Comments on Meeting on 9/23 and 9/24

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 projects presentation

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

ACP-California’s comments on the 2026-27 TPP meetings focus on the preliminary findings for the Energy-Only Resources Assessment that CAISO presented on September 23^rd and ask CAISO to evaluate additional cases to better reflect the range of operating conditions under which Energy Only (EO) resources can contribute to charging sufficiency for energy storage.

First, ACP-California greatly appreciates CAISO’s efforts to study how EO resources might be able to be used for charging sufficiency in the CPUC’s Slice of Day (SoD) Resource Adequacy (RA) program. EO resources continue to make up a sizable portion of the TPP portfolios that the CAISO receives from the CPUC, including over 15 GW of mapped generic, new EO resources in 2036 in the 2026-2027 TPP base case. However, there is currently severely limited commercial interest in EO projects because they cannot contribute to LSE’s RA obligations and are prohibited from counting towards the charging sufficiency requirements for energy storage under CPUC’s RA program.  With minimal exceptions for co-located resources, generating resources must have Full Capacity Deliverability Status (FCDS) in order to count towards charging sufficiency. As ACP-California has explained in the CPUC RA Docket (Rulemaking 25-10-003), there is an urgent need to expand Energy Only Energy Sufficiency (EO-ES) eligibility given near-term reliability needs on the CAISO grid, the lack of deliverability throughout the CAISO system, and the schedule for developer interconnection decisions. Clean generating resources may be able to come online faster – and provide energy value to the system – as EO resources. In Cluster 15 there are currently 12 GW of active EO requests. Having these resources available – compared to not having them (if they simply withdraw from the queue) – can clearly provide some value to the grid by providing for charging of energy storage devices in some hours. While it may be unreasonable to assume EO charging can occur on-peak when storage is typically discharging, or at high system needs hours, it is also reasonable to assume that some charging can and will occur in off-peak hours.

Thus, it is critical that the CAISO’s study of the ability for EO resources to charge energy storage looks beyond a single “worst case” scenario. Focus on the downside case may seem reasonable from an engineering judgment perspective, but will not reflect realistic market and dispatch patterns. This will discourage commercial interest in EO resources and likely result in these resources withdrawing from the queue, rather than proceeding as EO, an outcome that ultimately harms reliability.

The CAISO’s study examines potential for EO deliverability to storage resources during a single hour (11am) and a single case that is disconnected from the way the system of EO resources, other generating resources, and storage charging are likely to operate.  The results of such as study will show minimal/no ability for EO resources to charge batteries. We therefore urge CAISO to perform additional sensitivity analysis, utilizing various base cases of different operating conditions, to reflect EO resources’ range if ability to charge energy storage devices across different operating conditions. A range of operating cases, with sensitivities on the underlying dispatch of resources within those cases, will help the CPUC and stakeholders understand how EO resources might contribute to charging sufficiency in a variety of different hours and system conditions.

ACP-California understands the reasons that CAISO developed the case for the Energy-Only Resources Assessment in the way it did. The case generally reflects an hour where solar resources have high output, and other resources are also dispatched to high levels, while the storage devices on the system are set to charging mode. While ACP-California understands CAISO reasoning for developing the dispatch assumptions in this manner, we caution that the current case effectively studies a “worst case” hour and is unlikely to show that EO resources can contribute significantly to storage charging. The study case is such that thermal resources are dispatched nearly to their max, along with significant solar generation on the system. However, it is highly unlikely that thermal resources would be dispatching at these levels in the hour this case is studying during actual system operations, given their marginal cost compared to energy prices in that hour. And, as a result of the unrealistic dispatch assumptions used in CAISO’s current, this single hour likely represents a worst case for use of EO resources for charging and does not represent how EO resources may actually contribute to charging across the duration of a typical day. In actual operations, thermal resources would not be dispatched at these levels and would either be not operating or would be operating at PMin. It is crucial to study more realistic dispatch assumptions across multiple operating cases to determine how EO resources might be able to contribute to charging sufficiency across the 12 months and 24-hourly slices that are part of SoD.

We therefore urge CAISO to perform additional sensitivity analyses to help develop a range for how EO resources can support storage charging during different hours (e.g., HE 17, HE 8 and in Spring and Winter conditions). While CAISO’s current case may reflect a low-end value for how EO resources can contribute to EO-ES, ACP-California recommends running two additional sensitivities to better reflect a mid-range and a higher-range of how EO can contribute to charging sufficiency. To develop a higher-end estimate for how EO might contribute to charging sufficiency, ACP-California recommends CAISO use the same case it is currently using for this effort (B5-36SumOP) but with thermal resources at their minimum levels of generation (PMin or simply not running). Additionally, a mid-case which is informed by historical thermal operations curing similar conditions around 11am. CAISO could utilize the historical dispatch profile of the thermal fleet to inform a percentage of the resources’ Pmax to use to dispatch the thermal fleet to in the 36SumOP case. This will better reflect likely actual operations during this hour and provide a more realistic indication of how EO solar resources can contribute to charging sufficiency and may provide more of a “mid-range” for how EO resources can contribute to charging sufficiency. These additional sensitivities would provide a low, mid, and high range estimate which will be more useful for the CPUC to have on hand as they consider whether EO resources should be qualified to support charging sufficiency in some capacity. We urge CAISO to perform this additional work, as having a range of cases and sensitivities will help provide a better picture of the potential value of EO resources for charging sufficiency and help improve the record, whereas having a single “worst case” scenario is will not reflect the value that EO resources may be able to offer in different system conditions.

While we recognize a large number of studies may not be feasible for CAISO to perform ahead of the November meetings, we are deeply concerned that the current single hour likely represents the worst-case for EO charging. If some additional sensitivities aren’t studied, CAISO (and the CPUC) will end up relying on this worst-case scenario (one that represents the hour in which EO resources are likely least able to contribute to charging sufficiency) to make decisions about EO’s ability to contribute to charging sufficiency across every SoD hour in every month.

Ultimately, the grid will require additional energy generating resources and it is necessary for CAISO to study many hours to understand how EO resources might operate across SoD. As noted above,

IRP modeling approaches recognize energy sufficiency contributions of EO resources (as well as off-peak, non-RA imports) and credit storage for the benefits of EO solar. It is crucial for the CPUC and stakeholders to have a range of cases to assess EO’s contribution, and not simply the most conservative case that undervalues the potential for EO to charge energy storage resources. We look forward to working with CAISO to continue to improve the study cases and analysis for EO-ES.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 projects presentation

AltaGas’ comments focus on the portion of PG&E’s presentation related to Large Loads (LLs).  AltaGas is concerned that the LL interconnection process is being conducted in a piecemeal, business-as-usual fashion when a more proactive approach would yield far greater benefits. 

PG&E clarified during the meeting that it just studies the applications as they come in.  PG&E does not proactively advise load developers about more favorable sites, including those where they might benefit the grid (e.g., by relieving generation/storage deliverability constraints) or interconnect more quickly (because they don’t trigger upgrades, or where they could share interconnection facilities with generators).  We assume that the other PTOs, to the extent that they have received such LL interconnection requests, are addressing them in essentially the same reactive manner.

Encouraging LLs to site in areas where they trigger few or no upgrades, and benefit the grid as well, would benefit all parties.  Providing information about favorable interconnection locations to LL developers could significantly reduce both LL developer and ratepayer costs, enable faster and more economic LL connections, mitigate cost-shifting concerns, and relieve generation/storage deliverability constraints.    Similar information for generation/storage projects (e.g., locations where TP Deliverability is likely to be available) has proven extremely valuable to developers of those projects, and it is likely that LL developers would also value such information.

PG&E’s presentation indicated that it alone has received nearly 3,400MW of LL interconnection requests that have progressed to the study stage, and expectations seem to be that this number will grow in the future.  This is a historic opportunity for the CAISO and PTOs to work together to provide information to LL developers about promising sites that can help the grid and ratepayers, instead of passively analyzing interconnection requests as they come in without this beneficial information.

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

No comments at this time.

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

No comments at this time,

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

No comments at this time.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

No comments at this time.

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

COMMENTS OF B3K PROSPERITY

ON THE PRELIMINARY RELIABILITY STUDY RESULTS FOR THE PG&E KERN AND TEHACHAPI & BIG CREEK CORRIDOR STUDY AREAS

CALIFORNIA INDEPENDENT SYSTEM OPERATOR — 2026-2027 TRANSMISSION PLANNING PROCESS

Submitted via: Better Bakersfield and Boundless Kern (“B3K”), through the Advanced Energy Leadership Advisory Council (AELAC)

Submitted to: California Independent System Operator Corporation Infrastructure Development; Regional Transmission

Re: Comments on the preliminary reliability study results posted August 14, 2026 (document dated August 15, 2026), and on the material presented at Stakeholder Meeting #2, September 23-24, 2026, as they concern the PG&E Kern and Tehachapi & Big Creek Corridor study areas.

Better Bakersfield and Boundless Kern (B3K), through its Advanced Energy Leadership Advisory Council (AELAC), submits these comments pursuant to the comment opportunity established in the 2026-2027 Transmission Planning Process (“TPP”) schedule for material presented at Stakeholder Meeting #2. These comments are directed to the preliminary reliability study results for the PG&E Kern study area and, secondarily, to the Tehachapi & Big Creek Corridor study area. They are based on publicly posted CAISO, CPUC, and CEC material, which is identified in the source list at the end of this letter.

I. SUMMARY OF COMMENTS

The preliminary results identify significant modeled thermal overloads, voltage deficiencies, and stability concerns within the Kern-area transmission system under multiple planning scenarios and contingencies, with several conditions becoming more severe as modeled demand increases. In addition, Kern County stakeholders are aware of significant prospective load growth associated with industrial, commercial, and economic development projects that may not yet be fully reflected in utility energization requests or the planning baseline.

The severity of a substantial number of the identified violations increases under the 2031 Summer Peak High CEC Forecast sensitivity relative to the baseline case. B3K/AELAC views these results as warranting particular attention to Kern County load-serving capability. The resource portfolio for this cycle holds the PG&E Kern study area flat between 2036 and 2041, so the questions Kern County brings to this cycle are principally questions about serving load. B3K/AELAC respectfully request the following:

1.   That CAISO select and identify mitigations, in the final reliability study results due October 30, 2026, for the Kern-area findings presently carried as “Under Review,” and in particular for Midway-Gates 230 kV, Kern-Magunden 70 kV, and San Bernard-Weedpatch 70 kV.

2.   That CAISO confirm whether the scope of the Midway 115 kV Bus Upgrade (2526-R-08), as approved in the 2025-2026 Transmission Plan, resolves the additional Kern-area findings now assigned to it in this cycle, including under the high demand forecast; and that CAISO confirm the scope, sizing basis, and anticipated in-service dates of the Wheeler Ridge Junction and Tejon Area Reinforcement projects.

3.   That the detailed engineering analysis of Path 15 and Path 26, deferred from the 2025-2026 cycle into this cycle, be performed and reported in this cycle; that its scope include the Midway 115 kV and 230 kV terminal configuration; and that CAISO state how it will treat the two Kern- and Path 15-related economic planning study requests identified in the Study Plan.

4.   That CAISO treats the 2031 Summer Peak High CEC Forecast case as a planning case for the Kern area instead of as a sensitivity, given the number of Kern findings that bind more severely in that case.

5.   That CAISO and the affected Participating Transmission Owners confirm which Kern County load additions are reflected in the local-area reliability baseline through the Energy Commission’s “Known Loads” modifier and identify what documentation would be required for additional loads to be reflected in the next baseline.

6.   That CAISO indicates whether the Cal Flat-Gates 230 kV constraint receives any assessment in this cycle, in light of the resource remapping between the PG&E Kern and PG&E Fresno study areas described in the CPUC’s final busbar mapping report for this cycle.

II. KERN COUNTY IS DIVIDED BETWEEN TWO STUDY AREAS

Kern County is served by two Participating Transmission Owners and appears in the TPP as two of the eighteen study areas identified in Section 2.3 of the Study Plan. Western and northern Kern County, including Bakersfield, Midway, and Buttonwillow, is within the PG&E Kern local study area. Eastern and southern Kern County, including Tehachapi, Mojave, Rosamond, and the associated wind fleet, is assessed within the SCE Tehachapi and Big Creek Corridor local study area.

B3K/AELAC requests that CAISO characterize Kern County load-serving capability across both study areas rather than solely within each area in isolation.

III. COMMENTS ON THE PRELIMINARY RELIABILITY RESULTS

A. The Kern-area findings are demand-driven.

CAISO studied the PG&E Kern area across six baseline scenarios (2028, 2031, and 2036 summer peak; 2028 and 2031 spring off-peak; and 2036 summer off-peak) and three sensitivities, including a 2031 Summer Peak High CEC Forecast case representing higher demand growth. The results identify thermal overloads on nineteen 70 kV, 115 kV, and 230 kV facilities, low-voltage conditions at eighteen substation buses across sixteen substations, and potential WECC/NERC transient stability criteria violations under six separate contingencies.

The Midway-Gates 230 kV line loads to 125 percent in 2028 and 131 percent in 2031 under baseline demand, and to 141 percent under the 2031 high demand forecast. The same pattern appears across the following systems:

Source: PG&E Kern preliminary study results. Worst-case baseline is the highest loading across the six baseline scenarios.

B3K/AELAC do not dispute that worst-case and High CEC values are often driven by different binding contingencies, and that a lower High CEC figure for a given facility therefore does not indicate that higher demand improves that facility’s performance. For the facilities listed above, the high demand forecast produces the more severe result, and those facilities are concentrated on the corridors that would serve new load in the Bakersfield and Midway areas.

B. Severe findings carry no selected mitigation.

The severe thermal findings in the Kern area, and the most demand-sensitive one, are recorded as “Under Review”:

We note that the San Bernard-Weedpatch 70 kV also carries a 325 percent finding under a P7 double-circuit tower line outage that is assigned to the Wheeler Ridge Junction project; the 334 percent has no noted mitigation. Then, on the Kern-Magunden 70 kV contingency that produces the 452 percent result in 2028, the 2031 Summer Peak case is recorded as non-converged. The Kern County Parties request that CAISO report the 2031 result for that contingency in the final study results, since a non-converged case for this facility leaves the 2031 condition unquantified.

More generally, B3K/AELAC request that the Kern-area findings presently carried as “Under Review” receive a stated disposition in the final reliability study results due October 30, 2026, rather than being carried forward to a subsequent planning cycle. Where CAISO concludes that no mitigation is warranted, B3K/AELAC request that the basis for that conclusion be stated, including the demand level at which the finding would become actionable.

C. Low-voltage findings.

Eighteen substation buses at sixteen substations in the Kern area fall below the 0.9 per-unit planning standard under at least one studied condition. The lowest recorded values include Tejon 70 kV and San Bernard 70 kV at 0.58 per unit; Kern Ridge 115 kV, Temblor 115 kV, and Wheeler Ridge 115 kV and 70 kV at 0.59; Magunden 70 kV at 0.61; and Arvin 70 kV at 0.63. The complete list is at Attachment B.

Several of these findings are dispositioned “sensitivity only” or “continue to monitor.” B3K/AELAC request that CAISO identify, for each such finding, the load level or system condition at which the finding would move from monitoring into mitigation.

D. Transient stability at Midway.

The transient stability assessment for the Kern area was performed across a reduced scenario set of four baseline scenarios (2028 spring off-peak, 2031 and 2036 summer peak, and 2036 summer off-peak) and two sensitivities. Within that set, the preliminary results identify potential WECC/NERC criteria violations for an internal fault at bus-tie breaker 302 on Midway 115 kV Bus 1D; for an internal fault at bus-tie breaker 392 on Midway 115 kV Bus E; and for a fault on Midway-Wheeler Ridge 230 kV circuits 1 and 2, the last of which produces violations in all four baseline scenarios. Each is recorded as under review. Violations are also identified for non-redundant relay and battery failures at Westpark 115 kV, Corcoran 115 kV, and Kern Oil substation 115 kV, of which the first two have identified mitigations consisting of a redundant relay and a redundant battery supply respectively.

B3K/AELAC notes that the Midway-Wheeler Ridge 230 kV finding does not appear under the high demand sensitivity and advance it as a location-driven finding. Given that CAISO has stated that the need for upgrades on Path 15 and Path 26 has been established, and given that the detailed engineering for those upgrades was deferred into the present cycle, B3K/AELAC request that the Midway stability findings be resolved in this cycle and that their resolution be coordinated with the Path 15/26 engineering analysis.

E. Findings which do not support Kern County’s position.

In the interest of an accurate record, B3K/AELAC note two findings that do not support the position advanced in this letter. The preliminary results state that “no single contingency resulted in total load drop of more than 250 MW” and that there is “no single source substation with more than 100 MW” in the Kern area. Read together with the thermal and voltage results, the Kern system appears to be stressed at the facility level. B3K/AELAC do not characterize the Kern area as a bulk-system reliability emergency. The concern raised is the capability to reliably accommodate anticipated incremental load growth.

IV. LOAD NOT PRESENTLY REFLECTED IN THE BASELINE

As CAISO states on its Large Loads program page, “The ISO does not study load interconnections, but accounts for these loads in using the CEC’s demand forecast for study assumptions, forecasts, and network models.”

For the 2026-2027 cycle, the Study Plan provides that local area reliability studies and long-term local capacity requirement studies use the 2025 California Energy Demand Update Forecast 2025-2045, adopted by the Energy Commission on January 21, 2026, including the Known Loads load bus modifiers. CAISO’s stated rationale is that this “aligns local area transmission planning with utility distribution planning which already uses known loads to allow ample lead time for potential transmission upgrades.” The Known Loads modifier is applied to local area reliability studies; the Study Plan provides that the economic, policy, and bulk system peak studies continue to use the 2024 IEPR planning forecast. The PG&E Kern study area is a local area study, and is therefore one of the places in this cycle where documented Kern County load would register. As Section VII notes, it is also, on the current portfolio, the principal place where a Kern-area need can still be identified.

B3K/AELAC therefore raise the following, acknowledging that part of it is addressed to the Participating Transmission Owners and to the Energy Commission rather than to CAISO:

1.   That CAISO or the affected Participating Transmission Owners confirm which Kern County load additions were reflected in the local-area reliability baseline for this cycle through the Known Loads modifier, at which substations, and in which study years.

2.   That CAISO identify what documentation would be required for load additions to be reflected in the baseline for the next planning cycle.

V. COMMENTS ON STUDY ASSUMPTIONS

The observations in this section concern the demand forecast and the resource portfolio rather than the reliability results. They are offered because the portfolio determines whether a Kern-area need can be recognized on the generation side, and the results discussed in Section III describe the condition of the system that would serve new load. It is the second of these that B3K/AELAC is concerned with, and the observations below are intended to explain why.

1.   High demand forecast: The Study Plan describes the 2031 Summer Peak High CEC Forecast sensitivity in which load is increased by turning off Additional Achievable Energy Efficiency. Because a substantial share of the Kern-area findings bind more severely in that case, B3K/AELAC requests that CAISO treat it as a planning case for the Kern area instead of a sensitivity or alternatively state the criteria under which a sensitivity result is carried into mitigation selection.

