Comments on 2025-2026 Transmission Planning Process Meeting 9/24 and 9/25

1. Provide your organization's comments on the preliminary reliability results for the North area

The California Community Choice Association (CalCCA) appreciates the opportunity to comment on the preliminary reliability results in the California Independent System Operator’s (CAISO) 2025-2026 Transmission Planning Process (TPP). CalCCA supports measured transmission expansion based on established need, meeting the overall goals of reliability, clean energy targets, and affordability. The CAISO should make two improvements to the process to ensure the established need is based on a least-regrets, robust decision-making process with participation from all stakeholders and regulatory agencies: (1) increase transparency into load forecasting that triggers transmission investment needs; and (2) increase collaboration among regulatory agencies and stakeholders to ensure coordinated resource planning.

First, the CAISO should increase transparency into load forecasting that triggers transmission investment needs. The CAISO and Pacific Gas and Electric Company’s (PG&E) presentations during the Transmission Planning Process meeting indicate that mitigations may be necessary to integrate data center load included in the California Energy Commission’s (CEC) Integrated Energy Policy Report (IEPR) 2024 Demand Forecast and PG&E’s load interconnection application queue. Given the size and uncertainty of these new loads, load forecast accuracy is critically important. Under-forecasting can threaten reliability and/or clean energy goals, while over-procurement and the resulting system overbuild can lead to significant affordability concerns for customers.

The CAISO should seek to identify when mitigations are triggered due to large load additions and provide this information to stakeholders. At this time, it is not clear which reliability issues identified in the CAISO’s preliminary reliability assessment are primarily driven by large load additions, such as data center load, as opposed to other sources of load growth such as electrification or generic overall area load increases. The CAISO should seek to identify the set of mitigations that would be recommended if data center loads are included in the reliability assessment and the set of mitigations that would be recommended if data center loads are not included in the reliability assessment. Overall, increased transparency into load forecasting that triggers transmission investments is needed.

Second, the CAISO should also work with the CEC, California Public Utilities Commission (CPUC), and stakeholders to increase collaboration and ensure coordinated resource planning. Transparency regarding underlying load and transmission modeling assumptions can ensure procurement and transmission planning remain aligned. 

The CAISO should develop a transparent and standardized process for incorporating data center load into the forecasts used for transmission planning. This process should be based upon established criteria that inform the level of certainty of the load materializing. PG&E described the criteria it used to determine whether to include data center load in its assessments using implementation milestones such as the completion of an interconnection study or site control. While CalCCA appreciates PG&E’s measured approach to including data center load in its studies, a conversation with all regulatory agencies and relevant stakeholders is needed to establish standardized criteria and confidence levels for including data center load in transmission planning studies to ensure they adequately address reliability and affordability.

2. Provide your organization's comments on the preliminary reliability results for the South area

During the stakeholder meeting, the CAISO and Southern California Edison Company (SCE) stated that the Serrano-Del Amo-Mesa 500 kV Transmission Reinforcement Project, which was previously approved as a policy project in the 2022-2023, will be reevaluated in the 2025-2026 TPP due to significant increases to the project’s estimated cost. CalCCA supports the CAISO and SCE’s path forward for reevaluating the Serrano-Del Amo-Mesa 500 kV Transmission Reinforcement Project in light of these increased cost estimates. This reevaluation should seek to appropriately scope the project to address reliability and policy needs in a cost-effective manner and evaluate whether there are alternative projects that could more cost effectively meet these needs. Before finalizing a path forward in the TPP, the CAISO and SCE should conduct a transparent cost-benefit assessment so that stakeholders can understand the reliability, policy, and affordability trade-offs of the project and its alternatives driving the ultimate recommendation advanced in the TPP.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

See response in Section 1.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

See response in Section 2.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

CalCCA has no comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

CalCCA has no comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

CalCCA appreciates the CAISO’s work to develop and publish forward estimates of the high voltage transmission access charge (TAC). The CAISO’s estimates show significant increases in the TAC between now and 2036. The load forecast is an important driver of customer costs, including the TAC. While the CAISO indicates that a higher gross load growth rate reduces the impact of TAC rates in the long term, the load growth rate is very uncertain at this time due to the recent inclusion of large loads such as those from data centers. For these reasons, the CAISO should continue to be transparent about the drivers behind TAC growth and should, in future high voltage TAC updates, identify the transmission projects, regions, and needs that are driving future increases. In addition, as described in section 1, to ensure transmission investments driven by large load additions are prudent, the CAISO should: (1) seek to identify when mitigations are triggered due to large load additions and provide this information to stakeholders; and (2) develop a transparent and standardized process for incorporating data center load into the forecasts used for transmission planning based upon established criteria.

8. Provide your organization’s comments on the policy assessment update

Unaccounted for TPD

During the policy assessment update, the CAISO described its process for allocating previously unaccounted for resources requiring transmission plan deliverability (TPD). The process involves first modeling resources known to have commenced construction or to have a power purchase agreement and second adjusting the generic portfolio of resources. CalCCA supports this approach. Modeling the full amount of resources requiring TPD is necessary to ensure the policy assessment plans adequate transmission needed to fully integrate the amount of deliverable resources in the portfolio.

Integrating Out-of-State Wind

The CAISO proposes to engage with stakeholders through a Request for Information to better understand interest and opportunities for transmission projects for integrating out-of-state (OOS) resources consistent with the CPUC’s resource portfolios. CalCCA supports this approach. OOS resources make up a considerable portion of the CPUC’s portfolios used for transmission planning and, as the CAISO states, there are currently only three known transmission projects that can integrate these resources (i.e., SWIP-North, TransWest Express, and Sunzia). Understanding stakeholder interest in developing transmission to support the integration of OOS resources can inform whether the CPUC’s portfolios are realistic, especially under the new federal policies regarding wind resource development. Alternatively, understanding such stakeholder interest can inform whether the portfolios need to be adjusted to better reflect the amount of OOS resources that can reasonably be expected to deliver to California.

9. Provide your organization's comments on the economic assessment update

CalCCA has no comments at this time.

10. Provide your organization's comments on the TEAMs methodology discussion

CalCCA has no comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

CalCCA appreciates the CAISO including CalCCA’s request to explore allowing energy-only (EO) resources to seek deliverability in the Interconnection Process Enhancements 5.0 initiative. The CAISO should adopt CalCCA’s proposal requiring EO projects seeking deliverability to re-enter the queue for study under the full set of existing CAISO criteria, demonstrate a power purchase agreement for RA capacity to obtain deliverability, and to be limited in the number of times it can re-enter the queue.[1] This proposal addresses the CAISO’s concerns of projects circumventing the competitive queue process for deliverability and congesting the queue – concerns CalCCA shares – while maximizing opportunities for load-serving entities to contract with viable new projects to support reliability and policy objectives.

[1]            CalCCA Comments on the CAISO Straw Proposal (Aug. 25, 2025): https://stakeholdercenter.caiso.com/Comments/AllComments/9b0551da-cdeb-4413-8629-3801bb56231e#org-a1da5f2a-7e9a-4e52-a586-dc0d205462fa.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

Interconnection Intake, Busbar Mapping, and TPP Interactions

The CAISO should work with the CPUC to consider refinements to resource portfolio development and transmission planning processes necessitated by the new interconnection application intake process established in the Interconnection Process Enhancements 2023. The new interconnection intake process only accepts interconnection requests for projects located where there is already planned or existing TPD. The CPUC’s busbar mapping process relies primarily on the CAISO’s interconnection queue to identify points of interconnection (POI) with commercial interest. If a POI has zero TPD available, projects will not be able to enter the interconnection queue at that POI, unless and until TPD is added through new projects triggered in the TPP. TPP projects are triggered based on where resources are mapped through the busbar mapping process.

These interactions have the potential to create a circular feedback loop that results in excess interconnection requests and infrastructure build out in areas with existing or planned TPD and ignoring other areas where projects might be feasible, but no TPD exists. This could be especially problematic for location-constrained resources, like geothermal, wind, or other technologies that can only interconnect at specific POIs. Therefore, the CPUC and CAISO should consider how to identify areas with commercial interest outside of relying on what is in the interconnection queues.

Transmission Planning Under Uncertain Scenarios

The CAISO, in coordination with the CPUC, should reform the transmission planning portfolio development and decision-making processes to be more robust under uncertain scenarios. The ability for new capacity to interconnect to the transmission system is a key constraint on decarbonization efforts. Historically, the CPUC has optimized the resource portfolios used in the TPP using a single set of assumptions. This process should be revisited to account for current uncertainty in these assumptions, given the emergence of new large loads like data centers, changes in federal policy, and new technology innovation.

The CAISO and CPUC should focus on reforming tools and decision-making processes to accommodate uncertainty by: (1) working with stakeholders to specifically identify risks and uncertainty bounds for a robust optimization to inform portfolio development and transmission planning decision-making; (2) evaluating potential mitigation alternatives based upon the ability to provide multiple benefits (e.g., reliability and policy benefits), rather than on a single benefit in isolation; and (3) increasing the burden of proof on model assumptions that defer in-state transmission investments. Doing so will establish an expectation that the PSP is both low cost and low risk.

Research sponsored by Sonoma Clean Power and Peninsula Clean Energy has demonstrated the application of robust optimization to support decision making under uncertainty.[1] Results show that more proactive approval of transmission capacity, particularly lines that enable a diverse set of resources that satisfy grid needs under a range of scenarios, are the main opportunity to improve robustness of California’s grid planning. The Commission and CAISO should therefore reform transmission planning tools and decision-making processes to account for uncertainty using robust optimization methods that result in a portfolio that does well across a range of scenarios.

[1]            See Joint Comments of Sonoma Clean Power Authority and Peninsula Clean Energy on the Order Instituting Rulemaking, R.25-06-019 (Aug.1, 2025): https://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=574980356.

1. Provide your organization's comments on the preliminary reliability results for the North area

The California Department of Water Resources – State Water Project (CDWR-SWP) thanks the California Independent System Operator (CAISO) for the opportunity to comment on the CAISO’s 2025-26 Transmission Planning Process (TPP). CDWR-SWP understands that for the purposes of the TPP certain load and generation assumptions are made for the base cases that are run. There does remain certain contingencies of interest to CDWR-SWP due to historic curtailment issues with the PG&E Midway - Wheeler Ridge transmission system in Kern County. Previously, CDWR-SWP requested that CAISO explore potential options to expedite and fix these issues, while also assuring that the issues are at least modeled and accounted for properly in current planning processes at all levels (CPUC/CEC/WECC etc). 

Background:

1. CDWR-SWP is the majority owner of 75% of the capacity on the Midway – Wheeler Ridge (MWR) 230 kV transmission lines. CDWR-SWP owns and operates three critical pumping facilities to transport water to Southern California using these MWR Capacity Rights. CDWR-SWP obtained these Capacity Rights expressly due to the critical nature of the pumps in this region. CDWR-SWP’s MWR pump loads have remained fundamentally unchanged for the past 70 years and yet there has been an increasing history of curtailments to CDWR-SWP’s loads due to various transmission system issues. The most likely reason for these issues is the load growth in PG&E’s Wheeler distribution pocket.

2. A prolonged outage in 2024 caused a curtailment in CDWR-SWP’s capacity rights below CDWR-SWP's expected 75% capacity rights due to voltage support issues that should have been resolved by the use of PG&E’s previously TPP approved Capacitor Banks (CAP banks) at PG&E 230 kV Wheeler Substation. 

a. The addition of the CAP banks was approved in the CAISO’s 2011-12 TPP as the "Wheeler Ridge Voltage Support1 " project in which it was identified that there were voltage support issues on the Midway – Wheeler Ridge 230 kV transmission lines specifically at PG&E 230 kV Wheeler substation due to the large growth in PG&E’s radial sub-system there.

b. These curtailments had economic impacts to CDWR-SWP requiring reduction of energy scheduling by CDWR-SWP for critical water deliveries throughout California.

3. CDWR-SWP was informed by Pacific Gas and Electric (PG&E) in 2024 that the PG&E owned 225 MVAR Capacitor Banks (CAP Banks) at the PG&E 230 kV Wheeler Substation have been non-operational since their first attempt at being turned on in 2021. As CDWR-SWP was made aware by PG&E, the CAP banks cause voltage flickering above the 3% voltage deviation that is allowed with even only one step online because the steps are too large (three steps at 75 MVAR each) and PG&E has informed CDWR-SWP that they are working on a Corrective Action Plan but there is no approved plans at this point in time. The current suggestions by PG&E were a reduction in size of the CAP Banks.

4. To this day, all current and planning base cases (CAISO TPP/GIDAP & WECC) continue to include the CAP banks as operational whereas in reality, they have been inoperable basically since they first tried to come online. Since the units are modeled as operational, the actual system may not be as reliable in real-time.

5. The CAP banks were a previously approved TPP project and eligible for recovery through the Transmission Access Charge (TAC).

6. There are on-going operational limitations to CDWR-SWP’s ability to pump in certain contingencies, with the most severe instances including Summer peaks, post-solar hours. The CAISO’s TPP modeling and planning fail to reflect real-time operational constraints that exist to the MWR system.

a. These have been long-standing issues dating back at least a decade which have directly lead or heavily contributed to efforts such as the Wheeler Ridge 230/70 kV transformer upgrade installed in 2013, 2011-12 TPP Voltage Support (CAP Banks) project installed in 2021 and now nonoperational, the 2013-14 TPP Wheeler Ridge Junction Station and Wheeler Ridge-Weedpatch 70 kV Line Reconductor

b. The largest relief to these issues is by the Wheeler Ridge Junction Station project but this project was previously put on hold by CAISO in the 2019- 20 cycle until the 2022-23 cycle even as operational issues persisted. c. These projects are all “band-aid” fixes that do not necessarily address underlying Capacity Rights issues due to CDWR-SWP/PG&E’s 75%/25% ownership split of the Midway Wheeler Ridge line. The underlying modeling still needs to accurately reflect CDWR-SWP’s ownership rights. CDWR-SWP should not be experiencing curtailment to its most critical pumping plants that serve to deliver water to a large portion of California’s population. 

The CDWR-SWP appreciates that the 2027 Kern planning model accurately reflects that the CAP banks are inoperable but questions the use of the CAP banks in the 2030 and 2035 planning models. Additionally, the CDWR-SWP’s current understanding of PG&E’s proposal is to reduce the size of the CAP banks, but it is uncertain what downsizing will occur. The CAP banks in the 2030 and 2035 planning models have the CAP banks outputting ~ 155 MVAR but with the full 225 MVAR available and the 2040 planning models have the CAP banks outputting the full 225 MVAR. There is still the question of if those levels of output are reasonable as the previous and current planning models are unable to show the voltage flickering issues with the full output to begin with. How does PG&E intend to model the voltage flickering issue so that it is clear the new downsizing is even sufficient? There appears to be too many open questions to confidently say that the CAP banks will be available in future planning cases and the modeling should accurately reflect the status quo. The CDWR-SWP is requesting that PG&E and CAISO thoroughly review how the Midway – Wheeler Ridge system is modeled as there appear to be longstanding, real-time operational issues that are not properly being addressed in the planning realm beyond just the CAP banks issues as well. As majority owner of the capacity of the MWR line, CDWR-SWP should not be experiencing curtailment to its most critical pumping plants that serve to deliver water to a large portion of California’s population.

2. Provide your organization's comments on the preliminary reliability results for the South area

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

7. Provide your organization’s comments on the high voltage TAC update

8. Provide your organization’s comments on the policy assessment update

9. Provide your organization's comments on the economic assessment update

10. Provide your organization's comments on the TEAMs methodology discussion

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

The current volumetric-only approach to assessing TAC no longer best reflects cost causation and utilization of the transmission system, as the benefits for some are being paid for by the many. As noted by CAISO’s Neil Millar at the WEM Governing Body meeting on June 18, 2025, “Load forecasts have been escalating, and driving increased resource and transmission requirements”.

One of the major drivers for building new transmission is to meet the coincident peak demand when there is the highest strain on the transmission system. A hybrid TAC would incentivize loads to flex or shift out of the coincident peak which would thereby reduce the need for transmission buildout.

The TAC enhancement, as prior presented in 2018:

• Is in line with cost causation which is a CAISO principle for market design. The current TAC methodology makes no differentiation as to when load places constraint on the transmission system and is inconsistent with how transmission costs are allocated. Hybrid TAC addresses this limitation and would allocate part of TAC based on contribution to system coincident peak demand, a major driver for building new transmission.

• Charges part of TAC based on coincident peak and would encourage large load entities to curtail their energy consumption during peak periods, reducing the need for future transmission investment and would improve reliability; it provides a further price signal for entities to curtail and shift their load out of the peak periods.

• Would be in line with how CAISO allocates RA capacity obligations based on contribution to coincident peak demand.

• Was supported by CAISO’s Department of Market Monitoring.

• Is used by other ISOs like PJM, ISO-NE, NY ISO, and MISO in their assessment of transmission charges; they use coincident peak demand to charge for transmission usage. 

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

1. Provide your organization's comments on the preliminary reliability results for the North area

The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) provides these comments on the California Independent System Operator’s (CAISO) stakeholder meetings on the 2025-2026 Transmission Planning Process – Reliability Assessment and Study Updates on September 24-25, 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]

Cal Advocates has no comments on the reliability results for the North Area at this time.

[1] Cal. Pub. Util. Code, § 309.5.

2. Provide your organization's comments on the preliminary reliability results for the South area

Cal Advocates has no comments on the reliability results for the South Area at this time.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

The following are Cal Advocates’ comments on nine of Pacific Gas and Electric Company’s (PG&E) recommended reliability projects and assessments for the 2025-2026 Transmission Planning Process (TPP) cycle.  

1. Mariposa 70 kilovolts (kV) Voltage Support Project

To address low voltage issues at the Mariposa substation and neighbouring substations, PG&E recommends installing a 20 Megavolt-Ampere Reactive (MVar) voltage support device at the Mariposa substation and associated equipment to integrate this device.[1]  CAISO, in contrast, recommends a redundant relay or battery and the already approved Wilson area reinforcement to address potential thermal overloads in the project area.[2]  For low voltage issues in the project area, CAISO recommends continuing to monitor the area since reliability issues may occur only during the off-peak timeframe.[3]  Cal Advocates supports CAISO’s recommendation to pursue redundant relays and batteries and the already-approved Wilson area reinforcement project because these are cost-efficient solutions to address potential future reliability issues in the area.

