slide 29.

⁴ Draft Plan, Table ES-1, p.10.

⁵ Draft Plan, p. 75.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

CPAU strongly endorses the CAISO’s recommendation to approve the Ames to Palo Alto Project, as it is the most cost-effective mitigation to address the transmission planning criteria violations on the PG&E’s 115kV facilities serving the CPAU load. With CPAU’s rapid load growth, reliability vulnerability, and CAISO-identified reliability violations will continue for many years if the in-service date for the Project is delayed to 2034. CPAU urges the CAISO to modify the estimated in-service year to 2030. CPAU is committed to collaborating closely with the CAISO and PG&E to explore options to parallel track and expedite the Project and the “maintenance project.”  CPAU believes it is imperative for PG&E to initiate engineering and permitting activities for the Project immediately.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Clearway supports LSA’s comments on the TPP’s inadequate accounting for short-circuit duty impacts related to the upgrades within the TPP. The TPP should be amended to include SCD mitigation measures to ensure C15 projects do not bear the cost and timing impacts associated with SCD mitigation from the TPP upgrades. 

2. Please provide your organization’s comments on Frequency Response.

?No comments at this time. 

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

?No comments at this time. 

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

The TPP shows that there are constraints and undeliverable GW of capacity in Southern NV and there is significant development interest appearing in Southern NV. In multiple prior TPP cycles CAISO’s policy-driven studies have highlighted the constraints in this area and CAISO has chosen not to approve a policy-driven upgrade. CAISO also included remapping of CPUC-identified resources away from this area as a potential mitigation when they otherwise would have triggered an upgrade. Given the considerable amount of undeliverable capacity and the target years identified by the CPUC portfolios for enabling this capacity, CAISO should approve this policy-driven upgrade in Southern NV in this TPP cycle. Please provide CAISO’s reasons for not approving any upgrade at this point and please provide clarity on CAISO’s plans to evaluate Southern NV upgrades in order to meet the need dates as established by the CPUC portfolios. 

5. Please provide your organization’s comments on the Economic Assessment.

?No comments at this time. 

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Clearway supports the comments made by LSA relating to proposed Transmission Plan Deliverability for Long-Lead-Time resources. Specifically, more detailed information about the points of interconnection identifying the precise substations where the TPD is being reserved is necessary to ensure developers have insight into where CAISO is constraining interconnection and future TPD allocation cycles.  

Separately, Clearway recommends limiting use of ‘re-mapping’ resources as mitigation. There are some specific cases where re-mapping may be appropriate – for example, where only small amounts of MW need to be moved through re-mapping to avoid an upgrade, or where there is no commercial interest in the area. However, re-mapping should not be used to move hundreds of MWs through this mitigation tool, especially where there is demonstrated commercial interest.  

Clearway understands the need to question or revisit CPUC’s mapping if a small amount of mapped resource at a specific location without significant commercial interest is triggering an upgrade that will cost the ratepayers hundreds of millions. For example, Clearway understands CAISO’s position of not withholding TPD for resources mapped at Tesla because of lack of commercial interest. Using the same consideration: for areas and zones which have demonstrated sustained levels of commercial interest over several years and have also demonstrated policy-driven needs in several planning cycles, like Southern NV/EOP, CAISO should not consider resource re-mapping as a potential mitigation.  

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

No comment

2. Please provide your organization’s comments on Frequency Response.

No comment

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comment

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Engie appreciates the opportunity to provide comments to the CAISO's 2024-2025 Draft Transmission Plan. Engie has concerns about the proposed mitigation strategies in the following three transmission zones.

1. East of Pisgah

CAISO’s draft 2024-25 transmission plan indicates that significant upgrades in the East of Pisgah zone are delayed for a year to allow for additional analysis of broader upgrades to accommodate out-of-state wind.[1] This delay impacts the deliverability of almost 5000 MW needed by 2034 and 10,000 MW needed by 2039.[2]  The delay in approving upgrades in the East of Pisgah zone is concerning given the projected need identified in the base case portfolio. New transmission infrastructure can take up to 10 years to build, meaning the upgrades needed to accommodate 2034 resources are already behind schedule.  Additionally, these upgrades are related to broader decisions being made for additional out-of-state wind from the 2025-26 TPP base case portfolio, some of which is also needed by 2034. It is crucial to understand CAISO's plan to get this transmission built in time to meet these demands.

Furthermore, there is no discussion of cost-effectiveness for the potential mitigation options that CAISO considered for this area.  The ISO performed a sensitivity study to evaluate different alternatives to import additional Wyoming wind beyond TransWest Express capacity and to mitigate the Lugo – Victorville constraint.[3]  CAISO provides a discussion of the different benefits each mitigation option might provide (e.g. Trout Canyon – Lugo 500 kV line v. Western Bounty), but it fails to include any analysis of the costs of each option and how they relate to the potential benefits. This lack of analysis raises concerns about the efficiency and economic viability of the proposed solutions.

CAISO should not wait to approve the necessary upgrades in the East of Pisgah zone. Immediate action is required to ensure the deliverability of almost 5000 MW by 2034 and 10,000 MW by 2039. CAISO must provide a clear plan for building the required transmission infrastructure in time to meet these demands. Additionally, a thorough analysis of the cost-effectiveness of potential mitigation options, such as Trout Canyon vs. Western Bounty, should be included in the transmission plan.

2. North of Greater Bay Area:

The draft 2024-25 transmission plan indicates that the Cortina – Vaca 234 kV line has 1224 MW undeliverable in the 2039 baseline. The proposed mitigation is to "continue to monitor" with no potential mitigation or explanation provided.[4] The lack of potential mitigation or explanation for the undeliverable 1224 MW in the Cortina – Vaca 234 kV line is concerning. Without a clear plan for addressing this issue, there is a risk of future constraints that could impact the reliability and efficiency of the transmission system. CAISO should not rely solely on monitoring the undeliverable 1224 MW in the Cortina – Vaca 234 kV line. Immediate action is required to identify and implement potential mitigation options to ensure the deliverability of the required capacity by 2039. CAISO must provide a clear plan for addressing this issue to avoid future constraints and ensure the reliability of the transmission system.

3. Greater Bay Area:

The draft 2024-25 transmission plan proposes mitigating constraints in the Greater Bay Area by reducing battery energy storage systems (BESS).[5] However, the plan does not indicate where these MWs should be moved.  The proposal to mitigate constraints by reducing BESS in the Greater Bay Area raises concerns about the impact on transmission constraints at the new location. Even though these are relatively small volumes of BESS resources, CAISO should provide more information whenever it recommends this mitigation strategy. This includes identifying nearby alternative locations that might be able to accommodate additional capacity. Without this information, there is a risk of creating new constraints and inefficiencies in the transmission system.

[1] 2024-25 Draft Transmission Plan, p. 105.

[2] Id. at Table 3.5-13.

[3] Id. at Appendix F, p. 77.

[4] Id. at p. 87.

[5] Id. at p. 91.

5. Please provide your organization’s comments on the Economic Assessment.

No comment

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

No comment

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Fervo Energy Comments on the CAISO 2024-2025 Transmission Planning Process Draft Transmission Plan. 

Fervo Energy Company (“Fervo”) appreciates the opportunity to provide input on the CAISO 2024-2025 Transmission Planning Process (“TPP”) Draft Transmission Plan. Fervo requests that the CAISO consider the tremendous geothermal resources being developed in Nevada and Utah for import into the CAISO. Robust transmission planning analysis in advance of this influx of geothermal energy will be critical to deliver clean, firm, reliable power into the CAISO to meet reliability requirements and clean energy mandates. 

1. CAISO should prioritize the inclusion of geothermal in the assessment of transmission needed to support out-of-state resources in this TPP cycle and future TPP cycles. 

CAISO’s 2023-24 20-Year Transmission Outlook acknowledges that geothermal resources and out-of-state resources, among others, are expected to play a greater role in achieving California’s reliability and climate goals and that these resources create unique challenges in the planning and interconnection processes.[1] The resource portfolio approved for the 2025-26 TPP cycle begins to reflect the growth in geothermal capacity from Utah and Nevada, mapping over 900 GW to these areas by 2035. Additionally, the draft Inputs & Assumptions being developed by the CPUC for the 2024-2026 IRP cycle reflect the likelihood of even more growth by adding Enhanced Geothermal Systems (EGS) as a candidate resource, significantly increasing geothermal potential for future portfolios.[2]  

Several notable technological advances applied over the last five years have majorly expanded geothermal energy power production potential across the west. Namely, bench development and horizontal drilling advancements honed during the shale revolution have unlocked the ability to access additional layers of geothermal resource per well pad, resulting in a higher density of power generation per acre than hydrothermal approaches have been previously capable of.  

Moreover, accessing more geothermal resources per well pad facilitates more total available resources at a project as it lowers project costs, allowing the most cost effective and optimized deployment of capital. The resource potential estimates previously considered in state planning efforts have sited outdated analysis based on the spacing of vertical wells without horizontal drilling applications or bench development concepts. Not only does this technology application improve our resource efficiency and power density but also allows EGS to produce two to five times the amount of power from the same footprint as a single bench design.[3]

Despite this expected increase in geothermal resources’ contribution to resource portfolios, CAISO’s 2024-2025 TPP transmission plan does not centralize the necessity to begin adapting the planning process to prepare for it. In anticipation of increased geothermal growth in future cycles, Fervo recommends that CAISO emphasize geothermal in this year’s assessment of transmission needed to support out-of-state resources. 

2. CAISO should begin analysis for OOS geothermal in the 2025-2026 TPP cycle.  

This year’s Draft Study Plan states that CAISO will carefully analyze the needs for out-of-state (OOS) wind on new out-of-CAISO transmission.[4] The CPUC recommended this analysis to accommodate the significant increase in OOS wind in this year’s resource portfolio compared to prior years.[5] Due to the complexity of this analysis, CAISO is taking an extra year to determine the most efficient transmission solutions for these resources and to better understand the options, costs, and potential collaborations with other Balancing Area Authorities.[6] In other words, given the complexity of developing new transmission for OOS resources, CAISO needs two years instead of one to develop potential mitigation strategies. 

Fervo agrees that the process of developing transmission for OOS resources is complex and may require extra time and attention. Fervo encourages CAISO to begin this analysis for OOS geothermal in the 2025-26 cycle. Although the expected OOS geothermal growth has not yet fully materialized in the CPUC’s 2025-26 TPP portfolio, it is clearly indicated by both CAISO’s 20-Year Transmission Outlook and the CPUC’s proposed 2024-26 IRP cycle assumptions. Rather than waiting for future CPUC resource plans to reflect this growth and then having to delay the necessary transmission by a year as was required for OOS wind in this cycle, CAISO should begin the assessment of transmission needs for future OOS geothermal now to better align with anticipated geothermal growth. 

Fervo appreciates the opportunity to submit these comments in response to the CAISO 2024-2025 TPP Draft Transmission Plan.

Sarah Harper

Policy and Regulatory Affairs Associate

Fervo Energy Company

1999 Harrison Street, Suite 1800

Oakland, CA 94612

Telephone: (484) 802-4327

E-Mail: sarah.harper@fervoenergy.com

Hillary Hebert 

HMH Energy

Telephone: (303) 550-5037

Hillary@hmhenergy.com

Consultant to Fervo Energy

[1] 2025-2026 Transmission Planning Process Unified Planning Assumptions and Study Plan DRAFT dated February 19, 2025, p. 9.

[2] 2025_draft_inputs_and_assumptions_doc_20250220.pdf, p. 9.

[3] Fervo Energy Technology Day Presentation. 2024. https://fervoenergy.com/technology/  

[4]  2025-2026 Transmission Planning Process Unified Planning Assumptions and Study Plan DRAFT dated February 19, 2025, p. 82.

[5] Decision Transmission Resource Portfolios for the 2025-26 TPP, pp. 61-62

[6] 2025_draft_inputs_and_assumptions_doc_20250220.pdf, p. 82.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Golden State Clean Energy (“GSCE”) supports the reliability-driven projects recommended for approval in the Greater Bay Area, and particularly the new Manning-Metcalf 500 kV line. In addition to providing significant local area upgrades that will help with reliability and load growth, this transmission plan would also increase the Greater Bay Area’s access to regional renewables. As CAISO has noted, significant future load growth is expected to be concentrated in the Greater Bay Area, and this plan takes an important step to support economic development in the Bay Area while reducing reliance on gas-fired power plants. The projects in the plan will also help support renewable generation in the San Joaquin Valley.