2.   Resource portfolio: Table 19 of the CPUC’s final Resource-to-Busbar Mapping and Other Modeling Assumptions Report for this cycle maps 14,284 MW to the PG&E Kern study area in the 2036 base portfolio and the identical figure, 14,284 MW, in 2041. At that level, PG&E Kern is the largest single study area in the 2036 base portfolio. PG&E Kern and SCE North of Lugo are also the only two study areas in the base portfolio that show no growth across the final five years of the planning horizon; every other area grows between 8 and 150 percent. B3K/AELAC raises this not to seek a larger allocation, but because the flat figure is what leaves the load-serving questions in Sections IV and V as the substance of Kern’s interest in this cycle. B3K/AELAC requests that CAISO state whether the flat figure reflects a modeled completion of build-out by 2036 or a consequence of the busbar mapping methodology, and that B3K/AELAC be advised if a portfolio update in this cycle changes it.

3.   Composition of the PG&E Kern zone figure. B3K/AELAC notes that the PG&E Kern busbar-mapping zone is not coterminous with Kern County, and that the same report shows that 2,924 MW of the 14,284 MW total is Morro Bay offshore wind mapped to the Diablo Canyon 500 kV substation, which is not in Kern County. B3K/AELAC requests that CAISO, in any Kern-area assessment in this cycle, distinguish resources mapped within Kern County from resources mapped elsewhere in the PG&E Kern study area, and do not equate the zone with the county.

4.   Exceedance analysis. The report states that resources mapped in 2036 to the Fresno and Kern study areas “result in 5 constraint exceedances and the possibility of corresponding triggered upgrades only in Fresno and not Kern,” that “no additional exceedances are observed in 2041,” and that “as in the 25-26 cycle model years, no exceedances are shown in PG&E Kern.” B3K/AELAC does not dispute that finding, and request that CAISO identify what load or resource documentation would cause a Kern-area constraint to be recognized in that analysis.

5.   Resources remapped between study areas. The report notes that resources were remapped from buses in the PG&E Kern area “to better align with other criteria and to limit the exceedance on the Cal Flat-Gates 230 kV line, which has an identified White Paper upgrade with an estimated cost of $1,008 million,” and that those resources, 940 MW, “were placed in PG&E Fresno.” B3K/AELAC understands remapping of this kind to be a routine part of the busbar mapping methodology. B3K/AELAC wishes to clarify whether the Cal Flat-Gates 230 kV constraint receives any assessment in this cycle, and whether the remapping has any bearing on transmission need identified in or near the Kern study area.

VI. RELATIONSHIP TO OTHER SUBMISSIONS IN THIS CYCLE

These comments address CAISO’s preliminary reliability study results, they do not propose a transmission or non-transmission solution and are not submitted through the Request Window closing October 15, 2026.

VII. KERN COUNTY AND ENERGY EQUITY

Kern County hosts wind, solar, geothermal, storage, and transmission infrastructure that serves the State as a whole.

• Kern County is the largest electricity-producing county in California and one of the largest in the United States.
• Kern County has approximately one million residents, and its county seat, Bakersfield, is the ninth-largest city in California.
• Electricity produced in Kern County is delivered into the CAISO-controlled grid, which serves approximately 32 million consumers.
• Over the most recent 12-month period, power plants in Kern County generated nearly 35 terawatt-hours of electricity, well in excess of the County’s own consumption of around 6 terawatt-hours.
• Approximately 18.6 percent of Kern County residents live below the poverty line, and many communities experience significant air-quality and environmental burdens. (OEHHA).

B3K/AELAC requests that the planning process recognizes both Kern County’s role as a major energy-producing region and its emerging need for reliable transmission capacity to support local industrial and economic growth. B3K/AELAC recognizes that workforce development, community benefits, and broader economic-development considerations extend beyond CAISO’s direct transmission-planning authority. Nevertheless, where transmission investments are required in communities that host significant portions of California’s energy infrastructure, B3K/AELAC encourages coordination among CAISO, state agencies, utilities, and local stakeholders so that reliability planning supports both statewide energy objectives and sustainable regional economic development.

IIX. CONCLUSION

B3K/AELAC appreciates the opportunity to comment and request that the matters raised in Section I be addressed in the final reliability study results due October 30, 2026. Overall, B3K/AELAC note the complexity of the analysis and decision making, the time and respect provided in prior meetings and dialogue, and the continued opportunity to further engage in long-term planning of power resources in our region.

ATTACHMENT B

Kern-Area Findings, Preliminary Reliability Study Results

All values from the PG&E Kern preliminary study results posted August 14, 2026 (document dated August 15, 2026).

Table B-1. Thermal overload findings

Worst-case baseline is the highest loading recorded for the facility across the six baseline scenarios; a dash indicates no value at or above 100 percent in that column. Worst-case and High CEC values are frequently driven by different binding contingencies, and where a facility carries findings under more than one contingency, more than one disposition may apply. On the Kern-Magunden 70 kV contingency producing the 452 percent result, the 2031 Summer Peak case is recorded as non-converged. San Luis Obispo-Carrizo 115 kV appears in the PG&E Kern study area but is not located in Kern County. The first row on page 2 of the results carries no facility name and is treated here as a continuation of Lerdo-Kern Oil-7th Standard 115 kV from page 1; if so attributed, that facility’s 2031 High CEC value is 116 percent rather than 113 percent.

Table B-2. Low-voltage findings

Planning standard is 0.9 per unit. A dash indicates no reading below 0.9 per unit in that column. Substation names are given as they appear in the study results.

Table B-3. Transient stability findings

1.   Internal fault at bus-tie breaker 302, Midway 115 kV Bus 1D; potential violation in the 2028 spring off-peak scenario; under review.

2.   Internal fault at bus-tie breaker 392, Midway 115 kV Bus E; potential violation in the 2031 summer peak scenario; under review.

3.   Fault on Midway-Wheeler Ridge 230 kV circuits 1 and 2; potential violations in all four baseline stability scenarios; no issues under either sensitivity; under review.

4.   Failure of the non-redundant relay protecting the Westpark 115 kV substation bus; potential violations in the 2028 spring off-peak, 2031 and 2036 summer peak, and 2036 summer off-peak scenarios and in both sensitivities; mitigation identified (install redundant relay).

5.   Failure of the non-redundant DC control circuit at Corcoran 115 kV circuit breaker 122; potential violations in the 2028 spring off-peak and 2031 summer peak scenarios; mitigation identified (install redundant battery supply).

6.   Failure of the non-redundant DC battery supplying the Kern Oil substation 115 kV buses; potential violations in both sensitivity scenarios; dispositioned sensitivity only.

The transient stability assessment uses four baseline scenarios (2028 spring off-peak, 2031 summer peak, 2036 summer peak, and 2036 summer off-peak) and two sensitivities, a reduced set relative to the thermal and voltage assessments.

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

COMMENTS OF B3K PROSPERITY

Better Bakersfield and Boundless Kern (B3K), through its Advanced Energy Leadership Advisory Council (AELAC), submits these comments pursuant to the comment opportunity established in the 2026-2027 Transmission Planning Process (“TPP”) schedule for material presented at Stakeholder Meeting #2. These comments are directed to the preliminary reliability study results for the PG&E Kern study area and, secondarily, to the Tehachapi & Big Creek Corridor study area. They are based on publicly posted CAISO, CPUC, and CEC material, which is identified in the source list at the end of this letter.

II. KERN COUNTY IS DIVIDED BETWEEN TWO STUDY AREAS

Kern County is served by two Participating Transmission Owners and appears in the TPP as two of the eighteen study areas identified in Section 2.3 of the Study Plan. Western and northern Kern County, including Bakersfield, Midway, and Buttonwillow, is within the PG&E Kern local study area. Eastern and southern Kern County, including Tehachapi, Mojave, Rosamond, and the associated wind fleet, is assessed within the SCE Tehachapi and Big Creek Corridor local study area.

B3K/AELAC requests that CAISO characterize Kern County load-serving capability across both study areas rather than solely within each area in isolation.

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

COMMENTS OF B3K PROSPERITY

V. REQUESTED PROJECTS AND SCOPING CONFIRMATIONS

The following requests are directed to projects and candidate mitigations already identified in the record of this cycle or the preceding one. B3K/AELAC does not propose a new transmission element in these comments.

1. Midway 115 kV Bus Upgrade

The Midway 115 kV Bus Upgrade was approved as a reliability-driven project in the 2025-2026 Transmission Plan (project 2526-R-08, PG&E, Kern area, estimated cost $44 million to $89 million, estimated in-service date May 2033). The preliminary results in the present cycle assign a further cluster of 70 kV and 115 kV findings to that project, including Taft-Maricopa 70 kV at 178 percent, Taft-Elk Hills 70 kV at 163 percent, Copus-Lakeview 70 kV at 163 percent, Midway-Tupman-Rio Bravo-Renfro 115 kV at 129 percent, and Famoso-Lerdo 115 kV at 128 percent. Two of these worsen under the high demand forecast relative to the 2031 baseline: Midway-Tupman-Rio Bravo-Renfro, from 129 to 132 percent, and Famoso-Lerdo, from 121 to 123 percent.

B3K/AELAC request that CAISO confirm whether the scope approved in May 2026 resolves the findings now assigned to it in this cycle, including under the 2031 high demand forecast; whether a scope change is required; and whether the May 2033 in-service date remains current, given that the findings assigned to the project bind in the 2028 and 2031 study years. B3K/AELAC further requests that CAISO clarify how reliability will be maintained prior to the project’s anticipated in-service date. If the approved scope is sized to a demand forecast that has since been superseded, B3K/AELAC requests that CAISO state whether the sizing basis will be revisited this cycle.

2. Wheeler Ridge Junction Mitigation

Wheeler Ridge Junction is named as the candidate mitigation for four separate Kern-area findings: Weedpatch-Magunden 70 kV at 195 percent; San Bernard-Weedpatch 70 kV at 325 percent under a P7 double-circuit tower line outage; Buena Vista-Midway #2 230 kV; and the Wheeler Ridge 230 kV low-voltage finding at 0.85 per unit. The same electrical area produces the Midway-Wheeler Ridge 230 kV transient stability finding, which appears in all four baseline stability scenarios. B3K/AELAC requests confirmation of scope and schedule, and requests that CAISO state whether this project resolves the associated stability finding and the unmitigated 334 percent P6 finding on the same facility.

3. Tejon Area Reinforcement

Tejon Area Reinforcement is named as the candidate mitigation for two low-voltage findings: Magunden 70 kV at 0.61 per unit and Weedpatch 70 kV at 0.84 per unit. Adjacent findings at Tejon 70 kV, San Bernard 70 kV (both 0.58 per unit) and Arvin 70 kV (0.63 per unit) are dispositioned as sensitivity-only. B3K/AELAC requests that CAISO state whether the reinforcement as scoped resolves those adjacent findings, and if not, what would.

4. Midway-Gates 230 kV Mitigation

Midway-Gates 230 kV is one of the most demand-sensitive facilities in the Kern-area results, at 131 percent under the 2031 baseline and 141 percent under the 2031 high demand forecast, and it carries no selected mitigation. B3K/AELAC request that mitigation be identified in this cycle, and that the mitigation alternatives assessment consider the high demand forecast case.

5. Path 15 and Path 26 Deferred Engineering Analysis

In the Board-approved 2025-2026 Transmission Plan, CAISO states that "this transmission plan has identified and confirmed the need for new additional transmission on the 500 kV corridor in the San Joaquin Valley, encompassing the Path 15 corridor and portions of Path 26," and that "[T]he ISO has identified a preferred option to meet these needs, extending as far north as Tesla and south to Midway and Windhub." CAISO further states that "Given the magnitude and impact on the 500 kV backbone grid, the ISO has identified the need for additional engineering details to be completed before a functional specification can be completed and a competitive process launched, so the ISO plans to seek Board of Governors approval and move forward with transmission reinforcement in the 2026-2027 transmission planning cycle."

The Plan identifies that preferred option as Alternative 6, consisting of the Gates-Los Banos #3 500 kV series compensation together with a new Windhub-Tesla 500 kV line tying the Midway and Gates 500 kV substations. CAISO records that this alternative "had the highest benefit to cost ratios among all remaining alternatives and is considered the most economically favorable alternative in longer term," at an estimated total cost of $3,271 million, and that "[t]he ISO is planning to recommend this alternative for approval in the next planning cycle after conducting bulk system reliability assessment by modeling this alternative to confirm if there is any impact on the bulk system." For Path 26, CAISO indicated it would further assess the feasibility of a remedial action scheme for south-to-north flows under the common corridor outage of the Midway-Vincent 500 kV lines.

The southern terminals of the preferred option, Midway and Windhub, are both in Kern County. B3K/AELAC accordingly request that CAISO confirm, in this cycle: (a) the schedule on which the bulk system reliability assessment and additional engineering for Alternative 6 will be completed; (b) when CAISO expects to seek Board of Governors approval, and whether that remains within the 2026-2027 cycle; (c) how the Midway and Windhub terminal configurations will be scoped in the functional specification, including any 115 kV and 230 kV terminal work at Midway that would bear on the local findings discussed in Section IV of these comments; and (d) whether the benefit-to-cost showing for Alternative 6 depends on adoption of a revised congestion revenue allocation approach, and if so, the schedule for that determination.

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 2026-2027 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 23-24, 2026. 

Request for CAISO to Provide Evaluation of Storage Charging/Discharging Constraints

BAMx appreciates CAISO’s consideration of Remedial Action Schemes (RAS) and battery energy storage as alternatives to traditional transmission upgrades in the Preliminary Reliability Assessment. During its evaluation, CAISO has identified circumstances where charging requirements, discharge capability, or other operational constraints may limit the effectiveness of storage as a reliability mitigation.

BAMx requests that CAISO provide the results of these evaluations and identify the specific charging/discharging or operational constraints that led CAISO to determine that storage was not a viable or sufficient mitigation in certain planning areas. Greater transparency regarding these limitations would help stakeholders better understand when and where storage can effectively address identified reliability needs. BAMx further encourages CAISO to share these findings with the CPUC and CEC so that transmission-system reliability needs and storage operational constraints can inform future storage mapping and siting efforts, including those used as inputs to subsequent TPP cycles. 

More broadly, and as an example from outside the North area, CAISO’s results for the SCE Metro area show approximately 6,652 MW of energy storage curtailment in the 2036 summer off-peak case, out of roughly 11,000 MW installed.[2] Because off-peak hours are the charging window, BAMx requests that CAISO confirm whether this curtailment reflects a charging restriction, and whether the summer peak cases assume a storage state of charge consistent with the off-peak results. Several mitigations in the Preliminary Reliability Assessment rely on BESS dispatch during peak conditions; if the off-peak results show those units cannot be fully charged, the peak-hour needs may be understated and the operational mitigations overstated. BAMx requests that CAISO (1) run a sensitivity in which storage enters the peak hour at the state of charge implied by the off-peak results, (2) apply its charging/discharging methodology consistently to every PTO determination that storage is infeasible, and (3) document the methodology, with a worked example, in the draft Transmission Plan.

Request for CAISO to Include Affected System Owners in the Development of Potential Mitigations Being Further Evaluated This Cycle

BAMx appreciates CAISO’s efforts to develop comprehensive solutions to address the reliability issues identified in the San Jose[3], San Francisco, and Peninsula[4] areas. As CAISO continues to evaluate and develop comprehensive mitigation alternatives for these overloads, BAMx requests that CAISO coordinate with affected system owners during the development and evaluation of potential mitigations, particularly where the proposed solutions may impact neighboring or interconnected systems.

Additionally, BAMx requests that CAISO provide sufficient technical details, scope, and cost estimates for these mitigation alternatives with adequate time for stakeholders to review and provide meaningful input before the solutions are finalized or recommended for approval. Providing this information early in the development process will help ensure that potential impacts, alternatives, and costs are appropriately considered as part of the stakeholder process.

TAC Forecast Modeling/Data Errors

In BAMx’s review of the posted TAC model[5], BAMx identified several apparent modeling and data errors that materially affect the forecasted HV TAC rate. Specifically:

• The Serrano–Del Amo–Mesa 500 kV Transmission Reinforcement ($1,209.39 million) continues to be included in the model despite the project having been cancelled.
• The North of SONGS–Serrano 500 kV Line ($503 million) appears to be included twice in the model.
• Reliability capital for 2026 is entered in the model as approximately $329.60 million, whereas the posted capital cost file shows approximately $325.60 million, an apparent $4.0 million transcription error.

BAMx estimates that correcting the first two items alone would reduce the forecasted 2034 peak HV TAC rate by approximately $0.70–$0.90/MWh. Given the magnitude of these impacts, BAMx requests that CAISO review and correct these items in the next revision of the TAC model and update the resulting TAC forecast accordingly. BAMx further encourages CAISO to review the model for similar inconsistencies to ensure that cancelled projects, duplicate entries, or other outdated project information are not incorporated into the forecast.

Request for Earlier Posting of PTO Request Window Submittals

The PTO Request Window closed on September 14, but the PTO presentations were not posted until September 21, leaving stakeholders roughly one business day to reconcile several billion dollars of proposed capital against CAISO’s preliminary findings. Because the stakeholder meetings are not recorded and CAISO responds in writing only to submitted comments, adequate preparation time is important. BAMx requests that, in future cycles, CAISO post the PTO Request Window submittals, including alternatives analyses and cost bases, shortly after the window closes, and post the PTO presentations at least one week before the stakeholder meeting.

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

[2] CAISO September 23rd Presentation, p. 170

[3] CAISO September 23^rd Presentation, p. 27

[4] CAISO September 23^rd Presentation, p. 29

[5] https://www.caiso.com/documents/2025-2026-transmission-access-charge-high-voltage-capital-cost-estimates.xlsx; see also CAISO, 2025-2026 Transmission Access Charge Forecast Model with New Capital (Excel workbook).

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

BAMx Appreciates CAISO’s Consideration of Congestion Management, Including Reducing or Shedding Data Center Load, for VEA Area Constraints

BAMx appreciates CAISO’s consideration of congestion management solutions, including the potential reduction or shedding of data center load[1], as part of its Preliminary Reliability Assessment for the VEA area. BAMx understands that CAISO’s evaluation of transmission upgrade alternatives considers the feasibility and operational complexities associated with relying on congestion management as a reliability mitigation.

BAMx encourages CAISO to continue evaluating congestion management and other non-transmission alternatives where they may provide a viable means of addressing identified reliability constraints and potentially avoid or defer transmission upgrades.

BAMx understands from CAISO’s response at the stakeholder meeting that load curtailment is being considered primarily as an interim measure to allow new data center load to interconnect pending transmission upgrades. BAMx requests that CAISO clarify (1) the expected duration of the interim period and the conditions that would end it; (2) the contractual or tariff mechanism by which curtailment would be enforced, and which party holds that obligation; and (3) whether the planning cases model this load as firm while relying on it as curtailable in the mitigation. BAMx also requests that CAISO state a consistent policy on when load flexibility may be credited as a mitigation. For example, CAISO attributes overloads at Newark–Newark DIST and in the Monta Vista–Newark 115 kV pocket in significant part to known load,[2] yet a comparable curtailment assumption does not appear to have been tested in the Greater Bay Area.