2. Oro Loma 70 kV Area Reinforcement Project Rescope

To mitigate overloads and low voltage issues in the Oro Loma substation area, PG&E recommends rescoping the Oro Loma and Los Banos 70 kilovolt (kV) Area reinforcement projects to add a new line and to expand the Mercy Springs Switching Station and Ortiga 70 kV buses as needed.[4]  In contrast, CAISO recommends the Los Banos area reinforcement project “as is” for addressing area issues.[5] Cal Advocates recommends CAISO and PG&E rely on the previously approved Los Banos area reinforcement project to address area issues. CAISO’s reliability results did not provide justification for a new line or other improvements in the project area.  In addition, to address low voltages issues, Cal Advocates recommends CAISO and PG&E evaluate series capacitors on the 70 kV line between the Canal and Ortega substations to address voltage drops.[6] CAISO and PG&E should provide their results from their series capacitor evaluation at the November TPP meetings.

3. Midway 115 kV Bus Upgrade Project

To protect against potential overloads on certain sections of the Midway 115 kV line, PG&E recommends expanding the Midway bus and relocating connections to the bus.[7]  In contrast, CAISO’s reliability assessment did not recommend upgrades on the identified sections of Midway 115 kV line. Instead, CAISO confirmed that the previously approved Kern Reinforcement project can address reliability issues in the area and identified possible issues with only the sensitivity scenario in 2040.[8]  Cal Advocates recommends CAISO and PG&E rely on the previously approved Kern Reinforcement project to address reliability and recommends considering additional energy storage, if necessary, to address the potential reliability issues identified in the project area.

4. Eastshore and Newark Area Import Capability Reinforcement Conceptual Project

To address possible overloads in the Eastshore and Newark area, PG&E proposes reconductoring approximately 92 miles of 230 kV lines in the project area.[9] In contrast, CAISO’s August 2025 reliability results recommends minor mitigations ranging from considering a transformer capacity increase and relying on the already approved San Jose Area HVDC line project[10]  and to continue monitoring issues in the area.[11] In the September 24, 2025 reliability assessment stakeholder meeting (September 2025 meeting), CAISO stated that there will be potentially significant overloads in the area due to forecasted load from data centers.  CAISO explained that they are currently reviewing network upgrades for the area and the overloads due to large loads.[12] Cal Advocates supports CAISO additional investigation to confirm the large loads in the area and their contribution to overloads.  Cal Advocates also recommends that PG&E and CAISO conduct an additional power flow study to determine if the Eastshore area can receive power through a different substation rather than the Newark substation station and to continue evaluating the alternative options, which include transformer additions or upgrades.  Cal Advocates recommends that PG&E and CAISO present their analysis to stakeholders at the November TPP meetings.[13] 

5. South Oakland Reinforcement Conceptual Project Phase 2

To address potential overloads in the South Oakland area, PG&E proposes reconductoring 16 miles of 115 kV lines or building a new substation amongst other improvements.[14]  PG&E’s proposed conceptual project for the South Oakland area is significantly different from the project PG&E proposed last year.  In 2024, PG&E’s scope for the South Oakland area included a greater amount of line reconductoring and new loops.[15]  In contrast, in 2024 CAISO recommended reconductoring fewer lines in the South Oakland area.[16]  At the September 2025 meeting, CAISO recommended continuing to monitor possible reliability issues in the South Oakland area[17] or to consider a capacity increase for confirmed large load.[18]  Since the scope for the South Oakland project significantly changed from PG&E’s 2024 proposal, and CAISO is still reviewing the large load demand growth for the area, Cal Advocates recommends CAISO withhold approval of PG&E’s conceptual proposal.  Instead, Cal Advocates recommends that CAISO undertake the following and provide their results at the November TPP meetings:

1. Confirm the large load growth in the California Energy Commission (CEC)-Integrated Energy Policy Report (IEPR) proceeding. 
2. Consider lower cost alternatives to increase the power transfer capability of the existing lines and provide power system stability such as with capacitors in a series/series compensation [19] instead of considering only reconductoring the area lines.  Specifically, consider an alternative with series reactors[20] installed as part of the solution for the parallel lines between Grant and Eden Landing substations versus considering only reconductoring.[21]
3. Consider rebuilding certain substation equipment at the Oakland and Grant substations instead of building a new substation.

6. Metcalf – Monta Vista 230 kV Transmission Corridor Reinforcement

To address potentially significant overloads in 2040 in Santa Clara County, PG&E proposes reconductoring nearly 50 miles of 230 kV lines.[22]  In contrast, CAISO’s August 2025 reliability results only recommends continued monitoring. [23]  However, at the September 2025 meeting, CAISO presented mitigations to address new data center loads in Santa Clara County that are smaller in scope.[24] Since the load growth in Santa Clara County is still uncertain, Cal Advocates recommends CAISO confirm the load growth, determine the least cost mitigations and present their results at the November TPP meetings.  For the noted overloads, PG&E should consider a “DC run back” operational procedure similar to other schemes which can automatically reduce or reserve power flow for the Metcalf – Monta Vista 230 kV line.  Cal Advocates also recommends that PG&E and CAISO consider lower cost alternatives to increase line capacity, such as installing energy storage or capacitors.

7. Metcalf 230/115 kV Banks Upgrade Project

To address potential overloads in the South Bay area, PG&E proposes to upgrade all four of the transformers at the Metcalf substation along with any additional equipment needed to achieve full transformer capacity.[25] In contrast, CAISO’s August 2025 reliability results recommends to continue monitoring the area.[26] Cal Advocates recommends CAISO only approve the Metcalf substation transformers #2 and #3 upgrades at this time.  Based on PG&E’s power flow results, transformers #2 and #3 may need to be upgraded in the near term, if PG&E’s load forecasts are valid.  As an alternative, Cal Advocates recommends CAISO and PG&E continue evaluating a fifth transformer at Metcalf substation or consider energy storage as a lower cost option to upgrading all four transformers.  Cal Advocates also recommends that CAISO and PG&E provide their results at the November TPP meeting.

8. San Jose B 230/115 kV Transformer Bank Addition Project.

To address potential overloads in the San Jose Area, PG&E proposes to add a transformer to the San Jose B substation which currently has only one transformer.[27] In contrast, CAISO’s August 2025 reliability assessment suggests to continue monitoring the area and stated that they are still reviewing the long-term issues related to large loads.[28]  However, in the September 2025 meeting, CAISO recommended a transformer capacity increase or substation upgrade at Newark.[29] Since PG&E and CAISO are proposing different solutions for the San Jose area and CAISO is still reviewing the long-term load forecasts, Cal Advocates recommends: (1) CAISO complete their review and power flow studies to determine the appropriate solution for the San Jose area. (2) PG&E and CAISO evaluate energy storage’s potential to address the potential overloads. (3) PG&E and CAISO provide the results of their completed project evaluations that consider energy storage at the November TPP meetings.

9. South Bay 115 kV system Reinforcement Conceptual Project

To address load growth in the South Bay area, PG&E proposes reconductoring eight line segments and installing two new transformers at area substations.[30]  Last year, PG&E proposed a more limited project scope with only two line segment reconducting areas.[31] CAISO stated that PG&E’s proposal includes a capacity increase on the Los Esteros – Metcalf 230 kV line and that the overload driving this capacity increase is under review for “potential contribution from large loads.”[32]  Since CAISO is still reviewing the load growth for this area, Cal Advocates recommends CAISO confirm the load growth and provide their determination at the November TPP meetings.  Cal Advocates also recommends PG&E consider lower cost alternatives to increase line capacity such as installing energy storage or capacitors.

The following are Cal Advocates’ recommendations regarding new data center load.

1. CAISO should confirm whether new data centers are pursuing strategies to reduce their impact on the grid and ratepayers.

In its September 2025 presentation, PG&E explained that new data center load is partially driving the need for eight of its 10 proposed reliability projects.[33]  PG&E also stated that there are 14 new data centers proposed in its service area that all have site control.[34]  PG&E did not confirm, however, whether any behind the meter measures will or can play a role in reducing the expected data center load demand during critical need hours.[35]  This is inconsistent with PG&E’s statement earlier this year in a CEC Demand Analysis Working Group (DAWG) meeting that it will continue to evaluate load-shifting capabilities and strategies for data centers.[36]  CAISO stated during the September 2025 meeting that CAISO staff is still analyzing whether the new expected data center load in the greater Bay Area can be interruptible.[37],[38]  To confirm that the identified transmission upgrades are appropriately sized, CAISO and PG&E should first determine if the expected new data center load can be interruptible.  If data centers can power down or rely on their own energy storage during critical need hours, nine of PG&E’s proposed new reliability projects may not be necessary. 

 Data center load needs could also be reduced if the data centers co-located with generation, connected to a microgrid or pursued energy efficiency upgrades such as advanced data cooling technologies[39]^,[40] and information technologies efficiencies.[41]^,[42],[43]  The three major California electric utilities and CEC discussed these strategies along with load flexibility strategies in a February 2025 CEC workshop but PG&E failed to address this topic during its September 2025 meeting presentation.

Notably, other states require data center flexibility for interconnection.  For example, the state of Texas recently passed a law that requires new data centers to either deploy back-up generation or curtail load during an emergency grid event and to also contribute to interconnection costs.[44]

 This example illustrates that PG&E’s approach to addressing new data center load with only wire solutions is not cost-effective and is inconsistent with practices in other states and PG&E’s own “looking forward” statements at the DAWG. 

2. CAISO and the Participating Transmission Owners should isolate the costs to integrate new large loads to inform state policy.

CAISO and the PTOs fail to provide the cost impacts for the different drivers of new transmission investments in the TPP.  Instead, the cost impacts associated with accommodating new data center demand and new building and transportation electrification demand are undistinguishable.  California is in the midst of determining how to respond to new data center load and how to allocate costs for integrating new data center loads.  For this reason, CAISO should require the PTOs to estimate the portion of new TPP transmission projects that are associated with integrating new data center load.  This will enable the state to properly evaluate the impact of new data center load.

In addition, PG&E failed to provide the project cost estimates for individual interconnection projects and capacity upgrades in its Load Cluster 2024 (LC24) or Serial Data Center interconnection studies. Instead, PG&E presented a total cost estimate for interconnection and capacity upgrades.[45] This provides no insight into the costs for specific loads in the LC24 Scope Study and Serial Data Center projects in San Jose.  The estimated cost of the upgrades should be disaggregated and estimated for each data center project. This will help improve large load upgrade cost transparency and support analysis on cost allocation for these upgrades going forward.

3. There should be more review and transparency on new data center loads to confirm new projects are no regrets.

PG&E staff stated that the 14 proposed new data centers in their service area have site control.  However, PG&E staff did not confirm whether these data centers provided assurances that they are committed to their projects through security deposits and interconnection agreements or whether these data centers can be interruptible.[46]  Also, data center additions to load forecasts should demonstrate certainty of the load beyond just engineering drawings to ensure proposed transmission projects are “no regrets.” On September 18, 2025, the Federal Energy Regulatory Commission (FERC) Chairman Rosner recommended that utilities’ criteria for assessing the commercial readiness of large loads include observable milestones such as contracts, financial security deposits, and physical site control.[47]   Thus, to verify new data center load and confirm the data center driven transmission projects are appropriately sized, PG&E should be required to provide: (1) proof of signed interconnection agreements; (2) proof of compliance with financial commitments (e.g., security deposits and required financial advances); (3) proof of site control; and (4) relevant information to determine whether the new data center load can be interruptible.

[1] PG&E’s 2025 Request Window Proposal, CASIO 2025-2026 Transmission Planning Process (Presentation), PG&E, September 25, 2025 (PG&E Presentation) at slide 7.

[2] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Fresno Area, CAISO, August 15, 2025, Thermal Overloads at pp. 1-2.

[3] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Fresno Area, CAISO, August 15, 2025, Low-Voltage at pp. 6-8.

[4] PG&E Presentation at slides 9-11.

[5] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Fresno Area, CAISO, August 15, 2025, Thermal Overloads & Low Voltage at pp. 3, 6, 7 & 9.

[6] Capacitors are connected to lines for voltage compensation and power transfer enhancement.  This practice, known as series compensation, helps to improve the efficiency and stability of long-distance power transfers through transmission.  Sources: https://insights.globalspec.com/article/23194/role-of-capacitors-in-distribution-lines & https://www.electricaltechnology.org/2025/03/capacitors-in-series-in-power-lines.html

[7] PG&E Presentation slides at 15-18.

[8] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Kern Area, CAISO, August 15, 2025, Thermal Overloads at p 1.

[9] PG&E Presentation slides 21-23.

[10] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, CAISO, August 15, 2025, Thermal Overloads at pp. 11-12.

[11] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, CAISO, August 15, 2025, Thermal Overloads at pp. 1-2 &4, 9 & 10.

[12] 2025-2026 Transmission Planning Process, Stakeholder Meeting September 24-25, 2025, CAISO, (CAISO presentation) at slide 74.

[13] PG&E Presentation at slide 25.

[14] PG&E Presentation at slides 29-31.

[15] PG&E’s 2024 Request Window Proposals, CAISO 2024-2025 Transmission Planning Process, September 24, 2024 at pp. 58-61.

[16] Reliability Assessment Recommendations – PG&E Area Draft 2024-2025 Transmission Plan, CAISO, April 15, 2025  at slide 32.

[17] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, CAISO, August 15, 2025, Thermal Overloads at p. 2 &4 & Low Voltage at p. 20.

[18] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, CAISO, August 15, 2025, Thermal Overloads at p. 3 & 4.

[19] Advances in Series-Compensation Line Protection, Schweitzer Laboratories Inc., 63th Annual Georgia Tech Protective Relaying Conference, April 24-29, 2009 at p. 2.

[20] https://american-power.com/industry-news-blog/difference-between-shunt-reactor-and-series-reactor/

[21] PG&E Presentation at slide 30.

[22] PG&E Presentation at slide 36.

[23] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, August 15, 2025, Thermal Overloads at pp. 4,6,8, 9, 16 & 18.

[24] CAISO presentation at p. 76.

[25] PG&E Presentation at slide 46.

[26] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, CAISO, August 15, 2025, Thermal Overloads at pp. 7-8.

[27] PG&E Presentation at slides 49-51.

[28] 2025-2026 ISO Reliability Assessment – Preliminary Study Results, Study Area: PG&E Greater Bay Area, CAISO, August 15, 2025 at pp. 3, 5, 7-12, 21 and 27.

[29] CAISO presentation at slide 77.

[30] PG&E Presentation at slides 54-55.

[31] PG&E’s 2024 Request Window Proposals, CAISO 2024-2025 Transmission Planning Process, September 24, 2024 at slide 80.

[32] CAISO presentation at slide 77.

[33] PG&E presentation at slide 57.

[34] PG&E presentation at slide 2.

[35] S&P Global Market Intelligence Datacenters and energy — truths and myths two years into the Gen AI revolution (On-Demand) (5010190). This webinar discussed the truths and myths regarding data centers’ capacity to shift their load.  at minute 53.34. Dan Thompson, principal research analyst with S&P, clarified that older data centers are not as flexible at responding to grid needs because they were not designed with automated functions to respond to grid needs so it takes longer for them to react to grid issues.  However, Google found that when they shifted the load from their data center’s AC units/cooler and chillers, it shaved the data center’s load enough to be meaningful for the grid.  As a result, Google recently announced that its next generation of data centers will be designed to be able to shift AC load when needed.  Google and other Hyperscalers are also investigating ways to shift their workload to times when there is less stress on the grid.  Google is already shifting some workload to the night time frame when the grid is less stressed.

[36] PG&E Data Center Forecasting Presentation, Presented at the July 16, 2025 DAWG Workshop, July 18, 2025 at slide 14.

[37] Interruptible data centers, also known as flexible or grid-interactive data centers, can reduce their power consumption during times of high demand or grid stress, often in exchange for interruptible tariffs, lower rates, or faster interconnection. By curtailing usage for short periods, these data centers help stabilize the power grid, reduce costs for the utility and its customers, and can defer the need for costly infrastructure upgrade.

[38] Power Association of Northern California (PANC) meeting entitled Removing Friction from the Grid, June 11, 2025^,  Elliott Mainzer, President and CEO of CAISO statements at minute 49:15 “The big question that I have for the data center community is how can they prove that they can come to the table with some actual legitimate flexibility in their demand for electricity whether they install some batteries or whether they have some gen sets and how can the system operator and the utilities count on the use of some of that flexibility during peak periods. So that the cost of accommodating them [data centers] on the grid are not so high.”

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

[40] 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

[41] https://www.forbes.com/councils/forbestechcouncil/2024/03/26/heres-why-data-center-cooling-is-the-hottest-innovation-in-the-sector/, Liquid cooling systems also use less power—and, perhaps surprisingly, less water—than their air-driven rivals.

[42] https://news.mit.edu/2025/new-chip-tests-cooling-solutions-stacked-microelectronics-0428

[43] Opportunities to Use Energy Efficiency and Demand Flexibility to Reduce Data Center Energy Use and Peak Demand, ACEEE, October 2025 at p. iii.  Opportunities to improve efficiency include developing and using more efficient chips in servers, improving software and algorithms, adding heat recovery, and improving cooling and electric systems.

[44]  Enrolled Version of Texas Legislature Senate Bill No. 6, June 2025 at p. 3.  Senate Bill No. 6 2025, Amends Section 35.004 of Texas Utilities Code.

[45] PG&E presentation at slide 60 (total cost estimate for LC24 of $633 to $1,265 million for interconnection projects and $278- $556 million for capacity upgrades); and PG&E presentation at slide 69 (total cost estimate for serial data center projects in San Jose of $182 to $387 million for interconnection projects and $45 to $100 million for capacity upgrades.)

[46] California ISO (CAISO) 2025-2026 Transmission Planning Process, September 24-25, 2025, Customized Energy Solutions, October 3, 2025 at p. 17

[47] FERC Chairman Rosner's Letter to the RTOs/ISOs on Large Load Forecasting | Federal Energy Regulatory Commission, September 18, 2025.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

Cal Advocates makes the following recommendations on Southern California Edison Company’s  (SCE) reliability alternatives.

1. SCE and CAISO should confirm whether the proposed advanced reconductoring projects in SCE’s service area will still be the least cost-best fit alternative even without Department of Energy (DOE) grant funding.