Analysis in this TPP cycle showed that Northern California at a zonal level (NP26) could face supply shortages in the future. The new Manning-Metcalf 500 kV line should also help address this issue to some degree due to increased regional transfer capability and reduced congestion.

Nonetheless, major regional upgrades to accommodate the 2025-26 TPP portfolio, beyond the Manning-Metcalf 500 kV line, are still needed to increase NP26’s access to supply, including upgrades to unlock the 13.5 GW of solar and 5.1 GW of battery storage in the Fresno area. Path 15 corridor congestion grew significantly this TPP cycle, and that trend is expected to continue and expand next year. Given the large increase in Fresno area resources in the 2025-26 TPP portfolio, load growth in Northern California, and the important interaction Fresno area resources have with the Path 15 corridor, it is imperative that CAISO to continue to explore and identify an effective long-term solution to the Path 15 corridor and broader region in the 2025-26 TPP.

2. Please provide your organization’s comments on Frequency Response.

 No comment.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

 No comment.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

 No comment.

5. Please provide your organization’s comments on the Economic Assessment.

Gas Plant Usage

The draft 2024-2025 Transmission Plan states that “existing legislation calls for the CPUC to provide to the ISO by March 31, 2024 resource projections that are expected to reduce by 2035 the need to rely on non-preferred resources in local capacity areas. However, these projections are not yet reflected in the portfolios provided by the CPUC for the 2024-2025 Plan.”^[1]

GSCE supports the sensitivity portfolio as an important step to helping the CPUC comply with this existing law, which is codified in Public Utilities Code Section 454.57 (SB 887). GSCE is concerned by the CPUC’s slow progress meeting this requirement, and we believe that CAISO’s analysis of the sensitivity portfolio in this TPP is needed to allow the CPUC to better plan for gas plant retirement. GSCE urges CAISO to provide the CPUC with actionable data and conclusions to assist the CPUC in compliance with this statute. We are concerned that without guidance from CAISO the CPUC may continue to fall short of its statutory requirement to plan for gas plant retirements given limitations with existing modeling tools. Continued inaction by the CPUC to plan for gas plant retirement risks communities in the Bay Area and San Joaquin Valley continuing to bear a disproportionate burden of gas plant emissions.

In order for the CPUC to have actionable data and clear takeaways, GSCE believes it would be helpful for CAISO to clarify the following information:

• Differences in gas plant utilization between Northern and Southern California.
• For the gas utilization analysis in Appendix G, how the MW capacity values differ compared to the gas-fired power plant capacity retired in the base case and sensitivity portfolios.[2]
• How the gas utilization analysis in Appendix G relates to system versus local reliability requirements. For instance, data showing how much of the gas utilization is due to system versus local capacity needs would help stakeholders understand the impacts of retiring gas-fired plants in specific transmission areas, as well as the nature of the challenge to alleviate gas usage in areas most burdened by these resources.

Economic Study Request: Monarch

GSCE appreciates CAISO’s study effort and the detailed analysis of the Monarch transmission project. This analysis shows that Monarch has the potential to provide economic value to CAISO ratepayers in an area of the grid that experiences costly congestion. Monarch also provides the Greater Bay Area with increased access to Fresno area renewables and storage, which is helpful given the Greater Bay Area has some of the highest capacity factor gas-fired power plants on the CAISO system.[3]

GSCE understands that CAISO modeled the cost of Monarch, and all economic study request projects, as being fully funded by CAISO ratepayers. CAISO provides the following in Appendix G of the draft 2024-2025 Transmission Plan:[4]

The benefit to cost ratio calculation in this section was based on the assumption that all transmission upgrade alternatives are fully rate-based projects, and the capital costs of the projects were estimated based on the CAISO transmission per unit cost. If these cost assumptions change, the benefit to cost ratios need to be recalculated, although the production cost simulation results may not change. It is worth noting that total capacity of renewable and battery resources in the Fresno/Kern area and in the southern California areas may continue increase in future CPUC IRP portfolios, which will aggravate congestions on the Path 15 and Path 26 corridors. Transmission upgrade alternatives for mitigating Path 15 and Path 26 corridors assessed in this planning cycle need to be reassessed in future planning cycles with consideration of the resource capacity changes in the Fresno/Kern area and in the southern California areas.

GSCE has proposed CAISO study Monarch as a cost sharing arrangement involving CAISO and BANC, and we hope to continue to work with CAISO to capture this potential value in the 2025-26 TPP. GSCE believes that Monarch’s BCR would improve significantly if a cost sharing arrangement is captured, especially in combination with the significant increase in Fresno area resources in the 2025-26 TPP.  

[1] CAISO, Draft 2024-2025 Transmission Plan, pg. 143, March 31, 2025.

[2] CAISO, Draft 2024-2025 Transmission Plan, Appendix G, tables G.7-2, G.7-8, G.7-12, March 31, 2025 (comparing the MW value in these tables to Table 3.4-1 in the draft transmission plan).

[3] CAISO, Draft 2024-2025 Transmission Plan, Appendix G, tables G.7-2, G.7-8, G.7-12, March 31, 2025.

[4] CAISO, Draft 2024-2025 Transmission Plan, Appendix G, pg. G-85, March 31, 2025.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

  No comment.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

No comments.

2. Please provide your organization’s comments on Frequency Response.

No comments.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comments.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

No comments

5. Please provide your organization’s comments on the Economic Assessment.

Kern-Southland Energy Link, LLC appreciates the opportunity to provide comments on the 2024-2025 Transmission Planning Process (TPP) update provided on April 15, 2025.  

The economic analysis for K-SEL identified congestion savings on Path 26 and the La Cienega – La Fresa 230 kV constraints (with K-SEL eliminating all congestion on the La Cienega – La Fresa 230kV constraint), while there was a slight increase in congestion on the Midway – Whirlwind 500kV line. Our preliminary investigation shows that by accounting for changes in the resource build and by better optimizing modeling of the HVDC line, K-SEL can provide congestion savings on Path 26 that are greater than CAISO’s reported results.  

The LCR reduction benefit analysis found that K-SEL could provide capacity savings of $8.15M/year. However, this analysis simply took the cost of local capacity versus SP26 capacity costs and attributed the difference to the project. While this methodology shows some level of capacity savings, our preliminary investigation found that it may undervalue the LCR reduction benefits of the project. A more in-depth, multi-stage methodology would be more appropriate. This would enable the incorporation of the project into the resource planning process and allow for more realistic and optimal future resource siting and technology decisions. Additionally, this approach would allow for the inclusion of more detailed studies and metrics such as avoided transmission buildout from gas generation retirements, deliverability of resources, reduced reliance on Aliso Canyon, and scenario planning for retirements of in-basin generation.  

Finally, while the analysis conducted by CAISO was solely an economic analysis, K-SEL is a multi-value project with reliability, economic, and policy benefits. We believe a holistic approach is required to fully assess the benefits the project would bring to the State of California. We also support increased coordination between CAISO and the CPUC, allowing an iterative approach with feedback loops between the resource planning and transmission planning processes. 

We would be happy to provide detailed methodology and modeling support upon request. 

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

No additional comments.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The City and County of San Francisco (City) appreciates the opportunity to comment on the CAISO Draft 2024-2025 Transmission Plan (“Draft Plan,”). The comments and questions below address the material presented at the CAISO Stakeholder meeting on April 15, 2025, and the 2024-25 TPP draft report posted on March 31, 2025.  The City acknowledges the significant efforts of the CAISO staff to develop this comprehensive report. 

The City Urges CAISO Management to Recommend Approval of the Warnerville-Newark Transmission Expansion Project (WaNTEP) in Conjunction with the Greater Bay Area 500 kV Transmission Reinforcement Project

The City urges CAISO management to recommend approval of the Warnerville-Newark Transmission Expansion Project (WaNTEP) in the current planning cycle for the following reasons.

1. WaNTEP mitigates planning criteria violations that remain after implementation of (i) the recommended New Manning – Metcalf 500 kV line, (ii) the 500/230kV transformer at Metcalf, and (iii) multiple South Bay projects that address reliability issues associated with delivering imports into the Greater Bay Area.
2. WaNTEP, located on the existing City Right-of-Way (RoW), will face significantly reduced permitting, ROW acquisition, and siting challenges – factors that would add time, cost, and risk to the implementation of the other projects.
3. WaNTEP can be built over the next 5 to 7 years and addresses many of the planning criteria violations that the other projects eventually would mitigate. Therefore, WaNTEP would be a hedge against delays associated with implementing the greenfield 100-mile Manning-Metcalf 500kV project and the complex South Bay projects.
4. WaNTEP would access low-cost public debt financing to support the long-term cost containment objectives of the City and CAISO as partners.
5. Approving WaNTEP is consistent with the least-regrets planning approach, and CAISO has the opportunity to shape and integrate WaNTEP into the long-term objectives of the State.

Background

The City submitted a transmission project in the CAISO 2024-2025 TPP Request Window that will utilize the City’s existing 100-mile Moccasin-Warnerville-Newark 115kV line Right-of-Way (RoW) to rebuild a new 1,000 MW 70-mile High Voltage Direct Current (HVDC) line as the preferred option^[1]. In its application, the City showed that WaNTEP had demonstrable reliability benefits in reinforcing the transmission import infrastructure in the Greater Bay Area (GBA) and could be accomplished in a timely fashion utilizing the existing City RoW.  In particular, WaNTEP was shown to mitigate the overloads caused by the significant load increase in the GBA, consistent with the findings in the CAISO 2024-2025 TPP preliminary reliability assessment. WaNTEP was shown to have a considerable synergy with the Hybrid project under consideration in the San Jose Area in the CAISO 2024-2025 TPP. WaNTEP was also shown to provide significant policy (deliverability) and economic (congestion) benefits in enhancing the State’s ability to meet its policy goals.

CAISO’s Consideration of WaNTEP in 2024-2025 TPP

As indicated in the Draft Plan, the CAISO considered WaNTEP as an alternative to the New Manning – Metcalf 500 kV line, aka Greater Bay Area 500 kV Transmission Reinforcement project.[2] One reason the Draft Plan preferred the Greater Bay Area 500 kV Transmission Reinforcement project over WaNTEP was because it addresses overloads on the Metcalf – Moss Landing 500 kV and Las Aguilas – Moss Landing – Metcalf 230 kV path under P6 contingencies, that the WaNTEP project was not designed to address. The City appreciates the New Manning – Metcalf 500 kV line’s effectiveness in addressing this particular P6 overload and supports that project as a good solution to mitigate these specific problems. However, the City found numerous other reliability benefits offered by WaNTEP that are not addressed by the new Manning - Metcalf 500 kV line, and do not appear to have been considered by CAISO in its evaluation of WaNTEP.

WaNTEP is highly effective in addressing reliability criteria violations not addressed by the New Manning – Metcalf 500 kV line and complements it and two other projects in the South Bay area recommended for approval by CAISO by resolving planning criteria violations. WaNTEP is also a hedge against potential delays faced by the greenfield Manning – Metcalf 500 kV project. The City’s latest reliability assessment models the following three (3) transmission projects recommended for approval in the South Bay area in the Draft Plan.

1. Metcalf Substation 500/230 kV Transformer Bank Addition;
2. San Jose B to NRS 230kV line; and
3. South Bay Reinforcement Project

As shown in Table 1 below, there are eighty-one (81) planning criteria violations that remain unaddressed with the new Manning - Metcalf 500 kV line and the South Bay Projects that WaNTEP would mitigate, including thirteen (13) 115kV and two (2) 230kV P1 violations in 2034. See Appendix A Table 8 for the detailed contingency results. In 2039, a subset of sixty-three (63) contingencies were analyzed that have a large impact in the Greater Bay Area; the planning criteria violations are summarized in Table 2 with the details included in Appendix B Table 11. Without the additional projects recommended for approval in the Draft Plan, such as upgrading the Los Esteros – Metcalf 230kV line as part of the South Bay Reinforcement project, the Los Esteros – Metcalf 230kV line would have overloaded under contingency conditions even with the new Manning - Metcalf 500 kV line, but would be resolved with WaNTEP. We have excluded these instances from the above-mentioned tables.