[1] CAISO September 23^rd Presentation, p. 270

[2] CAISO September 23rd Presentation, p. 24, 27

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

Below, we provide comments on selected PG&E 2026 Request Window (RW) proposals.

Request for PG&E to Provide Supporting Analysis for Dismissal of Storage as a Potential Mitigation:

BAMx notes that PG&E identifies charging capacity constraints as a basis for eliminating battery energy storage systems (BESS) as a potential mitigation for numerous identified reliability constraints. However, limited supporting analysis has been provided demonstrating the charging constraints that would prevent BESS from serving as a viable mitigation. Given CAISO’s commitment to evaluate BESS energy sufficiency and charging feasibility using a documented methodology, BAMx requests that PG&E provide the technical analysis and results supporting its determination that charging constraints preclude the use of BESS for the identified reliability issues. Providing these results would allow stakeholders to better understand the charging limitations and evaluate whether storage has been appropriately screened as a potential alternative to transmission upgrades.

Several Conceptual Projects Provided Without Cost Estimates:

BAMx notes that PG&E presented seven (7) conceptual projects as part of its 2026 Request Window proposals, but did not provide cost estimates for these projects. BAMx recognizes that conceptual projects may include multiple alternatives that are still under development and that the project scope, design, and associated costs may change as the alternatives are further refined. Nevertheless, preliminary or planning-level cost estimates provide valuable information for stakeholders when reviewing and comparing potential alternatives, particularly when cost may help inform the selection or further development of a preferred solution. BAMx requests that PG&E provide available cost estimates, including appropriate ranges or planning-level estimates where more detailed estimates are not yet available, for all conceptual projects presented during this TPP cycle.

Request for PG&E and CAISO to Reconcile Request Window Proposals with CAISO’s Preliminary Findings:

In several instances, PG&E’s proposals appear to go beyond the needs or mitigations identified in CAISO’s Preliminary Reliability Assessment. BAMx requests that PG&E and CAISO address the following:

• Clear Lake–Lower Lake 60 kV Area Reinforcement: CAISO identifies the Clear Lake–Konocti 60 kV overload as a P2-4 issue, with mitigation through an operating solution, review of the existing Fort Bragg UVLS, a potential new RAS, and the approved Clearlake–Hopland reconductoring.[1] PG&E proposes a new 115/60 kV bank at Lower Lake plus reconductoring at $41.25–$82.5 million.[2] PG&E should explain why capital is required where CAISO’s assessment indicates an operating or RAS solution may suffice.
• Lerdo 115 kV System Upgrade: CAISO attributes the Lerdo–Kern Oil–7th Standard and Semitropic–Charca P3 overloads to mitigation by three previously approved projects (Kern 115 kV Area Reinforcement, Kern PP Reconductoring, and Midway Bus Upgrade).[3] PG&E should identify the residual need, if any, after those projects and any scope overlap with them.[4]
• Banta–Tracy 115 kV Line Reconductor: CAISO identifies P1/P2 overloads on a 599 A line.[5] PG&E proposes reconductoring to at least 1,800 A at $42.9–$85.8 million, with post-project loadings of 34–38%.[6] PG&E should explain why a roughly threefold rating increase is warranted and provide the cost of a right-sized alternative.
• Maple Creek Area Reinforcement: The approved Maple Creek reactive support project (which PG&E refers to as the Willow Creek Reactive Support Project) (ISD October 2028) is modeled in the base cases, yet CAISO still reports long-term P1/P2/P6 low voltages.[7] PG&E should explain why the approved project is insufficient and whether a resized reactive solution would be less costly than the $77.7–$155.4 million reconfiguration.[8]
• Central Coast: CAISO identifies P1/P2/P3/P6 overloads on the Green Valley–Paul Sweet, Green Valley–Camp Evers, Moss Landing–Green Valley #2, Moss Landing–Del Monte #1/#2, and Del Monte–Fort Ord lines without listing a mitigation.[9] BAMx requests clarification of whether these will be evaluated together with the Watsonville conceptual project.

Request for PG&E to Coordinate Potentially Overlapping Metcalf 500/230 kV Upgrades:

BAMx notes that PG&E identifies overloads on the Metcalf 500/230 kV transformers in connection with both the “North San Jose & De Anza 230 kV System Import Reinforcement” and “Metcalf and East San Jose Reconfiguration Project” conceptual projects. Alternatives presented for these projects contemplate upgrading transformers at Metcalf. In particular, Alternative 2 for each project includes upgrades to the existing Metcalf 500/230 kV transformer banks, indicating that the proposed mitigations may overlap. BAMx requests that PG&E evaluate these conceptual projects on a coordinated basis to determine whether the proposed Metcalf improvements can address the reliability needs associated with both projects and whether the scope of the individual alternatives can be optimized accordingly. A coordinated evaluation would help ensure that the alternatives account for improvements proposed under the other project and avoid potentially duplicative or unnecessary transmission investment.

Large Load Capacity Upgrade Projects Prioritized Over Previously Approved TPP Projects:

BAMx understands that the significant load growth identified through the load clusters requires PG&E to reevaluate the timing and sequencing of transmission projects. However, BAMx notes that certain large load capacity upgrade projects appear to be advancing ahead of transmission projects previously approved through the TPP. For example, the Cooley Landing–Palo Alto 115 kV project has an expected in-service date (ISD) of Q2 2032[10], while the previously approved New Ames–Palo Alto 115 kV project has an ISD of Q1 2034[11]. As CAISO’s own reliability assessments demonstrate, thermal overloads on the Ravenswood – Cooley Landing #1 and #2, Cooley Landing – Palo Alto, and Ravenswood – Palo Alto 115 kV lines emerge as early as 2028 and persist through the longer-term study years due to increased load levels.[12] Therefore, BAMx urges PG&E and CAISO to accelerate the Ames Distribution–Palo Alto project ahead of the current Q1 2034 ISD, and to ensure that the enabling substation work at Ames Distribution and Palo Alto proceeds without deferral.

BAMx recognizes that differences in project need, development timelines, and construction requirements may result in different in-service dates. However, the advancement of capacity upgrades driven by new Load Cluster projects should not delay or otherwise adversely affect the timely development of previously approved reliability projects needed to support existing municipal load and address identified system reliability needs.

BAMx requests that PG&E and CAISO evaluate these projects comprehensively, rather than as independent projects, when establishing project priorities and construction sequencing. In particular, PG&E and CAISO should evaluate whether advancing Load Cluster-driven capacity upgrades affects the schedule, availability of construction resources and outages, or timely completion of previously approved TPP reliability projects serving municipal load. Where competing projects cannot be advanced concurrently, BAMx requests that PG&E and CAISO explain the criteria used to establish project priority and how the reliability needs of existing municipal load are considered in that determination.

[1] CAISO September 23rd Presentation, p. 49

[2] PG&E September 24th Presentation, p. 36

[3] CAISO September 23rd Presentation, p. 107

[4] PG&E September 24th Presentation, pp. 25, 27

[5] CAISO September 23rd Presentation, p. 82

[6] PG&E September 24th Presentation, p. 41

[7] CAISO September 23rd Presentation, p. 39, 41

[8] PG&E September 24th Presentation, p. 31

[9] CAISO September 23rd Presentation, p. 89-90

[10] PG&E September 24th Presentation, p. 99

[11] Board Approved 2024-2025 Transmission Plan, May 19, 2026, p.84

[12] CAISO September 23rd Presentation, p. 30

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

Request for CAISO to Reconcile SCE’s Reactive Power Proposals with CAISO’s Own Findings:

CAISO recommends installing reactive support at one or two of five candidate locations (Serrano, Alberhill, Valley, Devers, or Mohave 500 kV),[1] and states that it will re-evaluate the scope of the Lugo 500 kV Reactive Power Reinforcement approved in the 2025-2026 plan. SCE proposes three reactive projects (Vincent, Devers, and Mohave) totaling roughly $675–$898 million, and Vincent is not among CAISO’s candidate locations.[2] BAMx requests that CAISO reconcile its finding with SCE’s portfolio, explain whether a rescoped Lugo project could reduce or eliminate the need for the Vincent and/or Devers projects, and present that comparison before recommending new reactive capital.

[1] CAISO September 23rd Presentation, p. 159-160

[2] SCE September 24th Presentation (Vincent, Devers, and Mohave reactive projects)

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

Request for GLW to Demonstrate the Proposed Charleston Park Projects Are Right-Sized:

CAISO’s VEA mitigations include the existing UVLS and RAS, post-contingency adjustments, and congestion management including reducing or shedding data center load. GLW proposes double-circuit 230 kV-capable structures and two 230/138 kV transformers at $84–$177 million to address 138 kV thermal and voltage issues, with several post-project loadings below 20%. BAMx requests that GLW and CAISO identify which violations remain after crediting the existing schemes and curtailment, and provide the cost of a 138 kV reconductoring and reactive support alternative sized to that residual need. BAMx also requests that GLW provide support for the December 2031 ISD given that the more significant violations appear in 2036 and 2041.

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

Request for SDG&E to Reconcile Project Need Years with CAISO’s Reliability Assessment:

CAISO’s Preliminary Reliability Assessment identifies several transmission upgrades in the SDG&E area as being needed in the 2041 planning cases. For the Border load pocket[1], CAISO ties the reconductoring of TL623B, TL645, TL646, and TL647 to the 2041 cases (B4/B6), while identifying Border/Otay BESS dispatch and the TL649 RAS as mitigation for the 2036 timeframe. Similarly, CAISO identifies the Del Mar-area[2] reconductoring of TL610, TL667, TL660, and TL6952 in the 2041 cases. However, SDG&E proposes 2036 in-service dates for several of these facilities, including TL647, TL649A, TL623B, and TL660/TL667. This appears to advance certain transmission improvements by approximately five years relative to the need reflected in CAISO’s Preliminary Reliability Assessment.

BAMx requests that SDG&E and CAISO reconcile the proposed project in-service dates with the need years identified in CAISO’s reliability assessment. Specifically, BAMx requests that SDG&E explain the reliability need, planning assumptions, or other system conditions supporting a 2036 need where CAISO’s assessment identifies the associated transmission need in 2041. If the earlier ISDs are being proposed for reasons other than the reliability needs identified by CAISO, BAMx requests that SDG&E clearly identify those drivers.

BAMx further notes that SDG&E dismisses storage across several projects on the basis that P3 contingency overloads remain unresolved. BAMx requests that SDG&E quantify the magnitude and duration of the residual P3 exposure and evaluate whether it can be managed operationally, or with storage combined with a smaller reconductoring scope, at lower cost.

BAMx also notes CAISO’s observation that the Border and Del Mar pockets peak at hour-ending 24 beginning in 2036, driven by transportation electrification, and that CAISO and the PTOs will perform load pocket studies for this growth.[3] Overnight vehicle charging is among the most shiftable loads on the system. BAMx requests that CAISO and SDG&E (1) confirm whether the underlying forecast assumes unmanaged charging, (2) reconcile SDG&E’s pocket-level forecasts with the CEC IEPR used in CAISO’s base cases, and (3) complete the load pocket studies, including a managed-charging sensitivity, before recommending reconductoring sized to the unmanaged peak.

[1] CAISO September 23^rd Presentation, pp. 302-303

[2] CAISO September 23^rd Presentation, p. 304

[3] September 23rd Presentation, p. 302-304

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 Energy-Only Resources Assessment Preliminary Findings discussion.

No comments at this time. 

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

No comments at this time. 

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 California Independent System Operator’s (CAISO) 2026-2027 Transmission Planning Process (TPP) stakeholder meeting. The following comments recommend, in summary, that the CAISO:

• Pursue proactive, least-regrets transmission planning to reduce transmission bottlenecks and ensure the system is prepared to interconnect projects in the pipeline;
• Evaluate large-load-driven upgrades for co-benefits to ensure these upgrades are used and useful in the event large load growth does not materialize as planned;
• Coordinate with the California Public Utilities Commission (CPUC) to fully evaluate transmission, storage, generation, and appropriate combinations of these alternatives to identify the most feasible, beneficial, and cost-effective solution to the Western LA Basin local reliability need before the CPUC makes a procurement need determination; and
• Prioritize its initiative to enhance Maximum Import Capability (MIC) so that load serving entities (LSE) have more procurement certainty for out-of-state projects.

I. THE CAISO SHOULD PURSUE PROACTIVE, LEAST-REGRETS TRANSMISSION PLANNING TO REDUCE TRANSMISSION BOTTLENECKS AND ENSURE THE SYSTEM IS PREPARED TO INTERCONNECT PROJECTS IN THE PIPELINE

Community Choice Aggregators (CCAs) have ambitious procurement targets set by their boards and the CPUC’s procurement orders. CCAs are actively seeking new projects to develop, and transmission system limitations and deliverability constraints are often creating bottlenecks to bringing new projects online. Proactive transmission planning is necessary to ensure sufficient transmission infrastructure to interconnect the significant amount of generation and storage in the pipeline.

CalCCA encourages the CAISO to continue moving toward proactive, least-regrets transmission planning that considers the long-term value of transmission investments. When evaluating alternatives, the CAISO should consider whether an alternative provides benefits beyond the immediate planning need, including whether it addresses needs identified across both the base case and sensitivity portfolios. Where an alternative performs well across multiple plausible futures, that broader value should factor into the CAISO’s assessment of the preferred solution. This approach can reduce the risk of incremental, piecemeal upgrades and better position the transmission system to accommodate California’s evolving resource mix and load growth.

CalCCA supports the CAISO’s consideration of transmission plan deliverability needs that may not otherwise be captured in the current planning analysis. The transmission plan should provide a complete picture of the upgrades necessary to support the portfolios transmitted to the CAISO and California’s long-term resource needs. Accounting for otherwise unrecognized deliverability needs can help avoid underestimating future transmission requirements and the need for subsequent incremental upgrades.

II. THE CAISO SHOULD EVALUATE LARGE-LOAD-DRIVEN UPGRADES FOR CO-BENEFITS TO ENSURE THESE UPGRADES ARE USED AND USEFUL IN THE EVENT LARGE LOAD GROWTH DOES NOT MATERIALIZE AS PLANNED

During the September 24, 2026, stakeholder meeting, Pacific Gas and Electric Company (PG&E) presented potential transmission upgrades necessary as a result of large loads in PG&E’s large load interconnection queue.[1] CalCCA’s understanding from the stakeholder meeting discussion is that PG&E includes large loads that have: (1) an application; (2) a deposit; and (3) have site control.

Given the uncertainty associated with the timing, magnitude, and ultimate realization of large loads, the CAISO should carefully evaluate transmission upgrades driven by PG&E’s large load forecasts before approving significant new investments. In particular, the CAISO should assess whether proposed upgrades provide additional reliability, policy, economic, or other system benefits that would remain valuable if the forecasted large loads do not materialize as expected. If the proposed upgrade does not have system benefits, CAISO should use caution before approving projects absent sufficient contractual commitments in order to protect against stranded costs.

Prioritizing projects with broader system benefits can mitigate the risk of stranded transmission costs while still preparing the system for potential load growth. The CAISO should also continue coordinating with PG&E, CCAs, and other relevant entities to incorporate the most current information regarding large-load development and project milestones into its evaluation, as recommended in CalCCA’s comments on the CAISO’s Large Loads proposal.[2]

III. THE CAISO AND CPUC SHOULD FULLY EVALUATE ALTERNATIVES TO ENSURE THE WESTERN LA BASIN RELIABILITY NEED IS FULLY ADDRESSED COST-EFFECTIVELY

In a recent Ruling,[3] the CPUC asks stakeholders to consider whether a procurement order should be issued to meet the Western LA Basin reliability need. As stated in CalCCA’s response to the Ruling,[4] it is premature to determine whether a procurement order is necessary, feasible, and cost-effective. The CAISO should coordinate with the CPUC to fully evaluate transmission, storage, generation, and appropriate combinations of these alternatives to identify the most feasible, beneficial, and cost-effective solution.

The CAISO and the Commission should develop a joint framework to assess wires and non-wires alternatives and their trade-offs before any geographically-specific procurement is ordered. The evaluation should extend beyond upfront project costs and consider factors affecting the feasibility and long-term value of each alternative, including land-use constraints, the ability to charge additional storage during relevant periods, interconnection queue information and development timelines, market competitiveness, resource availability, and implementation risk. A comprehensive comparison of these factors will help ensure that the selected solution can reliably address the identified need while minimizing costs and risks for consumers.

In summary, this assessment should:

• Identify transmission alternatives necessary for upgrade to reduce/remove constraints by local area;
• Quantify the cost of transmission upgrades to reduce each constraint per megawatt by local area;
• Identify the maximum amount of storage, and clean generation to charge the storage, within each local area necessary to reliably operate without emitting resources;
• Identify the suitable land for each type of clean generating technology or storage within the local area;
• With assistance of the CAISO, identify the effectiveness factor of each suitable site;
• Develop a cost estimate based on 3-5 to develop generation/storage within the local area to address the constraints;
• Evaluate, by local area, which option is the most cost effective and feasible to address clean energy needs of the local areas; and
• Identify the broader system value of each alternative.

V. THE CAISO SHOULD PRIORITIZE ENHANCEMENTS TO MAXIMUM IMPORT CAPABILITY

CalCCA encourages the CAISO to prioritize its initiative to enhance MIC.[5] Imports provide important reliability, resource diversity, and market benefits to California, and MIC limitations can constrain LSEs’ ability to access resources outside the CAISO balancing area. For example, LSEs cannot lock-in long-term MIC until the year before a project reaches commercial operations. This creates significant uncertainty for LSEs seeking to contract with in-development projects. The CAISO should advance this initiative expeditiously and evaluate opportunities to increase MIC where transmission capability can support additional imports.  

[1]            PG&E’s 2026 Request Window Proposals (Sept. 24, 2026) at 87-108, https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-PGandE-2026-2027-Transmission-Planning-Process-Sep-24-2026.pdf.

[2]            CalCCA Comments on Large Loads Straw Proposal Meeting (Sept. 2, 2026), https://stakeholdercenter.caiso.com/Comments/AllComments/43a11ec9-fe21-4255-bb1c-336ad3703845#org-42e07ef8-97f6-4e58-9b59-e8ae20e0f70a.

[3]            Administrative Law Judge’s Ruling Seeking Comments on Electricity Portfolios for the 20272028 Transmission Planning Process and Potential for Geographically-Targeted Procurement, Rulemaking (R.) 25-06-019 (Aug. 31, 2026), https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M616/K589/616589361.PDF.  

[4]            California Community Choice Association Comments on Administrative Law Judge’s Ruling Seeking Comments on Electricity Portfolios for the 2027-2028 Transmission Planning Process and Potential for Geographically-Targeted Procurement, R.25-06-019 (Sept. 28, 2026) at 17-20, https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M620/K998/620998776.PDF.