For the 2024-2025 TPP cycle, CAISO and SCE anticipated that the Department of Energy (DOE) would subsidize a portion of the total project cost of the Julian Hinds-Mirage 230 kV Advanced Reconductor Project. [1]  This expected DOE funding influenced CAISO and SCE’s determination of the least cost solution.  Since DOE grant funding for approved transmission projects may now be cancelled,[2]^,[3] it is unclear whether DOE grant funding will still be available for this project.  Thus, SCE and CAISO should confirm whether this project is still the least cost solution or that DOE funding has already been provided.

2. SCE’s Per Unit Cost Guide should include costs for common work items.

SCE’s Per Unit Cost Guide fails to include a cost estimate for reconductoring, which makes it difficult to determine if the costs of the Pardee-Santa Clara 230 kV Line Upgrade (Advanced Reconductoring) and Santa Clara-Vincent 230 kV Line Upgrade (Advanced Reconductoring) projects are reasonable.  Similarly, SCE’s Per Unit Cost Guide fails to include a cost estimate for shunt reactors, which makes it difficult to determine the costs of the Mohave 500 kV Bus Shunt Reactors project.  For these reasons, Cal Advocates recommends that SCE include the cost for common work items such as reconductoring in their Per Unit Cost Guide.

[1] 2024-2025 Transmission Plan Process: Draft Transmission Plan (Presentation), CAISO, April 15, 2025 at slide 42.

[2] https://www.energy.gov/articles/energy-department-announces-termination-223-projects-saving-over-75-billion

[3] DOE Terminates $7.56 billion in Energy Grants for Projects in Blue States, RTO Insider, October 7, 2025 at p. 3.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

Cal Advocates recommends CAISO withhold approval of GridLiance West’s proposed 230 kV Sagebrush Connection project.  CAISO’s reliability assessment did not identify significant issues in the same project area that justify this estimated $102 to $204 million project.[1]

[1] CAISO Presentation at slides 269-279.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

The following are Cal Advocates’ comments on San Diego Gas & Electric Company’s (SDG&E) recommended reliability projects and assessments.

1. Reconductor TL690B & TL697

SDG&E proposes to reconductor lines TL690B and TL697 to address possible overloads with expected load growth in Oceanside.[1]  CAISO observes similar issues in its assessment for the area.[2]  However, during the September 2025 meeting, CAISO confirmed that energy storage could be considered as part of the solution to address the potential reliability issues in Oceanside.  For this reason, Cal Advocates recommends that CAISO withhold approval of SDG&E’s proposed project and evaluate energy storage as part of the project scope to reduce the total project costs.  Cal Advocates also recommends that SDG&E provide the results of their energy storage evaluation at the November TPP meetings.

Cal Advocates also notes that the estimated costs for these reconductoring projects appears to be inconsistent with SDG&E’s 2025 Per Unit Cost Guide.  To illustrate, the Reconductor TL690B and TL697 project includes approximately 7.6 miles of reconductoring and is estimated to cost $100 million.[3] According to SDG&E’s 2025 Per Unit Cost Guide, reconductoring a transmission line costs between $1.62 million and $2.7 million per mile, depending on complexity.[4] Assuming this is a “high complexity” project, applying the high end of SDG&E’s cost scale results in a cost of $20.52 million,[5] five times less than SDG&E’s project cost estimate.[6]  Cal Advocates recommends that SDG&E explain the cost deviation from its Per Unit Cost Guide and confirm whether additional work beyond reconductoring is necessary in the November TPP meetings.                                                                                                                                                                                                                                                         

2. Reconductor TL647 and TL623B

SDG&E proposes to reconductor TL647 and TL623B to address an anticipated overload in the Border area starting in 2032.[7]  CAISO anticipates a similar overload but recommends system adjustments to the energy storage in the area to address the potential overload.[8] Cal Advocates recommends CAISO withhold approving this project, and recommends SDG&E consider energy storage as a lower cost solution and provide their results at the November TPP meetings.

3. Reconductor TL623C, TL623B and TL647

SDG&E proposes to reconductor TL 623C and TL 623B to address potential overloads starting in 2032 in southern San Diego.[9]  CAISO anticipates similar overloads but recommends system adjustments and operational actions.[10]  Cal Advocates recommends SDG&E and CAISO continue studying the system adjustment options that CAISO outlined, since they are more cost-effective options than reconductoring.  Cal Advocates also recommends that SDG&E consider energy storage or capacitors as lower cost alternatives to address line capacity issues than reconductoring.

4. New Oceanside Area 69 kV substation

SDG&E proposes addressing the growing demand in Oceanside and the Border load pocket with new substations to be installed by 2032 in San Diego.[11]  SDG&E fails to mention whether it considered cost effective alternatives.  CAISO also anticipates potential overloads in Oceanside and the Border areas, but recommends considering a range of mitigations including system adjustments, operational actions, energy storage, and power flow devices.[12]  Cal Advocates recommends that CAISO withhold approving SDGE’s proposed project.  Instead, Cal Advocates recommends, CAISO confirm whether the combination of the aforementioned lower cost alternatives could effectively address the identified reliability issues at the November TPP meetings. 

Cal Advocates also notes that SDG&E’s two proposed substation projects have nearly the same, scope but the cost for the proposed New Border Area 69/12 kV substation is a significantly higher cost than the proposed New Oceanside Area 69kV substation project.  For reference, the New Border Area 69/12 kV substation project could cost up to $140 million[13] while the New Oceanside Area 69kV substation project could cost up to $40 million.[14] Cal Advocates recommends that SDG&E explain the cost discrepancy between its two proposed substation projects at the November TPP meetings.

5. New Penasquitos- Mira Sorrento 69KV #2 line

SDG&E proposes a new Penasquitos- Mira Sorrento 69KV #2 line project that will be 2.01 miles long (assuming it is the same length as TL6959) with an expected cost of $124.5 million.[15] According to SDG&E’s 2025 Per Unit Cost Guide, a new transmission line costs between $4.32 and $8.64 million per mile, depending on the complexity.[16] Assuming this is a “high complexity” project, applying the high end of SDG&E’s cost scale results in approximately $17.37 million,[17] seven times less than SDG&E’s estimated project cost.  However, SDG&E’s presentation provided no indication of other work that would contribute to SDG&E’s higher project cost estimate.  SDG&E should explain the reason for this cost deviation from its Per Unit Cost Guide and specify whether additional work, not specified in the project scope, is necessary.

[1] SDG&E Presentation, 2025-26 TPP Proposals, September 25, 2025 (SDG&E Presentation), SDG&E at slide 3.

[2] San Diego Gas & Electric Area, Preliminary Reliability Results, 2025-2026 Transmission Planning Process Stakeholder Meeting, September 24-25, 2025 (CAISO Presentation for SDG&E Area) CAISO at slide 315.

[3] SDG&E Presentation at slide 3.

[4] SDG&E Final 2025 Per Unit Cost Guide, July 10, 2025, available at https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/Participating-transmission-owner-per-unit-costs-2025

[5] (7.6 miles) x ($2.7 million / mile) = $20.52 million

[6] SDG&E’s project scope gives no indication of other work that would contribute to the high project cost estimate.

[7] SDG&E Presentation at slides 5-6.

[8] CAISO Presentation for SDG&E area at slide 318.

[9] SDG&E Presentation at slides 5-6.

[10] CAISO Presentation for SDG&E area at slides 317-318.

[11] SDG&E Presentation at slides 8-9.

[12] CAISO Presentation for SDG&E Area at slides 312 and 317.

[13] SDG&E Presentation at slide 9.

[14] SDG&E Presentation at slide 8.

[15] SDG&E Presentation at slide 7.

[16] SDG&E Final 2025 Per Unit Cost Guide, July 10, 2025, available at https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/Participating-transmission-owner-per-unit-costs-2025.

[17] (2.01 miles) x ($8.64M / mile) = $17.37M.

7. Provide your organization’s comments on the high voltage TAC update

1. CAISO should provide the incremental impact of proposed new projects on the Transmission Access Charge.

CAISO’s Transmission Access Charge (TAC) forecast provides an estimate of the total transmission costs of all high-voltage CAISO-approved projects after each TPP cycle is complete (e.g., the 2023-2024 TAC Forecast Model with New Capital published on September 20, 2024).[1]   For purposes of estimating the new TAC, CAISO provides cost estimates for previously approved high voltage transmission projects in addition to the existing revenues recoverable through FERC authorized transmission rate base.  CAISO adds together costs from projects approved in the most recent Transmission Plan and projects approved in prior transmission plans with expected future capital costs.  Since the costs are aggregated from projects approved in multiple transmission plans, stakeholders cannot determine the incremental impact of projects approved in the most recent TPP cycle and their effect on the TAC rate.  Going forward, CAISO should separate the estimated costs for projects slated for approved in current TPP cycle from the cost estimates of previously approved projects to illustrate the impact of proposed new projects on the TAC for consideration and transparency.

2. CAISO and the PTOs should provide a high-voltage and low-voltage cost breakdown for projects that include both high and low-voltage upgrades.

CAISO’s high-voltage TAC forecast capital cost estimates for projects that include both high- and low-voltage upgrades fail to break down project costs by voltage level.  High- and low-voltage cost allocation for projects with multiple voltages is necessary to understand CAISO’ high-voltage and low-voltage TAC cost analysis and cost estimates.  Cal Advocates recommends CAISO provide a breakdown of the cost allocation for projects at multiple voltages in the 2025-2026 Draft Transmission Plan. 

3. CAISO should include all the high-voltage projects it approved in the 2024-2025 HV TAC forecast.

During the September 2025 meeting, CAISO provided a forecast of high voltage TAC (HV TAC) rates with CAISO-approved projects from the 2024-2025 TPP.[2]  Prior to this presentation, Cal Advocates developed a HV TAC forecast for the same 2024-2025 TPP cycle.  Cal Advocates’ forecast shows an 8-11% higher HV TAC rate after 2033 than the CAISO forecast, as shown below.  CAISO’s lower HV TAC rate is due to the absence of 10 CAISO approved transmission projects in the dataset.

Specifically, CAISO’s forecast appears to exclude approximately $2.2 billion in estimated costs associated with 10 CAISO-approved reliability projects from the 2024-2025 TPP, many of which are located on the 115 kV transmission system.  These include large-scale reliability reinforcements such as the North Oakland ($1.127 billion), South Bay ($434 million), and South Oakland ($250 million) projects, among others (see table below for all the omitted projects identified by Cal Advocates).[3]  CAISO should include the costs for all proposed projects in their TAC forecast or explain the reasons for any exclusions and whether there has been a change in how CAISO scopes such projects as high- or low-voltage upgrades.

Additionally, CAISO’s model omits capital costs for several in-flight projects that continue to appear in Chapter 8 of the 2024-2025 Transmission Plan, including the Los Banos 70 kV Area Reinforcement ($13.5 million), Diablo Canyon Area High Voltage Mitigation ($70 million), and Crazy Horse Canyon - Salinas - Soledad #1 and #2 115 kV Line Reconductoring ($108 million).  CAISO should update its model to include these project costs or provide an explanation for excluding them in the 2024-2025 forecast.

[1] CAISO Presentation at pp. 325-331.

[2] CAISO Presentation at pp. 325-331.

[3] The South Bay and South Oakland projects were presented as conceptual in the 2024-2025 and the 2025-2026 TPP cycle, and their scopes have changed.

8. Provide your organization’s comments on the policy assessment update

Cal Advocates does not have any comments on the policy assessment update.

9. Provide your organization's comments on the economic assessment update

Cal Advocates does not have any comments on the economic assessment update. 

10. Provide your organization's comments on the TEAMs methodology discussion

Cal Advocates does not have any comments on the Transmission Economic Assessment Methodology (TEAM) discussion.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

Cal Advocates does not have any comments on the CAISO Policy Initiatives presentation.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

1. All CAISO Participating Transmission Owners should provide project cost estimates within a 50% accuracy range to ensure projects are fully developed before approval.

PG&E continues to present project cost estimate ranges that include a budget contingency of 100%.  Such a high budget contingency indicates a level of uncertainty that does not merit project approval.  In contrast, SDG&E and SCE generally provide one project cost estimate for their projects, and on occasional provide cost ranges; however, their project budget contingencies are never 100%.[1]  Cal Advocates recommends all PTOs provide project cost estimates within a 50% accuracy range in their CAISO project presentations versus project cost estimate ranges that include greater budget contingencies, as project cost estimates should be more precise before subject to approval.

2. All CAISO Participating Transmission Owners should provide itemized project cost estimates in their CAISO presentations so that stakeholders may confirm whether the project cost estimates are reasonable.

At the September 2025 meeting, the PTOs provided only high-level project cost estimates but failed to include a cost breakdown structure of individual project scope items.  The PTOs also did not consistently provide the length of lines to be reconducted or of new proposed lines.  PTOs should provide costs for each project scope item and the miles of new transmission lines or reconducted lines for cost transparency.  Without this information, stakeholders are not able to confirm project costs are reasonable through comparisons between the proposed project costs and the PTO’s Per Unit Cost Guides. 

[1] PG&E Presentation at slide 7.

1. Provide your organization's comments on the preliminary reliability results for the North area

Cal Western has no comments on preliminary reliability results

2. Provide your organization's comments on the preliminary reliability results for the South area

Cal Western has no comments on preliminary reliability results

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

Cal Western has no comments on PG&E proposed reliability alternatives

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

Cal Western has proposed an alternative reliability solution for SCE Main and SCE Western LA Basin.  See Cal Western Request Window Submission Form submitted on 10-10-25.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

Cal Western has no comments on GLW proposed reliability alternatives

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

Cal Western has no comments on SDG&E proposed reliability alternatives

7. Provide your organization’s comments on the high voltage TAC update

Cal Western has no comments on high voltage TAC update

8. Provide your organization’s comments on the policy assessment update

Cal Western has no comments on the policy assessment update

9. Provide your organization's comments on the economic assessment update

California Western Grid Development LLC Comments on the

CAISO 2025-26 TPP September 24-25 Stakeholder Presentation

                                                                                                  (October 9, 2025)

California Western Grid Development LLC (“Cal Western”) appreciates the opportunity to submit comments on the September 24-25, 2025, Stakeholder Presentation (“Presentation”). Cal Western’s Pacific Transmission Expansion Project (“PTE” or “PTEP”) is being considered for study in 25-26 TPP as an economic project.[1]  Cal Western will also be filing tomorrow, October 10, 2025, a request for PTEP to be approved in the 25-26 TPP as the optimal solution to reliability needs identified by the CAISO in light of the cumulative reliability, economic and public policy benefits PTEP provides. That filing should be read in conjunction with these Comments

Cal Western appreciates CAISO’s willingness to consider changes to the way it measures economic benefits of new transmission including consideration of benefit categories not previously considered or quantified.[2]

As a general matter, Cal Western evaluated the PTEP economic impacts and provided the results of those studies in previous TPPs. Cal-Western engaged E3 to run a detailed study of PTEP economics in 2022 and provide a limited update to that study in 2024. Those studies provide proposed modifications to the method for quantification of certain benefit categories and are incorporated herein by reference. Cal-Western urges CAISO to review the E3 approach to valuing project benefits and adopt their methodologies as part of the CAISO envisioned TEAM enhancements discussed at the September 25, 2025, Stakeholder meeting.

We believe that if the CAISO’s TEAM Methodology quantifies all of the benefits of PTEP, the benefits would produce a benefit to cost ratio well in excess of 1/1. Therefore, we appreciate CAISO’s willingness to incorporate enhancements to its TEAM methodology in these 2025-26 TPP economic evaluations. (See Presentation Slides 45-63). For example, we are asking CAISO to change the way it values a reduction in transmission congestion to ensure PTEP is given credit for significantly reducing congestion, including on Path 26. Transmission that reduces congestion should be viewed as a positive benefit of the new transmission, not a negative benefit. Otherwise, by penalizing a transmission solution that reduces congestion, CAISO will ensure that transmission congestion remains or continues to worsen---the opposite result is needed. The Presentation makes it clear that CAISO is aware of this anomaly and is already thinking of solutions in the context of the EDAM, however Cal Western urges CAISO not to wait to modify its ratepayer benefit calculation for reduced congestion in this 2025-26 TPP. Cal Western proposes a simple fix by eliminating the negative payments to ratepayer component of the calculation since the payments ratepayers are receiving is simply money those ratepayers have paid to hedge or relieve congestion through their Scheduling Coordinators. New transmission reduces congestion payments to ratepayers but also reduces congestion costs to ratepayers. It is a wash.

We also request, based on the E3 study results, that the cost of local and system resources be updated to reflect gas generation as the marginal local RA resource in the LA Basin and battery storage as the marginal system RA resource when quantifying reduced LCR benefits. This is critical because PTEP reduces LCR requirements in the LA Basin on nearly a one for one basis or almost 2,000 MW. Importantly, it allows for the delivery of remote renewable system resources needed to meet local load and recharge local battery storage thereby maximizing the use of local battery storage. The CAISO’s April 10, 2025, LCR study results show that absent delivery of out-of-basin resources West LA can at most add 470 MW of new battery storage capacity.

Since wildfires have a huge economic impact in a number of respects and SB 887 requires reduced wildfire risks to be considered when transmission upgrades are being evaluated, we request CAISO to consider assigning a significant economic value to the wildfire risk mitigation that PTEP will provide. The cost incurred by utilities to fix or replace transmission is known or can be estimated (especially when excluding service interruptions and the disturbance of new construction or personal injury.)  SB 887 clearly requires this major state benefit to be valued in some way in planning new transmission.[3]

Similarly, the state’s goal to substantially reduce harmful air emissions in local capacity areas like LA by 2035 is at the center of the state’s energy policy to reduce reliance on non-preferred resources and must be viewed as a huge economic benefit of new transmission. With regard to health benefits, Cal-Western urges CAISO to calculate and consider the PTEP health benefits provided by reducing nitrogen oxides (“NOx”), sulfur oxide (“SOx”) and particulate matter that is less than or equal to 2.5 micrometers in diameter (“PM2.5”), in the LA Basin in general and particularly in disadvantaged communities in the LA Area. As CAISO knows, other ISOs, like the Midwest Independent System Operator (“MISO”), already include the value of these clean air benefits when calculating the economic benefits of a new transmission project. We ask CAISO include quantification of these clean air benefits in the 2025-26 TPP TEAM valuations.