As illustrated in Table 3, the new Manning—Metcalf 500 kV line introduced fifteen (15) additional P2, P5, P6, and P7 criteria violations, which WaNTEP mitigates in 2034. See Appendix A Table 9 for the detailed contingency results. In 2039 the subset of sixty-three (63) contingencies analyzed have a large impact on the Greater Bay Area and there are such instances as summarized in Table 4, where the new Manning—Metcalf 500 kV line introduced P0, P1, P2, P6, and P7 criteria violations which WaNTEP can mitigate. The details of the detailed contingency results are included in Appendix B Table 12. There are additional transmission planning criteria violations, such as on the Swift to Metcalf 115kV line that are caused by the new Manning - Metcalf 500 kV line and resolved by WaNTEP. We have excluded them from these tables as the CAISO has proposed new projects or rescoped the previously approved projects, such as using advanced conductors for the Swift to Metcalf 115kV line.

Table 3: 2034 New Overloads Caused by the New Manning - Metcalf 500 kV Line that are Mitigated with WaNTEP

Table 5 shows that WaNTEP or the new Manning-Metcalf 500 kV lines are effective in addressing sixty-three (63) planning criteria violations on several facilities in 2034. See Appendix A Table 10 below for the detailed contingency results. Table 6 shows comparable results for the year 2039 with a subset of contingencies. The detailed contingency results are included in Appendix B Table 13. WaNTEP outperforms the new Manning-Metcalf 500 kV project in some cases, while in others, the new Manning-Metcalf 500 kV project proves to be more effective. Both WaNTEP and the new Manning-Metcalf 500 kV line would be needed with the increasing load in the outer years, which is confirmed in the 2039 assessment. This is evident with the thirty-six (36) planning criteria violations from the subset of contingencies analyzed which are summarized in Table 7, with the details included in Appendix B Table 14.

WaNTEP Should Be Considered for Approval As a Reliability Project in the 2024-2025 TPP on Its Own Merit and Also as a Project Complementary to the Manning-Metcalf 500kV Project

WaNTEP, located on the existing City RoW, will face significantly reduced permitting, ROW acquisition, and siting challenges – factors that would add time, cost, and risk, ultimately affecting the deliverability of any alternative project. In addition, WaNTEP will access low-cost public debt financing to support the long-term cost containment objectives of the City and CAISO as partners. The City believes WaNTEP can be built over the next 5 to 7 years, and, therefore, would be a hedge against delays associated with implementing the greenfield 100-mile Manning-Metcalf 500kV project and the complex South Bay projects. In short, it is a least-regrets solution that complements these projects. As shown in Appendix A Table 8 and Appendix B Table 11, WaNTEP addresses several reliability criteria violations that would remain should the new Manning-Metcalf 500kV line be delayed. Furthermore, as we discuss in our response to Q.5, WaNTEP is also expected to reduce congestion on the Las Aguilas – Moss Landing 230 kV path. Given the significant standalone reliability and economic benefits associated with WaNTEP, we request that CAISO consider it for approval in the Final Transmission Plan. If the CAISO staff needs additional time to evaluate WaNTEP further, it could be performed as a continuation of the 2024-2025 TPP.

[1] The City also considered a 230kV Alternating Current (AC) line option for WaNTEP, but found the HVDC configuration to be more beneficial from a reliability standpoint. The City is open to considering alternatives, including the 230kV AC.

[2] Draft Plan, Appendix B, p. B-136-137, and Reliability Assessment Recommendations –PG&E Area Draft 2024-2025 Transmission Plan, 2024-2025 Transmission Planning Process Stakeholder Meeting, April 15, 2025 slide 34.

2. Please provide your organization’s comments on Frequency Response.

No comments at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comments at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

No comments at this time.

5. Please provide your organization’s comments on the Economic Assessment.

The City acknowledges that the new Manning-Metcalf 500kV line is effective in reducing and probably eliminating the congestion on the PG&E Moss Landing - Las Aguilas 230 kV line based on CAISO’s detailed economic assessment using a production cost model (PCM) simulation.[1] The City understands that the CAISO staff did not conduct a similar detailed economic assessment using a PCM simulation for WaNTEP. The City believes that WaNTEP would be an effective mitigation measure in reducing congestion on the Moss Landing - Las Aguilas 230 kV line until the new Manning-Metcalf 500kV line is built. The CAISO’s PCM analysis shows that the Moss Landing - Las Aguilas 230 kV line will be highly congested in the future, with the congestion cost as high as $290 million in 2039.[2] The CAISO PCM analysis calculates the annual net CAISO savings of $120 million in 2039 associated with the new Manning-Metcalf 500kV line. Building WaNTEP 4-5 years sooner than the new Manning-Metcalf 500kV line, could lead to significant CAISO ratepayer savings due to reduced congestion on the Moss Landing – Las Aguilas 230 kV line. Therefore, the City believes the CAISO needs to consider WaNTEP's economic benefits in addition to its significant reliability benefits leading to its approval in the current planning cycle.

[1] Draft Plan, Appendix F, p. G-21. See Table G.6-2: Congestion changes by modeling the Manning - Metcalf upgrade.

[2] Ibid.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

See the attached Appendix, which includes Appendix A and Appendix B.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Intersect Power notes that the Draft 2024-2025 Transmission Plan recommends approval of significant transmission projects (“TPP Upgrades”). While we strongly support these projects to meet California’s renewable energy goals and load forecasts, we have a critical concern: the short circuit duty (“SCD”) impacts created by these recommended TPP Upgrades have not been identified or recommended for concurrent approval. We believe it is impractical to implement these TPP Upgrades without simultaneously addressing their resultant SCD issues.

While CAISO may intend to consider and recommend SCD mitigation for approval in next year’s TPP cycle, Intersect Power strongly opposes this delay for several key reasons:

• Impact on Cluster 15 Postings: Including approved TPP Upgrades in the QC15 cluster study base case will likely attribute SCD mitigation costs caused by the TPP Upgrades to QC15 projects in their initial posting (5% of Network Upgrades). This would unfairly inflate these postings, regardless of any subsequent reclassification of the TPP Upgrades as Precursor Network Upgrades (PNUs).

• Critical Impact on Project Schedules (QC15 & TPP Upgrades): Delaying approval of necessary SCD mitigation until next year carries significant schedule risks. It could delay both QC15 projects and the very TPP Upgrades causing the issue by a year or more if SCD mitigation becomes the critical path. Conversely, concurrent approval in the current cycle allows immediate commencement of engineering and procurement for long-lead-time SCD mitigation equipment (e.g., high-voltage circuit breakers with lead times exceeding five years), potentially improving schedules by over a year.

• Increased Uncertainty for Cluster 15 Network Upgrades: Postponing the inclusion of SCD mitigation for the TPP Upgrades until next year’s cycle increases uncertainty regarding the eventual NUs required for QC15 projects and their ultimate economic impact. This delay also elevates the risk of inaccurately allocating SCD impacts between TPP upgrades and QC15 projects.

• Jeopardy to 2024-2025 TPP Approvals: Failure to approve necessary SCD upgrades in the current 2024-2025 TPP cycle creates unacceptable uncertainty for the already-approved, yet dependent, TPP Upgrades. If SCD mitigation is not approved in a subsequent cycle (for unforeseen reasons), the viability of the initially approved TPP Upgrades would be in question.

Therefore, Intersect Power strongly urges CAISO to include the SCD mitigation upgrades required to resolve the impacts of the recommended TPP Upgrades within the current TPP approval request. This concurrent approval is not merely preferable; it is essential for a clean and efficient transition to the reformed QC15 Cluster Study process and to avoid the significant financial and schedule risks outlined above, ensuring the timely and cost-effective implementation of critical transmission infrastructure.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Please see comments in response to prompt 4 that ask the CAISO to evaluate scope changes to proposed reliability-driven projects to increase TPD in Northern California.

2. Please provide your organization’s comments on Frequency Response.

No comments at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

 No comments at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

1.         Deliverability Scarcity in the North of Greater Bay Interconnection Area   Is Stalling Resource Development

Transmission Plan Deliverability (TPD) scarcity has significantly slowed renewable development in the North of Greater Bay Area (NGBA) and Sonoma Clean Power (SCP) and Redwood Coast Energy Authority (RCEA) are concerned that the limited scope of policy-driven upgrades in the 2024-25 TPP will not sufficiently address the problem. We have experienced firsthand how this shortage has complicated the advancement of long-lead time, high-value resources like geothermal and long duration energy storage, while also increasing procurement costs for Northern California Load Serving Entities (LSEs). This outcome is counter to the state's climate, reliability, and affordability goals.

We recognize that the forthcoming 2025-26 TPP resource portfolio from the California Public Utilities Commission (CPUC) attempts to address this issue by increasing resource allocations to constrained regions like the NGBA. However, SCP and RCEA strongly urge CAISO to proactively explore whether synergies between existing policy-driven or reliability-driven transmission projects could help unlock deliverability in this region in the 2024-25 TPP—without unnecessary delay or cost escalation.

2.         LSE Targets that Go Beyond State Targets Are Not Reflected in the TPP

Additional procurement targets CCAs jurisdictional Boards adopt beyond the state’s targets are not always reflected in the final Preferred System Plan and therefore not reflected in the TPP.

Targets such as local procurement goals or resource specific targets may affect where CCAs choose to site their projects, ultimately leading to a need for additional TPD in locations not considered in the TPP now. To clarify, RCEA and SCP find that in this TPP, there is insufficient TPD available for the resources needed to meet our Board adopted goals and priority for local resource development.

Therefore, we encourage changes to the TPP process to allow CAISO to seek information from LSEs on if they have any additional targets beyond what is reflected in the PSP.

3.         Expanded TPD is needed in the NGBA for Path 15 Congestion Relief

Northern California continues to face chronic TPD constraints, preventing viable renewable projects from advancing beyond the interconnection queue. These areas are proximate to existing 230 kV and 500 kV infrastructure, yet the lack of deliverability headroom has stranded queued capacity and limited clean energy procurement options. Simultaneously, Congestion Revenue Right (CRR) congestion rents and day-ahead Locational Marginal Pricing (LMP) spreads show sustained pressure on Path 15 (South to North). CAISO's 2024–2025 Production Cost Modeling (PCM) results show that Path 15 congestion totaled $389.42 million in 2034 and increased further to $521.80 million in 2039, affecting thousands of operating hours.

This makes Path 15 the most economically congested transmission corridor in California, significantly impacting ratepayers through redispatch costs and CRR underfunding. Congestion often results from internal transmission bottlenecks (e.g., Collinsville-Tesla or Delavan area overloads) limiting transfer to and from the Greater Bay Area (GBA) and Central Valley interconnection areas.

SCP and RCEA urge CAISO to examine how TPD-constrained upgrades in Northern California, particularly projects that relieve the Collinsville-Tesla and Delavan 230 kV bottlenecks , could relieve congestion on Path 15 by reducing dependency on Southern California resources. Further, the Delavan constraint has been identified in the North of Greater Bay Local Capacity Requirements (LCR) studies as a limiting element for multiple queued renewable projects. Collinsville–Tesla constraints directly affect flows across the northern terminus of Path 15, limiting dispatch flexibility from PG&E’s 230 kV backbone. The planned Manning–Metcalf 500 kV upgrade addresses South Bay supply but does not address upstream constraints in Northern California that would enable greater transfer headroom into and out of the GBA. We encourage CAISO to assess whether relatively lower-cost upgrades in the North Coast and Central Valley, such as reconductoring or reactive support at key substations (Delavan, Collinsville, Tesla), could provide multi-benefit solutions—enhancing both local deliverability and relieving south-to-north flows, thereby reducing Path 15 congestion.

As CAISO plans its 2025-2026 Transmission Planning Process and evaluates additional portfolio sensitivities (including high storage and higher Northern California renewable penetration), we urge CAISO to:

•           Include a targeted sensitivity on Delavan and Collinsville area constraints.

•           Quantify the marginal congestion reduction on Path 15 from incremental TPD in the north.