[5]            2027-2029-ISO-Draft-Market-Policy-Roadmap-Sep-24-2026, https://stakeholdercenter.caiso.com/InitiativeDocuments/2027-2029-ISO-Draft-Market-Policy-Roadmap-Sep-24-2026.xlsx?_gl=1*1oopggu*_ga*MTIwMzUwMzQyLjE3NDI4MzQ0MzE.*_ga_NDS4B4M2WP*czE3OTExNTYzNzAkbzkxNyRnMSR0MTc5MTE1NjQ2NCRqNTUkbDAkaDA.

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

See response in Section 1 above.

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

See response in Section 1 above.

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

See response in Section 1 above.

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

See response in Section 1 above.

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

See response in Section 1 above.

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

See response in Section 1 above.

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

See response in Section 1 above.

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

See response in Section 1 above.

10. Provide your organization's comments on the Energy-Only Resources Assessment Preliminary Findings discussion.

See response in Section 1 above.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

See response in Section 1 above.

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

10. Provide your organization's comments on the Energy-Only Resources Assessment Preliminary Findings discussion.

California Energy Storage Alliance (CESA) appreciates the opportunity to comment on the 2026-2027 TPP workshop. The workshop included a first look at CAISO’s promised study of potential energy-only charging sufficiency during off-peak hours.

The most notable information coming from this early report is that the amount and value of uncredited EO resources is substantial. CAISO’s curtailment table from the 2036 off-peak study suggests that in that year, there will be over 18 GW of energy-only resources that could be used for charging energy storage without triggering the contingencies CAISO identified. Seven out of sixteen study areas are unencumbered, even under the build-out modeled in the TPP. Accurately modeling these resources into the RA system under slice-of-day and providing compensation for their reliability contributions will reduce ratepayer costs and lead to more efficient development and resource allocation.

However, the study needs additional analytical work that targets the 2027-2028 timeframe. While preliminary results indicate that energy-only resources will make valuable contributions to resource adequacy in 2036, these findings cannot inform near-term procurement decisions without corresponding analysis of the transmission constraints and resource availability in the relevant compliance years. CAISO has repeatedly informed stakeholders in CPUC’s current RA proceeding that the 2026-2027 TPP process would include new modeling that could inform decision-making around energy-only resource charging sufficiency. That proceeding is addressing compliance requirements for 2027 and 2028, making the absence of modeling for those years a significant gap in the information available to decision-makers.

The study also provides information only about a single hour. This single-hour approach may substantially underestimate the availability of energy-only resources for storage charging, as transmission constraints that limit deliverability during the most constrained hour may not bind during other hours of the same day. Consequently, even on days with high production and high demand, the most constrained hour may not be representative of the energy-only generation available to support storage charging throughout the day.

As CESA pointed out during the TPP workshop, the adoption of the Slice-of-Day resource adequacy framework has fundamentally changed the ways in which the market values resources and must fundamentally change the way in which the market models them, as well. Accordingly, CAISO should evaluate charging sufficiency across the full 24-hour Slice-of-Day framework, or at minimum across the hours in which storage resources would reasonably be expected to charge. It is clear from the preliminary work CAISO has already presented that the availability of EO resources for charging sufficiency is heterogeneous, and more extensive modeling during solar hours will more accurately determine the actual availability of these resources. Expanding the model to evaluate generation hours throughout the market day will improve the accuracy of charging sufficiency assessments, supporting more efficient resource allocation while maintaining resource adequacy reliability requirements.

CAISO’s energy-only modeling information has been extremely brief, and the CAISO still has not published a written description of its methodology. The four slides presented on September 23 served only to provide a summary of results. CAISO should schedule a workshop to discuss the EO study methodology prior to the November meeting to allow stakeholders the opportunity to examine and offer potential improvements to the methodology. At a minimum, CAISO must publish its methodology in written format. September’s preview makes this even more urgent, as it both hints at the scale of EO resources that are already providing charging sufficiency to the system and makes it clear that in some areas, future access to these resources depends on transmission investment. Given the unrealized value locked up by overly-restrictive charging sufficiency limits, CAISO should prioritize providing current and actionable information to the CPUC in November.

Finally, CAISO indicated that it will provide information in November on BESS that may be unable to charge because of transmission constraints, including the affected locations. CESA questions how this analysis relates to the central issue of whether existing energy-only resources can support storage charging during off-peak hours. If CAISO intends to revisit the deliverability status of storage resources already determined to qualify as FCDS, it should state that purpose explicitly and explain the basis for doing so. Even suggesting such a change could create significant commercial uncertainty for existing and planned projects. CAISO should therefore clearly describe the objective, methodology, and potential implications of this analysis and provide stakeholders a meaningful opportunity to review and respond before drawing any conclusions.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

No comment at this time

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) 2026-2027 Transmission Planning Process (TPP) – Reliability Assessment and Study Updates on September 23-24, 2026.  Cal Advocates is an independent ratepayer advocate with a statutory 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 does not have any comments, at this time, on the preliminary reliability results for the North area. 

[1] Cal. Pub. Util. Code § 309.5.

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

Cal Advocates does not have any comments, at this time, on the preliminary reliability results for the South area. 

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

1.  Maple Creek Area Reinforcement Project

To mitigate voltage violations in the Humboldt area, Pacific Gas and Electric Company (PG&E) proposes to loop the Humboldt-Trinity kV line into Maple Creek substation, convert the existing Maple Creek Substation into a 115/60 kV substation, and reconductor approximately 14 miles of the Humboldt-Maple Creek 60 kV line for $155.4 million.[1]  In contrast, CAISO’s analysis suggests that the Garberville Reinforcement Project, approved in the 2022-2023 TPP, will resolve the voltage violations.[2]  Cal Advocates recommends CAISO and PG&E rely on the previously approved Garberville Reinforcement Project to address the potential reliability issues in the Humboldt area rather than PG&E’s alternative

2. To Protect Ratepayers, CAISO Should Require Signed Agreements as a Condition for CAISO Concurrence of Data Center Interconnection Projects.

In the September 24, 2026, meeting, PG&E presented $2.6 billion in upgrades to be submitted to CAISO for concurrence.[3]  In the 2025-2026 TPP, CAISO concurred with PG&E’s proposed upgrades to interconnect numerous data centers, totaling $1.9 billion.[4]  This continues a trend of high project costs going through the concurrence process.  However, PG&E has yet to demonstrate that these customers have completed readiness requirements and are fully committed to interconnecting.  

CAISO should require the Participating Transmission Owner (PTO) to demonstrate the large loads’ completion of readiness requirements as part of the CAISO’s load interconnection request and study process.  Readiness requirements include proof of site control, executed interconnection agreements, procurement of long-lead time materials, and financial commitments.[5]  Currently, PG&E submits applications to CAISO after customers sign off on an Engineering Study.  PG&E submits Advice Letters to the California Public Utilities Commission (CPUC) for approval only when they contain a Signed Agreement which has more certainty than the Engineering Study.[6]  Unlike customers with a signed Engineering Study, customers with Signed Agreements have agreed to a payment schedule and are financially obligated to pay their initial advance.[7]  PG&E presented nearly 3,500 MW of data center and large-load projects for concurrence.[8]  To date, PG&E has only submitted Signed Agreements to the CPUC for only 19%  of that 3,500 MW ( ~650 MW).[9] 

It is unclear if the customers for whom PG&E is requesting concurrence have completed any readiness requirements.  Once PG&E receives CAISO’s concurrence, PG&E can build the transmission projects regardless of the customer’s load coming online.  If the customer load fails to materialize, existing Transmission Access Charge (TAC) customers will be left to fund the interconnection costs of the failed concurrence project   

CAISO should withhold concurrence for projects until PG&E submits the customers’ Signed Agreements that provides more certainty regarding the customers’ completion of readiness requirements. 

[1] PG&E Presentation at 31.

[2] CAISO Presentation (September 23, 2026) at 40-41.

[3] PG&E Presentation at 87-108.

[4] CAISO 2025-2026 Transmission Plan at 92-94.

[5] FERC, Order Instituting Proceeding Under Section 206 of the Federal Power Act (OSC), June 18, 2026, ¶ 55.

[6] See Attachment 1 to Advice Letter (AL) 7569-E, Attachment 1 to AL 7667-E, Attachment 1 to AL 7635-E, Attachment 1 to AL 7785-E, Attachment 1 to AL 7814-E, Attachment 1 to AL 7853-E, and Attachment 1 to AL 7919-E.

[7] Comments on the December 17, 2025 California Energy Commission (CEC) Integrated Energy Policy Report (IEPR) Commissioner Workshop on Energy Demand Forecast Results, Cal Advocates, December 31, 2026, available at https://www.energy.ca.gov/event/workshop/2025-12/iepr-commissioner-workshop-energy-demand-forecast-results.

[8] PG&E Presentation at 92, 98.                                              

[9] See AL 7569-E (90 megawatts (MW)), AL 7667-E (49 MW), AL 7635-E (90 MW), AL 7785-E (250 MW), AL 7814-E (30 MW), AL 7853-E (49.5 MW), and AL 7919-E (97.3 MW).

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

Cal Advocates does not have any comments, at this time, on the Southern California Edison Company (SCE) proposed reliability projects. 

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

Cal Advocates does not have any comments, at this time, on the GridLiance West (GLW) proposed reliability projects. 

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

Cal Advocates does not have any comments, at this time, on the San Diego Gas & Electric Company (SDG&E) proposed reliability projects. 

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

1. CAISO Should Include the Impacts on the High-Voltage Transmission Access Charge (HV TAC) for Transparency and Due Process in the Draft Plan.

CAISO first provided its HV TAC analysis for the 2025-2026 TPP at the September 23, 2026 meeting.  This analysis would be much more useful and timely for stakeholder comment if it were included in the 2025-2026 Draft Plan.  Inclusion here would provide stakeholders the opportunity to weigh in on the financial impact of the plan, prior to CAISO Board consideration. 

In the previous five TPP cycles, CAISO’s Draft Plan failed to include the cost impact analysis of the Draft Plan to HV TAC rates.^[1]  CAISO’s HV TAC analysis provides critical cost information necessary to fully evaluate the impact of the Draft Plan on transmission rates.  Excluding the HV TAC analysis reduces transparency and denies stakeholders the ability to analyze and vet the cost impacts of CAISO’s proposed plan.  Given California’s ongoing rates crisis, it is critical that stakeholders have the opportunity to provide feedback on this analysis prior to CAISO Board consideration.  To improve transparency and to provide the necessary due process, CAISO should post its 2026-2027 HV TAC forecast with its 2026-2027 Draft Plan, including forecast model worksheets, and include HV TAC forecasts in all future draft TPP plans.

In the September 23, 2026 meeting, CAISO indicated that the HV TAC analysis reviewed in the meeting was also presented in the 2025-2026 Revised Draft Plan.  While the chart in CAISO’s presentation was included in the Revised Draft Plan,[2] the associated worksheets were not provided until September 21, 2026.  The release schedule in the 2025-2026 TPP does not change Cal Advocates’ recommendations above.  The release of the forecast chart in the Revised Draft Plan does not provide a commenting opportunity.  Further, it is impracticable to analyze the forecast chart without the associated worksheets that were released long after the CAISO Board approved the 2025-2026 Transmission Plan.  Cal Advocates recommends that CAISO should post its 2026-2027 HV TAC forecast with the 2026-2027 Draft Plan, including forecast model worksheets, and include HV TAC forecasts in all future draft TPP plans to improve transparency and to provide due process

2. CAISO Should Reevaluate its HV TAC Analysis for Accuracy.

CAISO’s HV TAC analysis includes inaccurate capital costs.  Projects that were canceled in the 2025-2026 TPP are still included in CAISO’s model.  These projects include East Shore 230 kV Bus Terminals Reconfiguration, Metcalf 230/115 kV Transformers Circuit Breaker Addition, New Helm 230/70 kV Bank #2, and Serrano-Del Amo-Mesa 500 kV Transmission Reinforcement.[3]  The Serrano-Del Amo-Mesa 500 kV Transmission Reinforcement project is the largest of the mistakenly included projects at over $1 billion.  CAISO should reevaluate the HV TAC to correct these errors and any other potential errors.  Upon revision, CAISO should post the revised HC TAC model with a document describing the updates that were made.

[1] Only the previous five draft transmission plans were checked.  See CAISO Draft 2025-2026 Transmission Plan at 173; CAISO Draft 2024-2025 Transmission Plan at 194; CAISO Draft 2023-2024 Transmission Plan at 161; CAISO Draft 2022-2023 Transmission Plan at 170; CAISO Draft 2021-2022 Transmission Plan at 382.

[2] CAISO 2025-2026 Revised Draft Transmission Plan at 175 and CAISO Presentation (September 23, 2026) at 320.

[3] CAISO 2025-2026 Transmission Plan at 167 and 2025-2026 Transmission Access Charge High Voltage Capital Cost Estimates, available at https://www.caiso.com/generation-transmission/transmission/transmission-planning.

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

Cal Advocates does not have any comments, at this time, on the policy assessment update. 

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

Cal Advocates does not have any comments, at this time, on the economic assessment update. 

10. Provide your organization's comments on the Energy-Only Resources Assessment Preliminary Findings discussion.

Cal Advocates does not have any comments, at this time, on the Energy-Only Resources Assessment Preliminary Findings discussion. 

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

1.  CAISO’s TPP Should Consider California’s Skyrocketing Electric Rates.

California is in a rates crisis, with the second highest electricity rates in the country.^[1]  In the meeting on September 24, 2026, PTOs proposed $5.9 billion in transmission upgrades.[2]  This $5.9 billion does not include 9 proposed projects that were presented without cost estimates.[3]  Between 2023 and 2026, TPPs approved costs of $7.3 billion,^[4] $6.1 billion,^[5] $4.8 billion,^[6] and $8.6 billion.[7] This totals $26.8 billion in TPP approved costs in the last 4 years alone. The four most recent TPPs are more than 9 times the annual average over the previous 22 TPP years.^[8]  This staggering financial commitment to transmission infrastructure is unsustainable and could result in a more than 60% increase in the HV TAC, from its current rate of $15.82/MWh to $26.00/MWh, by 2035.^[9] 

Accordingly, Cal Advocates recommends that CAISO continue to: (1) re-evaluate previously approved projects for necessity, (2) ensure that approved projects are the most cost-effective, and (3) consider low-cost grid enhancing technologies (GETs) and energy storage, where feasible.

2. CAISO and its PTOs Should Provide Itemized Project Cost Estimates and the Length of Proposed New and Reconductored Lines for All Proposed Projects.

CAISO and its PTOs regularly fail to provide information on the cost for individual project major components and the length of new and reconductored lines.  These exclusions obscure the cost of individual project scope items.  Without this necessary information, it is impossible for stakeholders to compare the proposed project descriptions to PTO cost benchmarks and confirm whether the project costs estimates are reasonable. 

For example, projects that exclude line lengths cannot be verified using the PTO Per Unit Cost Guides.[10]  Every one of SDG&E's proposed projects were reconductoring projects, but none of SDG&E’s proposed projects include line lengths in their descriptions.[11]

Federal Energy Regulatory Commission (FERC) Order No. 890 and the proceeding transmission planning Order No. 1000-A require that transmission providers provide sufficient details in their regional transmission planning process to allow replication of the results of the planning study.[12]^{, [13]}

To comply with the FERC Orders No. 890 and 1000-A’s openness and transparency transmission planning principles, Cal Advocates recommends that CAISO and its PTOs include the costs for each major component and the approximate length of new transmission lines or reconducted lines for every proposed project.

3. All CAISO Participating Transmission Owners Should Provide Project Cost Estimates Within a 50% Accuracy Range to Ensure Project Designs 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 such a high level of uncertainty that does not reasonably merit CAISO project approval.  In contrast, SDG&E and SCE generally provide a project cost estimate or cost ranges with contingencies less than 100%.  Cal Advocates recommends all PTOs provide project cost estimates within a 50% contingency range in their CAISO project presentations.

The following are Cal Advocates’ recommendations regarding new large load interconnections.

1. CAISO Should Refrain from Using its Concurrence Process for Approving Costly Network Upgrades for Large-Load Interconnection. 

The concurrence process allows for a degree of uncertainty that is unsuitable for approving costly transmission projects for large-load customers.  CAISO’s concurrence process deviates from the more formalized TPP demand forecast and CPUC resource portfolios to accommodate speculative, large loads.  PTOs request concurrence for an upgrade based on their own load forecast and planning assumptions, rather than the fully vetted California Energy Commission’s (CEC) forecasting assumptions used in the TPP.  Confidence level assumptions underlying the CEC’s Integrated Energy Policy Report (IEPR) process are meant to reduce the levels of uncertainty incorporated into system planning.  Large loads that receive concurrence do not have to align with the confidence levels embedded into the TPP or complete any readiness requirements prior to CAISO’s review and concurrence.  The proposed clarifications to the concurrence process therefore give PTOs an opportunity to inject speculative loads into transmission planning and could impair the state’s aim to coordinate resource planning and result in stranded costs.  In addition, CAISO’s concurrence process fails to include any transparent evaluation of alternative transmission technologies like GETs or energy storage.

CAISO should refrain from using its concurrence process for approving transmission projects for large-load interconnections.  Instead, CAISO should study projects proposed by PTOs as an additional sensitivity case in that year’s TPP reliability modeling scenarios or hold approval until the load can be sufficiently studied in a future TPP study year.  The CAISO holds an annual TPP process so withholding the approval process a single year will have a negligible effect on these long-term projects.

2. If the Concurrence Process Continues to be Used for Large Load Interconnections, the Costs of Concurrence Projects Should be Reflected in the Plan Totals.

In the September 24, 2026 meeting, PG&E presented $2.6 billion in upgrades that it planned to submit to CAISO for concurrence.  Thus, continuing the trend of increased use of the concurrence process that started with the 2025-2026 TPP.[14]  The previous TPP approved $6.7 billion in new transmission capital expenditures^[15] and concurred with $1.9 billion in data center network upgrades,^{[16], [17]} for a total of $8.6 billion in project costs.  The utilities treat CAISO project concurrences the same as a CAISO approval.  For example, in a hearing considering a new large-load interconnection tariff (Rule 30 proceeding) at the CPUC, PG&E stated that “CAISO concurrence allows us to proceed forward.”^[18]  For improved transparency on the impacts to ratepayers, future TPPs should reflect that they are approving the total cost of transmission network upgrades and concurred local network upgrades, rather than solely the cost of approvals described in the previous TPP.  

3. CAISO and the PTOs Should Provide Details on the Costs to Integrate New Data Center Loads.

CAISO and the PTOs should specify the cost impacts of data centers and large loads because they are driving upgrades that are studied through CAISO’s TPP.   Currently, due to the limited information that CAISO shares, the cost impacts associated with accommodating new data center demand are undistinguishable from other loads. 

For example, PG&E proposed 8 transmission upgrades for CAISO approval in the Greater Bay Area.  There is load growth forecasted in the Greater Bay Area, specifically an increase in the 2035 peak load forecast of over 1.8 GW since the 2024-2025 planning cycle.[19]  PG&E proposed over 2 GW of large loads in the Greater Bay Area,[20] indicating that large-loads and data centers are major contributors to the transmission projects in the Greater Bay Area.  CAISO should work with PG&E to quantify the cost impact of large-loads and data centers on the transmission grid, including projects that go through the CAISO TPP study process. 