In this regard, SB 887 added a new Section 454.57 to the Public Utilities Code (Paragraph (e) (4) (A)) “requiring the Commission 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.” (emphasis added). The Commission’s recent resource portfolios add significant new clean resources intended to substantially reduce the use of gas plants in compliance with SB 887 while leaving the gas plants in the portfolio as a reliability backstop. However, this has not achieved the desired result because, unlike CAISO’s model, the Commission’s model does not see local transmission constraints that prevent the delivery of replacement energy. For its part, CAISO will run the gas plants as long as they are in the portfolio and needed due to local transmission constraints. So, rather than a 70% reduction in the use of gas intended by the CPUC portfolios, the 24-25 TPP Base Portfolio showed gas plants in transmission constrained local areas did not come close to the CPUC’s intended 70% reduction.

With a 10-year lead time for new transmission it may not be possible to comply with the SB 887 (2035) deadline, but quick action in this TPP can limit the delay. One easy solution is for CPUC to instruct CAISO to only rely on the gas plants up to a specific reduced level and let CAISO’s model determine what transmission is needed to access the needed out-of-basin resources after accounting for the increased use of local battery storage made possible by the new transmission.   

CAISO’s Presentation Slide 63 provides in response prior comments by Regenerate California and Cal Western (to consider and explain analysis of gas plant retirements), states: that ISO will continue to work with Regenerate California and Cal Western to ensure that the transmission plan aligns with the CPUC portfolios more explicitly. In this regard it is important to note that SB 887 does not require gas plant retirements but rather substantially reduced use of, or reliance on, gas plants in local capacity areas. We are hopeful CAISO will approve needed transmission to bring remote resources from the system portfolio to transmission constrained local areas, which can lead to a solution that allows for compliance with SB 887.

Cal Western also requests CAISO to recognize the economic value of reduced curtailments of renewable resource. The 2022 E3 study evaluated two additional benefits centered around reduced curtailment. In recent years, curtailments, especially of solar resources, have grown significantly in California, a trend that is likely to increase dramatically given the scale of renewable capacity additions projected in the coming decades. Curtailment is a function of A) over production during times of low load, and B) localized congestion preventing power generated in one area from serving load in another. New transmission is the best way to alleviate renewable generation curtailment.

Clean power that gets curtailed does not generate a renewable energy credit (“REC”) and therefore does not contribute to state clean energy mandates. New transmission that reduces renewable generation curtailment creates an economic benefit that can be quantified in TEAM evaluations. Reduced generation curtailment not only allows for avoided incremental renewable builds and is therefore a more efficient way to achieve state goals, but it also has quantifiable greenhouse gas savings.

In the case of PTEP, if we assume the reduced renewable generation curtailment displaces gas generation, and that displaced gas has an average emissions rate of 0.4 tons/MWh, then this curtailment reduction would help avoid 52,000 tons of annual greenhouse gas emissions. Assuming emissions compliance credits are trading around $60/ton in 2031, this leads to an additional value of $3.1 million/year.

Combining these, avoided curtailment is valued at $5.7 million per year, which when forecast across 50 years and discounted back to the present using a 7% real rate, translates to $84 million in present value.

Again, Cal Western appreciates the level of work on the part of CAISO to identify and respond to the many issues raised by all parties and look forward to continuing to work with CAISO.

[1] See, March 12, 2025, request to be studied as an economic project; and CAISO June 2025 final study plan list of projects to be studied as economic projects (pages 91-92).

[2] See Presentation Slide 63.

[3] 454.57 (h) It is the policy of the state that planning for new transmission facilities considers the following goals: (1) Minimizing the risk of wildfire.

10. Provide your organization's comments on the TEAMs methodology discussion

California Western Grid Development LLC Comments on the

CAISO 2025-26 TPP September 24-25 Stakeholder Presentation

                                                                       (October 9, 2025)

California Western Grid Development LLC (“Cal Western”) appreciates the opportunity to submit comments on the September 24-25, 2025, Stakeholder Presentation (“Presentation”). Cal Western’s Pacific Transmission Expansion Project (“PTE” or “PTEP”) is being considered for study in 25-26 TPP as an economic project.[1]  Cal Western will also be filing tomorrow, October 10, 2025, a request for PTEP to be approved in the 25-26 TPP as the optimal solution to reliability needs identified by the CAISO in light of the cumulative reliability, economic and public policy benefits PTEP provides. That filing should be read in conjunction with these Comments

Cal Western appreciates CAISO’s willingness to consider changes to the way it measures economic benefits of new transmission including consideration of benefit categories not previously considered or quantified.[2]

As a general matter, Cal Western evaluated the PTEP economic impacts and provided the results of those studies in previous TPPs. Cal-Western engaged E3 to run a detailed study of PTEP economics in 2022 and provide a limited update to that study in 2024. Those studies provide proposed modifications to the method for quantification of certain benefit categories and are incorporated herein by reference. Cal-Western urges CAISO to review the E3 approach to valuing project benefits and adopt their methodologies as part of the CAISO envisioned TEAM enhancements discussed at the September 25, 2025, Stakeholder meeting.

We believe that if the CAISO’s TEAM Methodology quantifies all of the benefits of PTEP, the benefits would produce a benefit to cost ratio well in excess of 1/1. Therefore, we appreciate CAISO’s willingness to incorporate enhancements to its TEAM methodology in these 2025-26 TPP economic evaluations. (See Presentation Slides 45-63). For example, we are asking CAISO to change the way it values a reduction in transmission congestion to ensure PTEP is given credit for significantly reducing congestion, including on Path 26. Transmission that reduces congestion should be viewed as a positive benefit of the new transmission, not a negative benefit. Otherwise, by penalizing a transmission solution that reduces congestion, CAISO will ensure that transmission congestion remains or continues to worsen---the opposite result is needed. The Presentation makes it clear that CAISO is aware of this anomaly and is already thinking of solutions in the context of the EDAM, however Cal Western urges CAISO not to wait to modify its ratepayer benefit calculation for reduced congestion in this 2025-26 TPP. Cal Western proposes a simple fix by eliminating the negative payments to ratepayer component of the calculation since the payments ratepayers are receiving is simply money those ratepayers have paid to hedge or relieve congestion through their Scheduling Coordinators. New transmission reduces congestion payments to ratepayers but also reduces congestion costs to ratepayers. It is a wash.

We also request, based on the E3 study results, that the cost of local and system resources be updated to reflect gas generation as the marginal local RA resource in the LA Basin and battery storage as the marginal system RA resource when quantifying reduced LCR benefits. This is critical because PTEP reduces LCR requirements in the LA Basin on nearly a one for one basis or almost 2,000 MW. Importantly, it allows for the delivery of remote renewable system resources needed to meet local load and recharge local battery storage thereby maximizing the use of local battery storage. The CAISO’s April 10, 2025, LCR study results show that absent delivery of out-of-basin resources West LA can at most add 470 MW of new battery storage capacity.

Since wildfires have a huge economic impact in a number of respects and SB 887 requires reduced wildfire risks to be considered when transmission upgrades are being evaluated, we request CAISO to consider assigning a significant economic value to the wildfire risk mitigation that PTEP will provide. The cost incurred by utilities to fix or replace transmission is known or can be estimated (especially when excluding service interruptions and the disturbance of new construction or personal injury.)  SB 887 clearly requires this major state benefit to be valued in some way in planning new transmission.[3]

Similarly, the state’s goal to substantially reduce harmful air emissions in local capacity areas like LA by 2035 is at the center of the state’s energy policy to reduce reliance on non-preferred resources and must be viewed as a huge economic benefit of new transmission. With regard to health benefits, Cal-Western urges CAISO to calculate and consider the PTEP health benefits provided by reducing nitrogen oxides (“NOx”), sulfur oxide (“SOx”) and particulate matter that is less than or equal to 2.5 micrometers in diameter (“PM2.5”), in the LA Basin in general and particularly in disadvantaged communities in the LA Area. As CAISO knows, other ISOs, like the Midwest Independent System Operator (“MISO”), already include the value of these clean air benefits when calculating the economic benefits of a new transmission project. We ask CAISO include quantification of these clean air benefits in the 2025-26 TPP TEAM valuations.

In this regard, SB 887 added a new Section 454.57 to the Public Utilities Code (Paragraph (e) (4) (A)) “requiring the Commission 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.” (emphasis added). The Commission’s recent resource portfolios add significant new clean resources intended to substantially reduce the use of gas plants in compliance with SB 887 while leaving the gas plants in the portfolio as a reliability backstop. However, this has not achieved the desired result because, unlike CAISO’s model, the Commission’s model does not see local transmission constraints that prevent the delivery of replacement energy. For its part, CAISO will run the gas plants as long as they are in the portfolio and needed due to local transmission constraints. So, rather than a 70% reduction in the use of gas intended by the CPUC portfolios, the 24-25 TPP Base Portfolio showed gas plants in transmission constrained local areas did not come close to the CPUC’s intended 70% reduction.

With a 10-year lead time for new transmission it may not be possible to comply with the SB 887 (2035) deadline, but quick action in this TPP can limit the delay. One easy solution is for CPUC to instruct CAISO to only rely on the gas plants up to a specific reduced level and let CAISO’s model determine what transmission is needed to access the needed out-of-basin resources after accounting for the increased use of local battery storage made possible by the new transmission.   

CAISO’s Presentation Slide 63 provides in response prior comments by Regenerate California and Cal Western (to consider and explain analysis of gas plant retirements), states: that ISO will continue to work with Regenerate California and Cal Western to ensure that the transmission plan aligns with the CPUC portfolios more explicitly. In this regard it is important to note that SB 887 does not require gas plant retirements but rather substantially reduced use of, or reliance on, gas plants in local capacity areas. We are hopeful CAISO will approve needed transmission to bring remote resources from the system portfolio to transmission constrained local areas, which can lead to a solution that allows for compliance with SB 887.

Cal Western also requests CAISO to recognize the economic value of reduced curtailments of renewable resource. The 2022 E3 study evaluated two additional benefits centered around reduced curtailment. In recent years, curtailments, especially of solar resources, have grown significantly in California, a trend that is likely to increase dramatically given the scale of renewable capacity additions projected in the coming decades. Curtailment is a function of A) over production during times of low load, and B) localized congestion preventing power generated in one area from serving load in another. New transmission is the best way to alleviate renewable generation curtailment.

Clean power that gets curtailed does not generate a renewable energy credit (“REC”) and therefore does not contribute to state clean energy mandates. New transmission that reduces renewable generation curtailment creates an economic benefit that can be quantified in TEAM evaluations. Reduced generation curtailment not only allows for avoided incremental renewable builds and is therefore a more efficient way to achieve state goals, but it also has quantifiable greenhouse gas savings.

In the case of PTEP, if we assume the reduced renewable generation curtailment displaces gas generation, and that displaced gas has an average emissions rate of 0.4 tons/MWh, then this curtailment reduction would help avoid 52,000 tons of annual greenhouse gas emissions. Assuming emissions compliance credits are trading around $60/ton in 2031, this leads to an additional value of $3.1 million/year.

Combining these, avoided curtailment is valued at $5.7 million per year, which when forecast across 50 years and discounted back to the present using a 7% real rate, translates to $84 million in present value.

Again, Cal Western appreciates the level of work on the part of CAISO to identify and respond to the many issues raised by all parties and look forward to continuing to work with CAISO.

[1] See, March 12, 2025, request to be studied as an economic project; and CAISO June 2025 final study plan list of projects to be studied as economic projects (pages 91-92).

[2] See Presentation Slide 63.

[3] 454.57 (h) It is the policy of the state that planning for new transmission facilities considers the following goals: (1) Minimizing the risk of wildfire.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

Cal Western has no comments on CAISO Policy Initiatives Presentation

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

Cal Western has no additional comments at this time.

1. Provide your organization's comments on the preliminary reliability results for the North area

 No comment.

2. Provide your organization's comments on the preliminary reliability results for the South area

 No comment.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

 No comment.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

 No comment.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

 No comment.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

 No comment.

7. Provide your organization’s comments on the high voltage TAC update

 No comment.

8. Provide your organization’s comments on the policy assessment update

CAISO Must Study Transmission Solutions for 1,150 MW of Wind in NE California

CalWEA is alarmed that CAISO is proposing not to fulfill the CPUC’s request to study transmission solutions, including routes and potential costs, to deliver 1,150 MW of in-state (but out-of-CAISO) northeast California wind resources, and to interface with BPA and NVE about potential regional solutions.[1]  The Commission indicated that this planning information would inform its further consideration regarding whether to plan for such transmission solutions in next year’s Transmission Planning Process.[2]

In the CAISO’s slides for the Sept. 24-25, 2025, Stakeholder Meeting, CAISO acknowledges, in Slide 27, that “CPUC staff recommend CAISO conduct additional analysis and defer approving any potential transmission solutions needed for the OOS wind resources which include … 1,150 MW of Northern California wind mapped to three NVE substations.” (Emphasis added.) And yet, the diagram on p. 9 shows 1,150 MW as “Out of CAISO Imports” at Malin. Slide 27 states “in 2035 base portfolio and 2040 base and sensitivity portfolio cases, these resources are modeled off-line. Instead, we build a 2040 out-of-state wind sensitivity case to have all these resources on to study any system impact and transmission solutions that are driven by these out-of-state wind resources.”

On the stakeholder call, CalWEA’s consultant asked CAISO to describe the off-line modeling. CAISO responded that there is sufficient MIC to support Northeast California wind resources and, therefore, they are not modeled in the sensitivity study.  These resources are assumed to be included in import flows into CAISO. 

CAISO’s proposal contradicts, and fails to fulfill, the CPUC’s request.  MIC availability is very limited, and load-serving entities control its use.  It is short-term and thus generally does not support project financing. In any case, MIC is no substitute for transmission upgrades that access Northeastern California.

CalWEA therefore strongly urges CAISO to study 1,150 MW, as the CPUC requested, to inform the Commission’s 2026-27 TPP portfolios.  CPUC’s busbar mapping shows these resources interconnected at a new substation near the existing Leavitt substation in central western Nevada (300 MW), a new substation near the existing Madeline substation (700 MW), and at the Hilltop substation (150 MW). 

Recommendation to Study Tesl- to-Collinsville Upgrade

CalWEA continues to recommend that CAISO consider upgrading the Tesla to Collinsville pathway. All NGBA resources, whether for short-term RA or long-term reserved capacity, would benefit substantially from this relatively modest upgrade.  Furthermore, to promote more efficient use of transmission planning deliverability capacity, CAISO should use the ELCC capacity value for offshore wind, approximately 50% of nameplate capacity, rather than the 83% value that CAISO currently plans to use without justifying the value.

Reserving Transmission Capacity for Onshore Wind LLT Renewables

CalWEA appreciates CAISO’s plan to involve stakeholders, at an upcoming stakeholder meeting, in reviewing the deliverability capacity to be reserved for onshore California wind and other “long lead time” renewables, as requested by the CPUC. 

[1] The CPUC stated the following in its Decision 25-02-026 (Feb. 26, 2025) (emphases added):

p. 59 “…1,150 MW of in-California wind that is mapped to substations in far Northeast California and outside of the CAISO balancing area …”

p. 62:  “[W]e will ask [CAISO] to undertake a special study of the various routes and combinations for the OOS wind amounts [including Northeast California wind] to learn more information about the details of potential routes. This will allow for analysis of alternative locations for injecting the resources onto the CAISO grid and the potential transmission solutions.”

Conclusions of Law “13. It is reasonable to request that the CAISO not trigger the approval of significant new transmission to support Northeast California wind and OOS wind on new regional transmission lines this year, but rather study these options and interface with regional partners outside of California, in order to plan for future development of this transmission with a better understanding of routing options and potential costs.”

Ordering Paragraph 2:  “The California Public Utilities Commission (Commission) requests that the California Independent System Operator (CAISO) analyze the transmission needed for the base case portfolio reflected in Ordering Paragraph 1, but not yet trigger approval of the solutions necessary to support out-of-state wind resources on new transmission and in-state wind resources that are beyond of the CAISO balancing area and are specifically identified in the results of the mapping of resources to busbars discussed in Section 5 of this decision. Instead, the Commission recommends that the CAISO conduct the analysis and begin regional discussions (with entities responsible for regional planning and balancing areas outside of the CAISO planning area) about the appropriate siting and potential costs of such upgrades, for further consideration in next year’s Transmission Planning Process.”

[2] CPUC D. 25-02-026 at p.63 (emphasis added): “Finally, there is a similar issue with respect to in-state/on-shore wind in Northern California, where 1.1 GW of wind is mapped to the Eastern side of the Sierra Nevada mountains in the NV Energy system (not within the CAISO). This area currently has commercial interest with two projects being developed. However, the resources would currently have to connect through the Bonneville Power Administration (BPA)-NV Energy connection, which has limited capacity, and then be imported into California through the California Oregon Intertie (COI).

“Similar to the OOS wind issues generally discussed above, for this year’s TPP, we are asking the CAISO to do additional study on transmission solutions to upgrade the NVE/BPA system or directly interconnect the CAISO grid to deliver these in-state (but out-of-CAISO) wind resources. This can advance the identification of transmission locations and costs, without triggering potentially expensive or not-well-targeted solutions. This is also a complex question that requires interfacing with BPA and NVE about potential regional solutions. Thus, conducting further study this year will prepare us in next year’s TPP to actually trigger the appropriate transmission when more details are known.”

9. Provide your organization's comments on the economic assessment update

 No comment.

10. Provide your organization's comments on the TEAMs methodology discussion

 No comment.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

 No comment.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

 No comment.

1. Provide your organization's comments on the preliminary reliability results for the North area

The City and County of San Francisco (the “City”) appreciates the opportunity to comment on the CAISO’s 2025-2026 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 24-25, 2025. 

There Are Strong Reliability and Strategic Justifications for CAISO to Approve WaNTEP in the Current TPP Cycle

Over the last three transmission planning cycles, the CAISO has approved a significant amount, both in scope and cost, of transmission upgrades to meet the State’s greenhouse gas reduction goals and rapid load growth. California is facing major challenges in building the transmission infrastructure that it needs, including rising costs, project feasibility, and project viability. Some challenges are driven by the need for new Right-of-Way (RoW) acquisition and environmental review, resulting in permitting delays, increased construction costs, and reduced reliability. These delays force needed generation projects and new loads to wait to come online. The cost increases are on top of the high costs and revenue requirements associated with projects developed by the original Participating Transmission Owners.