•           Consider assigning economic-driven status to transmission projects that address both localized deliverability and regional flow efficiency.

We’d also like to flag that the California Public Utilities Commission (CPUC)'s Integrated Resource Plan (IRP) optimization model (RESOLVE) currently does not incorporate Path 15 congestion as a constraint in portfolio selection. While we understand this enhancement is planned for future cycles, it underscores that the responsibility currently falls on CAISO to assess transmission-congestion-informed portfolio feasibility and economic benefits in the interim.

This type of multi-benefit transmission analysis—combining deliverability, congestion relief, and resource enablement—is precisely the type of holistic evaluation envisioned under Federal Energy Regulatory Commission (FERC) Order 1920-A. Considering TPD upgrades in the Delavan–Tesla–Collinsville area as candidates for economic or policy-driven designation could yield measurable statewide benefits and help CAISO meet its planning obligations under the order’s new mandates.

4.         Evaluate Synergistic Opportunities Before Finalizing the Plan

We request that CAISO evaluate whether small scope changes to the following projects could provide incremental deliverability benefits to the NGBA:

•           Greater Bay Area 500 kV Reinforcement Project

•           Metcalf–Manning 500 kV Line

•           Metcalf 500/230 kV Bank Addition

•           Eagle Rock–Fulton–Silverado 115 kV Reconductoring

•           Humboldt-Fern Road 500 kV & Humboldt-Collinsville 500 kV

These projects are already included in the draft transmission plan for reliability or policy reasons. Even modest modifications—such as additional transformer capacity, adjusted substation interconnections, or switching flexibility—could yield valuable deliverability access for Northern California projects. We encourage CAISO to conduct targeted sensitivity assessments to explore these options before finalizing the plan.

5.         Eagle Rock Project Should be Leveraged to Support Geothermal Resource Reservations

If the Eagle Rock–Fulton–Silverado 115 kV reconductoring project is approved as a policy-driven upgrade, and it is determined to enable deliverability, we request that CAISO consider reserving a modest amount of TPD capacity for geothermal resources in the NGBA. Geothermal was designated by the CPUC as a long-lead time, reliability-enhancing resource, and reservation of TPD in alignment with that designation would be both prudent and equitable.

5. Please provide your organization’s comments on the Economic Assessment.

Please see comments in response to prompt 4 that highlight the potential economic benefits of increasing TPD in Northern California to alleviate Path 15 congestion.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

We echo the concerns raised by the Large-Scale Solar Association (LSA) (as articulated by Susan Schneider) regarding the lack of transparency in TPD reservations and their downstream impacts. While we understand that reservations reflect the CPUC portfolio and future upgrades, they still result in interim constraints that affect resource developers, including SCP’s and RCEA’s pipeline projects.

We request that CAISO:

•           Provide substation-level mapping of all TPD reservations, including those tied to offshore wind, geothermal, and out-of-state resources.

•           Indicate how much capacity has been reserved vs. allocated in each interconnection area.

•           Clarify the implications on Maximum Import Capacity (MIC) and interconnection queue limitations in downstream substations.

•           Incorporate these transparency elements into the final transmission plan and stakeholder deliverables for the 2025–26 TPP.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

LS Power appreciates the opportunity to comment on the Draft 2024-2025 Transmission Plan. 

The Draft Plan shows the ideal in-service date for the NRS – San Jose B 230 kV line concurrent with the expected in-service date of the Metcalf-San Jose B HVDC and the Newark-NRS 230 kV line projects in 2028, and the target in-service date should be no later than 2030 (Pages 69-70).  LS Power has concerns about CAISO’s designated ideal in-service date for the proposed NRS – San Jose B 230 kV line. As a competitive transmission solicitation eligible project, the earliest a project sponsor will be identified is late first quarter 2026. Project development will not potentially begin until the second quarter 2026, leaving just over two years for the project sponsor to permit, order, and receive necessary long-lead time materials, and then construct a major transmission project by a mid-2028 in-service date. This timeline seems potentially infeasible and would almost certainly require extraordinary measures to expedite, increasing costs for Transmission Access Charge customers compared to a more typical schedule.  Additionally, both LS Power and PG&E have significant approved work at the Skyline HVDC terminal and San Jose B site into 2028, which requires sequenced construction efforts due to space constraints.  This makes a concurrent interconnection date for the NRS – San Jose B 230 kV line impractical.  For these reasons, LS Power recommends that the NRS – San Jose B 230 kV line competitive transmission project have a targeted in-service date of no sooner than 2030. 

2. Please provide your organization’s comments on Frequency Response.

LS Power has no comments at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

LS Power has no comments at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

LS Power has no comments at this time.

5. Please provide your organization’s comments on the Economic Assessment.

LS Power has no comments at this time.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

LS Power has no comments at this time.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

LSA is concerned that the TPP analyses have not adequately accounted for short-circuit duty (SCD) impacts of the numerous transmission upgrades recommended for approval in this planning cycle.  Preliminary examinations by our members indicate considerable potential SCD impacts from these new upgrades.

Specifically, we are concerned that, if the approved transmission upgrades are included in the base cases for Cluster 15 projects (as they should be) but the SCD mitigation for those upgrades is not, this will trigger SCD upgrades in those interconnection studies, resulting in high cost and timing impacts for these projects.  Even if the SCD mitigation is included in the next TPP cycle (and there is no guarantee that would occur), so the mitigation measures are then reclassified as Precursor Network Upgrades (PNUs), in the meantime these projects would have to post security and bear the COD impacts of the upgrades.

It would make much more sense to include the required SCD mitigation in the TPP recommendations in this cycle, consistent with the upgrades causing the SCD impacts, and LSA strongly believes that the draft Transmission Plan should be amended to include those SCD mitigation measures.

2. Please provide your organization’s comments on Frequency Response.

No comment at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comment at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

No comment at this time.

5. Please provide your organization’s comments on the Economic Assessment.

No comment at this time.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

LSA’s comments in this section focus on the proposed Transmission Plan Deliverability (TPD) reservations for Long-Lead-Time (LLT) resources, in Section 1.2.2.3 (Deliverability Reservations for Long Lead-Time Resources) of the draft transmission plan.

As LSA has stated before, we have significant concerns about the CAISO’s actions to wall off large amounts of deliverability for favored technologies.  The adverse impact of this action is magnified under the CAISO’s new Interconnection Request (IR) intake process, which limits capacity accepted for study based on available deliverability at each location.

The CAISO is proposing to hold back nearly 12,000MW of deliverability, for up to 15 years, including capacity not just on new upgrades “approved for a specific purpose,” but on transmission approved for other purposes.

LSA understands that the information in the transmission plan is implementation of its current policies and does not expect these comments to result in a policy change.  LSA also recognizes that this is the first planning cycle to include information about TPD reservations and appreciates the CAISO’s willingness to take this step toward additional transparency.  However, additional information is needed in order to have a serious policy discussion about the need for and impacts of these policies, and we believe that such discussions have not yet been held.

In view of the large amount of deliverability involved, and the promise of even more extensive and pervasive reservations in the future (more on that below)), LSA requests here: (1) better explanations of the terminology and data presented; and (2) explanations of the timeframes used to determine the reservation amounts; and (3) better transparency concerning the downstream impacts of these reservations.

Better explanation of the terminology and data

The CAISO should better explain the information presented in the draft plan, for example:

• “Current Reservations:”  In response to our questions at the stakeholder meeting, the CAISO clarified that these are actually recommended reservations in this TPP cycle, though some (e.g., some import reservations were carryovers from earlier planning cycles.  The CAISO should distinguish the reservations from earlier cycles from new proposed reservations in this planning cycle, and explain the need for the new reservations.

• TPD Allocations:  In response to our questions at the stakeholder meeting, the CAISO clarified that the 2,900+MW “reservation” at Diablo Canyon includes 2,500MW already allocated to offshore wind projects in the queue that gained their TPD Allocations in the same way as other projects and are subject to the same retention requirements (and thus are not of concern to LSA and others), as opposed to “proxy” reservations for resources not yet in the queue that may or may not ever materialize.  The CAISO should distinguish between reservation amounts that have been allocated to projects in the queue and those reserved for later, more speculative projects.

• Points of Interconnection (POIs):  The CAISO’s new IR intake process is highly dependent on TPD available at specific POIs.  Better identification is needed for the POIs involved for some areas – “North Coast,” “Central Coast,” and “Imperial Irrigation District.”  (In response to our questions at the stakeholder meeting, the CAISO clarified that North Coast means Humboldt Substation, Central Coast means Diablo Canyon Substation, and Imperial Irrigation District is unspecified mix of Mirage/Devers and Imperial Valley). 

Developers need to know the locations where the CAISO is constraining interconnections of and TPD allocations to non-favored resources, long before the next TPD Allocation cycle or publication of data for the next interconnection window.  This information should be included in the final Transmission Plan.

The CAISO said at the stakeholder meeting that developers one could look up the portfolio mix in the CPUC studies and orders, but LSA believes that the CAISO’s transmission plan should be a self-contained document; developers and other market participants should not have to look up such information in multiple documents when the CAISO could easily include such important information in its very large transmission plan. 

Explanations of the timeframes used

With few exceptions, the proposed TPD reservations use the 2039 portfolio numbers to determine the TPD reservations, where those exceed the 2034 figures.  Inherently, the longer the time horizon, the greater the degree of uncertainty, and locking up TPD for 15 years – much of it from existing transmission – warrants further discussion and justification.  TPD Allocations in 2039 would likely be to LLT resources that would not come on line until perhaps the 2040s, 20 years or more into the future. 

The CAISO’s transmission plan should include explanation and justification for reserving TPD for as long as 15 years for this purpose, for resources that may materialize two decades or more from now.  Given the uncertainty of such long-term projections, LSA asks the CAISO to consider using the 2034 figures instead unless it can state reasons for using the less-certain 2039 figures.

Impact on “downstream” substations

Logically speaking, TPD reservation at substations remote from load would also reduce available TPD at other substations between those points and load centers, since TPD is “deliverability to the aggregate of load.”  This will reduce the ability of projects with non-favored technologies to interconnect or obtain TPD Allocations at all of these intermediate substations, not just the outer locations where the TPD is reserved.

For example, a TPD reservation at Palo Verde would impact IR and TPD Allocation capacity at Colorado River, Redbluff, Devers, Valley, Alberhill, and other substations.  Likewise, a TPD reservation at Diablo Canyon would impact IR and TPD Allocation at Gates/Midway and POIs to the north, and also Midway/Vincent and POIs to the south.

LSA believes that a rational discussion of the CAISO’s TPD reservation approach requires transparency concerning all of the impacts, at all the locations where those impacts would occur.  The CAISO said at the stakeholder meeting that those impacts at other locations would be reflected when the Cluster 16 TPD substation mapping is released before the application window, but that mapping would just show the available TPD (if any) after the reservation impacts were subtracted out, not the reductions in available TPD from the reservations themselves. 

TPD reservations going forward

The CAISO signals in Chapter 1.2.2.3 of the draft plan its intent to follow this same TPD reservation process in the 2025-2026 planning cycle for “the additional resource types and locations” indicated in CPUC Decision 25-02-026.  Among other things, that decision asks the CAISO to refrain from approving new transmission for a significant portion of the recommended base portfolio. 

If the CPUC believes that these resources are so highly uncertain that the CAISO should exclude them from its new-transmission recommendations, then the CAISO should also exclude those resources from its TPD reservations.  It would be even more unfair, and jeopardize the rest of the portfolio, if the CAISO refrains from approving new transmission for these resources but still reserves TPD for them.  This inconsistent treatment would further erode the interconnection ability and TPD available from existing and already-approved transmission for more viable resources.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

NextEra Energy Resources, LLC (NEER) commends the CAISO for including the Manning-Metcalf 500 kV line as a reliability-driven project recommended for approval. This project and the two policy-driven projects in the PG&E Fresno area – reconductoring of the GWF-Kingsburg 115kV line and a new 230/70 kV bank at Helm – will support resources development in the area where NEER has renewable energy projects. The proposed Greater Bay Area 500 kV Transmission Reinforcement, including a new 500 kV line from Manning to Metcalf, is essential for supporting increased supply needs in the Bay Area and will also help relieve known thermal overloads and congestion on the Panoche-Las Aguillas-Moss Landing 230 kV path, which is one of the bottlenecks prohibiting the effective integration of solar and storage projects in Central California including NEER projects.