In its Order to Show Cause (OSC), FERC states that transparency measures related to network upgrades for large-loads are necessary for public utility commissions and other state regulators “to understand which transmission costs are caused by which transmission customers” and to “protect residential and small commercial customers.”[21]  To comply with the OSC, CAISO should identify the portions of upgrades attributable to data centers and other drivers of load growth.  To increase transparency, Cal Advocates recommends that CAISO and its PTOs identify the data center-driven transmission costs in the 2026-2027 TPP.  This will enable stakeholders to properly evaluate the impact of integrating data center loads. 

4. CAISO and the PTOs Should Consider Operational Solutions and Congestion Management, Including Large-Load Curtailment and Managed Charging for Electric Vehicles.

To address certain contingencies, CAISO and the PTOs should study operational solutions as alternatives to transmission projects.  PG&E is proposing transmission projects for contingencies that could potentially be addressed through operational solutions.[22]   

In its Large Load Straw Proposal, CAISO is considering two new flexible load interconnection services: an interim flexible option and a permanent flexible option.[23]  CAISO should consider large-load curtailment in its analysis of certain contingencies.  For example, the Conceptual Lerdo 115 kV System Upgrade Project in the Kern area is driven by a P3 contingency.[24]  PG&E proposed 489 MW of large loads in the Kern area that could be contributing to the P3 contingency.  CAISO should study alternatives that apply congestion management and large-load curtailment to the Kern area before approving the conceptual transmission project in Kern.  CAISO should study large-load curtailment for areas with contingencies that are impacted by large-load growth in the load area.   

Additionally, CAISO is planning for a 2041 peak load profile that peaks at hour 24 due to transportation electrification and electric vehicle (EV) charging.[25]  CAISO should incorporate managed charging of EVs in its analysis of the 1-in-10 peak day net load profile.  This analysis may show that less expensive operational alternatives can eliminate or defer costly network system upgrades.

[1] California legislators push energy bills as electricity costs remain among nation's highest, Darrielle Fair, August 24, 2026, available at https://www.cbsnews.com/sacramento/news/california-legislators-push-energy-bills/.

[2] $870.78 million (PG&E Proposed Reliability Projects) + $2,569 million (PG&E Proposed Load Cluster and Serial Load Interconnection Projects) + $1,610.2 million (SCE Proposed Reliability Projects) + $177 million (GLW Proposed Reliability Projects) + $657 million (SDG&E Proposed Reliability Projects) = $5,883.98 million.

[3] PG&E proposed 7 conceptual projects and 2 cluster study projects without cost estimates. PG&E Presentation at 3 (7 conceptual projects listed), 96 (Serial Data Center #3), and 107 (South Bay LC25-PS5).

[4] CAISO 2022-2023 Transmission Plan at 3.

[5] CAISO 2023-2024 Transmission Plan at 3.

[6] CAISO 2024-2025 Transmission Plan at 7.

[7] Total of approved projects and concurred projects. CAISO 2025-2026 Transmission Plan at 7 and 92-94.

[8] Cal Advocates Transmission Data Dashboard at 3, available at https://www.publicadvocates.cpuc.ca.gov/press-room/reports-and-analyses/transmission-data-dashboard-2025.

[9] CAISO Presentation (September 23, 2026) at 320.

[10] Per Unit Cost Guides, available at https://www.caiso.com/library/current-cost-guides.

[11] SDG&E Presentation at 3-9.

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

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

[14] PG&E Presentation at 87-108.

[15] CAISO 2025-2026 Transmission Plan at 7.

[16] CAISO 2025-2026 Transmission Plan at 92-94.

[17] To address a new large load interconnection request that comes in after development of the demand forecast and CPUC resource portfolios, Participating TOs may submit proposals into the ISO’s Transmission Planning Process for the ISO’s concurrence in the Transmission Plan. Large Load Considerations Issue Paper, CAISO, January 30^th, 2026 at 9.

[18] Reporter’s Transcript, Evidentiary Hearing, A.24-11-007, April 15, 2026 at 523, lines 9-10.

[19] CAISO 2025-2026 Transmission Plan at 4.

[20] CAISO 2025-2026 Transmission Plan at 91; PG&E Presentation at 92 and 98

[21] OSC at ¶ 68.

[22] PG&E Presentation at 24-27.

[23] CAISO Large Load Considerations Straw Proposal, August 12, 2026 at 38.

[24] PG&E Presentation at 26.

[25] CAISO Presentation (September 23, 2026) at 280.

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

California Western Grid has no comments on the reliability results for the North area.

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

California Western Grid Comments on the CAISO September 23-24, 2026, Stakeholder Presentation Regarding the 2026-2027 Transmission Planning Process  

California Western Grid Development, LLC (“California Western Grid”) appreciates the opportunity to comment on the CAISO Presentation to Stakeholders at the September 23-24 Stakeholder Meeting. Our comments will focus on the Preliminary Reliability Assessment Results for SCE Main planning area and Southern California Bulk System. We commend the CAISO for identifying mitigation alternatives for SCE Main which include a ‘comprehensive  reliability’ solution for LA. We urge CAISO approve in this 2026-27 TPP a comprehensive solution for the LA basin.

The CAISO September 23 presentation includes the following with respect to reliability needs in LA. (page183 emphasis added):

Summary of Potential New Upgrades in SCE Main

• Utilize energy storage resources to meet LCR, subject to verification of storage charging and discharging constraints
• Implement a phased upgrade strategy for the LA Basin system, including rebuilding, reconfiguring, and/or adding new 230 kV facilities as needed, such as
  • add a 4th AA bank at Mesa 500/230 kV substation
  • add a new 230 kV line from Mesa to Laguna Bell or Lighthipe
  • convert the Vincent - Ridondo-Mesa 230 kV line that was built to 500 kV specification to a new Vincent-Mesa 500 kV #2 line
  • rebuild Mesa–Laguna Bell #1 and #2, Mesa–Lighthipe, Mesa - Center, and Center–Del Amo 230 kV transmission lines, and upgrade associated substation equipment as needed
  • re-configure the Western LA Basin 230 KV network
• Pursue a comprehensive transmission solution developing 2,000 MW of HVDC system to Western LA     Basin, subject to feasibility and cost-effectiveness

• ? convert Antelope – Pardee and Vincent – Pardee 230 kV lines that were built to 500 kV specification to two 500 kV lines, along with adding Pardee 500 kV substation
  • ? develop a 2000 MW HVDC source to Western LA Basin via submarine route along the Pacific coast or via underground route, subject to feasibility and cost-effectiveness

California Western Grid has for several years been proposing a comprehensive transmission solution Project to the CAISO referred to as the Pacific Transmission Expansion Project (“PTE” or “PTEP”).  Again, this year, PTEP will be filing with CAISO by the October 15 submission deadline as the optimal reliability solution in the 2026-2027 TPP to address reliability needs in LA.  PTEP is a 2000 MW HVDC transmission source to Western LA Basin via submarine route along the Pacific coast and via underground route.  And, while prior studies have shown, storage/batteries are not an adequate solution due to the need for energy from outside the LA  Basin to re-charge the batteries.  PTEP would supply that energy allowing for increased reliance on battery storage and reducing the need for local reliability resource procurement.

In addition to presenting the potential solutions for SCE Main, the CAISO presented a Summary of Potential Upgrades in Southern Bulk at slide 160 on September 23. California Western Grid was disappointed that the same comprehensive solution, a 2,000 MW HVDC submarine cable to Western LA Basin was not listed among the possible mitigations, especially to help relieve the Path 26 and related area overloads.

The PTEP can significantly reduce Path 26 and Southern Bulk area congestion.  Slide106 of the CAISO June15, 2026 Presentation of the Draft Transmission Plan in the 2025-2026 TPP. showed PTEP could reduce production costs by as much as $221 Million/ yr. (see Case A-7 (PTEP).  Those economic savings should be added to the LA Basin reliability benefits of PTEP which can eliminate the need for rebuilding, reconfiguring and adding new HVAC facilities in SCE Main.

The economic benefits of the PTEP make a comprehensive reliability solution even more compelling, especially since Slide 106 shows that the economic benefits alone of PTEP could exceed a cost-benefit ratio of 1-to-1 meaning it pays for itself.  

              Finally, PTEP has also been designed to limit disruption to commercial and residential interests and limit landowner issues. And very importantly the submarine route mitigates any wildfire risks.

              California Western Grid urges CAISO to approve PTEP as a comprehensive cost effective solution for LA that is consistent with the increased focus on long-term planning and away from short-term disjointed band aid solutions.

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

California Western Grid has no comments on PG&E's proposed reliability projects presentation.

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

California Western Grid has no comments on SCE proposed reliability projects presentation.

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

California Western Grid has no comments on GLW proposed reliability projects presentation.

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

California Western Grid has no comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 projects presentation

No comment.

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

No comment.

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

No comment.

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

No comment.

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

No comment.

10. Provide your organization's comments on the Energy-Only Resources Assessment Preliminary Findings discussion.

CalWEA appreciates CAISO’s preliminary assessment of EO resources’ ability to charge storage facilities during off-peak load periods, which showed no curtailment resulting from dispatching EO solar resources in 29 of 42 Study Area/operating-condition combinations, including all three modeled conditions—P0, P1, and P7—in seven of the 14 Study Areas containing EO solar.

This favorable result occurred despite three unduly conservative study parameters that CAISO confirmed were employed on the stakeholder call in response to a question.  Those study parameters were: 

1. The selection of the most constrained off-peak hour—11 AM on a high system need (HSN) load day—to represent over 90 percent of off-peak load hours during the year,
2. The assumption that storage resources must be charged at full charging capacity (storage resources have 20 hours to be charged for their 4-hour discharge obligation), and
3. The use of a dispatch scenario that contradicts CAISO’s own operating SCUC/SCED unit commitment/dispatch protocols by assuming that dispatchable (e.g., thermal) FCDS resources were dispatched at very high output during an off-peak hour when no-cost and emission-free solar output from EO resources were available to be used by the system but were curtailed by CAISO’s selected dispatch. 

To properly assess the ability of various resources to meet system demand (system load plus storage charging needs) at any selected off-peak load hour, the assessment should be conducted under more operationally representative conditions whereby dispatchable (e.g., thermal and hydro) FCDS resources are dispatched at a level determined by the CAISO’s SCED algorithm.  At a minimum, CAISO should justify its selection of such unrealistic study conditions. 

In addition, the study should:

• Consistent with the next steps identified on slide 316, report for each Study Area and P0, P1, and P7 condition the extent of curtailment of EO resources’ output for each study/contingency combination.  If the extent of curtailment is limited, EO resources can be presumed generally to reach load during most off-peak hours that constitute the overwhelming majority of the 8760 annual hours.
• Focus on determining whether any storage resources, due to their unique location, are unable to accept service during off-peak system conditions.

CalWEA urges CAISO to properly weigh a low-risk strategy of enabling EO-resource charging of storage to unlock substantial benefits, including:

• Bolstering system reliability by (a) ensuring that storage resources will be fully charged and ready to contribute GHG-free energy to the grid during on-peak hours; and (b) using EO resources that can be brought online relatively quickly and at lower cost because they generally do not require major deliverability transmission upgrades that are slow to materialize.
• Increasing the ability of load-serving entities to meet unprecedented and challenging near-term resource requirements to meet grid reliability requirements and greenhouse gas targets.  Furthermore, allowing EO resources to charge storage may be the only near-term pathway to achieving the Commission’s reliability and GHG objectives given transmission delays associated with FCDS charging resources.
• Saving ratepayers considerable transmission upgrade costs by using EO resources to charge during off-peak periods, which will also foster a more robust and competitive market.

Even under CAISO’s assumed conservative stress-case conditions, its preliminary study results show that EO generation in many areas should be eligible as charging resources without limitation.  This may be shown to be true also for most resources under reasonable operating conditions.  Any remaining resources may warrant appropriate limits or derated charging capacity. 

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

No comment.

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

The City of Palo Alto (“Palo Alto” hereafter) appreciates the opportunity to comment on the CAISO’s 2026-2027 Transmission Planning Process. The comments below address the material presented at the CAISO stakeholder meeting on September 23-24, 2026.

CAISO’s Preliminary Results Confirm Near-Term Reliability Needs on All Three Palo Alto Import Lines

Palo Alto appreciates CAISO staff identifying P1 through P7 overloads, in both the near-term and long-term study years, on the Ravenswood–Cooley Landing #1 and #2, Cooley Landing–Palo Alto, and Ravenswood–Palo Alto 115 kV lines.[1] These include the three 115 kV lines, physically located within a tight corridor, that serve the entire City of Palo Alto, and the results confirm the findings of prior planning cycles, that is, the reliability need is near-term (c. 2028), and it is growing.

Notably, CAISO does not identify a specific mitigation for these overloads. Instead, CAISO lists generic options (maintenance projects, line re-rates, topology reconfiguration, and bus upgrades) and refers to a potential “more comprehensive approach” that would introduce a new source to the San Francisco and Peninsula pocket, to be assessed later in this cycle. Palo Alto welcomes CAISO’s evaluation of longer-term regional solutions and requests to be included in that assessment. However, a regional source that is only now entering conceptual assessment is unlikely to be in service for a decade or more, well after the overloads CAISO identified. An undefined future project should not substitute for, or delay, a previously approved solution that addresses the same needs on a nearer-term schedule.

Additionally, Palo Alto requests CAISO provide sufficient technical details, scope, and cost estimates for these mitigation alternatives with adequate time for stakeholders to review and provide meaningful input before the solutions are finalized or recommended for approval. Providing this information early in the development process will help ensure that potential impacts, alternatives, and costs are appropriately considered as part of the stakeholder process.

The Approved Ames Distribution–Palo Alto 115 kV Project Must Be Accelerated, Not Deferred

CAISO approved the New Ames Distribution–Palo Alto 115 kV project in the 2024-2025 Transmission Plan to prevent overloads on the Ravenswood–Palo Alto 115 kV lines and to add a diverse source of supply to Palo Alto.[2] In the 2025-2026 Transmission Plan, CAISO expanded the scope to use advanced conductors with a summer emergency rating of 3,000 A or higher, recognizing that load growth had made the original scope insufficient.[3] The project is the designated solution for the very facilities CAISO again identifies as overloaded in this cycle in 2028.

Despite this, the project retains an estimated in-service date of Q1 2034. As Palo Alto has explained in prior comments, the 2034 date reflects sequencing behind PG&E’s enabling substation work, not the time required to construct the line itself.[4] Palo Alto is therefore deeply concerned that on September 23, 2026 PG&E issued an immediate stop-work order on 2026 work for the two enabling projects, the Ames Distribution 115 kV Ring Bus Conversion and the Palo Alto 115 kV Breaker-and-a-Half (BAAH) Conversion with no estimated date for resuming work. Because the new line cannot be constructed and connected to the Palo Alto Switching Station without prior environmental review and permitting, any deferral of the early project planning and permitting directly delays the Ames project and extends Palo Alto’s exposure to the overloads CAISO has identified. In the September 23, 2026 presentation the CAISO explicitly highlights the upgrade of the Palo Alto Switching Station 115 kV Redundant Bus Differential Relay as a potential mitigation measure for the P5 contingency issue.

Palo Alto urges CAISO and PG&E to:

1. Confirm the current status and schedule of the Ames Distribution Ring Bus Conversion and the Palo Alto BAAH Conversion, and state the Ames Distribution–Palo Alto in-service date necessary to mitigate the identified overloads in the 2026-2027 Transmission Plan;
2. Ensure that the enabling substation work proceeds without further deferral, and parallel-track preliminary engineering, environmental review, procurement, and construction planning for the line itself;
3. Accelerate the in-service date of the Ames Distribution–Palo Alto project well ahead of 2034, consistent with the timing of the identified near-term overloads; and
4. Require PG&E to notify CAISO and affected stakeholders when work on a CAISO-approved project or its enabling facilities is stopped or deferred and track those changes in the Transmission Development Forum.

Long-Lead Development Work on the Ames Project Should Continue Without Interruption

Even if PG&E must re-sequence some capital-intensive construction work, Palo Alto urges PG&E not to stop the development activities for the Ames Distribution–Palo Alto line itself. Preliminary engineering, route selection and refinement, environmental studies, and permitting require relatively little capital expenditure, but they take considerable time. If these activities are deferred along with the enabling substation work at Palo Alto and Ames, the overall project schedule will slip by at least as long as the deferral, plus the time needed to remobilize, even after construction funding becomes available.

Continuing this development work now preserves the option to accelerate construction as soon as the enabling substation work resumes, at modest cost to ratepayers. Deferring it saves little but wastes time that cannot be recovered. Palo Alto therefore requests that:

• PG&E continue preliminary engineering, route refinement, and environmental and permitting work on the Ames Distribution–Palo Alto 115kV line without interruption, regardless of the status of the enabling substation work;
• PG&E report the status and schedule of these development activities, including the planned start and completion of environmental review, through the Transmission Development Forum and PG&E’s Transmission Project Review process; and
• CAISO reflect in the 2026-2027 Transmission Plan the in-service date that results from PG&E’s current schedule, and identify any interim operating measures needed to manage the identified overloads until the project is in service.

The Need for the Ames to Palo Alto Project  is Independent of Data Center Load Growth

Palo Alto is also concerned that potential revisions to regional load forecasts, including any reduction in forecasted data center load, could be used to justify further delays. The need for the Ames to Palo Alto project rests on more than load magnitude. All three 115 kV lines serving Palo Alto share a single corridor near the end of the Palo Alto Airport runway. On February 17, 2010, an aircraft struck that corridor, damaging all three lines and interrupting power to the entire city, including Stanford Hospital, Stanford Children’s Hospital, and the Veterans Administration Medical Center, for approximately ten hours.[5] A September 2021 aircraft incident nearly caused a similar outage. The Ames to Palo Alto project provides the only planned source of supply independent of that corridor. Its source-diversity and common-mode-outage benefits are independent of how quickly regional load grows, and any forecast revisions should not be used to defer the project.

[1]CAISO September 23rd Presentation, p. 29.

[2]Board Approved 2024-2025 Transmission Plan, “Ames Distribution – Palo Alto 115 kV transmission line” project.

[3]Board Approved 2025-2026 Transmission Plan, May 19, 2026, pp. 83-84.

[4]City of Palo Alto Comments on the CAISO 2025-2026 Draft Transmission Plan, April 2026; City of Palo Alto Comments on the 2025-2026 TPP Preliminary Reliability Results, October 2025.

[5]City of Palo Alto letter to the CAISO Board of Governors in support of the Ames Distribution – Palo Alto 115 kV Line Project, May 12, 2025.