The City has proposed a unique transmission project, the Warnerville-Newark Transmission Expansion Project (“WaNTEP”), in the 2024-2025 TPP to help address these challenges. During the CAISO Board meeting on May 22, 2025, the CAISO Board of Governors (“BoG”) directed CAISO staff to continue to evaluate WaNTEP as an extension of the 2024-2025 TPP. The original scope of WaNTEP, as included in the CAISO 2024-2025 TPP Request Window, entails utilizing the City’s existing 100-mile Moccasin-Warnerville-Newark 115 kV line Right-of-Way (RoW) to rebuild a new 1,000 MW 70-mile High Voltage Direct Current (HVDC) line or a 230 kV Alternating Current (AC) line option. Based upon the CAISO’s feedback, the City is open to considering additional configurations that utilize the City’s RoW from Warnerville to Newark, including a potential Warnerville-Tesla-Newark 230 kV AC line.

The City’s study found that the P1, P6, and P7 overloads on eight (8) 230 kV lines found in the CAISO preliminary assessment in 2035 and 2040 were eliminated by each of three (3) potential WaNTEP configurations: 1,000 MW HVDC, Warnerville-Newark 230 kV AC, and Warnerville-Tesla-Newark 230 kV AC. The overloads addressed by WaNTEP include the Castro Valley-Newark 230 kV, Lonetree-Cayetano 230 kV, Monta Vista-Saratoga 230 kV, Moraga-Castro Valley 230 kV, and Pittsburg-San Mateo 230 kV lines. The Grant-Oakland-J-Edes 115 kV, Lawrence-Monta Vista 115 kV, and Newark F-Zanker-KRS 115 kV are among the 115 kV lines with contingency overloads that are eliminated with WaNTEP reconfigurations in 2035 and 2040. An additional eight (8) 230 kV facilities, including Birds Landing Sw Sta-Contra Costa PP 230 kV, North Dublin-Cayetano 230 kV, Tesla-Newark #1 & #2 230 kV, Hicks-Metcalf 230 kV, Saratoga-Vasona 230 kV, and Pittsburg-Eastshore 230 kV, have overloads in 2040 that are addressed by WaNTEP.[1]

Furthermore, the City found that the WaNTEP configurations are effective in eliminating additional contingency overloads in 2035 and 2040 on the following eight (8) 230 kV lines not included in the CAISO’s preliminary assessment: Gregg-Herndon-1 or 2 230kV, Metcalf-Los Esteros 230 kV, Parkway-Moraga 230 kV, Tesla C-Ppassjct 230 kV (A Segment Of Tesla-Newark 230 kV), Vaca-Dix-Bahia 230 kV, Vaca-Dix-Parkway 230 kV, and Vascowindjct-Cayetano 230 kV. As we discuss further, in response to Q.3, addressing these contingency overloads on these key 230 kV and 115 kV import lines into the GBA requires a comprehensive regional planning exercise rather than piecemeal reconductoring on all these lines, which would be unnecessary and highly expensive, especially since the CAISO is validating load growth projections.

In addition to the reliability benefits, we also found significant additional policy benefits with consistent alignment between the State and the City’s long-term goals, including:

• Easier to build: The value of leveraging the City’s existing RoW cannot be overstated. It will have lower costs, with a greater degree of confidence in timely project delivery, compared to any greenfield project option.
• More compelling as load grows: The California Energy Commission (CEC) continues to forecast significant load growth. While we have focused our reliability analysis on the 2035 case, the reliability benefits increase materially for the 2040 case, due to increased loads.
• Increases capacity to deliver renewables: While our analyses have been focused on the Greater Bay Area, we anticipate significant renewable development to the east of Tesla, including from Fresno area resources. These needed resources would be facilitated by the WaNTEP’s connection between Warnerville and the Bay Area.
• Substantial and effective hedge for the State: There can be any number of reasons that project delivery, generation, and/or load forecasts can and will change. The uncertainty associated with the feasibility, scope of, and costs of greenfield projects is well-known. One such example is the CAISO’s decision to exclude the previously approved Serrano–Del Amo–Mesa 500 kV Transmission Reinforcement project in the base cases for the reliability, policy, and economic assessments in the current TPP. This decision was driven by SCE’s determination that the project cost would be multiple times greater than the original estimates. If additional previously-approved greenfield projects, such as the new Manning-Metcalf 500 kV line are delayed for any reason, WaNTEP would meaningfully mitigate reliability issues until the previously-approved projects can be completed. Because the WaNTEP project can be completed sequentially, looping through Tesla if/when future generation development materializes, it would serve as a hedge against delays in the timing or changes to the location of future generation, including offshore wind.

In summary, the City strongly urges the CAISO to approve WaNTEP in the current planning cycle.

[1] See PG&E September 24^th Presentation, p. 79.

2. Provide your organization's comments on the preliminary reliability results for the South area

No comments at this time.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

CAISO Should Approve WaNTEP Now and Consider A Subset of the Proposed Reconductoring Projects in Future TPP Cycles As CAISO Monitors Load Growth

PG&E proposed the following two (2) Request Window (RW) projects in the current TPP as presented during the September 25^th meeting.

• Eastshore and Newark Area Import Capability Reinforcement Conceptual Project: This project entails reconductoring of multiple 230 kV lines in East Bay; and
• Metcalf- Monta Vista 230 kV Transmission Corridor Reinforcement Project: This project entails reconductoring four (4) 230 kV lines between Metcalf and Monta Vista.

Although PG&E has estimated the capital cost for the Metcalf - Monta Vista 230 kV Transmission Corridor Reinforcement Project at $133 M - $266 M, they have not provided a capital cost estimate for the Eastshore and Newark Area Import Capability Reinforcement Conceptual Project. Due to the extensive scope of reconductoring more than 100 miles of 230 kV lines, which potentially would result in rebuilding certain sections of those lines to accommodate larger conductors, the Eastshore and Newark Area Import Capability Reinforcement Conceptual Project will likely be very expensive and may have physical and environmental challenges.

PG&E identified the worst overloads under certain contingencies that drive the need for the two above-mentioned RW projects.[2] The WaNTEP project addresses most of the overloads, providing significant flexibility for focusing work on subsets of the PG&E projects first. In Table 1 below, we have summarized the loadings on the 230 kV facilities with and without the three possible WaNTEP configurations in 2035. Table 1 shows that WaNTEP, especially the Warnerville-Tesla-Newark 230 kV AC configuration, effectively eliminates the overloads on the Eastshore and Newark Area Import 230 kV lines. Furthermore, it also effectively reduces the contingency loadings on the Metcalf- Monta Vista 230 kV Transmission Corridor, and in the case of Monta Vista – Saratoga 230 kV and Vasona – Metcalf 230 kV, eliminates them. These findings demonstrate that WaNTEP enhances the PG&E projects by providing a hedge against project delays and by extending the time horizon before further upgrades will be needed. Furthermore, WaNTEP is a significantly more cost-effective and reliable solution than the PG&E-proposed reconductoring projects, addressing a broader set of issues quickly, while allowing CAISO more time to review the load growth that drives these upgrades. For these reasons, CCSF urges the CAISO to approve WaNTEP in the current planning cycle, and then determine whether reconductoring a subset of these 230 kV facilities is required in subsequent planning cycles, as we gain more clarity on the scale and location of the load growth.

Table 1: Loading on 230 kV Facilities in GBA with and without WaNTEP: 2035

[2] See PG&E September 25^th Presentation, p. 22 and p.35.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

No comments at this time.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

No comments at this time.

8. Provide your organization’s comments on the policy assessment update

No comments at this time.

9. Provide your organization's comments on the economic assessment update

No comments at this time.

10. Provide your organization's comments on the TEAMs methodology discussion

No comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

No comments at this time.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No comments at this time.

1. Provide your organization's comments on the preliminary reliability results for the North area

The City of Palo Alto Utilities (“CPAU” hereafter) appreciates the opportunity to comment on the CAISO’s 2025-2026 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 24-25, 2025. 

CPAU appreciates CAISO staff flagging the new overloads as soon as 2027, and is ready to work with PG&E to start predesign work on the previously approved Ames Distribution to Palo Alto 115 kV line to address these overloads

CPAU appreciates CAISO staff highlighting the new P2 and P7 violations on Cooley Landing #1 and Ravenswood to Palo Alto #1 and #2 115 kV lines due to increased load.[1] CPAU also appreciates how CAISO staff noted how the Ames Distribution to Palo Alto 115 kV line (“Project” hereafter, approved by ISO in 2024-2025 TPP[2]) largely addresses these issues through nearly 2040. As noted in the current preliminary reliability assessment results and presentation, without the “Project”, the Cooley Landing to Palo Alto 115kV line is overloaded as early as 2027. However, the previously approved “Project” eliminates the overloads on the Cooley Landing to Palo Alto 115kV line, while also limiting the P7 overload on Ravenswood to Palo Alto 115kV to only 1% in 2035.[3] Overall, these results confirm the need for the “Project” to be advanced. CPAU, therefore, believes that PG&E needs to prioritize the “Project” and start the project scoping phase, comprising the preliminary engineering and environmental assessment as soon as possible. 

CPAU is eager to work with PG&E to begin work to potentially expedite the “Project’s” In-Service Date

CPAU understands the “Project” could be completed in three to five years.  However, the CAISO’s 2024-2025 TPP 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.[4]  As described above, with CPAU’s rapid load growth the CAISO-identified reliability violations will remain unaddressed for many years under the current in-service date of 2034 for the “Project”. 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’s 2025 actual 1-in-10 peak was 17% higher than the 2025 peak projected in the previous year’s TPP forecast, exceeded the current TPP forecast, and is continuing to grow

CAISO staff 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, multifamily housing developments, and electrification. CPAU has worked closely with the CEC staff to incorporate CPAU’s demand forecast in the current forecast (the 2024 Integrated Energy Policy Report (IEPR), which the CEC formally approved on January 21, 2025). This demand forecast is higher than the one assumed in the previous planning cycle, as noted in the comments filed by CPAU in the last TPP.[5] Importantly, CPAU’s load growth has shown up even faster than anticipated in the current forecast, with the 2025 peak demand 8% higher and energy sales 11% higher than the current planning forecast used in the 2025-26 TPP cycle.

The CAISO Staff presentation referenced the large increases in CPAU’s expected 1-in-10 peak loads in the current forecast[6] relative to the previous year’s forecast.[7] While all of the CEC’s load growth projections across the state are less firm beyond 2030, CPAU’s actual 1-in-10 peak demand in 2025 exceeded the previous year’s forecast and current CEC load forecast approved in January 2025. So, while the CAISO staff presentation notes a 47 MW (=224-177) increase by 2030 from one CEC forecast to the next, CPAU’s actual 1-in-10 peak was 26 MW (=183-157) higher than the peak load in the CEC forecast for 2025 in the previous planning cycle. In other words, 26 MW (=183-157) of this “47 MW increase by 2030” already occurred in the 2023-2025 timeframe, meaning that 26 MW of this “47 MW” near-term growth is just adjusting CEC’s baseline to actual load beginning in 2025. Additional data center load growth, large commercial load growth, and unprecedented all-electric multifamily housing which are nearly final construction inspections are leading to the additional load increases of 20 MW or so on top of the CEC electrification forecasts. CPAU has been in close communication with PG&E and CEC regarding CPAU’s load growth projections as these have been driven by data centers and large commercial load growth which are not captured in standard regression forecasts.

To provide additional context to CPAU’s expected load growth, the current planning cycle anticipates 4.8% per year peak load growth for the PG&E Greater Bay Area from 2025-2035, whereas CPAU’s latest forecast is only projecting annual average peak load growth of 2.4% over the next ten years, since our actual 1-in-10 peak for 2025 has already reached 183 MW.

CPAU would like to emphasize that we believe beginning the scoping phase of the “Project” is the best use of resources, rather than CAISO approving additional projects, such as reconductoring the 115kV import lines into Palo Alto, as it continues to monitor the long-term load growth. The CAISO 2024-2025 Transmission Plan approved the Ames Distribution – Palo Alto 115 kV transmission line with a minimum capacity requirement of 1,500 Amps.[8] CPAU is committed to working closely with CEC and PG&E staff to reconcile forecast assumptions to right-size the Ames Distribution to Palo Alto 115 kV line. Specifically, CPAU encourages PG&E to explore alternatives with higher capacity conductors needed for the “Project” given the load growth while assessing their cost-effectiveness in the project scoping phase.

[1] Presentation- 2025-2026 Transmission Planning Process - Sep 24, 2025; Slides 72 & 75 https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2025-2026-Transmission-Planning-Process-Sep-24-2025.pdf

[2] https://stakeholdercenter.caiso.com/InitiativeDocuments/BoardApproved-2024-2025-TransmissionPlan.pdf

[3] CAISO Preliminary Reliability Assessment Results for PG&E-GBA.

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

[5] City of Palo Alto comments regarding higher load growth than anticipated and adopted in the 2024 IEPR. https://stakeholdercenter.caiso.com/Comments/AllComments/b81c4cdc-7902-4f62-bdb8-97648c0a8e24#org-42f42944-c6db-4cf4-8477-43e5f25c6e7f

[6] 2024 IEPR Update

[7] 2023 IEPR Forecast

[8] See Appendix H: “Project” Need and Description, p. H-27.

2. Provide your organization's comments on the preliminary reliability results for the South area

No comments at this time.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

CPAU would urge PG&E to advance the Ames Distribution to Palo Alto 115 kV project and parallel track it alongside the substation maintenance project at Palo Alto Switching Station, such that it is online in time to mitigate reliability issues. CPAU is committed to working alongside PG&E to move this project along.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

No comments at this time.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

No comments at this time.

8. Provide your organization’s comments on the policy assessment update

No comments at this time.

9. Provide your organization's comments on the economic assessment update

No comments at this time.

10. Provide your organization's comments on the TEAMs methodology discussion

No comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

No comments at this time.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No comments at this time.

1. Provide your organization's comments on the preliminary reliability results for the North area

EPE appreciates that PG&E mentioned several system reconfigurations in lieu of upgrades.

1. There are alternatives to the long lead upgrades and SCD restrictions identified by the Utilities, that would allow resources to interconnect sooner rather than later and would still maintain a safe and reliable grid. Can a list of alternatives evaluated to address the SCD and/or long lead time upgrades be provided?
2. As utilities in this region are receiving large load requests, it is imporant for developers to understand the locations of such requests to better site future large load projects.
3. Just like there is a generation queue. EPE recommends CAISO have a Load Queue for each Utilitiy in a comprable manner that protects confidentiality and provides POI and MW requested, synanomous to the generation queue.
4. Can CAISO please have a list major substations serving local load, where capacity is needed and new substations will be needed to serve new load that will ome into those areas. Request for clarificatiopn on where NEW Load Serving Substations will be needed. 

2. Provide your organization's comments on the preliminary reliability results for the South area

There are alternatives to the long lead upgrades and SCD restrictions identified by the Utilities, that would allow resources to interconnect sooner rather than later and would still maintain a safe and reliable grid. 

1. For example, the potential of operating transmission lines as normally open with an automatic transfer-close scheme that would close in the lines under  outage conditions. This would enable a reduction to SCD at locations where duty exceeds existing breaker ratings. To understand this recommendation, we can look at two (2) specific examples within SCE:
   • Operating the Barre-Del Amo 230kV Line normally open at Barre substation and implementing a scheme whereby the loss of either the Barre-Alamitos #1 230kV or Barre-Alamitos #2 230kV Lines would result in closing in the Barre-Del Amo 230kV Line. This configuration would lower 3-Phase SCD at Barre  Sub and Serrano Substation 230kV Bus by approx.11kA and 2.5KA, respectively.
   • Line and Bus reconfiguration at Miraloma 230kV Sub, which would pair the existing Mira Loma-Vista #2 230kV line with the Mira Loma-Ranch Vista #1 in a common break and a half position, and operate bus side breakers normally open, to create a single Rancho Vista-Vista 230 kV transmission line. This will reduce SCD at Etiwanda 230kV and Miral Loma East 230kV busses by 2.3kA and 10.4kA respectively.
   • This Line and Bus reconfiguration at Mira Loma, would ELIMINATE the need to upgrade Mira Loma Substation to GIS for 80kA capability. 
   • A comparable Line & Bus reconfiguration, can and should be evaluated at other locations where GIS is being recommended by the Utilities.
2. As utilities in this region are receiving large load requests, it is imporant for developers to understand the locations of such requests to better site future large load projects.
3. Just like there is a generation queue. EPE recommends CAISO have a Load Queue for each Utilitiy in a comprable manner that protects confidentiality and provides POI and MW requested, synanomous to the generation queue.  

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

We are grateful

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

Given that SCE's Subtransmission System is non-CAISO controlled, and radial in nature, there is not much information on the subtransmission. EPE recommends SCE make more information available on the need for NEW A-Stations to provide incremental load-serving capacity. These New A-Station will require new connections to the CAISO-controlled grid, which should  be properly identified and documented.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comment.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comment.

7. Provide your organization’s comments on the high voltage TAC update

No comment.

8. Provide your organization’s comments on the policy assessment update

The Policy assessments assigns or reserves certain MW for "future policy driven projects." This idea is great, however if there are REAL generation projects that are ready to go live, EPE recommends that the CAISO consider these Genenration projects that are ready be connected be taken into consideration towards the policy MW reservation for allocation. Start earmarking these projects against the policy MW reservation. Bringing REAL Project to fruition.

9. Provide your organization's comments on the economic assessment update

No comment.

10. Provide your organization's comments on the TEAMs methodology discussion

No comment.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

No comment.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No.

1. Provide your organization's comments on the preliminary reliability results for the North area

2. Provide your organization's comments on the preliminary reliability results for the South area

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

7. Provide your organization’s comments on the high voltage TAC update

8. Provide your organization’s comments on the policy assessment update

9. Provide your organization's comments on the economic assessment update

10. Provide your organization's comments on the TEAMs methodology discussion

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

Fervo Energy Company (“Fervo”) appreciates the CAISO sharing its 2025-2026 Transmission Planning Process (“TPP”) reliability study results during the stakeholder call on September 24-25. Fervo thanks the CAISO for its continued commitment to planning for the State’s inter-regional power delivery needs and engaging stakeholders in this process.