The CPUC IRP assumptions used in this cycle require approximately 15 GW of clean energy resources in Central California. In parallel, the 20-year Transmission Outlook study models as much as 40 GW of clean energy development in this area. In addition to reliability benefits, NEER anticipates that these projects will facilitate access to clean energy resources in the Central Valley area.

2. Please provide your organization’s comments on Frequency Response.

No comments at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comments at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

NEER respectfully urges CAISO to address the lack of deliverability capacity in the East of Pisgah area as expeditiously as possible. CPUC Integrated Resource Plan (IRP) portfolio transmittals to CAISO have consistently indicated the area as one of the largest for clean energy development. Numerous cost-effective renewable and storage resources are in the area, including a large portfolio of NEER renewable energy projects.  If the State is to reach its SB 1020 (Laird, 2022) and SB 100 (De León, 2018) requirements in a reliable and least-cost manner, the CAISO must begin planning now for transmission solutions to deliver these resources.

As shown in the policy-driven assessment, several on-peak deliverability constraints were found in both base and sensitivity portfolios for the East of Pisgah area. While the multiple and complex Remedial Action Schemes (RAS) being considered and planned-for in this area can provide short-term solutions, they could compromise the reliability and flexibility of CAISO’s grid operations. More importantly, RAS do not add Transmission Plan Deliverability (TPD) capacity sufficient to accommodate all stranded Cluster 14 and earlier-queued resources (e.g., out-of-state wind imports assumed to inject at the Harry Allen 500kV bus and Lugo 500kV bus), while still leaving some TPD capacity for allocation to Cluster 15 projects. A longer-term solution is needed, such as the Trout Canyon-Lugo 500 kV line, to provide deliverability to these projects.

The CPUC portfolios as studied in the current and past TPP cycles (2022-2023 TPP, and 2023-2024 TPP) are aligned with the CAISO 20-Year Outlook which points to the same transmission line – Trout Canyon-Lugo 500 kV – needed to address the chronic constraint on the Eldorado-Lugo 500 kV and Lugo-Victorville 500 kV lines impacting the East of Pisgah area. NEER acknowledges the CPUC request (Decision 25-02-025, Ordering Paragraph 2) for CAISO to conduct further analysis and begin regional discussion about appropriate siting and potential costs of out-of-state wind resources, including through the East of Pisgah area. CPUC’s request for CAISO to delay triggering approval of solutions necessary to support out-of-state resources on new transmission, pending further analysis, has real impacts on other renewables and storage projects that are waiting for deliverability in the East of Pisgah area. CAISO’s Wyoming wind sensitivity for the area shows, once again, that new transmission solutions are needed. As CAISO studies this further in the next TPP cycle, NEER requests a transparent process for stakeholders to engage, and an expeditious approval of a new transmission line to cost-effectively integrate the constrained resources in the East of Pisgah area.

5. Please provide your organization’s comments on the Economic Assessment.

No comments at this time.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

In the CPUC’s IRP process to adopt the 2024-2025 TPP base case portfolio, [1] NEER flagged a concern about in-state wind capacity assumptions likely being overstated. Whereas the portfolio assumes 831 MW of new Tehachapi wind capacity, 375 MW of new Solano wind capacity, 2,258 MW of new Northern California wind capacity, and 711 MW of new Southern Nevada wind capacity by 2030, NEER believes that the assumed new capacity is not likely to materialize due to numerous factors that constrain development in those regions, including limited transmission capacity, limited real estate availability, siting and permitting constraints, and impacts to the wind resource due to existing generation resources. If these resources do not materialize, the state will need other resources to fill the gap. The resources behind deliverability constraints in the East of Pisgah area have the greatest potential for low-cost clean energy resources to serve as a contingency, if the in-state wind resources fail to develop.

[1] Comments of NextEra Energy Resources, LLC on Proposed 2023 Preferred System Plan and Transmission Planning Process Portfolios, November 13, 2023, in R.20-05-003. Available at: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M520/K851/520851104.PDF

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

No comment at this time.

2. Please provide your organization’s comments on Frequency Response.

No comment at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

No comment at this time.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

No comment at this time.

5. Please provide your organization’s comments on the Economic Assessment.

No comment at this time.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

NCPA appreciates the details provided regarding the deliverability reservations for long lead-time resources. But NCPA continues to request more details on these reservations. Transparency regarding this information will be important to assist planning and development opportunities for alternative technologies and resources. Specifically, NCPA requests information on: (1) what TPD is being reserved down to the specific busbars; (2) what portion, if any, of the deliverability reservations described on slide 21 has been reserved through the TPD allocation process; (3) which internal transmission constraints are impacted by the proposed projects; and (4) which deliverability reservations are for subscriber PTOs. This information will help stakeholders better understand the near-term and long-term impacts of the deliverability reservations.

NCPA further reiterates that CAISO should establish clear rules and requirements to determine when a proposed Long Lead Time Generation or Storage Resource is no longer viable.  In the current political environment, there is considerable risk faced by resource developers, particularly offshore wind development.  While NCPA does not object to allowing a Long Lead Time Generation and Storage Resource to defer a first attempt to seek TPD, there should be clear rules and requirements to allow CAISO to make an ultimate determination of when a resource is no longer feasible for development and, if such determination is made, to release any reserved TPD to the market for the purpose of interconnecting alternative projects.  Whether such rules and requirements are based on defined timelines (e.g., if the project is delayed beyond an expected COD) or tied to key regulatory changes that result in the project no longer being viable, it will be necessary to develop such criteria to ensure that infeasible projects do not linger in the queue holding valuable TPD that could be used by other interconnection customers.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Pacific Gas and Electric Company (PG&E) appreciates the opportunity to provide comments in response to the Draft 2024-2025 Transmission Plan and information presented during the stakeholder meeting on April 15, 2025.  PG&E recognizes the substantial efforts and commends the California Independent System Operator’s (CAISO) Staff for its diligent work in performing the studies associated with the 2025 plan and the review of the projects submitted into the 2024 Request Window.  Below are comments that address various aspects of the Reliability-driven projects being recommended for approval.

In Service Date Concerns on the San Jose B – NRS 230 kV Line

PG&E appreciates the CAISO’s commitment to the Greater Bay Area, including San Jose, and the CAISO’s efforts to improve the reliability and capacity of the electrical grid in the San Jose area via the proposed NRS – San Jose B 230 kV line. The draft study plan states the target in-service date should be no later than 2030, but that the ideal in-service date for this project is concurrent to the expected in-service date of the Metcalf-San Jose B HVDC and the Newark-NRS 230 kV line projects in 2028 (Pages 69-70). PG&E has several concerns about the ideal timing associated with the in-service date for the proposed NRS – San Jose B 230 kV line.  First, as a competitive transmission solicitation eligible project, the earliest a project sponsor will be identified is late first quarter 2026. That means that project development will not potentially begin until the second quarter 2026. That leaves less than three years for the project sponsor to permit, order and receive necessary long-lead time materials, and then construct a major transmission project by the ideal 2028 in-service date. That timeline seems infeasible. Second, requesting any bidder to submit a proposal for a project in-service date that is less time than a normal job timeline has a high potential of being unnecessarily more expensive which is an affordability issues for all Transmission Access Charge (TAC) customers.  Finally, both LS Power and PG&E have approved work related to this project which requires sequenced construction efforts due to land constraints, which makes an interconnection date before 2030 infeasible for the NRS – San Jose B 230 kV line.  For these reasons, PG&E recommends that the NRS – San Jose B 230 kV Line competitive transmission project have a targeted in-service date of no sooner than 2030. 

Clarification Request on San Jose B – NRS 230 kV Line Project Scope

In the 2024–2025 Draft Transmission Plan (Page 69) and Appendix I (pages I-10), the narrative indicates that the proposed San Jose B – NRS 230 kV line will "need to be looped into a planned 230/115 kV switching station" to facilitate delivery of power to nearby 115 kV networks serving large data center loads.  However, this key design element does not appear in the CAISO’s April 15, 2025, stakeholder presentation, specifically in Slide 33, where the description and diagram of the project do not mention the loop into the 230/115 kV switching station.  PG&E respectfully request that CAISO clarify the scope of this project and explicitly confirm whether the San Jose B – NRS 230 kV line will be looped into the planned 230/115 kV switching station as described in the Draft Plan. PG&E supports this design approach, as looping the line into the switching station will improve service to the 115 kV system and better position the network to serve data center and other load growth in the South Bay.

Manning–Metcalf 500 kV Line – Need for Further Evaluation of Path 15 Impacts

The Draft Transmission Plan includes the Manning–Metcalf 500 kV line project to reinforce south-to-north transfer capability into the Greater Bay Area.  While PG&E supports the objective of improving regional reliability and load-serving capacity, PG&E requests that CAISO acknowledge that further studies investigating different scenarios will be needed to evaluate if the project results in any unintended impacts on Path 15.  In particular, PG&E recommends that CAISO coordinate with the selected project sponsor to ensure there are plans to mitigate any identified impacts to Path 15.  This assessment will be important for ensuring long-term system reliability and alignment with Western Electricity Coordinating Council (WECC) path ratings.  The WECC Project Progress Report (PPR) process may serve as an appropriate venue to conduct and document such evaluation in coordination with affected transmission owners and path operators.  In addition, given the existence of a large STATCOM at the Gates 500 kV Substation and the HVDC converter station at Metcalf 500 kV, PG&E also recommends that Sub Synchronous Control Interaction (SSCI) and Sub-Synchronous Resonance (SSR) risk be evaluated with the selected project sponsor for the Manning-Metcalf 500 kV line. 

PG&E looks forward to collaborating closely with CAISO and the selected project sponsor on these evaluations.  By aligning our efforts and focusing on comprehensive, forward-looking planning, we can ensure that the investments made into the grid infrastructure yield maximum benefits in terms of reliability, compliance, and economic efficiency, while supporting the state’s renewable energy objectives effectively.

STATCOM Project Inconsistencies

Across the Draft Transmission Plan, there are inconsistencies with the in-service dates for the Round Mountain 500 kV Dynamic Voltage Support and Gates 500 kV Dynamic Voltage Support projects, specifically on pages 187, 188, and 192.  PG&E respectfully requests that the CAISO ensure consistency across these references and confirm the in-service dates for both projects throughout the Draft Plan.  In addition, on page 192, the project name listed in Table 8.3-1 as “Round Mountain-Table Mountain statcom – re Diablo Canyon” is referring to Gates 500 kV Dynamic Voltage Support and as such needs to be updated to reference the appropriate project name of ‘Gates 500 kV Dynamic Voltage Support’.

Increased Ampacity Ratings for the South Oakland Reinforcement Project

In order to meet expected load growth in South Oakland, PG&E requests that the CAISO update the minimum line ratings in both the Draft Plan main text (Pages 65-66) and Appendix H for the South Oakland Reinforcement Project.  PG&E requests the following specific edits:

1. Reconductor Moraga – San Leandro #1, #2, and #3 115 kV lines to at least 2288 Amps summer normal rating or higher. [Previously 1500 Amps]
2. Reconductor Moraga – Oakland J 115 kV line to at least 2288 Amps summer normal rating or higher. [previously 2000 Amps]
3. Reconductor San Leandro – Oakland J 115 kV line to at least 2288 Amps summer normal rating or higher. [Previously 2000 Amps]

2. Please provide your organization’s comments on Frequency Response.

N/A 

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

N/A 

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Clarification on In-Service Date for the new policy projects

The Draft Plan presents conflicting in-service dates for the three new Policy-driven Transmission Projects: (1) Eagle Rock- Fulton- Silverado 115 kV Line Reconductor, (2) Reconductor of GWF – Kingsburg 115 kV line and (3) New Helm 230/70 kV Bank #2.  Specifically, the Draft Plan (Page 190) and Appendix H indicate different timelines.  PG&E believes the correct in-service dates are all no sooner than 2034 and requests that the CAISO align all references accordingly for the three Policy-drive transmission projects.