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 projects presentation

Palo Alto Supports the Cooley Landing–Palo Alto 115 kV Reconductoring, Which Addresses CAISO-Identified Reliability Needs

In its load interconnection presentation, PG&E proposes reconductoring 2.72 miles of the Cooley Landing–Palo Alto 115 kV line at an estimated cost of $23 million and an estimated in-service date of Q2 2032, as a capacity upgrade associated with LC25-PS6, a 30 MW load increase at the customer-owned Facebook Junction 60 kV station.[1] Palo Alto supports this upgrade. However, CAISO independently identifies overloads on the same line in its preliminary reliability assessment, so the upgrade addresses existing reliability needs and is not driven solely by the new load interconnection. Palo Alto requests that PG&E and CAISO size the reconductoring to meet the CAISO-identified reliability needs as well as the load interconnection.

Previously Approved Projects Serving Existing Load Should Be Prioritized Over New Load Interconnection Upgrades

PG&E is seeking CAISO concurrence on capacity upgrades for 19 large load projects totaling approximately 2 GW, several of which are in the Peninsula and De Anza areas near Palo Alto. Until the Cooley Landing–Palo Alto upgrade and the Ames Distribution–Palo Alto line are both in service, the additional LC25-PS6 load may further reduce the import capability available to serve Palo Alto. PG&E states only that interim solutions are being developed until the long-term capacity upgrades are in service. Palo Alto requests that PG&E describe those interim solutions and demonstrate that they will not reduce the import capability or reliability of service to Palo Alto.

More broadly, Palo Alto urges CAISO and PG&E to prioritize completion of previously approved reliability projects that serve existing customers, such as the Ames Distribution–Palo Alto line, rather than allowing those projects to be deferred while capacity upgrades for new large loads proceed. It would be inequitable for an approved project serving Palo Alto’s existing load to slip while upgrades on the same transmission system serving new large loads move forward, ahead of previously approved reliability projects.

[1]PG&E September 24th Presentation, LC25 Capacity Upgrades table and LC25-PS6 project slide, pp. 99, 108.

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

No comments at this time.

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

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

No comments at this time.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 projects presentation

EPE has reviewed the proposed projects and has the following general comments:

Any line reconductors should designed as to accommodate the largest conductor type used at the voltage class involved as to ensure the reconductor can withstand the test of time.  In evaluating each proposal, EPE notes language that reads "achieve the minimum required rating of...". Such language may drive a reconductor upgrade that falls short of need within the next few years as study assumptions evolve.  EPE appreciates desire minimize cost but designing to a minimum may actually expose rate-payers to much higher cost if evolving study assumption prove the reconductor to be marginal and require near-term further reconductor.  Specific project comments are as follows:

REEDLEY-OROSI-DINUBA 70 KV SYSTEM REINFORCEMENT PROJECT - ensure reconductor is properly sized to withstand test of time by reconductoring with largest 70 kV conductor size used.

EXCHEQUER 115 KV SYSTEM RECONFIGURATION PROJECT - proposed project does not appear to mitigate Category P3 conditions which reflect initial condition of loss of generator unit followed by System adjustments with a loss of a transmission circuit.  With the proposed mitigation, the P3 case involving initial loss of the Exchequer PH unit followed by System adjustment would experience the same results under loss of the Le Grand 115 kV line as both sources would be lost. A new 115 kV source line from Le Grand appears to be required to address this P3 category.

WATSONVILLE AREA REINFORCEMENT PROJECT - It is unclear why a second Green Valley 115/70 kV transformer bank is needed when installing a new Green Valley-Watsonville 70 kV line.  From the looks of things, it appears that the existing Green Valley transformer bank is overloaded due to the retirement of the Watsonville-Salinia 115 kV line section.  EPE recommends evaluating the scenario of not retiring this line segment to determine if a second transformer bank is indeed required.

SOUTH LOS PADRES REINFORCEMENT PROJECT - No comment

LERDO 115 KV SYSTEM UPGRADE PROJECT - No comment

MAPLE CREEK AREA REINFORCEMENT PROJECT- No comment

CLEAR LAKE-LOWER LAKE 60 kV AREA REINFORCEMENT PROJECT - No comment

BANTA - TRACY 115 kV LINE RECONDUCTOR PROJECT - No comment beyond general commet above

HAMMER – COUNTRY CLUB 60 kV RECONDUCTOR PROJECT - No comment beyond general commet above

MARYSVILLE 60 kV REINFORCEMENT PROJECT - No comment beyond general commet above

MORAGA 115 kV BUS UPGRADE PROJECT - No comment

NEWARK E-F 230 kV BUS TIE LIMITING ELEMENTS UPGRADE PROJECT - No comment

CONTRA COSTA –NEWARK 230 kV CORRIDOR REINFORCEMENT PROJECT - Need to see results of alternatives explored before providing further feedback

STATION M.A. REARRANGEMENT PROJECT - No comment

MILLBRAE 230 KV ADDITION AND SYSTEM RECONFIGURATION PROJECT - Recommend installing two 230/115 kV transformer banks for redundancy at new Milbrae 230 kV.

EDENVALE 115 kV AREA REINFORCEMENT PROJECT - Given load serving needs, a third line may be suited as taking long-term outages to reconductor may not be practical. 

METCALF AND EAST SAN JOSE RECONFIGURATION PROJECT - Further details are needed to properly evaluate proposals. Will provided more comments once alternatives are evaluated and information is presented.

NORTH SAN JOSE & DE ANZA 230 kV SYSTEM IMPORT REINFORCEMENT PROJECT - Further details are needed to properly evaluate proposals. Will provided more comments once alternatives are evaluated and information is presented.

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

1. Whirlwind 230 kV SCD Upgrade - It is unclear what exactly is driving such high SCD as no new 500 kV transmission lines are being introduced.  New resources at Whirlwind would increase SCD at 230 kV but such results should be identifeid as part of the Generation Interconnection Studies and assigned to resources connecting to Whirlwind 230 kV.  As presented, teview of study results suggests that three AA-Banks can never be paralleled causing concerns on localized deliverability since loss of one AA-Bank would result in a capacity of no more than ~1500 MW on each 230 kV bus section.  Operating three AA-Banks in parallel will result in over 4000 MW of deliverability.  Need more details related to SCD study results.

2. Rio Hondo 230 kV SCD Upgrade - No comment

3. Whirlwind 500 kV Transmission Line Relocation - SCE should evaluate relocating Antelope 500 kV T/L as shown in Alternative 2 (paired with new AA-Bank assuming it is still required after addressing comments provided above) and relocationg Vincent 500 kV T/L to vacated position following move of Antelope 500 kV T/L.  This will utilize existing fully equipped position to support relocation of Vincent 500 kV T/L lowering overall cost.  End result would pair a AA-Bank with the Antelope T/L and a AA-Bank with the Vincent T/L. Both lines would have power flows in same direction so there is no concern with loop flow down one AA-Bank and up the second AA-Bank. This option will require a single 500 kV CB if Whirlwind 230 kV SCD Upgrade is approved or two 500 kV CBs if Whirlwind 230 kV SCD Upgrade is not approved.  Total cost would be reduced.

4. Mesa 1AA (Fourth) Bank Project - Project makes sense only if more resources outside of the LA Basin are used to serve load witihin the LA Basin.  Language suggests this to be the case for purposes of charging Basin area BESS with solar located outside of LA Basin.  If such assumption is the case, EPE has no further comments. Otherwise, need further details surrounding driver of need.

5. Mesa-Vincent No. 2 500 kV Line Conversion - Unclear how second 500 kV line will actually get to Mesa as route is constrained approximately 2 miles west of Mesa.  An alternative is to use the Mesa-Vincent No.2 230 kV (partially built at 500 kV) to route new line into Mesa (relocating 66 kV lines between two sets of double circuit 220 kV tower lines). This alternative will eliminate common corridor outage conditions resulting in overall better reliability

 6. Vincent 500 kV Reactive Power Reinforcement - Unclear if this is required with installation of new Mesa-Vincent No.2 500 kV T/L.  EPE recommends this be evaluated with and without new line installed.

 7. Mohave 500 kV Voltage Support - It appears that the incremental voltage is tied to new generation (incremental line and cable charging when operating at low output conditions).  Question is whether this should be addressed with generation addressing such incremental reactive resource injection by installing reactors to absorb such incremental reactive power.

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

Only comments involve eliminating new 230/21 kV substation in favor of installing new 230/21 kV transforamtion at existing sites.  

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

EPE has reviewed the proposed projects and has the following general comments:

Any line reconductors should designed as to accommodate the largest conductor type used at the voltage class involved as to ensure the reconductor can withstand the test of time. EPE appreciates desire minimize cost but designing to a minimum may actually expose rate-payers to much higher cost if evolving study assumption prove the reconductor to be marginal and require near-term further reconductor.

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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

Wish I had more time to comment as CAISO Symposium and CESA conference made commenting a bit challenging.

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

In reviewing the 2036 Base Case SCE Eastern study assumptions, the total generation assumptions are noted as follows:

These values would drive an overload on the MWD 230 kV line running from Camino to Eagle Mountain as evidenced by MWD's claim of Affected Systems. EPE would expect a Policy Driven Upgrade be identified and supported that would address such overload since this upgrade would be needed to support such  2036 Base Portfolio Busbar Mapping + Unaccounted for TPD values considered in the 2027-2036 Transmission Plan. Without such upgrade, the values assumed cannot be accomodated.  EPE request that the CAISO identify how the impacts to MWD are being addressed in support ot the 2036 Base Portfolio Busbar Mapping + Unaccounted for TPD values considered in the 2027-2036 Transmission Plan.

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

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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

GreenGenStorage, LLC (GreenGen) is developing the Mokelumne Pumped Storage Project, a 400 MW pumped storage hydro project in Amador and Calaveras Counties that uses two existing reservoirs and requires no new dam. The project’s license application was filed with FERC on March 14, 2025, and noticed as accepted on August 25, 2026 (FERC Project No. 14796-002). The project reaches the CAISO grid at the Bellota 230 kV substation by way of the Salt Springs to Tiger Creek to Bellota line. In the North area reliability assessment, Bellota is one of the supply sources for the Central Valley area and anchors the Stockton/Stanislaus (Tesla to Bellota) divisions (CAISO 2026-2027 Transmission Planning Process slides, September 23 presentation, slides 69 and 79-83). In the CPUC portfolio busbar mapping slides, it falls within the PG&E Greater Bay Area (CPUC Portfolio Busbar Mapping Diagrams September 23 presentation, 2036 Base Case- PG&E GBA, slide 2). GreenGen’s comments concern how the North area studies, including the policy-driven assessment update presented on September 24, treat the long-duration storage mapped at Bellota.

Preliminary results at Bellota and Tiger Creek. The preliminary North area results identify a cluster of issues on the 230 kV system between Tiger Creek and Bellota and at Bellota itself. (CAISO, 2026-2027 ISO Reliability Assessment, Preliminary Study Results, PG&E Central Valley, August 14, 2026). Most of these results are marked under review or continue to monitor, and others are assigned to redispatch or to the approved Lockeford-Lodi Area 230 kV Development.

The 400 MW of LDES mapped at Bellota would reach the CAISO grid over this same system. GreenGen asks the CAISO to confirm whether the 2036 reliability cases include that resource. GreenGen also asks that the CAISO evaluate these issues together with the deliverability of the LDES mapped at Bellota, and that it prefer mitigation that resolves the reliability issues while supporting that deliverability. Where redispatch is identified as the mitigation, GreenGen asks the CAISO to clarify whether it assumes reduced output from storage at Bellota.

Long lead-time reservation at Bellota. GreenGen supports the CAISO’s modeling of 400 MW of long-duration energy storage (LDES) at Bellota in the 2036 base portfolio busbar mapping (CAISO 2026-2027 Transmission Planning Process slides, September 24 presentation, slide 10). That amount reflects the CPUC’s decision in D.26-02-057 to map the full 400 MW design capacity of the Mokelumne Project at Bellota. The Board-approved 2025-2026 Transmission Plan reserves 310 MW of deliverability for LDES at Bellota (CAISO 2025-2026 Transmission Planning Process, Errata to Table 1-1 of the Board-approved 2025-2026 Transmission Plan, July 29, 2026). GreenGen asks that the 2026-2027 Transmission Plan specify the long lead-time reservation at Bellota at 400 MW, consistent with the portfolio the CAISO is now studying.

Deliverability at Bellota. The CAISO’s 2026 Transmission Capability Estimates for Use in the CPUC's IRP Process spreadsheet- Revised 07/15/2026 represent Bellota through a single consolidated Bellota Area constraint with zero MW of estimated FCDS capability and one identified upgrade, a new 230/115 kV transformer bank and 115 kV line reconductor providing 196 MW. The CAISO’s 2024 Transmission Capability Estimates (revised 08/28/2024) represented the same area through the Bellota-Weber and Tesla-Bellota 230 kV constraints and identified a 230 kV Bellota-Weber upgrade providing 460 MW. GreenGen asks that the policy-driven assessment test the deliverability of the full 400 MW of LDES mapped at Bellota in the 2036 and 2041 base portfolios. GreenGen also asks the CAISO to explain what drove the consolidation of the Bellota constraints between the 2024 and 2026 estimates. If the 400 MW is not deliverable, the assessment should evaluate a policy-driven solution sized to the mapped resource.

Unaccounted-for TPD allocations. The CAISO’s 2026-2027 Transmission Planning Process slides presented on September 24, explains that CPUC staff identified unaccounted-for TPD allocations at locations that would affect deliverability reservations for long lead-time resources, including location-constrained LDES, and that allocations at other buses behind the same constraint were reduced where portfolio resources exceeded TPD allocations (slide 19). GreenGen asks the CAISO to confirm whether any of the Greater Bay Area allocations listed on slides 22 and 23 in this presentation are behind the constraint or constraints that govern Bellota. If they are, GreenGen asks the CAISO to please explain how they were adjusted so that they do not displace the deliverability needed for the LDES mapped at Bellota.

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 projects presentation

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 2026-2027 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 23-24, 2026.

The City has completed its transmission planning studies including the Warnerville–Newark Transmission Expansion Project (WaNTEP), a 230 kV reconfiguration of its existing approximately 70-mile Warnerville–Newark 115 kV transmission corridor. Using the 2036 Greater Bay Area Summer Peak case, the City's studies show that WaNTEP helps address several reliability issues identified in the CAISO Preliminary Reliability Assessment:

• Lone Tree–Cayetano 230 kV line. The CAISO identified near- and long-term overloads on this line under P0 through P7 contingencies.[1] In the City's studies, WaNTEP reduces loading on this line for the P7 outage of the Tesla–Newark No. 2 and Newark–Los Esteros 230 kV lines from about 100% to about 96% of the facility rating. The P0 loading is also reduced from about 101% to about 97%.
• Cayetano–North Dublin 230 kV line. The CAISO identified long-term overloads on this line under P2 contingencies.[2] In the City's studies, WaNTEP reduces loading on this line for the P2 outage of the Newark D Section 1D and Newark E Section 1E 230 kV bus sections from about 100% to about 95% of the facility rating.
• Las Positas–Newark 230 kV line. The CAISO identified near- and long-term overloads on this line under P2 and P7 contingencies.[3] In the City's studies, WaNTEP reduces loading on this line for the P2 outage of the Newark D Section 1D and Newark E Section 1E 230 kV bus sections from about 105% to about 94% of the facility rating. The overload for the P7 outage of the Contra Costa–Moraga Nos. 1 & 2 230 kV lines is also reduced from about 103% to about 98%.
• Trimble–NRS 230 kV line. The CAISO identified long-term overloads on this line under P1, P2, and P7 contingencies.[4] In the City's studies, WaNTEP reduces loading on this line for the P7 outage of the Tesla–Newark No. 1 and Tesla–Ravenswood 230 kV lines from about 110% to about 99% of the facility rating.
• Los Esteros–Metcalf 230 kV line. The CAISO identified near- and long-term overloads on this line under P2 contingencies at Newark and Metcalf.[5] In the City's studies, WaNTEP brings this line within its rating for several P2 and P6 contingencies. For example, loading for the outage of the Tesla–Newark No. 1 and No. 2 230 kV lines falls from about 100% to about 93%.
• Metcalf–Monta Vista 230 kV path. The CAISO identified near-term overloads under one P7 contingency on the Monta Vista–Hicks, Saratoga–Monta Vista, and Metcalf–Hicks 230 kV lines. It also identified long-term overloads on those lines, and on the Metcalf–Vasona 230 kV line, under P1, P2, and P6 contingencies.[6] In the City's studies, WaNTEP reduces post-contingency loadings on these lines by about 1 to 5 percentage points. While this does not eliminate the overloads, it would reduce the scope of any additional mitigation needed on this path.

The CAISO has indicated that it will conduct a comprehensive review of mitigations for these and other long-term overloads in the East Bay, Diablo, Mission, South Bay, and De Anza areas. Its potential mitigations include flow control or capacity increase solutions on the Contra Costa–Newark 230 kV path[7], a 230 kV line upgrade on the Metcalf–Monta Vista path, and solutions that introduce new sources to the area.[8] The City asks the CAISO to consider the benefits of WaNTEP described above when it evaluates potential mitigations for these issues.

[1] CAISO September 23rd Presentation, p. 24.

[2] Ibid.

[3] Ibid.

[4] CAISO September 23rd Presentation, pp. 27 and 33.

[5] Ibid.

[6] CAISO September 23rd Presentation, p. 26.

[7] CAISO September 23rd Presentation, p. 24.

[8] CAISO September 23rd Presentation, pp. 26, 27, and 33.

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 projects presentation

No comments at this time.

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

No comments at this time.

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

No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

No comments at this time.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 projects presentation

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

The Large-scale Solar Association (LSA) appreciates the opportunity to comment on CAISO's preliminary findings from the Energy-Only (EO) Resources Assessment. LSA supports CAISO's effort to inform the CPUC's Slice of Day discussion by evaluating whether EO resources can reliably deliver energy to charge batteries during off-peak hours. Because these results may shape how EO resources are treated in resource adequacy policy, the study's methodology needs to be transparent and defensible. These comments request additional transparency about the study methodology and question whether the methodology is aimed at the right issue.

The assessment lacks a clear methodology description.

LSA has not found a clear written description of the methodology behind the preliminary results.  The materials presented during the September 23, 2026, stakeholder call provide a high level description of the methodology, but there is not enough detail to fully understand the results.  For example, LSA's understanding, based on CAISO's statements at various stakeholder meetings, is that FCDS resources are dispatched first and EO resources fill whatever transmission capacity remains. LSA believes that this “leftover space” approach may be appropriate but deserves careful review since this approach does not match the way the market dispatches. At a minimum, the dispatch methodology should be transparent so that stakeholders can fully understand the implications for EO resources.

The assessment may misdescribe the battery charging question.

For charging sufficiency, what matters is how much total energy can reach the batteries during off-peak hours. Even though the current on-peak deliverability assessment measures how much capacity can reach the aggregate of load on the CAISO system, this charging sufficiency-focused assessment should measure how much energy can reach batteries.  The materials from the September 23, 2026 stakeholder call indicate that CAISO “evaluated whether EO resources can reliability deliver energy across the transmission system to charge batteries during off-peak hours… .” [1]  The current approach does appropriately focus on off-peak hours, but it is unclear whether it measures how much energy can reach batteries v. the aggregate of load.  CAISO should clarify this assumption and if the methodology measures how much energy can reliability deliver to the aggregate of load, as it does for the on-peak deliverability assessment, CAISO should explain how this is relevant to the question of whether EO resources can reliably charge batteries. 