Fervo is a leading developer of utility-scale EGS projects, leveraging advanced drilling and subsurface technologies to access new geothermal heat resources previously deemed unsuitable due to limitations in conventional geothermal drilling methods. EGS already provides reliable, clean, and dispatchable power today and is rapidly scaling to meet the energy demands of the future.  

Fervo has a portfolio of lease holdings across the West, including in California, and is actively developing projects to support the California grid, including the 500-megawatt Cape Station project in Beaver County, Utah. All 500 megawatts are fully contracted with California Load Serving Entities (“LSE”), including Southern California Edison (“SCE”), Ava Community Energy, Clean Power Alliance (“CPA”), Desert Community Energy, and Shell Energy, to meet procurement orders under D.21-06-035.

Fervo appreciates the CAISO’s acknowledgement that the out-of-state resource requirements cannot be fully accommodated by the existing and planned transmission projects. Fervo supports an approach that rapidly and robustly closes this gap, such as the suggested RFI for inter-regional transmission solutions. Moreover, Fervo supports the idea that out-of-state transmission project needs should be driven by technology-neutral resource requirements.

EGS resources are now being mapped in the CPUC resource portfolios, and, as such, Fervo encourages CAISO’s approach to inter-regional transmission planning to incorporate these results. The Department of Energy’s (“DOE”) EGS Shot Analysis estimates that, with EGS technology, there is enough geothermal technical potential under American soil to meet the electricity demand of the entire world. EGS resources such as Fervo’s are slated to come online quickly and in large quantities to meet inter-regional energy needs. Fervo acknowledges that the CPUC resource portfolio for the 2025-26 TPP process does not yet include significant volumes of geothermal.  However, the recently released proposed portfolio for the 2026-27 TPP cycle includes approximately 2 GW of out-of-state geothermal (see slide 47 at CPUC 2026-27 TPP Portfolio Analysis), reflecting the increasing competitiveness of this clean firm resource.  To adequately prepare for the onboarding of these resources, Fervo respectfully requests that CAISO consider future geothermal potential when deciding between multiple otherwise equal mitigation options and integrate the most up-to-date CPUC resource portfolios where possible in future regional transmission planning discussions.

Fervo thanks the CAISO for its commitment to stakeholder engagement and coordination.

1. Provide your organization's comments on the preliminary reliability results for the North area

2. Provide your organization's comments on the preliminary reliability results for the South area

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

7. Provide your organization’s comments on the high voltage TAC update

8. Provide your organization’s comments on the policy assessment update

9. Provide your organization's comments on the economic assessment update

10. Provide your organization's comments on the TEAMs methodology discussion

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

GreenGenStorage, LLC (GreenGen) fully supports the CAISO re-starting its Storage as a Transmission Asset (SATA) Initiative after completing other pending RA initiatives. The CAISO previously pursued the SATA initiative in the 2018-19 timeframe. In the nearly seven years since that initiative closed, the CAISO and LSEs have gained considerable experience in operating and procuring storage assets. At the same time, the need for long-duration energy storage resources has grown exponentially, with the CPUC’s latest draft resource portfolios indicating a need for 13.2 GW of 8-hour storage and 5.4 GW of 12-hour storage by 2036. Providing a mechanism to procure and dispatch long-duration energy storage as a transmission benefit can play a pivotal role in ensuring the necessary resources are built out in the timeframe necessary. GreenGen looks forward to actively participating in the SATA initiative once it is re-started. 

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

1. Provide your organization's comments on the preliminary reliability results for the North area

See attached

2. Provide your organization's comments on the preliminary reliability results for the South area

See attached

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

See attached

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

See attached

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comments

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comments

7. Provide your organization’s comments on the high voltage TAC update

See attached

8. Provide your organization’s comments on the policy assessment update

See attached

9. Provide your organization's comments on the economic assessment update

No comments

10. Provide your organization's comments on the TEAMs methodology discussion

See attached

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

See attached

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No comments

1. Provide your organization's comments on the preliminary reliability results for the North area

MWD has no comments on this topic at this time. 

2. Provide your organization's comments on the preliminary reliability results for the South area

The Metropolitan Water District of Southern California (MWD) appreciates the opportunity to provide comments on the preliminary reliability results for the South area as presented during the CAISO’s September 24-25 stakeholder meetings.  MWD owns and operates (through its transmission operator) the Colorado River Aqueduct Transmission System (CRATS), which was constructed to support the water operations of the Colorado River Aqueduct (CRA) system, including five pumping stations representing an approximate peak demand of 280 MW within the CAISO balancing authority area.  Through the CRA, MWD is responsible for delivering of water supply to more than 19 million people located in southern California.

The CRATS is located adjacent to and is interconnected with both the CAISO-controlled transmission system and transmission system facilities of the Western Area Power Administration (WAPA).  Thus, conditions on both the CAISO and WAPA electric systems can have a significant impact on the operations of the CRATS and CRA.  

According to recent assessments by MWD, due to changes in resource portfolios used in the CAISO’s annual TPP assessments and growing loads in the southern area of the CAISO, MWD’s CRATS at increased risk of experiencing overloads.  These increases are observed in both in frequency and magnitude.  TPP study results also indicate pre-contingency/post-transient voltage deviations that go beyond MWD’s operating voltage ranges and applicable reliability criteria by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC). 

Table 1 summarizes this emerging trend using published study results from the current and previous TPP cycles (illustrated only using P0/P1 contingencies):

Table 1: SCE Eastern Area - MWD Line/Bus Overload and Voltage Violations

During this time, MWD’s water pumping loads and its usage of the CRATS have not varied.  As recently as the CAISO’s 2024/25 TPP cycle, only P1 thermal overloads with no voltage deviations were detected on the MWD system.

MWD requests that the CAISO evaluate, assess, and report on solutions for the thermal, voltage, and transient stability violations that are observed.  Although the CAISO may have historically relied on remedial action schemes (RAS) in the SCE Eastern area to mitigate these violations, MWD urges the CAISO to more fully assess whether reliance on a RAS or other operating adjustments provides effective mitigation, particularly in the long term. 

For those violations that cannot be fully mitigated by the cited RAS or other mitigation measures, MWD requests that the CAISO work with MWD to identify and develop acceptable mitigation measures in order to meet requirements of applicable NERC, WECC, and CAISO Transmission Planning Standards.  In particular, MWD requests that the CAISO take appropriate actions to reduce reliability impacts on the CRATS that are caused or exacerbated by conditions on the CAISO system, in order to reduce the risk to MWD’s water operations.  Absent adequate mitigation within the CAISO system, the impacts shown in the current TPP reliability study results will negatively impact operations of the CRATS, which will, in turn, create risks for operations on the CRA system.

Finally, MWD requests that the CAISO approach the identification and recommendation of mitigations for reliability violations uniformly for both CAISO-controlled system and adjacent systems that are impacted due to conditions on the CAISO grid.  MWD recognizes that the CAISO does not plan for or fund system improvements for entities that are not Participating Transmission Owners (PTOs) in the CAISO.  However, MWD does encourage the CAISO’s technical analysis to follow consistent criteria for identifying and recommending system improvements for both PTOs and non-PTOs in order to promote the overall reliability and resiliency of the BES.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

MWD has no comments on this topic at this time. 

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

MWD has no comments on this topic at this time. 

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

MWD has no comments on this topic at this time. 

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

MWD has no comments on this topic at this time. 

7. Provide your organization’s comments on the high voltage TAC update

MWD has no comments on this topic at this time. 

8. Provide your organization’s comments on the policy assessment update

MWD has no comments on this topic at this time. 

9. Provide your organization's comments on the economic assessment update

MWD has no comments on this topic at this time. 

10. Provide your organization's comments on the TEAMs methodology discussion

MWD has no comments on this topic at this time. 

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

MWD has no comments on this topic at this time. 

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

MWD has no comments on this topic at this time. 

1. Provide your organization's comments on the preliminary reliability results for the North area

2. Provide your organization's comments on the preliminary reliability results for the South area

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

7. Provide your organization’s comments on the high voltage TAC update

8. Provide your organization’s comments on the policy assessment update

PivotGen supports CAISO’s efforts to assess the integration of out-of-state (OOS) resources both as part of the policy assessment based on the CPUC portfolios, and also as part of a larger interregional planning effort. 

As noted on Slide 36 of CAISO’s September 25, 2025 presentation, “There are no known transmission projects that can integrate required resources apart from SWIP-N (Idaho), TWE (Wyoming), and SunZia (New Mexico)”.  While these transmission projects will support CPUC portfolios, there are OOS renewable resources not currently reflected in the portfolios that are being developed and can take advantage of these transmission projects to deliver renewable capacity to CA.  Specifically, PivotGen is developing up to 1 GW of wind and solar in Nevada.  These renewable projects are located along the SWIP-N corridor and the capacity can be delivered to CAISO utilizing SWIP-N. 

PivotGen encourages CAISO to continue to support the development of SWIP-N in order to facilitate development of renewables for delivery to CA. 

9. Provide your organization's comments on the economic assessment update

10. Provide your organization's comments on the TEAMs methodology discussion

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

1. Provide your organization's comments on the preliminary reliability results for the North area

The City of Santa Clara, dba Silicon Valley Power (SVP), appreciates the opportunity to comment on the CAISO’s 2025-2026 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 24-25, 2025. SVP acknowledges the significant efforts of the CAISO and PTO staff to develop this material. 

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, the SVP’s load is expected to grow considerably in the next several years, primarily driven by hyper-scale data centers. SVP has had seven new 60 kV-connected data centers come into service in the past four years, one 60 kV-connected data center is currently under construction and is expected to be operational by early next year, and 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 Newark to NRS 230 kV and NRS to San Jose B 230 kV AC Transmission projects. 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 from 762 MW peak in 2025[1] (800 MW when adjusted to 1-in-10 conditions) to 1,672 MW in 2035. Based on this growth, other identified PG&E 115 kV transmission projects might be required to maintain the overall system reliability.

Increased Load Growth in SVP, as well as the surrounding San Jose area, will likely place stress on SVP’s Import Facilities

The purpose of this section is to identify that some facility overloads, like those on the Newark 230/115 kV TB #11, are emphasized in the CAISO’s September 24^th presentation.[2] However, the CAISO’s September 24^th presentation did not include several important issues that were identified in its preliminary reliability assessment. We summarize those P1 and P6 issues on the Newark-NRS 115kV #1 and #2, Newark-Zanker-KRS 115kV, NRS-SRS 115kV #1 and #2, lines as early as 2035 in Table 1 below. The P1 issues require that the CAISO consider approving reconductoring the Newark-NRS 115kV lines, NRS to SRS #1 and #2 115kV lines, and Newark-Zanker-KRS 115kV lines by 2035.

Table 1: Long-Term Contingency Overloads on Key SVP Import Facilities in 2035 and 2040

Source: *CAISO Preliminary Reliability Assessment for PG&E GBA

**Identified in SVP internal study using TPP 25/26 GBA Preliminary model, but not reported in CAISO Assessment

In addition to the long-term issues shown in Table 1 above, SVP notes that the CAISO’s preliminary reliability assessment has also found a number of near-term issues on the same facilities, such as Newark-Northern Receiving Station #1 & #2 115kV, Newark F-Zanker-KRS 115kV, NRS-SRS #1 & #2 115kV, as early as 2027, as shown in Table 1. Therefore, it is critical that the CAISO-approved projects, such as Newark-NRS 230kV and Metcalf-San Jose B 230kV lines, are constructed and in-service by their planned online dates.[3] If these previously-approved projects are delayed, then it will be critical that CAISO, PG&E, and SVP identify the operational mitigations and update the Silicon Valley Area operating procedure, i.e., the CAISO’s OP7340.

[1] Actual instantaneous peak of 762 MW on September 23, 2025.

[2] See the “Summary results for San Jose” in the CAISO’s September 24^th Presentation, p.77.

[3] CAISO 2021-2022 Transmission Plan, dated March 17, 2022 with modification included in the CAISO San Jose Area Transmission Plan, dated November 5, 2024.

2. Provide your organization's comments on the preliminary reliability results for the South area

No comments at this time.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

SVP supports some elements of the PG&E-proposed South Bay Reinforcement Conceptual Project

SVP endorses the following two (2) elements of the proposed project.

1. SVP strongly supports reconductoring the Newark–Kifer 115 kV line, given the issues identified in Table 1 above. For the same reasons, SVP also requests that the CAISO add the reconductoring of both the Newark-NRS 115kV lines and NRS to SRS #1 and #2, given the studies show P1 issues causing overloads on these lines as early as 2035.
2. Reconductor FMC JCT-FMC portion of the Kifer – FMC 115 kV Line: SVP supports reconductoring this line segment using the largest feasible conductor ampacity given feasibility constraints on this segment, as PG&E indicated in the September 25^th meeting. SVP also encourages PG&E to adopt the same approach when sizing the previously-approved Kifer-FMC 115kV reconductoring project. SVP recommends that PG&E use the same ampacity for the Kifer-FMC 115kV as it will choose for the San Jose B-Trimble 115kV line, if possible, as both the lines share common towers and underground sections with the KRS–FMC Jct 115kV line for more than 2.5 miles.

Need for Transparency Regarding the Load Growth Assumptions in PG&E Studies, Especially Those Pertaining to the Data Center Load Growth

PG&E presented its Load Cluster 2024 (LC24) and Serial Interconnection Studies during the September 25^th stakeholder meeting.[1] SVP’s high-level assessment of the data center loads incorporated in PG&E’s Data Center Load Cluster 2024 (LC24) and Serial Data Center Load Interconnection indicates the following.[2]

• PG&E Serial queued loads (~700 MW) are not included in the CAISO TPP GBA cases.
• PG&E Cluster queued loads (~840 MW) are partially modeled; only about 620 MW appears to be represented.
• In total, approximately 920 MW of data center load in PG&E’s queue is missing from the CAISO TPP GBA cases. We note that the CAISO GBA cases include 152MW of data center load modeled at the Nortech 115kV, which is not part of PG&E’s Cluster or Serially studied loads. However, there is 250MW of Data Center 3 load modeled by PG&E at Los Esteros 230kV. It is possible that there is an overlap between the 152MW load at Nortech and the 250MW load at Los Esteros.

Substantive additional network upgrades are triggered by the Serial and LC24 loads on the transmission facilities serving SVP’s load to address reliability issues beyond those identified in the CAISO’s preliminary reliability assessment.[3] Given the direct relevance of these loads to SVP’s system reliability and the lack of clarity regarding the load assumptions, PG&E’s study cases and study reports must be shared with SVP so that SVP can perform affected system studies (in coordination with the CAISO, LS Power and PG&E) to assess the potential adverse impact that these data centers would cause on SVP’s system reliability. Without performing detailed affected system studies, SVP is concerned that reliance on the CAISO’s 2025-2026 TPP reliability study cases are insufficient to ensure the reliability of SVP’s system.

PG&E-Interconnected Load Adversely Affecting SVP’s Reliability and Need for Holistic Approach in Identifying South Bay Reliability Needs 

SVP performed an independent analysis modeling the 920MW of “incremental” data center loads included in PG&E’s Serial and LC24 studies in the CAISO GBA Summer Peak power cases for the year 2035. This analysis indicates that the overloads on both the Newark–NRS 115kV lines and Newark–Zanker–Kifer 115 kV line are significantly worse with the addition of these incremental PG&E data center loads in 2035, as shown in the last column included in Table 2 below. Additionally, SVP notes that these incremental PG&E data center loads results in major P0 and P1 overloads on Los Esteros-Nortech 115kV and a P1 overload on Los Esteros-SSS 230kV would trigger the need for additional network upgrades, as also observed by PG&E, but which were not observed in the CAISO base case (See Table 1) because the CAISO base case did not include these incremental PG&E data center loads. With these overloads, some segments of these lines would require rebuilding, necessitating the need to upgrade the tower structures rather than simply reconductoring the existing lines. The results of the studies appear to indicate that the PG&E-connected data center loads, including these incremental PG&E data center loads, would adversely affect SVP’s system reliability. For instance, the Serial Data Center 1 seeking interconnection to the New 230 kV/34.5 kV substation “Midpoint” on Newark-NRS 230 kV Line, creates reliability issues for SVP’s system as reflected in the major P1 overload on the NEWARK D -NRS 400 115 kV line #1 line with the loss of NEWARK D-DC1 230kV line segment of the NEWARK D to NRS 230 kV line. This begs the question as to whether the currently anticipated point of interconnection, Data Center 1 is appropriate, and whether such an interconnection would require a separate (as yet unanticipated) Newark-NRS 230kV line. 

Table 2: Contingency Overloads on Key SVP Import Facilities in 2035 Without and With PG&E Data Center Loads

SVP is also concerned that these reconductoring projects will not meet their expected in-service dates, which is complicated by the clearance issues required for multiple previously approved reconductoring projects in the South Bay. For example, PG&E’s Series Compensation (SmartValve series reactors at Los Esteros/Nortech) project will have taken four (4) years to complete since its approval. Using this as the example, it seems unrealistic to expect reconductoring the same Los Esteros to Nortech 115kV line (required to interconnect Serial - Data Center 3 at Los Esteros) by 2028. Additionally, CAISO operating procedures, such as OP7340, rely on system adjustments to mitigate several of the overload contingency combinations identified in Table 2, which will be worsened by the anticipated additional PG&E data center loads. CAISO OP7340 will have to be reassessed with PG&E’s anticipated additional data center loads to determine if further mitigations or adjustments are required. The additional reliability issues driven by PG&E-interconnected data center loads, including the anticipated incremental PG&E data center loads, require the CAISO to undertake a comprehensive regional transmission planning approach that reconciles the current CEC-adopted load growth assumed in the CAISO TPP cases and the incremental PG&E data center loads to account for affected systems, including that of SVP.