5. Please provide your organization’s comments on the Economic Assessment.

Request for a CAISO hosted workshop overviewing the TEAM method

While PG&E does not have specific comments on the results of this years’ Economic Assessment, we reiterate a request for a review of the methodology.

To PG&E’s knowledge, the last time the CAISO hosted a workshop providing an overview of the Transmission Economic Assessment Methodology (TEAM) method was in 2017.  Given the increases in approved transmission projects, congestion, and resource siting trends, PG&E proposes that CAISO provide the stakeholder community with some training on the TEAM method so that stakeholders are better informed to comment about the results.

For example, aligned with the assumption in the Integrated Resource Plan (IRP), new solar development will use the Production Tax Credit (PTC).  Given the value of the PTC and the increase in the value of the Portfolio Content Category 1 (PCC1) Renewable Energy Credit (REC), PG&E is not sure that the assumption that renewables will curtail at $-25 will always be reasonable.  PG&E would like to better understand the forum to discuss important assumptions like this one regarding modeled congestion prices.  PG&E would also be interested in a scenario where a lower curtailment value is used (i.e., further negative).  In another example, revenues for certain resources (“owned facilities”) are assigned to load-serving entities (LSEs).  PG&E understands that the CAISO is considering renewables and utility-owned generation as Owned Facilities but would appreciate further clarity.  Given the increasing amounts of curtailment expected in the CAISO system, it is important to verify that costs of curtailment, congestion, and negative pricing are being modeled appropriately.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Request for CAISO to provide more transparency on TPD results

PG&E agrees with stakeholders on the April 15th stakeholder call that the CAISO should provide more transparency on what Transmission Plan Deliverability (TPD) results from new upgrades.  The upgrades will result in some amount of TPD being made available, some of which is driven by policy projects.  If the CAISO does not provide visibility into how much TPD will result from the upgrades, stakeholders will not be able to judge if resources in the preferred plan will be able to be studied in Cluster 16.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The Port of Oakland (Port), established in 1927 as an independent department of the City of Oakland, serves as trustee for all Port property under the California Tidelands Trust. It operates four primary lines of business: Aviation, Maritime, Commercial Real Estate (CRE), and Utilities. Port operations, along with those of its tenants and customers, collectively drive significant local, regional, national, and global economic activity, supporting over 98,000 jobs across the region.

The Port of Oakland’s Seaport is among the ten busiest container ports in the United States and serves as one of four major West Coast gateways for containerized shipments. It is the primary maritime link for international cargo flows to and from Northern California, the agricultural Central Valley, and western Nevada and is a significant export Port of California and US agricultural and other products. The Oakland International Airport (OAK) is a critical component of the San Francisco Bay Area’s transportation infrastructure, ranking as the region’s leading airport for air cargo, second in aircraft movements, and third in passenger volume. The Port is uniquely the only port authority in the state that operates a publicly owned utility (POU), which provides electric utility services to Port-operated and tenant-operated facilities.

As a stakeholder and a publicly owned utility (POU) with distribution facilities that are interconnected with PG&E at transmission and distribution levels, the Port of Oakland appreciates the opportunity to provide input on the 2024-2025 CAISO Transmission Planning Process. The Port's unique position as a major driver of regional industrial and commercial growth and its critical role in supporting California’s zero-emission and climate resilience policies underscore the importance of prioritizing electrical infrastructure improvements in the Oakland area.

The Port is a recipient of multiple state and federal grants supporting sustainable infrastructure development. These include grants under the EPA’s Clean Ports program, MARAD’s Port Infrastructure Development Program (PIDP), the Trade Corridor Enhancement Program (TCEP) administered by CalSTA, and funding from the Inflation Reduction Act and the Bipartisan Infrastructure Law. These grants underscore the Port’s commitment to advancing green and resilient infrastructure, including electrification projects and clean energy initiatives, which align with CAISO’s goals. The Port intends to integrate these grant-funded efforts with the transmission planning process to optimize resources and accelerate project implementation.

The Port appreciates CAISO's efforts in addressing the increasing energy demands of the Oakland area and looks forward to continued collaboration to ensure the timely and efficient delivery of these critical infrastructure projects. The Port would like to provide the following specific comments with regard to the Reliability Assessment Recommendations – PG&E Area, provided at the 2024-2025 Transmission Planning Process Stakeholder Meeting held on April 15, 2025:

PG&E’s North Oakland Reinforcement Project:

The Port supports and is committed to actively participating in the planning process for PG&E’s North Oakland Reinforcement Project.

Significant industrial and commercial growth at the Port, mostly driven by electrification, will result in substantial load increases. This includes the urgent need for expanded Electric Vehicle (EV) charging infrastructure to support clean and sustainable operations at the Port of Oakland Seaport.

The Port strongly advocates for the soonest possible in-service date for the North Oakland Reinforcement Project, currently planned for May 2032, as the Port is most directly impacted by limitations in the Oakland load pocket. Accelerating this timeline will better align with the immediate and growing demands of industrial electrification and EV infrastructure expansion.

The Port supports PG&E’s project scope including rebuilding two existing 115kV lines into four lines and performing other work in and around Oakland to bring more capacity to the area. This solution appears to be the most viable and efficient approach to increasing capacity in the North Oakland area and meeting the region’s near-term energy demands.

PG&E’s South Oakland Reinforcement Project:

The Port supports PG&E’s project scope for increased transmission capacity to the South Oakland area and is eager to actively participate in this process.

Like the North Oakland area, industrial and commercial load in South Oakland is rising significantly, driven by the electrification of facilities and operations at OAK and surrounding areas. Specifically, forecasted activity growth and electrification of facilities and equipment will require more demand.

The Port emphasizes the urgency of PG&E’s efforts to implement comprehensive solutions for the South Oakland Area. Timely planning and execution are essential to accommodate the rapidly evolving energy needs of this region. The success of OAK and other sustainable initiatives depends on timely investments in transmission capacity. The Port strongly urges prioritizing the development of South Oakland capacity expansion plans to ensure alignment with these transformative projects.

The Port will actively collaborate with PG&E throughout the project planning and implementation process and will work closely with community partners to build broad support across Oakland. Collaborations with stakeholders will ensure that these vital infrastructure improvements serve the needs of all Oakland residents and businesses.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

The City of Santa Clara, dba Silicon Valley Power (SVP), appreciates the opportunity to comment on the CAISO Draft 2024-2025 Transmission Plan (“Draft Plan,” hereafter). The comments and questions below address the material presented at the CAISO Stakeholder meeting on April 15, 2025, and the 2024-25 TPP draft report posted on March 31, 2025.  SVP acknowledges the significant efforts of the CAISO staff to develop this comprehensive report.

SVP Supports the CAISO-Proposed “Hybrid” Transmission Project and South Bay Reinforcement Project for the San Jose Area

The CAISO-proposed “Hybrid” transmission project (“Hybrid project,” hereafter) is comprised of the following network additions:

1. A new Newark to NRS high capacity 230 kV AC line;
2. A new 1,000 MW HVDC link between Metcalf and San Jose B 230 kV; and
3. A new high capacity 230 kV AC line between San Jose B and NRS.

SVP’s independent assessment indicates that the third element of the Hybrid project, that is, adding the high capacity 230 kV AC line between San Jose B and NRS, which is recommended for approval in the Draft Plan[1], would increase SVP’s import capability and improve the San Jose area’s overall reliability. However, SVP’s assessment indicates a potential adverse impact on SVP’s transmission system and surrounding PG&E systems.

SVP also supports the newly proposed South Bay Reinforcement Project,[2] which is expected to address several overloads identified in the Draft Plan with the Hybrid project. However, SVP’s studies indicated that the Kifer (KRS) – FMC 115 kV line will be adversely impacted and overloaded with the proposed project additions under credible NERC & CAISO contingency conditions that must be addressed if the new San Jose B and NRS 230kV line element of the Hybrid project and the South Bay Reinforcement Project are approved.

SVP’s Load Continues to Grow at a Dramatic Rate, and CEC and SVP Expect Significant Load Growth Over the Next Several Years

As the CAISO is aware, SVP’s load is expected to grow considerably in the next several years, primarily driven by hyper-scale data centers.[3] SVP has had seven new 60 kV-connected data centers come into service in the past three years, one 60 kV-connected data center is under construction and expected to be in service  this summer, eleven 60 kV-connected data centers are waiting for SVP’s approval to connect to the SVP system contingent upon the completion of the CAISO-proposed “Hybrid” Transmission projects and South Bay Reinforcement Projects, and SVP is actively working with twelve future data center customers. Each of these existing and future data centers are expected to ramp up significantly in the future 10-year planning horizon and beyond, causing SVP’s 1-in-10 peak load forecast to increase to 1,368 MW in 2034. The 2035 1-in-10 peak load forecast is even higher at approximately 1,636 MW, which assumption will be incorporated into the 2025-2026 Transmission Plan.

The Hybrid Project Requires KRS – FMC 115 kV Line Reconductoring

SVP used the CAISO 2024-2025 TPP final reliability assessment 2034 cases (October 2024 posted version) for the Greater Bay Area (GBA) Summer Peak conditions to perform steady state power flow analysis to assess any potential adverse impacts of the Hybrid project, the new 4^th Metcalf 500/230 kV transformer, the new Greater Bay Area 500 kV Transmission reinforcement project and South Bay Reinforcement project on SVP’s system. Table 1 below summarizes SVP’s findings that show overloads on the FMC – San Jose B and KRS – FMC JCT 115 kV lines. CAISO has discussed using an HVDC Run Back scheme with SVP to mitigate overloads caused by these project additions. The loadings in Table 1 indicate that the use of an HVDC Run Back scheme could be an effective mitigation strategy.

Table 1: SVP Studies Showing Instances in 2034 Where the San Jose B HVDC Runback Scheme Fixes or Reduces Overloads

The HVDC Run Back scheme is effective in mitigating some issues on the FMC – San Jose B and KRS – FMC JCT 115 kV lines, as shown in Table 1; however, the use of the HVDC Run Back scheme causes new overloads and increased loadings on the Northern part of the SVP system between Newark, NRS, and KRS as shown in Table 2.

Table 2: SVP Studies Showing Instances in 2034 Where the San Jose B HVDC Runback Scheme Causes New Overloads or Increased Loading North of SVP

In addition to the new overloads and increased loadings to the North of SVP that would be caused by the use of an HVDC Run Back, use of this scheme would also cause new overloads South of SVP, as noted in Table 3. The San Jose A – San Jose B and Metcalf – Baily 115 kV lines become overloaded with the use of a HVDC Run Back scheme under contingency conditions.

Table 3: SVP Studies Showing Instances in 2034 Where the San Jose B HVDC Runback Scheme Causes New Overloads South of SVP

SVP’s study results showed that applying a 0 MW HVDC Run Back scheme on the Metcalf-San Jose B HVDC line can either completely mitigate or significantly reduce overloads along the San Jose B – FMC – KRS 115 kV path for P1 and P6 contingencies. However, use of the HVDC Run Back scheme causes the system north of SVP and parts of the 115 kV system south of the San Jose area to experience increased loading or new overloads along the following lines:

• Los Esteros - SSS 230 kV
• Newark - NRS 115 kV #1 & #2 lines
• Zanker - KRS 115 kV lines
• Los Esteros - Nortech - NRS 115 kV lines
• San Jose A – San Jose B 115 kV line
• Metcalf - Baily 115 kV lines

Avoiding a KRS – FMC JCT 115 kV mitigation by applying a 0 MW HVDC Run Back scheme on the San Jose B HVDC causes new reliability overloads that will need to be addressed concurrent with the Hybrid project’s in-service dates of 2028 & 2030. An optimal Run Back point between 0 and 1,000 MW may exist where an HVDC Run Back scheme on the San Jose B HVDC may be more effective than a 0 MW setting. To determine the optimal point, SVP submits that a comprehensive study covering various years and seasonal conditions should be conducted. CAISO should perform this study to ensure that one or multiple HVDC MW Run Back setpoints effectively mitigate all overloads without creating new ones. Implementing such an automatic operation could lead to hundreds of potential setpoints for contingencies, seasonal conditions, and different operating year combinations. Having this type of scheme would increase both complexity and the risk of HVDC Run Back mis-operations. Therefore, SVP suggests that the most cost-effective and reliable solution would be to reconductor the KRS – FMC JCT 115kV line instead of using an HVDC Run Back scheme as a mitigation measure.