Requests for the November stakeholder meeting

LSA asks CAISO to provide a clear written description of its methodology with the final results in November, and to address the following questions:

1. What is the exact dispatch and curtailment order among FCDS resources and EO resources and what is CAISO's rationale for it?
2. Does the off-peak assessment measure how much energy can reach the aggregate or load or batteries and what is CAISO’s rationale?

LSA appreciates CAISO's consideration of these comments and looks forward to the November results.

[1] See slides 312 – 316 at https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2026-2027-Transmission-Planning-Process-Sep-23-2026.pdf

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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

LS Power Grid California, LLC ("LS Power") appreciates the opportunity to comment on the preliminary reliability results for the PG&E Bulk system presented on September 23-24, 2026.

The preliminary reliability results identify a reliability need on the corridor where CAISO found an economic need last cycle

In the 2025-2026 Transmission Plan, CAISO's economic assessment identified congestion on the Path 15 corridor and portions of Path 26 and found that a new Windhub–Tesla 500 kV line tied into the Midway and Gates 500 kV substations (Alternative 6) was the most economically favorable longer-term alternative. CAISO said it would consider recommending that alternative for approval in this planning cycle after a bulk system reliability assessment and noted that its scope "may need to be fine-tuned" after that assessment.[1] That alternative was defined and evaluated as a congestion-relief measure in production cost simulation; its terminations were not selected for reliability performance.

The 2026-2027 preliminary reliability results now show reliability issues on the same corridor. In the 2036 summer peak case CAISO reports:[2]

• Gates–Midway 500 kV at 124–126% for single-element and bus/breaker contingencies (P1, P2);
• Los Banos–Gates #3 and Manning–Gates 500 kV at 146–148% for P6 contingencies;
• Manning–Harlan 500 kV at 117–121% (P1, P2) and Harlan–Midway 500 kV at 124% (P6);

CAISO attributes these overloads to heavy south-to-north Path 26 flow and notes that the P6 contingencies remain to be investigated. The need is not limited to the 2036 peak: Harlan–Midway is overloaded for the loss of Gates–Midway and Gates–Diablo in the 2028 spring off-peak case (111%) and in the 2031 off-peak cases (103–115%), and Gates–Midway is at 104–107% in the 2036 summer off-peak case.

These results support the need for a new Windhub–Tesla line on a reliability basis, in addition to the economic basis identified last cycle.

A Windhub–Tesla line tied into Manning and Orchard is a strong reliability solution to these overloads and should be among the configurations CAISO evaluates in its bulk system reliability assessment.

To test this, LS Power added the Windhub–Tesla line to CAISO's posted 2036 summer peak bulk case and ran CAISO's PG&E Bulk and Southern Bulk contingency files for four tie-in configurations: the Midway and Gates configuration of Alternative 6, and configurations using LS Power's Orchard and Manning stations. Table 1 compares the configurations on reliability performance alone, against CAISO's posted pre-project loadings. The following findings stand out.

1.  Orchard performs the same as Gates as a tie-in point. With the Midway tie retained, routing the line through Orchard instead of Gates gives the same loadings on every facility in Table 1. The Orchard–Gates 500 kV ties, rated at 2554 MVA each, are not a limiting element for any contingency studied, including with additional generation dispatched at Gates.

2.  A Manning tie fully relieves the Gates-area overloads. With the line tied at Manning, Los Banos–Gates #3 and Manning–Gates fall from 146–148% to below 90%. With the tie at Gates or Orchard they fall to 93–94%.

3.  Tying into both Orchard and Manning captures both effects. Interconnecting to Manning and Orchard mitigates overloads on Gates-Midway (125% to below 90%), Manning-Gates and Los Banos – Gates #3 500 kV (147% to 93%) and Manning – Harlan (120% to below 90%).  These impacts are similar to results observed when the project ties in at Midway and Gates or Manning substations.

All configurations also relieve Tesla–Los Banos 500 kV (120% to below 90%) and Metcalf–Moss Landing 500 kV (116% to below 90% for the Manning–Metcalf and Tesla–Los Banos P6), which bears on CAISO's observations about the Tesla–Metcalf–Moss Landing loop.

Beyond the reliability results, three considerations favor Manning and Orchard as tie-in points:

Substation expansion. CAISO has recognized that a short-circuit duty study is needed to assess substation expansion for this reinforcement, and that the cost estimates in last cycle's economic assessment did not include substation upgrade costs that could be significant for some of the existing stations [3].

• Manning substation is currently under construction, and the project team is already working on preliminary design for expansion to accommodate Manning – Metcalf line termination and Cluster 15 projects. There will be space available to add a new loop in.
• Orchard has expansion space on the east side, clear of the existing 500 kV bus. The new line can be routed on the east side of the existing 500 kV corridor into that area, avoiding crossings of energized circuits and the outage coordination, structure heights and right-of-way they require.

At Manning, now under construction, and at Orchard, where expansion space is available, short-circuit duty can be addressed in design. At existing stations it is a retrofit, requiring equipment replacement or substantive reconfiguration.

Manning is where the corridor divides. Manning is the southern terminal of the Manning–Metcalf 500 kV line as well as a station on the Midway–Los Banos path. A tie at Manning places the new capacity where flow splits toward Metcalf and toward Los Banos and Tesla as shown in Figure 1 below.

Figure 1. Simplified 500 kV Corridor along Path 26

Resources. In its policy-driven assessment CAISO adds to the CPUC portfolio the transmission plan deliverability already allocated to interconnection requests that has no corresponding resource in the portfolio ("unaccounted for TPD"). CAISO's tabulation of those amounts includes 782 MW at Manning 500 kV and 924 MW at Gates (541 MW at 500 kV and 383 MW at 230 kV), in addition to the portfolio resources mapped to both substations.[4] Tying the new 500 kV line into Orchard and Manning can help with any potential constraints identified in the Policy Study that are associated with these resources.

Requests

LS Power respectfully asks CAISO to:

1. Evaluate Windhub-Tesla 500 kV with connections to LS Power’s Manning and Orchard substations.
2. Report the reliability impact of this configuration, along with the preliminary economic assessment results at the November 18, 2026 stakeholder meeting if available and include it in the draft 2026-2027 Transmission Plan.
3. Compare the alternatives on total cost, including short-circuit mitigation and substation expansion at each terminal.
4. Post the modeling files for the alternatives studied to the Market Participant Portal so that stakeholders can review the results.

LS Power would be open to share its power flow models and results with the CAISO staff.

Table 1. 2036 summer peak loading (%) with and without the Windhub–Tesla 500 kV line, by tie-in configuration

Notes to Table 1: "CAISO posted" values are from CAISO's September 23 slides 134–137, or from the August 14 preliminary results where a row is not on the slides (Manning–Harlan P1-2 and Tesla–Los Banos). Post-project values are LS Power's results on CAISO's 2036 summer peak bulk case; the Gates and Orchard configurations gave identical values and share a column. "<90" means below the 90% monitoring threshold used in the study. The line was modeled with a triple bundled 954 ACSR Cardinal conductor and 70% series compensation

[1] California ISO, 2025-2026 Transmission Plan (Board approved May 19, 2026; updated version Board approved August 27, 2026), Executive Summary pp. 10–11; Chapter 4 (Economic Planning Study), section 4.5.3 (Path 15 Corridor) pp. 124–128 and section 4.6 p. 129, https://www.caiso.com/documents/board-approved-2025-2026-transmission-plan.pdf; Appendix G (Production Cost Simulation and Economic Assessment Detailed Results), section G.9.3, pp. G-71 to G-73, https://www.caiso.com/documents/board-approved-2025-2026-transmission-plan-appendix-g-economic.pdf.

[2] California ISO, 2026-2027 Transmission Planning Process stakeholder presentation, September 23, 2026, Bulk System preliminary reliability assessment results, slides 134–137, https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2026-2027-Transmission-Planning-Process-Sep-23-2026.pdf; California ISO, PG&E Bulk preliminary reliability results (thermal overloads), posted August 14, 2026, https://stakeholdercenter.caiso.com/InitiativeDocuments/North-Bulk-2026-2027-Transmission-Planning-Process-Preliminary-Results.pdf.

[3] California ISO, 2025-2026 Transmission Plan, Appendix G, pp. G-59 and G-73, https://www.caiso.com/documents/board-approved-2025-2026-transmission-plan-appendix-g-economic.pdf.

[4] California ISO, 2026-2027 Transmission Planning Process stakeholder presentation, September 24, 2026, Policy-Driven Assessment Update, "Unaccounted for TPD Allocation," slide 19 (definition) and slides 20–25 (tabulation by substation; Manning and Gates rows on slide 24), https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2026-2027-Transmission-Planning-Process-Sep-24-2026.pdf.

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

The Windhub–Tesla reinforcement would parallel the Midway–Whirlwind and Midway–Vincent 500 kV lines, where CAISO reports overloads and lists potential mitigation options.[5] LS Power’s analysis shows that the proposed Windhub–Tesla alternative is also effective in mitigating some of the overloads reported in the Southern CAISO Bulk assessment.

[5] California ISO, 2026-2027 Transmission Planning Process stakeholder presentation, September 23, 2026, Southern Bulk preliminary reliability assessment results, slides 151–152 (Midway–Vincent and Midway–Whirlwind 500 kV) and slide 153 (SCE Northern 500 kV lines), https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2026-2027-Transmission-Planning-Process-Sep-23-2026.pdf.

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

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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

No comment at this time

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

Ormat urges CAISO to upgrade the Control area as a long-term investment in California’s access to clean firm geothermal power and a no-regrets solution in the best interests of ratepayers. Relying on congestion management and redispatch severely impairs existing clean firm power from reaching load centers and sends a forward signal to developers to avoid building more clean firm power.

Ormat is one of the largest developers and suppliers of geothermal power in California and Nevada. As a developer, owner, and operator of geothermal energy facilities in California and Nevada, Ormat and its affiliates are committed to well-structured markets and processes that encourage the development and procurement of high-quality generation resources and promote the best value for ratepayers.

Significant geothermal generation in the Mammoth Lake area is constrained by limits in the Control-Inyokern corridor, as is the import of Nevada geothermal through the Silver Peak intertie. Access to this clean, firm power is reliant on transmission upgrades. Currently, geothermal in this region is routinely curtailed, including approximately 140,000 MWh in 2025. Levels of congestion reflect persistent constraints that discourage further development. Resources in the area are also exceptionally dispatched with a frequency that suggests CAISO’s current TPP modeling of the area may be lacking.

CAISO’s preliminary results for the North of Lugo area reinforce the need to address transmission constraints in this region. The reliability assessment identifies multiple overloaded facilities in and around the Kramer system, including the Sandlot–Kramer 230 kV line, Kramer transformers, and Kramer–Coolwater facilities. CAISO also identifies redispatch of the Kramer, Coolwater, Inyokern, and Control 115 kV system as a mitigation for some identified overloads. However, the preliminary assessment does not identify a transmission upgrade to increase transfer capability between Control, Inyokern, and Kramer. Instead, CAISO primarily relies on congestion management, redispatch, and remedial action schemes to address the identified constraints, while the previously approved Kramer–Coolwater 115 kV project remains on hold and was not modeled in the assessment. These operational mitigations may address near-term reliability violations, but they do not address the underlying transmission limitation or provide the additional transfer capability needed to support existing and future geothermal generation.

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

No comment at this time

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

Ormat appreciates SCE’s evaluation of reliability needs in the North of Lugo area and its proposed Coolwater CRAS. However, the proposed CRAS addresses contingency-related thermal violations through generation tripping rather than increasing transmission capability in the broader Control–Inyokern–Kramer area. SCE also notes that the TPP base cases did not model full generation output in the 230 kV corridor and that, at higher dispatch levels, additional infrastructure considered by SCE was insufficient to mitigate the resulting thermal overloads. Given existing geothermal curtailment and the potential for additional geothermal development in the region, Ormat encourages SCE to evaluate transmission solutions that would increase transfer capability from the Control and Inyokern areas, rather than relying solely on operational measures and remedial action schemes to manage constraints.

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

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

No comment at this time

10. Provide your organization's comments on the Energy-Only Resources Assessment Preliminary Findings discussion.

No comment at this time

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

No comment 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 projects presentation

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

Pacific Gas and Electric Company (PG&E) appreciates the opportunity to comment on the CAISO’s September 23 to 24 Transmission Planning Process (TPP) workshop presentations.  PG&E offers the following comments in response to CAISO’s presentation of its Energy-Only Resource Assessment study and preliminary findings.

1. PG&E Appreciates CAISO’s Efforts to Assess Deliverability of Energy-Only Resources

As the CAISO’s presentation on September 23rd recognized, PG&E and a number of other parties have proposed modifications to the CPUC’s Resource Adequacy (RA) program to more reasonably account for the reliability contributions of energy-only (EO) resources to the CPUC’s Slice of Day (SOD) charging sufficiency requirement.  PG&E recognizes the effort involved and appreciates that the study presented by CAISO offers some preliminary additional insight into the ability of EO resources to deliver energy across the transmission system and contribute to the charging of energy storage resources.  With that said, it is important to recognize the limitations of the study, as presented thus far, with respect to the CPUC’s SOD framework.  Firstly, it is PG&E’s understanding that this study examines a single hour (HE 11) during a 2036 summer off-peak scenario.  While this is a step towards a more comprehensive view of deliverability, it is not aligned with the hourly SOD framework.  Relevantly, four-hour energy storage resources charge over multiple hours.  Thus, evaluating deliverability for a single hour may produce overly conservative results as it pertains specifically to the CPUC’s charging sufficiency requirement.  PG&E believes the study should evaluate how much energy from EO resources can be made available during the day for deliverable energy storage to discharge during the system on-peak window.

The CAISO’s study may be conservative in the near-term period prior to the 2036 studied scenario.  If generation and load interconnection outpaces transmission development in the CAISO’s 2036 scenario, modeled curtailment results could reflect a more constrained system than the near-term reality.  To allow parties time to examine that question, PG&E requests that CAISO provides further information regarding the 2036 system assumptions as well as the curtailment results using system assumptions that reflect the near-term system reality.

In order to facilitate further examination of these results, PG&E appreciates CAISO’s commitment to providing additional information in November 2026 regarding curtailment amounts and locations.  PG&E specifically requests that CAISO provide the total number of all modeled resources in each study area, including FCDS, PCDS, and EO resources by resource type.  PG&E also requests the CAISO provide actual curtailment volumes by resource type and deliverability status in each study area.  This information is critical as the CPUC, and other parties, further consider whether EO resources should be eligible to meet LSEs’ charging sufficiency requirements under the SOD framework.  In PG&E’s view and based on its analysis submitted in the CPUC’s RA proceeding, EO resources are likely contributing at some level to charging sufficiency.  However, CAISO’s initial study results and presentation do not provide enough information for the CPUC to make a more robust determination on the eligibility of EO resources to meet LSEs’ charging sufficiency requirements.[1]  Additionally, PG&E requests more information regarding resource re-dispatch, assumption adjustment, or Remedial Action Schemes (RAS), by study area, that may have been performed to mitigate any modeled overloads.  PG&E would appreciate more information regarding these adjustments, to understand how they are being applied across zones and scenarios, and whether they impact modeled curtailment results under different contingencies.

2. PG&E Requests Additional Information Regarding Deviation from CAISO’s 2026-2027 TPP Study Plan

CAISO’s 2026-2027 Transmission Planning Process (TPP) Final Study Plan, published on June 15, 2026, outlines a series of methods and assumptions “intended to capture a reasonable scenario for the load, generation, and imports that stress the transmission system, but not coinciding with an oversupply situation.”  Included in these assumptions are Table 3.5-2: ISO System-Wide Generator Dispatch Assumptions that stipulates a 15 percent dispatch assumption for thermal resources.  However, CAISO’s presentation on September 23rd described dispatch assumptions for thermal resource of 100 percent.  PG&E’s interpretation is that an inconsistency exists between the two studies and requests the CAISO confirm if PG&E’s understanding is accurate.  If not, CAISO should provide its rationale for having different thermal resource dispatch assumptions.  PG&E has concerns regarding this potential inconsistency and whether it may create an oversupply situation, which CAISO expressed a desire to avoid, and overstate EO curtailment.

To support stakeholders’ understanding of the study results and facilitate alignment with the CAISO’s study approach, PG&E requests CAISO provide additional documentation describing the study methodology, assumptions, and any significant deviations from the June 15 TPP Final Study Plan.  Such information would help stakeholders better assess the applicability of the results and understand how the study outcomes were derived.  At a minimum, PG&E requests the CAISO provide information on load level, import assumptions, production duration curves, production levels, dispatch assumptions for all resource types and deliverability categories, energy storage charging and discharging assumptions, and any adjustments by study area (if applicable).

[1] For example, CAISO’s results only showed that a curtailment has occurred or has not occurred.  However, it is also important to know the level of curtailments because, while a curtailment can occur, it could also contribute to charging energy storage resources if it is not a 100 percent (i.e., full) curtailment.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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

Santa Clarita Valley Water Agency (SCV Water) appreciates the opportunity to comment on CAISO’s preliminary reliability results.

CAISO identifies significant thermal overloads at both Gates 500 kV and Manning–Gates 500 kV during the 2036 Summer Peak, driven primarily by heavy south-to-north flows on Path 26. Gates 500 kV reaches approximately 125 percent of its applicable rating under several P1 and P2 contingencies, while Manning–Gates reaches approximately 147 percent under P6 contingencies. These results demonstrate substantial transmission limitations.

These overloads are particularly concerning given the significant renewable buildout planned for the Kern and Fresno interconnection study areas. CPUC’s latest Integrated Resource Plan includes over 1,300 MW of solar at the Arco 230 kV substation including 455 MW of Energy Only Deliverability Status solar. The Gates–Manning 500 kV area constraint is the most significant constraint in the Fresno area with zero available Transmission Plan Deliverability, affecting 102 Points of Interconnection (“POIs”), and the Gates 500/230 kV transformer area constraint currently leaves only 85 MW of available TPD to serve 180 POIs. Without additional transmission capacity, these constraints will limit the ability of planned resources to achieve deliverability and contribute to California’s resource needs.

SCV Water urges CAISO to identify and advance transmission upgrades that resolve the Gates and Manning–Gates constraints and materially increase deliverability available to new resources in the Kern and Fresno areas. Given the magnitude of the modeled overloads, the limited TPD currently available, and the volume of resources contemplated in the CPUC portfolio, CAISO should evaluate these upgrades as a priority in the current TPP rather than relying on operational mitigation or deferring investment to future planning cycles.

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 projects presentation

While SCV Water appreciates PG&E’s proposed local reliability upgrades in the Kern area, we encourage PG&E and CAISO to consider whether additional bulk transmission upgrades could more effectively address the significant constraints identified in the broader Kern/Path 26 area and provide greater long-term transfer capability.