In summary, SVP requests that the CAISO:

• Ensure that the impact of PG&E’s incremental 920 MW of data center loads on the reliability of the South Bay is fully evaluated in the CAISO 2026-2027 TPP, rather than making any determinations in the 2025-2026 TPP. Delaying the determinations until the CAISO 2026-2027 TPP will allow all of PG&E’s anticipated data center loads to be vetted and assessed under the CEC 2025 Integrated Energy Policy Report (2025 IEPR), which, in turn, will enable the CAISO to perform a more comprehensive regional transmission planning assessment of the reliability needs in the South Bay.
• Include SVP in any meetings held to discuss the need to expand CAISO OP7340, and/or the need for a remedial action scheme, determined necessary to accommodate PG&E’s anticipated data center loads as a result of the CAISO’s 2026-2027 TPP assessment.
• Thoroughly assess the reasonableness of the anticipated online dates of PG&E’s anticipated data center loads, given the scale of additional network upgrades they trigger, and the clearance issues required for multiple previously approved reconductoring projects in the South Bay.
• Ensure that SVP is provided the opportunity to conduct affected system studies in coordination with the CAISO, LS Power, and PG&E, to assess the potential adverse impacts the anticipated PG&E data center loads would cause on the reliability of SVP’s system.

[1] See PG&E’s 2025 Request Window Proposals, September 25, 2025, pp.61-66, and pp. 69-72.

[2] Ibid, p.57.

[3] See PG&E’s September 25^th Presentations: pp.61-66, and pp. 69-72.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

No comments at this time. 

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

 No comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

 No comments at this time.

8. Provide your organization’s comments on the policy assessment update

 No comments at this time.

9. Provide your organization's comments on the economic assessment update

 No comments at this time.

10. Provide your organization's comments on the TEAMs methodology discussion

 No comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

Pursue the “Structure enhancements to the Transmission Access Charge” Initiative

During the September 25^th stakeholder meeting, the CAISO indicated that they no longer plan to pursue the “Structure enhancements to the Transmission Access Charge” initiative. The CAISO indicated the following justification for this decision. “Since 2018, levels of behind-the-meter solar have stabilized, rendering these changes unnecessary and overly complex in today’s market.” Stabilization of behind-the-meter solar generation is an insufficient rationale for failing to implement the TAC structure changes that were fully vetted and recommended for adoption in 2018. The proposed changes address significant cost causation issues with the current volumetric TAC structure. The volumetric-only approach neither reflects cost causation principles nor appropriately accounts for the utilization and benefits of the existing transmission system. These shortcomings were evident when the approach was comprehensively debated in 2018, and there is nothing that has changed in terms of the current market design, including the advent of the extended day-ahead market, to alter that conclusion. In its Draft Final proposal in 2018, the CAISO, after extensive consultation with stakeholders, reached the conclusion that “a hybrid approach utilizing both peak demand and volumetric measurements of customer use to assess TAC charges is preferable because the transmission system provides both energy and capacity functions, and other reliability benefits, and a two-part hybrid approach captures both peak demand and volumetric use and better accounts for these functions.”[1]

The hybrid approach balances recovery of transmission system costs based on both coincident peak usage and volumetric usage. The hybrid approach recognizes that Peak demand and reliability needs are a significant factor triggering investment in the transmission system, while also considering the benefits of policy projects and other energy delivery functions of the transmission system that accrue throughout all hours of the day and year. The existing volumetric-only approach is indifferent to when consumption occurs, which does not reflect cost causation principles. Recovery of transmission costs based on coincident peak demand charges is commonly used in other regions, as was noted during the 2017/2018 stakeholder initiative. For the above-mentioned reasons, CAISO should not dismiss implementation of the hybrid TAC structure previously vetted and recommended for approval. CAISO should hold stakeholder meetings to brief stakeholders on the findings and recommendations resulting from the previous efforts, allowing for stakeholder input, discussion, and consideration of any necessary adjustments to the draft final recommendations that may be warranted.

[1] Transmission Access Charge Structure Enhancements, Draft Final Proposal, September 17, 2018, p.3.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No comments at this time.

1. Provide your organization's comments on the preliminary reliability results for the North area

Sonoma Clean Power(SCP) appreciates CAISO’s commitment to identifying needed reliability upgrades based on the 2024 IEPR Load Forecast, which includes significant growth in load in the North area from data centers.  Although data center load growth is still speculative and it is premature to procure all the generation resources needed to serve projected load growth, it’s critically important CAISO identify and approve potential grid infrastructure needs to accommodate a range of future scenarios.  Without these grid upgrades in place, the CAISO and LSEs will be unable to respond to load growth - which will result in serious reliability and affordability consequences.

While identifying the scope of reliability upgrades, CAISO should consider opportunities to right-size upgrades that can also support policy objectives - including addressing acute Transmission Plan Deliverability (TPD) constraints for resource development in Northern California.  As an example, the CAISO should consider alternatives to reliability upgrades proposed in the Greater Bay Area that may also relieve the Collinsville-Tesla 500 kV, Windmaster-Delta Pumps 230 kV, or other constraints that have zero or minimal TPD.

Although not discussed in the call, SCP would also like to draw attention to the 2040 Winter Peak results posted in August.  In reviewing the results for SCP’s local region of PG&E North of Greater Bay Area, the scope of overloading in the 2040 Winter Peak is staggering, and much larger than what is represented in earlier years or non-winter conditions.  SCP encourages the CAISO to begin working with the CPUC on a holistic approach across the reliability assessment, policy portfolio, interconnection process, and resource adequacy programs to identify low-cost mitigations.  This could include changing the framework of TPD and Full Capacity Deliverability Status (FCDS) that underlies Resource Adequacy (RA), interconnection, and transmission planning but is currently focused on high system need hours in the summer.

2. Provide your organization's comments on the preliminary reliability results for the South area

No comments at this time.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

SCP reiterates its support in prompt 1 for right-sizing reliability projects if they can provide benefits in addressing TPD constraints that are limiting the interconnection of resources to meet state policy needs.  In particular, PG&E’s upgrades near the Newark substation should be reviewed for opportunities to both address reliability needs and address TPD constraints in the Bay Area.  If minor adjustments to scope could unlock additional TPD, those alternatives should be pursued. 

In addition, PG&E should consider the use of advanced conductors in planned and future reconductoring projects. Advanced conductors can significantly increase transmission capacity compared to conventional aluminum-steel conductors Their reduced sag and higher thermal limits improve grid reliability and allow more efficient power delivery under high load or high temperature conditions with lower line losses. Moreover, the lighter composite cores can reduce mechanical stress on towers and minimize wildfire ignition risks. Deploying advanced conductors represents a cost-effective strategy to enhance transmission reliability and deliverability in constrained areas while supporting California’s clean energy and wildfire mitigation goals.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

No comments at this time.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

 No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

No comments at this time.

8. Provide your organization’s comments on the policy assessment update

Transmission Plan Deliverability (TPD) scarcity has brought renewable development in the North of Greater Bay Area (NGBA) to a standstill. This shortage has directly complicated the advancement of long-lead-time, high-value resources such as geothermal and long-duration energy storage, while driving up procurement costs for Northern California Load Serving Entities (LSEs). These outcomes run counter to the state’s climate, reliability, and affordability goals. While the CPUC’s 2025-26 TPP resource portfolio begins to address this by allocating additional capacity to constrained regions, SCP asks CAISO to proactively explore whether synergies between existing policy-driven or reliability-driven projects could unlock deliverability in the NGBA without unnecessary delay or cost escalation.

Northern California continues to face chronic TPD constraints despite proximity to existing 230 kV and 500 kV infrastructure, leaving queued renewable capacity stranded and limiting clean energy procurement options. At the same time, persistent congestion on Path 15 has made it the most economically congested corridor in California, with CAISO’s 2024-25 PCM results showing congestion costs rising from $389 million in 2034 to $522 million in 2039. SCP asks CAISO to evaluate targeted upgrades in these areas that could simultaneously relieve Path 15 congestion and improve deliverability into the Greater Bay Area. Relatively lower-cost reinforcements, such as reconductoring or reactive support additions at Delavan, Collinsville, and Tesla could deliver multi-benefit outcomes: enhancing local deliverability, reducing redispatch and CRR underfunding, and improving north–south transfer efficiency.

SCP also encourages CAISO to revisit the previously approved Collinsville-Humboldt transmission project to assess whether staging or partial repurposing of that project could provide near-term deliverability and congestion-relief benefits for Northern California. The Collinsville-Humboldt project, initially identified to support offshore wind integration, traverses a corridor that could also serve onshore geothermal and storage development if strategically phased or adapted. Evaluating whether interim configurations or shared infrastructure could advance both offshore readiness and inland TPD availability would align with CAISO’s goals of optimizing existing investments and accelerating clean energy integration under constrained budgets.

SCP further recommends that CAISO include a sensitivity on the Delavan and Collinsville constraints in the 2025-26 TPP, quantify marginal congestion reduction from incremental TPD investments in Northern California, and consider assigning economic driven status to such projects. Because the CPUC’s IRP model (RESOLVE) used for the 2025-26 TPP portfolio does not assess Path 15 congestion in portfolio optimization, CAISO’s proactive assessment of these synergies is critical. This type of multi-benefit, congestion-informed planning aligns directly with FERC Order 1920-A’s call for holistic evaluation of deliverability, reliability, and economic benefits. Considering targeted upgrades in the Delavan-Tesla-Collinsville corridor as potential economic or policy-driven projects could yield measurable statewide benefits and ensure that clean, firm, and diverse resources in Northern California can contribute fully to meeting California’s decarbonization and reliability goals.

SCP also asks CAISO to consider utilizing unaccounted Transmission Plan Deliverability (TPD) in the NGBA area for geothermal resource reservation as part of the long-lead-time (LLT) resource framework. Given geothermal’ s proven reliability and year-round capacity value, reserving unallocated TPD for these resources would ensure that high-capacity-factor, clean firm projects can proceed while long-term transmission solutions are developed. Such an approach would advance statewide LLT procurement objectives, help diversify the resource mix in Northern California, and provide critical clean capacity to balance growing solar and storage portfolios.

9. Provide your organization's comments on the economic assessment update

No comments at this time.

10. Provide your organization's comments on the TEAMs methodology discussion

No comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

No comments at this time.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No comments at this time.

1. Provide your organization's comments on the preliminary reliability results for the North area

No comments at this time.

2. Provide your organization's comments on the preliminary reliability results for the South area

No comments at this time.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

No comments at this time.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

No comments at this time.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

No comments at this time.

8. Provide your organization’s comments on the policy assessment update

No comments at this time.

9. Provide your organization's comments on the economic assessment update

No comments at this time.

10. Provide your organization's comments on the TEAMs methodology discussion

No comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

In 2015, CAISO staff contemplated changing the structure of the Transmission Access Charge (TAC) from a purely volumetric method, to one that reflects volume and peak-coincident demand, which the State Water Contractors (SWC) continue to support. Throughout the multi-year process, stakeholders and staff engaged in meaningful discussions to advance this initiative. However, in 2018, that effort was put on hold to develop the Extended Day Ahead Market (EDAM).  

Earlier this year, CDWR submitted a proposal to revisit/restart the TAC initiative as part of the 2025 Policy Initiatives Catalog. In our view, the current CAISO TAC structure does not fully compensate or make whole entities such as the State Water Project (SWP) for their ability to shift load. Ultimately this results in entities like the SWP subsidizing transmission rates for entities unable or unwilling to shift their load and unfairly burdens water ratepayers of the SWP - 27 million Californians and ¾ of all of California’s disadvantaged communities.  

This proposal was folded into the 2025-2026 Transmission Planning process. During the stakeholder meeting on September 25, and in a follow up conversation, CAISO staff indicated they would not be pursuing this initiative for several reasons including the significant changes to the system since 2018, complexity of the initiative, and capacity of staff to work on another complex issue. 

While we are disappointed the TAC structure initiative will not move ahead this year, we respect CAISO staff’s decision and appreciate the engagement and discussion. 

SWC still believes this initiative should be considered in the future for the following reasons:  

• The current volumetric-only approach no longer reflects causation and utilization of the transmission system, resulting in inequitable allocation of costs.  Transmission networks are built to handle coincident peak demand when the grid is strained the most. Having been built in the 1960’s, the SWP isn’t a driver of new transmission and its customers, water ratepayers, should not shoulder nor subsidize costs associated with the buildout of future grid for non-water delivery-related demands. 

• The proposal aligns with CAISO’s own Resource Adequacy (RA) capacity obligations based on contributions to coincident peak demand where load shifting is valued under system and local RA requirements.  

• The proposal is consistent with California’s climate goals as articulated by Governor Newsom[1] and state agencies[2] regarding expansion of load/demand flexibility to maximize the existing transmission network and to incentivize future users to curtail and shift loads outside of peak hours.  

• Other regional transmission organizations and independent system operators factor coincident peak demand in determining and allocating transmission charges including MISO, NY ISO, ISO-NE and PJM.[3]  

We look forward to continuing to work with CAISO staff on initiatives ensuring a reliable and affordable grid for all Californians.   

[1] Governor Gavin Newsom – Building the Electricity Grid of the Future: California’s Clean Energy Transition Plan, May 2023.

[2] CPUC Demand Response Program / CEC Load Flexibility Goal Press Release

[3] Transmission Access Charge Structure Enhancements, Draft Final Proposal, September 17, Pg. 18.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

1. Provide your organization's comments on the preliminary reliability results for the North area

The Bay Area Municipal Transmission group (BAMx)^[1] appreciates the opportunity to comment on the CAISO’s 2025-2026 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 24-25, 2025. 

BAMx Appreciates CAISO’s Consideration of Low-Cost Transmission Alternatives

BAMx applauds the CAISO staff’s efforts in relying on the implementation of Remedial Action Schemes (RAS) and battery storage solutions in its Preliminary Reliability Assessment. The CAISO has effectively and rightfully utilized the existing/planned RAS solutions and also included some new battery storage projects to mitigate the contingency overloads. BAMx understands the CAISO’s recommendation for transmission upgrade alternatives takes into consideration the inadequacy and complexity of RAS in certain planning areas. BAMx encourages the CAISO to transfer such valuable feedback to the California Public Utilities Commission (CPUC) and California Energy Commission (CEC) so that it is incorporated as part of the battery storage mapping exercise in the next Transmission Planning Process (TPP) cycle from the reliability standpoint.

CAISO Needs to Consider Placing Some Previously-Approved Projects On Hold

Integrating North Coast Offshore Wind (OSW) has long been recognized as a challenging undertaking, given the technical, environmental, and scheduling risks involved. Such risks indicated value in staging transmission improvement decisions on higher-cost and technically challenging elements should be made later in the process, until more information becomes available. The current federal moratorium and funding cancellations have significantly affected offshore wind project approvals. This is evident in the withdrawal of certain offshore wind projects, both in the Central and North coasts, from the CAISO generation interconnection queue, and the cancellation of $679 million in offshore wind port infrastructure funding for eleven projects, including Humboldt Bay.[2]

BAMx applauds CAISO’s efforts in including the cost containment mechanisms in the approved project sponsor agreements for the two major OSW-driven transmission projects, i.e., New Humboldt 500 kV Substation, with a 500/115 kV Transformer, and a 500 kV line to Collinsville [HVDC operated as AC] Project and New Humboldt to Fern Road 500 kV Line Project.[3] However, given the uncertainty associated with the development of OSW at least in the near to medium-term, there is a possibility that these major transmission projects would remain underutilized, if not stranded. Using the CAISO 2024-2025 TAC model, BAMx estimates that these transmission projects, with a combined potential capital cost of $4.14 billion, would add nearly $3/MWh to the ever-increasing CAISO high voltage transmission access charge (HV TAC). Therefore, BAMx recommends that the CAISO coordinate with the CPUC and CEC to consider placing these two transmission projects on hold until there is more clarity on the viability of OSW in the North Coast.

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

[2] https://www.transportation.gov/briefing-room/trumps-transportation-secretary-sean-p-duffy-terminates-and-withdraws-679-million

[3] New Humboldt 500 kV Substation, with 500/115kV Transformer, and a 500 kV line to Collinsville [HVDC operated as AC] Project Sponsor Selection Report, June 2, 2025 and New Humboldt to Fern Road 500 kV Line Project Sponsor Selection Report, June 2, 2025

2. Provide your organization's comments on the preliminary reliability results for the South area

BAMx Supports CAISO’s Decision to Review and Investigate Alternatives to the Previously-Approved Serrano–Del Amo–Mesa 500 kV Transmission Reinforcement Project

During the September 24^th meeting, the CAISO informed stakeholders of its decision to exclude the previously approved Serrano–Del Amo–Mesa 500 kV Transmission Reinforcement project in the base cases for the reliability, policy, and economic assessments. BAMx supports this decision as SCE has determined the project’s cost to be several times higher than originally estimated. Both the CAISO[1] and SCE[2] have identified additional reliability issues in the absence of the Serrano–Del Amo–Mesa 500 kV Transmission Reinforcement project. BAMx requests that the CAISO consider a combination of the most cost-effective mitigation measures that would address these reliability issues. If additional policy and economic projects are needed to address the absence of the Serrano–Del Amo–Mesa 500 kV Transmission Reinforcement project, then the CAISO and stakeholders should evaluate whether those projects eliminate the need for some of the reliability-driven transmission projects.   

[1] September 24^th Presentation, pp. 182-83.

[2] September 25^th Presentation, pp. 19-20.

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

Below, we provide comments on the selected PG&E’s 2025 Request Window (RW) proposals.

Oro Loma 70 kV Area Reinforcement Project Rescope: This project entails the following two (2) elements.

1. Reconductor 2.4 miles of the Los Banos - Livingston Jct. – Canal 70 kV Line from Los Banos to Santa Nella Substation.
2. Reconductor 10.8 miles of the Mercy Springs SW. STA. – Canal – Oro Loma 70 kV Line from Mercy Springs SW. STA. to Canal Substation.

#1 above is consistent with the CAISO’s preliminary reliability findings.[1] However, #2 is not, as neither CAISO nor PG&E has shown a demonstrated need for the #2 reconductor. Therefore, we request that the CAISO verify PG&E’s assessment before approving the #2 portion of the Oro Loma 70 kV Area Reinforcement Project Rescope.

Eastshore and Newark Area Import Capability Reinforcement Conceptual Project: This project entails reconductoring of multiple 230 kV lines in East Bay. Has PG&E performed any preliminary engineering and environmental assessment to explore the feasibility of this project? BAMx notes that the scope and cost of reconductoring more than 100 circuit miles of 230 kV lines would be extensive; and some segments of these lines would require rebuilding, necessitating the need to upgrade the tower structures rather than simply reconductoring the existing lines. The reliability issues driving the need for PG&E’s proposed projects require a comprehensive regional planning approach. Such a regional planning effort may require the CAISO to consider approving a transmission project that enhances imports into the Greater Bay Area, rather than pursuing piecemeal reconductoring multiple 230 kV lines with high-ampacity conductors, which may involve tower replacements, construction and clearing issues. This is especially relevant as CAISO is reviewing the validity of load growth in this area.