KRS – FMC 115 kV Line Reconductoring Synergies with the “South Bay Reinforcement Project”

The KRS – FMC Jct 115 kV line is 5.7 miles long and is comprised of both overhead and underground conductors. Given its relatively short length, the cost of reconductoring this line would be small in comparison to the overall $205 million - $410 million estimated cost[4] of the South Bay Reinforcement Project. Using PG&E’s per unit cost estimates, SVP estimates that the KRS – FMC Jct 115 kV reconductoring will incrementally increase the cost of the South Bay Reinforcement Project in the range of $5-$10 million.

The Trimble – San Jose B 115 kV line reconductoring included in the South Bay Reinforcement Project, is planned to be capable of achieving 3,000 Amps (598 MVA), and this line shares common towers and underground sections with the KRS – FMC Jct 115 kV line for more than 2.5 miles. From the clearance and logistical standpoint, completing both reconductoring projects simultaneously would be cost-effective and practical. For example, if some of the towers need additional reinforcements to carry the reconductored lines, then that determination can be made if both the circuits are considered for reconductoring at the same time. Similarly, if the shared underground section needs to be abandoned to facilitate the construction of a new underground segment capable of carrying 3,000 Amps, both circuits can be upgraded simultaneously. Therefore, it will be cost-effective to reconductor both KRS – FMC Jct 115 kV and Trimble – San Jose B 115 kV lines simultaneously. As mentioned earlier, SVP’s load assumed in the 2025-2026 TPP is higher than the one assumed in the current planning cycle and will likely worsen the loading on the KRS – FMC Jct and FMC Jct – FMC 115 kV lines. Therefore, delaying approval until the next TPP cycle would not only exacerbate the overloading issue, but is also likely to sacrifice any cost-savings that could be available by reconductoring the KRS - FMC 115 kV line simultaneously with reconductoring the Trimble – San Jose B 115 kV line.

SVP Recommends CAISO to Stage Reconductoring of the FMC Jct – FMC 115 kV Line

Once the KRS–FMC Jct 115 kV line is reconductored, the 1.58-mile FMC Jct – FMC 115 kV line will become the limiting element at 307 MVA. Under contingency conditions forecast for 2034, this line is projected to reach 95% of its emergency rating, as shown in Table 5 below.

Given SVP’s growing load forecast, which will be incorporated into the next TPP cycle, this line is expected to exceed its emergency rating within the 10-year planning horizon. To ensure long-term system reliability, SVP recommends staging the reconductoring of the FMC Jct – FMC 115 kV line following the completion of the KRS – FMC Jct 115 kV line reconductoring project. This phased approach will provide operational flexibility while reducing disruption and ensuring a smooth transition in system upgrades. SVP urges CAISO to approve this reconductoring effort, upgrading the FMC Jct – FMC 115 kV line to 3,000 Amp capacity as the next step in strengthening the transmission network.

Table 5: Examples of SVP 2034 Loadings approaching 100% on the FMC Jct – FMC 115 kV line

SVP’s Closing Comments

SVP supports the CAISO-proposed Hybrid transmission project and the new South Bay Reinforcement Project, recognizing their importance in enhancing regional reliability and addressing growing energy demands. However, SVP’s independent analysis shows that with these projects in their current composition, significant overloads on the KRS – FMC Jct 115 kV line will remain, requiring mitigations to maintain operational stability under credible NERC & CAISO planning standards. Reconductoring the KRS – FMC Jct 115 kV line is essential to mitigating these impacts, ensuring seamless integration with planned infrastructure improvements, and proactively addressing SVP’s and the overall South Bay region’s rapidly growing load.

Once the KRS–FMC Jct 115 kV line is reconductored, the FMC Jct–FMC 115 kV line will become the limiting element. Given SVP’s growing load forecast, which will be incorporated into the next TPP cycle, the FMC Jct – FMC 115 kV line is expected to exceed its emergency rating under contingency conditions within the 10-year planning horizon. To maintain long-term system reliability, the reconductoring of the FMC Jct–FMC 115 kV line should be staged following the completion of the KRS–FMC Jct reconductoring project. This phased approach will provide operational flexibility, minimize disruptions, and ensure a smooth transition in system upgrades.

Further, aligning the KRS–FMC Jct 115 kV line reconductoring effort with the South Bay Reinforcement Project, given its shared towers and underground sections with the Trimble–San Jose B 115 kV line,  provides cost-effective logistical synergies while securing system reliability. Given the relatively small cost relative to the broader transmission upgrades already included in the plan, and the substantial reliability benefits gained, SVP urges CAISO to approve this reconductoring effort in the current planning cycle to ensure a resilient, future-ready transmission network.

[1] See “San Jose B-NRS 230 kV line”, pp. 69-70, 2024-2025 Transmission Plan Draft, March 31, 2025.

[2] See “South Bay Reinforcement Project”, pp. 70-72, 2024-2025 Transmission Plan Draft, March 31, 2025.

[3] SVP’s load growth includes load where back-up generation has been granted CEC-approved small generator exemptions for the hyper-scale data centers in SVP’s service territory. 

[4] See “South Bay Reinforcement Project”, page 72, 2024-2025 Transmission Plan Draft, March 31, 2025

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

Please see attached letter for full comments with footnotes and citations. In particular please refer to Recommendation #1 and #5 for this question.

2. Please provide your organization’s comments on Frequency Response.

Regenerate has no comments on Frequency Response at this time.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

Please see attached letter for full comments with footnotes and citations. 

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

Please see attached letter for full comments with footnotes and citations. In particular please refer to Recommendations #2, #3, #4, #6, #7, and #8 for this question.

5. Please provide your organization’s comments on the Economic Assessment.

Please see attached letter for full comments with footnotes and citations. In particular please refer to Recommendation #9 and #10 for this question.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Please see attached letter for full comments with footnotes and citations.

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.

Viridon California LLC (“Viridon”) appreciates the CAISO’s efforts to study and identify solutions to address emerging load growth and congestion issues, particularly in the Northern California region.   Viridon supports including the new Manning-Metcalf 500 kV facility in the final Transmission Plan to address Greater Bay Area reliability issues.  The new Manning-Metcalf line is a significant first step in meeting reliability needs, and Viridon believes that the CAISO should continue to study cost-effective solutions to Path 15 congestion to further enhance reliability and address wholesale energy cost disparities between Northern and Southern California ratepayers.

As the CAISO notes in the draft Transmission Plan, Path 15 congestion increased significantly in this cycle compared to previous transmission planning cycles, based in part on the high volume of CPUC portfolio resources in the Fresno/Kern areas.  This upward trend in Path 15 congestion may be further exacerbated by a material increase in resources mapped to the Fresno area in the CPUC portfolios studied in the 2025-2026 planning cycle.

At the same time, the CEC’s recent IEPR demand forecast suggests the CAISO system may shift to a winter peak by 2040.[1] Based on CAISO’s reliability results in the draft Transmission Plan, Path 15 is projected to be fully loaded during the winter peak as early as 2034, with ~5,400 MW South to North flow. In addition, PG&E’s recent earnings call indicated an additional 3.2 GW of datacenter interconnection requests during the first quarter of 2025, pushing total datacenter interconnection requests to 8.7 GW in the PG&E area.[2]  The CAISO’s economic study results combined with these new developments put additional importance on the need to reinforce Path 15.

Viridon’s recent acquisition of an economic interest in the Los Banos-Gates #3 500 kV line (the Path 15 Project) presents new opportunities to optimize existing facilities to cost-effectively serve CAISO customers.  This transmission facility is an 84-mile, 500 kV transmission line linking Northern and Southern California. The facilities are owned and maintained by the Western Area Power Administration (“WAPA”) and operated by the CAISO.  Viridon believes its acquisition of the Path 15 Project and associated partnership with WAPA can result in cost-effective and timely solutions that the CAISO can consider in future cycles. 

In addition to addressing reliability and congestion issues, Viridon believes the Los Banos-Gates #3 line can play a vital role in interconnecting new renewable and storage resources in the central California area.  There is significant developer interest in siting new resources near the Path 15 Project, and the facility received its first interconnection request in the Cluster 15 cycle.  Viridon looks forward to working with the CAISO and WAPA to comprehensively study how the Path 15 Project can be best used to help interconnect new resources in a timely and cost-efficient way.

In an effort to further advance CAISO’s analysis on these issues, Viridon also provides specific comments and questions for CAISO’s consideration below:

• Winter Reliability Assessment – Please confirm that the 2024-2025 transmission plan studied a 2034 Winter Peak load condition in its reliability assessment (as noted in the Final Study Plan) and provide the winter peak hour used in this analysis.
• Future Policy-Driven Need Assessment – Does the CAISO plan to study Winter Peak load conditions as part of the policy-driven need assessment in future planning cycles to plan for potential shift of HSN from summer to winter?
• Manning-Metcalf 500 kV Impact on Path 15 – Does the CAISO intend to redefine Path 15 to reflect the new Manning-Metcalf line?  Will the CAISO engage in a path rating update for Path 15 based on the addition of the line?
• TEAM Training – Viridon supports PG&E’s comment on the 2025-2026 Draft Study Plan requesting TEAM training. Ensuring that stakeholders understand the TEAM economic analysis is critical to presenting cost-effective solutions to address the identified congestion challenges.

[1] See the CEC’s revised demand forecast, Item 09 Revised 2023 AAFS Hourly Results of the CED Forecast.

[2] See PG&E’s Q! 2025 earnings call, noting that its data center pipeline has grown from 5.5 gigawatts to 8.7 gigawatts. https://finance.yahoo.com/news/q1-2025-pg-e-corp-071850005.html. 

1. Please provide your organization’s comments on Reliability-driven Projects Recommended for Approval.

2. Please provide your organization’s comments on Frequency Response.

3. Please provide your organization’s comments on Maximum Import Capability Expansion Requests.

4. Please provide your organization’s comments on Policy-driven Projects Recommended for Approval.

5. Please provide your organization’s comments on the Economic Assessment.

Please find citations supporting these comments in the attached document.

The Working for Advanced Transmission Technologies (“WATT”) Coalition appreciates the opportunity to provide comments to the California Independent System Operator (“CAISO”) on the 2024-2025 Draft Transmission Plan. We appreciate that CAISO highlights a focus on “Continued consideration of grid-enhancing technologies, not only as a best practice, but as required by FERC Orders No. 1920/1920-A and 2023, and encouraged in California legislation”. Our comments aim to provide support and suggestions for that work.

The WATT Coalition is a trade association focused on facilitating the adoption of advanced technologies on the US electric transmission system that improve reliability, lower costs, and enable economic development. WATT includes generation owners and developers, clean energy finance interests, and transmission owners; and technology vendors, offering expertise in Advanced Power Flow Control, Dynamic Line Ratings, and Topology Optimization. The views and opinions expressed in this filing do not necessarily reflect the official position of each of WATT’s individual members. 

A. Background 

1. About Grid Enhancing Technologies  

Grid Enhancing Technologies (“GETs”) optimize the delivery of power over existing infrastructure. This includes Dynamic Line Ratings (“DLR”), which adjust transmission capacity in real time based on environmental conditions rather than relying on static limits that often unnecessarily restrict power delivery; Advanced Power Flow Controllers (“APFC”), which actively manage power flows to alleviate congestion and improve system flexibility; and Transmission Topology Optimization (“TTO”), which uses software-driven network reconfiguration to maximize grid efficiency. These technologies have been successfully deployed around the world to unlock additional grid capacity, reduce congestion costs, and improve overall system reliability. 

GETs are gaining momentum in the United States, but are far from being widely deployed. WATT does not know of any U.S. utilities or system operators that have systematized their evaluation and deployment of GETs across relevant teams. Valuable new resources on steps to adopting GETs in the U.S. come from The Brattle Group and Grid Strategies in April 2025: Incorporating GETs and HPCs into Transmission Planning Under FERC Order 1920; Electric Power Engineers: Assessment and Evaluation of Grid Enhancing Technologies (GETs), (discussed in Section III.b below); and, from January 2025, the Electric Power Research Institute’s Grid Enhancing Technologies for a Smart Energy Transition (“EPRI GET SET”) initiative: white papers on "Applications and Opportunities” for DLR, APFC and TTO.