South Oakland Reinforcement Phase 2 Conceptual Project: This project entails reconductoring of multiple 115 kV lines in the East Bay. Has PG&E performed any preliminary engineering and environmental assessment to explore the feasibility of this project? It may make sense for the CAISO to consider approving a transmission project that improves imports into the Greater Bay Area rather than pursuing piecemeal reconductoring several 115 kV lines with high-ampacity conductors, which may involve tower replacements, construction and clearing issues, especially since the CAISO is reviewing the validity of load growth in this area. One of those 115 kV lines is the Grant-Eastshore #1 115 kV. This line was also found to be overloaded in the 2024-2025 Transmission Plan. However, the CAISO found that "these issues are less critical and can be resolved through operational solutions or minor projects, such as installing additional breakers and series reactors."^[2] It is unclear to BAMx why this solution would not be adequate instead of reconductoring the Grant-Eastshore #1 115 kV line.

Metcalf- Monta Vista 230 kV Transmission Corridor Reinforcement Project: This project entails reconductoring of four (4) 230 kV lines between Metcalf and Monta Vista. Has PG&E performed any preliminary engineering and environmental assessment to explore the feasibility of this project? Just like in the case of Eastshore and Newark Area, and South Oakland areas, it may make sense for the CAISO to consider approving a transmission project that improves the imports into the Greater Bay Area rather than pursuing piecemeal reconductoring several 230 kV lines with high ampacity conductors which may constitute tower replacements, construction and clearing issues, especially since the CAISO is reviewing the validity of the load growth in this area.

Metcalf 230/115 kV Banks Upgrade Project: This project entails replacing the existing 230/115 kV banks #1, #2, #3, and #4 to achieve at least 560 MVA summer normal rating and 616 MVA summer emergency rating. BAMx requests the details on the existing transformers regarding their age and condition to see whether they can be relocated and/or repurposed. The CAISO may need to explore certain operating solutions and system adjustments, such as dialing additional flows on the Metcalf-San Jose B HVDC line to reduce flows of the 115 kV lines that are driving the overloads on the Metcalf 230/115 kV banks. Other alternatives, such as converting some of the 115 kV lines north of Metcalf (Metcalf-El Patio) to 230 kV, should be explored and compared with the proposed projects of replacing all the existing transformers at Metcalf and reconductoring several 115 kV lines for their cost-effectiveness.

Furthermore, based on the contingency loadings reported by PG&E, it appears that transformers #2 and #3 are in need of replacement sooner than #1 and #4. Therefore, if the CAISO decides to consider approving the replacement of these transformers, BAMx recommends that the CAISO only approve replacing the existing 230/115 kV banks #2 and #3 at this time, and to approve the replacement of the remaining two transformers only if needed in the future, depending on load growth.

[1] See CAISO Greater Fresno Area Preliminary Reliability Assessment Results, 2025-2026 Transmission Planning Process Stakeholder Meeting, September 24-25, 2025, pp.102-104.

[2] Board Approved 2024-2025 Transmission Plan, May 30, 2025, p.68.

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

SCE’s RW projects include the Pardee-Santa Clara 230 kV Line Upgrade (Advanced Reconductoring) and Santa Clara-Vincent 230 kV Line Upgrade (Advanced Reconductoring). In last year’s RW, the costs for the same projects were estimated at $71M - $85M, but they seem to have increased to $141M - $215M based upon SCE’s latest RW applications. In the 2024-2025 Transmission Plan, the CAISO approved Julian Hinds-Mirage 230 kV Advanced Reconductor Project. The estimated cost for this project was $76M, which could now likely be in the range of $141M - $215M. Given the significant cost increase and the fact that there is no possibility of the cost of this project being shared by the Department of Energy’s Charge 2T program grant any longer, BAMx recommends that the CAISO revisit the need and scope of the Julian Hinds-Mirage 230 kV Advanced Reconductor Project.

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

No comments at this time.

7. Provide your organization’s comments on the high voltage TAC update

Replacing Wheeling Charges with EDAM Access Charges

BAMx appreciates the continued work of the CAISO in keeping the stakeholders updated about the likely impact of its decision to approve transmission projects affecting the High Voltage (HV) Transmission Access Charge (TAC). BAMx appreciates the opportunity to comment on the CAISO's 2024-2025 HV TAC Estimating Model ("TAC Model" hereafter) that was posted on the CAISO website on September 12, 2025.

Capital Project Cost Comments

BAMx has the following questions and comments on some of the capital transmission projects included in the TAC Model. We request the CAISO to address them in the next revision of the TAC Model. All the recommended corrections below are expected to increase the projected HV TAC further.

• Gates 230/70 kV Transformer Addition: CAISO approved the Gates 230/70 kV Transformer Addition project costing $72M in the 2023-2024 TPP.[1] However, this project appears to be missing from the CAISO 2023-2024 Transmission Plan High Voltage Transmission Access Charge Capital Costs. We estimate approximately 50% of the Gates 230/70 kV Transformer Addition project to be part of the HV Transmission Revenue Requirement (TRR). BAMx previously raised this concern last year as part of the comments on the 2023-2024 TAC Model, however, it appears that our comments remained unaddressed.
• Riverside Transmission Reliability Project (RTRP): We noticed that the latest TAC model continues to exclude the capital expenditure associated with Riverside Transmission Reliability Project (formerly Jurupa 230 kV Sub). According to SCE's AB 970 quarterly report (Q1 2021), this project was approved by the CAISO in 2007 with a current planned in-service date of 10/15/2026. A Certificate of Public Convenience and Necessity (CPCN) for this project was granted on 03/12/2020 and indicates that its capital cost is approximately $450M. It appears that the more recent cost estimates are higher at $730M, with the City of Riverside’s portion limited to approximately $208.8M.[2] Please explain why the SCE portion of the capital expenditures associated with the RTRP was excluded from the TAC Model.
• Alberhill Transmission Project: The TAC model continues to assume the old capital cost of $212.93M. This amount needs to be updated to ~$450M to reflect SCE's updated cost estimate included in the Alberhill CPUC CPCN proceeding (A.09-09-022).  Please explain why the capital expenditure associated with the Alberhill in the TAC Model is so low.
• GLW/VEA area upgrades: Based on the CAISO's 2022-2023 Transmission Plan, the estimated cost of the increased scope is $228M for a total cost of the recommended re-scoped project of $506M with an estimated in-service date of 2027.[3] The TAC model includes a cost of $656M. Please identify the source of this higher capital cost estimate.

TAC Forecast is Highly Sensitive to Some Key Assumptions

It is important to note that several factors have contributed to the HV TAC projection tapering off in the later years. These include:

1. An increase in the CAISO-side gross load growth rate from 1.27% in the 2023-2024 TAC Model to 2.18%, which is the denominator in the HV TAC calculations.
2. A reduction in the capital costs associated with some of the projects in the 2023-2024 TAC Model by almost $2 billion, as summarized in the Table below. These capital costs are used to develop the annual TRR, which forms the numerator of the projected HV TAC.

3. The projected HV TAC in the 2024-2025 TAC model does not take into consideration future transmission projects that would be approved by the CAISO in the subsequent transmission planning cycles; and
4. The projected HV TAC in the 2024-2025 TAC model does not include any utility “self-approved” projects, which are not subject to review by the CAISO or any regulatory body but have historically had a significant impact on TAC.

[1] CAISO 2023-2024 Transmission Plan, p.5.

[2] https://www.raincrossgazette.com/city-council-approves-controversial-riverside-transmission-reliability-project/

[3] CAISO 2022-2023 Transmission Plan, May 10, 2023, p.79.

8. Provide your organization’s comments on the policy assessment update

CAISO Needs to Exercise Caution in Modeling the Impact of Resources Unaccounted for in TPD Allocation

During the September 25^th presentation, the CAISO identified nearly 7,000 MW and 5,000 MW in 2035 and 2040, respectively, of FCDS resources in key MIC regions that were previously not accounted for in the portfolios. BAMx understands that accounting for these new resources would mean identifying additional constraints that were not considered in the mapping originally provided by CPUC in D.25-02-026. BAMx encourages the CAISO to adjust or reshuffle the busbar mapping of the portfolio to minimize triggering any unnecessary and excessive transmission upgrades that were not envisioned by the CPUC in its initial portfolios.

9. Provide your organization's comments on the economic assessment update

BAMx appreciates the CAISO’s presentation of how the CAISO is exploring the feasibility and alternatives of implementing the Extended Day Ahead Market (EDAM) congestion revenue allocation in TEAM.[1] Currently, the CAISO models wheeling access charges between any two balancing authority areas (BAA) within WECC. BAMx notes that with the upcoming implementation of EDAM, the CAISO will need to replace these wheeling charges with EDAM access charges. Also, the CAISO needs to incorporate this new logic with a phased onboarding of new BAAs joining the EDAM.

[1] CAISO’s September 25^th Presentation, pp. 52-58.

10. Provide your organization's comments on the TEAMs methodology discussion

No comments at this time.

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

Pursue the “Structure enhancements to the Transmission Access Charge” Initiative

During the September 25^th stakeholder meeting, the CAISO indicated that they no longer plan to pursue the “Structure enhancements to the Transmission Access Charge” initiative. The CAISO indicated the following justification for this decision. “Since 2018, levels of behind-the-meter solar have stabilized, rendering these changes unnecessary and overly complex in today’s market.” Stabilization of behind-the-meter solar generation is an insufficient rationale for failing to implement the TAC structure changes that were fully vetted and recommended for adoption in 2018. The proposed changes address significant cost causation issues with the current volumetric TAC structure. The volumetric-only approach does not reflect the cost causation, utilization, and benefits of the existing transmission system. It was not the case when this initiative was comprehensively debated in 2018, and there is nothing that has changed in terms of the current market design, including the advent of the extended day-ahead market, that changes this assessment. In its Draft Final proposal in 2018, the CAISO, after extensive consultation with stakeholders, reached the conclusion that “a hybrid approach utilizing both peak demand and volumetric measurements of customer use to assess TAC charges is preferable because the transmission system provides both energy and capacity functions, and other reliability benefits, and a two-part hybrid approach captures both peak demand and volumetric use and better accounts for these functions.”[1]

The hybrid approach balances recovery of transmission system costs based on both coincident peak usage and volumetric usage. This recognizes that Peak demand and reliability needs are a significant factor triggering investment in the transmission system, while also considering the benefits of policy projects and other energy delivery functions of the transmission system that accrue throughout all hours of the day and year. The existing volumetric-only approach is indifferent to when consumption occurs, which does not reflect cost causation. Recovery of transmission costs based on coincident peak demand charges is commonly used in other regions, as was noted during the 2017/2018 stakeholder initiative. For the above-mentioned reasons, CAISO should not dismiss implementation of the hybrid TAC structure previously vetted and recommended for approval. CAISO should hold stakeholder meetings to brief stakeholders on the findings and recommendations resulting from the previous efforts, allowing for stakeholder input, discussion, and consideration of any necessary adjustments to the draft final recommendations that may be warranted.

[1] Transmission Access Charge Structure Enhancements, Draft Final Proposal, September 17, 2018, p.3.

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

No comments at this time.

1. Provide your organization's comments on the preliminary reliability results for the North area

2. Provide your organization's comments on the preliminary reliability results for the South area

3. Provide your organization's comments on PG&E's proposed reliability alternatives presentation

4. Provide your organization's comments on SCE proposed reliability alternatives presentation

5. Provide your organization's comments on GLW proposed reliability alternatives presentation

6. Provide your organization's comments on SDG&E proposed reliability alternatives presentation

7. Provide your organization’s comments on the high voltage TAC update

8. Provide your organization’s comments on the policy assessment update

II. TRANSCANYON’S COMMENTS ON THE CAISO DRAFT 2025-2026 TRANSMISSION PLAN

TransCanyon recognizes and appreciates CAISO’s detailed analysis of CAISO’s transmission system for the next ten years recognizing significant challenges of uncertainty in Federal energy policy, increased data center load growth, climate change impacts, extreme events and changing resource mixes required to achieve the policy goals that California is marching toward. The recognition that significant improvements are necessary to meet the reliability, policy and economic goals of the state is very timely. TransCanyon supports CAISO’s continuing examination of potential transmission projects to access the out-of-state wind included in the CPUC resource portfolios and offers any support that it can provide in the stakeholder engagement process. TransCanyon’s Cross-Tie Project, further described below, could provide CAISO up to 1500MW of bi-directional transmission capacity from resources in Utah and Wyoming when combined with other transmission in PacifiCorp and NV Energy systems. TransCanyon is not opposed to potential partial or full TAC recovery of the capital cost of Cross- Tie if that, combined with access across other lines, would be of benefit to CAISO load-serving entities. TransCanyon already has an existing FERC approved formula rate for projects within CAISO, which was obtained when TransCanyon submitted its proposal to develop the Delany to Colorado River project for CAISO.

9. Provide your organization's comments on the economic assessment update

10. Provide your organization's comments on the TEAMs methodology discussion

11. Provide your organization's comments on the CAISO Policy Initiatives Presentation

12. Provide any additional comments your organization has on the September 24-25 Transmission Planning Process Meeting

I. TRANSCANYON, LLC

TransCanyon, LLC, a joint venture between subsidiaries of Berkshire Hathaway Energy and Pinnacle West Capital Corporation, is an independent developer of electric transmission in the western United States. TransCanyon’s mission is to develop, build, own and operate electric transmission infrastructure for the benefit of all utility customers. TransCanyon is led, managed, and operated by professionals with significant experience in developing, building, owning and operating transmission infrastructure in the western United States.

II. TRANSCANYON’S COMMENTS ON THE CAISO DRAFT 2025-2026 TRANSMISSION PLAN

TransCanyon recognizes and appreciates CAISO’s detailed analysis of CAISO’s transmission system for the next ten years recognizing significant challenges of uncertainty in Federal energy policy, increased data center load growth, climate change impacts, extreme events and changing resource mixes required to achieve the policy goals that California is marching toward. The recognition that significant improvements are necessary to meet the reliability, policy and economic goals of the state is very timely. TransCanyon supports CAISO’s continuing examination of potential transmission projects to access the out-of-state wind included in the CPUC resource portfolios and offers any support that it can provide in the stakeholder engagement process. TransCanyon’s Cross-Tie Project, further described below, could provide CAISO up to 1500MW of bi-directional transmission capacity from resources in Utah and Wyoming when combined with other transmission in PacifiCorp and NV Energy systems. TransCanyon is not opposed to potential partial or full TAC recovery of the capital cost of Cross- Tie if that, combined with access across other lines, would be of benefit to CAISO load-serving entities. TransCanyon already has an existing FERC approved formula rate for projects within CAISO, which was obtained when TransCanyon submitted its proposal to develop the Delany to Colorado River project for CAISO.

III. TRANSCANYON’S CROSS-TIE PROJECT

The Cross-Tie Transmission Line Project (CTP) is a proposed 213-mile, 1500 MW, single circuit

500kV HVAC transmission project that will be constructed between central Utah and east-central Nevada to strengthen the electrical interconnection between the PacifiCorp and the NV Energy transmission systems while supporting interregional power transfers by linking the Rocky Mountain area to the Great Basin area. The project facilitates CAISO meeting California’s RPS and GHG policy objectives by increasing transmission capability for CAISO to access resources in Utah and Wyoming, and for CAISO to export excess solar energy to Utah and Wyoming. The CTP will connect PacifiCorp’s Clover 500kV substation in central Utah with NV Energy’s Robinson Summit 500kV substation in east-central Nevada, which will effectively link the Gateway South Project (PacifiCorp) with the Desert Southwest by utilizing the existing One Nevada Line (NV Energy/Great Basin Transmission, LLC), the planned Greenlink Projects (NV Energy) and the Harry Allen - Eldorado 500kV line (CAISO). Robinson Summit, which is the western terminus of CTP, will become a CAISO scheduling point when the SWIP-North Project is placed in service. TransCanyon has been developing CTP since 2016 and plans to start construction in 2026 with a proposed in-service date in the fourth quarter of 2030.

CTP is in late-stage development, having achieved the following developmental milestones:

Permitting: The NEPA process for the CTP is nearing completion. TransCanyon obtained a Final Environmental Impact Statement on September 20, 2024 and anticipates a Record of Decision from the BLM within the next month. BLM and United States Forest Service Rights-of-Way should be obtained by the end of 2025. State permitting is not anticipated to be an issue; right-of-way procurement is not expected to be difficult; and most of the route is on Federal land.

WECC Rating Process: CTP’s Project Review Group approved the Phase 2B Report on December 1, 2022, and the Cross-Tie Project achieved Phase 3 status on January 17, 2023, with an accepted bidirectional rating of 1500 MW.

Engineering and Design: CTP achieved 60% design on November 8, 2024, and is scheduled to achieve 90% design by the end of 2025.

Interconnection Process: System Impact Studies and Facility Studies have been completed for the interconnection of the CTP at Clover 500kV with PacifiCorp and at Robinson Summit 500kV with NV Energy. Requests for draft interconnection agreements have been made to PacifiCorp and NV Energy and it is anticipated that Interconnection Agreements for both interconnections will be executed by the end of 2025. The 2030 in-service date reflects the long-lead time equipment necessary for network upgrades at the NV Energy Harry Allen Substation.

Operation and Maintenance: It is anticipated that the CTP will be within the PacifiCorp East Balancing Authority Area and PacifiCorp is expected to perform the Operation and Maintenance for the CTP through a services agreement that is currently being negotiated.

Subscription of CTP Transmission Capacity: As CTP adds significant capacity increase between the PacifiCorp and NV Energy systems, these load serving entities are potential subscribers. Capacity could also be available to CAISO as discussed above. TransCanyon has also been in conversations with several energy developers, power marketers, and data centers who have shown interest in subscribing for CTP transmission capacity.

V. CONCLUSION

TransCanyon appreciates the opportunity to participate in the CAISO 2025-2026

Transmission Planning Process and applauds CAISO’s efforts to ensure transmission

development in the CAISO footprint supports a reliable and efficient system to enable

California to meet its future reliability, policy and economic goals. TransCanyon looks forward

to working with CAISO to further examine options for transmission projects, including CTP, supporting the integration of Out-of-State wind resources in the planning resource portfolios.