2. Congestion remains expensive for Californians 

In 2024, congestion costs in CAISO totaled $983 million. Given the magnitude of congestion on the system, there is significant opportunity for economically-driven planning to reduce these costs. GETs can often resolve 40% or more of transmission congestion by unlocking additional grid capacity. Research by the U.S. Department of Energy, as well as worldwide case studies, have established that GETs provide a cost-effective means of alleviating congestion. GETs should be systematically studied as part of CAISO’s planning process, which could additionally fulfill the new requirements of Senate Bill 1006 (“SB1006”) for utility GETs studies, described below. 

3. New state law requirements would be efficiently fulfilled by incorporating GETs in economic planning 

Section 1.6.8 of the Draft Transmission Plan, “Relevant state legislation,” mentions Senate Bill 1006 (“SB1006”) passed in 2024, which "requires the IOUs to evaluate their lines and submit a plan for GETs integration into the ISO’s annual transmission planning process, beginning in 2026”. It is the WATT Coalition’s view that the enactment of SB1006 last year requires utilities to systematically evaluate the deployment of GETs. The law requires GETs to be evaluated to:  

(A) Increase transmission capacity.  

(B) Reduce transmission system congestion.  

(C) Reduce curtailment of renewable and zero-carbon resources.  

(D) Increase reliability.  

(E) Reduce the risk of igniting wildfire, by means of investments that are consistent with the transmission utility’s approved wildfire mitigation plan.  

(F) Increase capacity to connect new renewable energy and zero-carbon resources.  

(G) Increase flexibility to reduce risks surrounding technology and permitting uncertainties in statewide electrical system planning and improve optionality for load-serving entities. 

WATT believes that because CAISO performs economic planning on behalf of the California utilities, it could efficiently support their implementation of SB1006 by studying GETs in the TPP. Indeed, it would be most efficient for California ratepayers if CAISO centralized the economic evaluation of GETs. The law reads “On or before January 1, 2026, and every two years thereafter, each transmission utility shall prepare a study of the feasibility of projects using grid-enhancing technologies” to increase transmission capacity, reduce congestion, reduce curtailment, increase reliability, reduce wildfire risk, increase capacity for zero-carbon resources, and increase flexibility and optionality around forecasting and construction risks. Therefore, an economic evaluation of the value of GETs on the California grid must be performed before the end of this year. Another benefit of CAISO performing such an analysis on behalf of the utilities would be that CAISO would have the ability to study the value of GETs across utility seams, where there may be significant transmission constraints. 

B. Responses to Draft Transmission Plan 

1. Overview of CAISO’s evaluation of GETs 

In Section 1.4 of the Draft Transmission Plan, “Additional Transmission Plan Influences,” CAISO distinguishes between GETs that are used by the ISO in planning and those used by the ISO in operations. “The ISO typically considers advanced conductors and power flow controllers as planning tools providing an alternative to other capital expenditures. We also consider dynamic thermal line ratings and topology optimizations in accessing operational benefits through additional capacity providing economic or emergency measure uses”. The WATT Coalition encourages CAISO to leverage all GETs across various aspects of both transmission planning and operations. For instance, tools like DLR can provide critical insights into line performance that can and should inform asset replacements and infrastructure investment decisions. Similarly, APFC allows for rerouting of power from overloaded lines in real-time, offering reliability benefits that can be factored into operational strategies. 

At the most recent CAISO TPP stakeholder meeting on April 15, a representative of the ISO stated that “You can’t use DLR in planning, since you won’t be able to forecast what the weather conditions will be”. WATT respectfully responds to this concern, noting the growing body of research that demonstrates the feasibility of incorporating weather-adjusted line ratings (“WALR”) into planning models. WALR relies on historical weather data and statistical modeling to estimate line capacities under likely conditions. For example, the study Time Series Power Flow and Contingency Analysis with Weather Adjusted Line Ratings: A Synthetic WECC Case Study by AES Corporation staff showed that applying WALR reduced total overloaded hours by more than 80% for heavily loaded lines, and reduced net overloads by 67%, eliminating over 18,000 cumulative hours of overloads while only causing an additional 355 hours of additional overloads. These results, achieved through planning models using historical weather profiles, affirm that DLR-type ratings can inform long-term investment decisions under planning paradigms. The CAISO successfully studies weather-dependent generation resources in planning models – weather-dependent transmission performance should also be considered. In addition, NREL has demonstrated that benefits of DLR can be rapidly estimated with existing datasets. We recommend that CAISO follow either of these models to identify candidate lines for DLR deployment. 

2. Establishing a framework for GETs evaluation 

In Section 1.6.7 of the Draft Transmission Plan, “Grid-Enhancing Technologies and non-wires solutions,” CAISO  acknowledges stakeholder requests for a formal framework to integrate GETs into both transmission planning and operations. “Stakeholders have suggested that [sic] establish a framework to integrate Grid-Enhancing Technologies (GETs) into the transmission planning process and transmission operations, noting the significant benefits of GETs in reducing congestion and curtailment, mitigating constraints, enhancing traditional transmission upgrades, and serving as alternatives to traditional upgrades in the transmission or interconnection process”. CAISO noted that it “supports appropriate application and deployment of these technologies, and will continue to evaluate and consider opportunities for GETs in the annual transmission planning process as we have done for several years. This consideration is now required under FERC Orders No. 1920 and 1920-A. In addition, FERC Order No. 2023 requires transmission providers to consider opportunities to deploy GETs in the resource interconnection process."

WATT recommends that CAISO establish this framework and share it with stakeholders. WATT is curious how the ISO is evaluating and considering opportunities for GETs without such a framework. Specifically, WATT recommends establishing a transparent, criteria-based framework for evaluating GETs across both planning and operations, and then including this framework in the TPP to meet FERC Order 1920 compliance and, as appropriate, SB1006 requirements where the requirements made for utilities may be more efficiently performed by CAISO, such as in CAISO’s centralized economic planning work. CAISO might also open a docket and leverage stakeholder input to inform the creation of this framework.  

Furthermore, the American Council on Renewable Energy (“ACORE”) and Electric Power Engineers (“EPE”) recently released a joint report titled “Assessment and Evaluation of Grid Enhancing Technologies”. This report highlights various methods of incorporating GETs into transmission planning, emphasizing the need for frameworks that account for the full suite of benefits that GETs provide in planning, such as congestion reduction, improved reliability, and enhanced renewables integration. EPE also stresses the importance of integrating GETs into long-term planning models that enable fair comparisons of benefits with traditional infrastructure and ensure least-cost solutions for ratepayers.  

3. CAISO’s economic planning process should look at historic grid congestion and planned outages to identify cost-effective deployments of GETs  

WATT recommends that CAISO use both historical and forward-looking inputs to identify cost-effective deployments of GETs on the transmission system. Historical congestion data can provide valuable insight into recurring system constraints driven by seasonal demand patterns and weather variability. While congestion costs may fluctuate from year to year, many constraints appear consistently over time. This is particularly true of those constraints driven by structural limitations and typical usage patterns.  

As part of a robust analytical process, we recommend that CAISO review congestion patterns over a specific historical period. Other state laws, such as those passed in Minnesota, would suggest a historical period of 3 years. CAISO could quantify congestion over time and assess whether specific bottlenecks are temporary or systemic and likely to recur due to consistent generation and load patterns. Transmission owners can supplement this analysis by reporting whether specific congestion events are anticipated to continue or be resolved by forthcoming projects or operational changes. 

In addition to historical analysis, CAISO should strengthen its ability to forecast congestion by incorporating planned outages into its production cost modeling. As system expansion plans increase in complexity, understanding the congestion impacts of long-term or overlapping outages becomes more important. MISO has demonstrated leadership in this area, analyzing the congestion effects of outages associated with major transmission upgrades. While previous modeling exercises may have captured a relatively small share of actual congestion events, enhanced benchmarking using historical data and improved simulation techniques could significantly improve accuracy. 

Grid Enhancing Technologies are particularly well-suited to mitigate congestion caused by temporary outages or delays in infrastructure buildout. Their relatively low cost and short deployment timeline make them ideal for addressing constraints that may last for several months or years but do not justify major capital investment. Case studies support this approach: MISO reported that five strategic topology reconfigurations saved $21 million in congestion costs in just one year. In Pennsylvania, deployment of Dynamic Line Ratings on two key constraints within PPL Electric Utilities’ territory reduced congestion by $60 million year-over-year.

5. GETs can serve as bridge solutions to complement transmission construction 

In Section 1.6.5 of the Draft Transmission Plan, “Transmission Project Execution and Completion,” CAISO notes that it is “focused on ensuring timely completion of transmission projects and network upgrades needed to serve load and alleviate congestion”. WATT strongly supports this priority and emphasizes that Grid Enhancing Technologies (GETs) can serve as valuable interim solutions to reduce congestion, maintain system reliability, and accelerate resource interconnection while long-lead infrastructure projects are under development. 

Given that many major transmission projects take 7–10 years to complete, there is a pressing need for tools that can bridge the gap between current system constraints and future capacity. GETs can be deployed in months, not years, offering near-term relief and increased grid flexibility.

A notable case study illustrating this role comes from Colombia, where the national grid operator deployed APFC technology to mitigate the impacts of a three-year transmission outage. The APFC devices rerouted power flows around the constrained path, avoiding the need for load shedding and delivering more than $70 million in net system savings during the outage period. 

WATT recommends that CAISO incorporate GETs into its project execution strategy, even as temporary or supplemental solutions, to support project sequencing. Doing so would not only alleviate congestion in the interim but also reduce pressure on project timelines and create flexibility in how and when large capital investments are phased in. 

6. Looking ahead to Phase 3 of the 2024-2025 Transmission Planning Process or Phase 1/2 of the 2025-2026 Transmission Planning Process 

Section 1.3.1.3 of the Draft Transmission Plan says “the ISO may incorporate into the annual transmission planning process specific transmission planning studies necessary to support other state or industry informational requirements to efficiently provide study results that are consistent with the comprehensive transmission planning process. In this cycle, these focus primarily on grid transformation issues and incorporating renewable generation integration studies into the transmission planning process.”

WATT recommends that CAISO leverage Phase 3 of the 2024-2025 Transmission Planning Process (TPP) to conduct a statewide study of GETs to reduce grid congestion. This study would support the implementation of SB1006, which requires each transmission utility to evaluate the feasibility of projects using GETs by January 1, 2026, and every two years thereafter.  

A CAISO-led, system-wide study would offer several advantages: 

• Consistency and efficiency: A centralized study would prevent duplicative modeling efforts across multiple utilities and ensure that assumptions, methodologies, and outcomes are harmonized across the state. 

• Cost savings for ratepayers: By identifying high-impact, cost-effective opportunities to deploy GETs for congestion relief, curtailment reduction, and enhanced reliability, the study could lower the cost of transmission service and accelerate clean energy deployment. 

• Support for long-term planning: Incorporating GETs into baseline planning assumptions would help CAISO comply with FERC Order Nos. 1920 and 2023 and reflect the state’s commitment to innovative transmission solutions. 

If it is not possible to complete such a study in the 2024-2025 TPP process, CAISO should work to complete such a study through the 2025-2026 TPP before the end of the year. WATT encourages CAISO to scope the GETs study in consultation with transmission owners, the CPUC, and the CEC to ensure it aligns with SB1006 reporting needs and broader state energy goals. Completing a statewide study on the potential for GETs to reduce grid congestion would demonstrate CAISO’s commitment to forward-looking, data-driven transmission planning and further establish its leadership in modern transmission planning. 

7. Conclusion 

We reiterate our appreciation for the opportunity to provide comments on CAISO’s 2024-2025 Draft Transmission Plan and look forward to engaging in further next steps. Please do not hesitate to reach out to the WATT Coalition with any questions on the content of these comments or on Grid Enhancing Technologies more broadly.  

Respectfully submitted, 

Julia Selker 

Executive Director 

WATT Coalition 

Jselker@gridstrategiesllc.com 

6. Please provide your organization’s additional comments on the Draft 2024-2025 Transmission Plan April 15, 2025 stakeholder call discussion.