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

No comments at this time

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

No comments at this time

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

SCV Water appreciates CAISO’s presentation of its preliminary results for its energy-only charging sufficiency resource assessment. The question of the potential contribution of energy-only resources to storage charging sufficiency is critical both to developers and to load-serving entities throughout the state.

The top-line findings are positive, demonstrating that large volumes of energy-only resources’ production are deliverable during charging hours. Given this early finding, SCV Water urges CAISO to expand its analysis with more timely and detailed evaluations, focusing on upcoming delivery years rather than 2036 and examining the four lowest-price hours in a peak market day. Because storage charges at the lowest price and greatest availability, the modeling of a peak constraint hour may underestimate the value of EO resources, while basing EO decisions on less-constrained days may overstate its dependable charging contribution. Moreover, because RA sufficiency is now evaluated on a slice-of-day basis rather than solely during the peak hour, understanding EO deliverability across potential charging hours is necessary for stakeholders and regulators to evaluate a resource’s contribution to storage charging sufficiency.

SCV Water looks forward to CAISO’s presentation of its methodology and results in the planned November stakeholder meeting. The analytical value of the assessment CAISO performs is heavily dependent on the model assumptions and formulation, and stakeholder feedback will assist CAISO in refining it. Prior to the November meeting, CAISO should release a more detailed report describing its methodology, assumptions, and results, allowing stakeholders to meaningfully evaluate the analysis in advance. In particular, CAISO should provide quantitative results for each study area, including the amount of energy-only capacity evaluated, the quantity and share of production that is deliverable during the modeled charging hours, and the magnitude of any curtailment or other deliverability limitations. Providing this information in advance would allow the November meeting to focus on substantive discussion of the methodology, results, and potential refinements.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

No comments at this time

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

Slide 34 lists 6 transformer banks and more than a dozen transmission lines that are at risk for overloads “in the longer-term scenarios,” but apparently proposes no mitigation. Is it generally the CAISO position that it does not need to propose mitigation at this time for all identified overloads, particularly in 2041 cases, because there is enough time between now and 2041 to perform a “comprehensive review and assessment.”

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

• 1. Slide 144 describes case BB8 as a 2036 off-peak case when it is actually a 2031 case (as shown on slides 145, 146, and 148. Please correct this error.

  2. Slide 164 describes case B8 as a 2036 off-peak case when it is actually a 2031 case (as shown on slides 165, 166, and 168. Please correct this error.

  3. On slide 155, the text refers to overloads in cases B1, B5, S1, and S2. But the single-line graphic refers to overloads in cases B1, B2, B3, B5, S1, and S2.

  a. Do cases B2 and B3 have overloads or not?

  b. Why are there no overloads in case B4, which has higher loads than case B3?

  4. Slide 156 says that a mitigation option is to “manage pre-contingency flow for P7” outages.

  a. Is it correct that this would be done by rejecting scheduled generation that would not cause overloads under P0 conditions but would lead to overloads under P7 conditions? If not, what is the mechanism to “manage pre-contingency flow”?

  b. Is it CAISO policy to allow pre-contingency restrictions on generation schedules as an alternative to reinforcing the grid to prevent overloads?

  5. In Slide 160, converting an existing Vincent-Mesa 230 kV line to 500 kV is described as, inter alia, addressing P7 contingencies. This was discussed during the 9/23 meeting. Please confirm that the 230 to 500 conversion would not resolve the P7 contingency, because there would still be two Vincent-Mesa lines subject to outage from the same event.

  6. Slide 170 indicates that in a case with 6867 Mw of generic storage modeled by the CAISO, over 70 percent of it would need to be curtailed under P0 conditions, and about 97% would need to be curtailed under a P7 contingency.

  a. How much of the potentially required curtailment could be eliminated by locating the generic storage at or north of Vincent, or at or east of Mira Loma or Serrano?

  b. How much of the potentially required curtailment could be eliminated by spreading the required Mwh of charging across multiple hours, including night hours when wind and fossil generation would be available?

  c. In order to support maximum battery discharge for 4 hours, how many charging hours would be required at half the maximum charging rate, assuming the starting point was zero percent charged?

  7. In the CAISO’s SCE modeling, cases B3 and B5 are both summer 2036 cases, with B3 described as “on-peak” and B5 described as “off-peak.” From the point of view of stresses on the transmission system, charging load for batteries or for long-term storage needs to be added to customer load to determine the total load on the system. By assuming maximum charging load at 11 am, the CAISO has created “off-peak” B3 cases with total loads far higher than in the “on-peak” B5 cases. In particular, slides 165 and 166 show an SCE Main load of 33,808 Mw (net load) + 3612 Mw (charging load) = 37,420 Mw in case B3, and an SCE Main load of 27,182 Mw (net customer load) + 24,736 Mw (charging load) = 51,918 Mw in case B5. Thus generation at HE11 on the peak day in 2036 would need to be about 14,498 Mw (39%) higher than at the HE18 time of peak customer load. Batteries are also shown as charging at the time of both winter and summer peak loads in 2041 (slide 166, cases B4 and B6).

• a. Please explain why the CAISO believes this is a representative, or even a plausible, off peak scenario.

  b. Please explain why the CAISO expects thousands of Mw of charging load at the time of peak load in both summer 2036, summer 2041, and winter 2041? When are these batteries expected to be discharging, if they are charging in both the on-peak and off-peak scenarios?

  8. In the CAISO’s SDG&E modeling, cases B3 and B5 are both summer 2036 cases, with B3 described as “on-peak” and B5 described as “off-peak.” From the point of view of stresses on the transmission system, charging load for batteries or for long-term storage needs to be added to customer load to determine the total load on the system. By assuming maximum charging load at 11 am, the CAISO has created “off-peak” B3 cases with total loads far higher than in the “on-peak” B5 cases. In particular, slides 275 and 276 show an SDG&E net load of 5758 Mw in case B3, and an SDG&E load of 4163 Mw (net load) + 4179 Mw (battery charging) + 500 Mw (long duration storage charging) = 8842 Mw in case B5. Thus generation at HE11 on the peak day in 2036 would need to be about 3084 Mw (53%) higher than at the HE18 time of peak customer load. Please explain why the CAISO believes this is a representative, or even a plausible, off peak scenario.

  9. Slide 242 shows, in section 3, that the P6 loss of Serrano-Valley and either of Cielo Azul-Colorado or Palo Verde-Colorado results in divergence, which can be avoided by reducing BESS charging.

  a. Is it the CAISO’s position that planning for reductions in BESS charging is an acceptable mitigation for divergence?

  b. Would a second line west from Valley (either Valley-Serrano or Valley-Recon) avoid these P6 divergence cases?

  c. Has the CAISO ever considered the benefits of adding a second line west from Valley, given that the current system has two 500 KV lines all the way from Arizona to Colorado to Red Bluff to Devers to Valley, but only one 500 kV line west of Valley? If not, is it willing to do so in this planning cycle?

  10. Slide 279 shows hourly net load on the peak day for SDG&E in four different years. Please provide a similar page showing net load plus battery charging?

  11. Slide 280 shows various components of load for the peak day in 2041.

  a. Please provide a similar page for 2036

  b. Please provide similar pages for 2036 and 2041 showing battery and LDES charging loads as well (behind-the-meter charging is already shown on slide 280, but not front-of-the-meter charging).

  12. Slide 282 identifies an overload of the Hoodoo Wash-Hassayampa 500 kV line to 108% of its normal rating after a P1 outage of the Hoodoo Wash-North Gila line, with the proposed mitigation being to “reduce gen output of Hoodoo Wash solar resources for P1 contingencies.”

  a. Is the reduction in Hoodoo Wash generation assumed to occur after the P1 contingency, or in anticipation of it?

  b. What is the emergency rating of the Hoodoo Wash-Hassayampa line as a percentage of its normal rating, and would it be high enough to allow post-contingency mitigation after a P1 outage without exceeding the emergency rating?

  c. The busbar mapping diagram provided by the CAISO for the September 23-24th sessions shows 2805 Mw of Pmax solar at Hoodoo Wash, and 298 Mw Pmax of lithium battery storage there. What were the assumed operating levels of those two resources pre-contingency in the case that results in the P1 overloads described in slide 282?

  13. Slide 289 identifies multiple thermal overloads associate with P3 and P6 contingencies and a low voltage problem in the S1 case. In which case(s) do the thermal overloads occur?

• 14. The CAISO has been requested to study a Dunes-Devers 500 kV line and a Cielo Azul-Imperial Valley 500 kV line. The same entity also requested that the CAISO study a 2nd IV-Recon line, as was discussed verbally on September 23-24th.

  a. Was this an oversight, or has the CAISO made a decision not to study IV-Recon #2? And if so, why?

  b. In studying the Dunes-Devers proposal, will the CAISO consider it only as an incremental facility over and above the planned-but-not-yet-built North Gila-IV #2 and IV-Recon lines? Or will the CAISO also study the economic and policy impact of this proposal as an alternative to one or the other or both of those two lines?

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

No comments

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

1. SCE’s presentation made no mention of the now-abandoned Mesa-Del Amo-Serrano 500 kV project approved in the 2022-23 transmission plan. What is the CAISO position regarding the appropriateness of previously approved projects being dropped:

a. By their proponents (SCE, in this case)

b. By the CAISO after restudy

c. In response to changed grid configuration (load changes, changes in generation such as battery installations, etc.)

d. In response to changes in cost

e. In response to analyses by non-proponents

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

No comments

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

1. SDG&E provides estimated costs of $235 million to reconductor four 69 kV lines in the Border load pocket, and $422 million to reconductor four lines in the Del Mar load pocket.

a. What are the costs per mile that underlie these reconductoring cost estimates?

b. How do these costs compare to the cost of other alternatives?

2. This is a comment about the CAISO's 9/24 presentation, for which no comment block has been provided. It is included here because it is about the SDG&E system: 

Slide 18 is labeled as SDGE, but is not. This was discussed on 9/24. Please update the slide deck to include the correct slides.

3. This is a comment about the CAISO's 9/24 presentation, for which no comment block has been provided. but is included here because it is about the SDG&E system:

The CAISO has been requested to study a Dunes-Devers 500 kV line and a Cielo Azul-Imperial Valley 500 kV line (Slide 35). The same entity also requested that the CAISO study a 2nd IV-Recon line, as was discussed verbally on September 23-24th.

a. Was the omission of IV-Recon #2 from Slide 35 an oversight, or has the CAISO made a decision not to study IV-Recon #2? And if so, why?

b. In studying the Dunes-Devers and Cielo Azul-IV proposals, will the CAISO consider them only as incremental facilities over and above the planned-but-not-yet-built North Gila-IV #2 and IV-Recon lines? Or will the CAISO also study the economic and policy impact of these proposals as an alternative to one or the other of those two lines?

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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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 2026-2027 Transmission Planning Process. The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 23-24, 2026. SVP acknowledges the significant efforts of the CAISO and PTO staff to develop this material. 

Request for CAISO to Include SVP in the Development of Potential Mitigations Being Further Evaluated This Cycle

SVP appreciates CAISO’s efforts to develop comprehensive solutions to address the reliability issues identified in the San Jose[1] area, including the long-term overloads on the Metcalf 500/230 kV and 230/115 kV transformer banks, the Trimble–Northern Receiving Station (NRS) 230 kV line, and the San Jose B 230/115 kV transformers. As CAISO continues to evaluate and develop comprehensive mitigation alternatives for these overloads, SVP requests that CAISO coordinate with affected system owners, including SVP, during the development and evaluation of potential mitigations, particularly where the proposed solutions may impact neighboring or interconnected systems.

Additionally, SVP requests that CAISO provide sufficient technical details, scope, and cost estimates for these mitigation alternatives with adequate time for stakeholders to review and provide meaningful input before the solutions are finalized or recommended for approval. Providing this information early in the development process will help ensure that potential impacts, alternatives, and costs are appropriately considered as part of the stakeholder process.

Request to Evaluate and Address Short-Circuit Duty Impacts on the SVP System in Current Planning Cycle

In recommending removal of the hold status on the De Anza 115 kV Substation Project and the South Bay Reinforcement Project (Revised Scope Item G), CAISO acknowledged that the short-circuit duty concerns identified by SVP are regional impacts associated with multiple transmission projects, and committed to continue coordinating with SVP and PG&E through the 2026-2027 TPP to evaluate and address those impacts.[2] SVP’s analysis indicates that these impacts are driven primarily by the Tesla–Trimble–Metcalf 230 kV Corridor Expansion Project and are further increased by the two previously on-hold projects. Of particular concern, the 115 kV breakers planned to be installed in 2029 at NRS are already rated at 80 kA, the highest commercially available rating for this voltage class, yet are projected to approach or exceed their duty ratings. Therefore, further increases in fault current at NRS will not be able to be addressed by breaker replacement alone; mitigation of the projected additional impacts will require reactors or system reconfiguration.

For these reasons, SVP requests that CAISO (1) describe the scope and schedule of the short-circuit duty evaluation CAISO committed to for this TPP cycle; (2) include the identified mitigations in the 2026-2027 Transmission Plan; (3) allocate the cost of those mitigations to the projects that cause the impacts, consistent with cost-causation principles; and (4) going forward, include short-circuit duty assessments of affected systems in its project recommendations before Board approval, to avoid repeated post-approval mitigation of previously approved projects.

CEC’s[3] SVP Updated Load Forecast Was Not Applied in Latest Posted Reliability Assessment Cases

SVP provided CAISO with updated load forecasts[4] for use in the CAISO 2026–2027 TPP Preliminary Reliability Assessment cases for the Greater Bay Area (GBA) summer peak conditions for years 2028, 2031, 2036, and 2041. These load updates are consistent with the California Energy Commission’s (CEC) adopted load forecast and should be implemented in the reliability assessment cases. However, SVP’s review of the latest posted reliability assessment cases indicates that these updated load forecasts were only incorporated into the 2028 GBA cases, and were not incorporated into the 2031, 2036, and 2041 GBA cases. Table 1 summarizes the differences between the SVP load currently modeled in the posted cases and the updated load forecast provided by SVP on 07/08/26, and 09/11/26.

Table 1: Comparison of Modeled and Updated SVP Load Forecasts (CEC Forecast)

The differences are material in certain study years, particularly in 2031, where the posted case understates SVP load by approximately 114 MW relative to the updated forecast provided by SVP. Use of the lower load assumptions could materially affect the identification, magnitude, and timing of reliability concerns on facilities serving SVP and the Greater Bay Area. Although the system-level forecast differences are not significant in 2036 and 2041, the bus-level forecasts differ significantly. Accurate bus-level modeling is critical because the location of load directly affects flows on SVP facilities and can materially influence the resulting reliability findings. Table 2 summarizes impactful overloads that appear on the SVP system with the updated bus level forecast.

Table 2: Summary of Overloads With SVP Updated Bus-Level Forecast

As shown in Table 2, use of SVP’s updated bus-level forecast materially changes the reliability results, causing several facilities that remain below their applicable ratings in the posted cases to become overloaded. This further demonstrates why accurate bus-level load modeling is critical, as differences in load allocation can directly affect BES flows and the identification and timing of reliability needs.

SVP requests that CAISO incorporate the updated SVP load forecasts into its final GBA reliability assessment cases and reevaluate the applicable reliability results using the corrected load levels. SVP further requests that CAISO identify any changes to reliability concerns, project need dates, or mitigation requirements resulting from incorporation of the updated forecast and reflect those changes in subsequent reliability assessment results.

SVP Identified P1 Overloads on the NRS–SRS 115 kV Lines Not Identified in CAISO’s Preliminary Reliability Assessment

SVP performed an independent steady-state power flow analysis to assess potential impacts to the SVP system using the CAISO 2026–2027 TPP Preliminary Reliability Assessment cases for the Greater Bay Area (GBA) summer peak conditions for years 2028, 2031, 2036, and 2041.

SVP’s analysis identified a P1 overload on the NRS–SRS 115 kV Lines #1 and #2 beginning in 2036. The overload occurs for the P1 contingency, “COMPONENT_SW-SRS 115KV [0] MOAS OPENED on NRS 300_SRS,” which first appears in the 2036 contingency file and was not included in the 2028 or 2031 outage files. Accordingly, this contingency was not evaluated for those earlier study years. As summarized in Table 3, the NRS–SRS 115 kV Lines #1 and #2 are loaded to 153.6% in the 2036 summer peak case and 168.1% in the 2041 summer peak case under this contingency.

As discussed in the load forecast section, SVP’s supplemental analysis using the updated SVP load forecast provided to CAISO also identified overloads on the NRS-SRS 115 kV facilities as early as 2031 under other P1 contingencies.  These results further demonstrate that the timing and severity of reliability constraints affecting the SVP system are sensitive to both the load forecast and the contingency set modeled in the reliability assessment.

Table 3: Summary of NRS – SRS 115 kV Line Overloads

This contingency represents a non-SVP outage that results in significant overloads on SVP facilities. However, these overloads were not identified in CAISO’s Preliminary Reliability Assessment results for GBA. Given the magnitude of the identified overloads and their impact on SVP facilities, SVP requests that CAISO review and confirm the modeling and results associated with this P1 contingency and evaluate the resulting overloads beginning in 2036. If CAISO confirms the identified reliability issue, SVP requests that CAISO coordinate with SVP and the applicable facility owners to identify and evaluate appropriate mitigation measures as part of the 2026–2027 TPP.

Interim Mitigation Needed for Overloads Prior to In-Service Dates of Previously Approved TPP Projects

CAISO previously approved several transmission projects expected to provide long-term relief for reliability concerns affecting the SVP system and its import facilities, including the Tesla–Trimble–Metcalf 230 kV Project, De Anza 115 kV Substation, and South Bay Reinforcement Rescope Project. However, these projects have estimated in-service dates ranging from 2031 through 2034, with the De Anza 115 kV Substation expected to be in-service in 2031, the South Bay Reinforcement Rescope Project in 2032, and the Tesla–Trimble–Metcalf 230 kV Project in 2034[5].

SVP’s review of the 2026–2027 TPP Preliminary Reliability Assessment cases identifies overloads on SVP facilities and key facilities supporting SVP imports that occur prior to the in-service dates of the previously approved projects intended to provide long-term mitigation. As summarized in Table 4, certain reliability concerns emerge as early as 2028 and become more significant in the 2031 study year.

Table 4: Near-Term Overloads Impacting SVP

While the previously approved projects appear to provide relief for these overloads in the longer-term study cases, SVP remains concerned about the reliability gap between the initial occurrence of these overloads and the expected in-service dates of the associated transmission projects. In particular, CAISO’s results identified overloads reaching 124% in 2028 and up to 142% in 2031, prior to completion of some of the planned long-term improvements.

SVP requests that CAISO evaluate and identify appropriate interim mitigation measures to address these reliability concerns until the previously approved transmission projects are placed in service. Such interim measures could include, as appropriate, updating the Silicon Valley Area operating procedure, i.e., the CAISO’s OP7340, Remedial Action Schemes (RAS), interim facility upgrades, project acceleration, or other feasible mitigation alternatives. SVP further requests that CAISO coordinate with SVP and PG&E in developing these interim solutions and identify the mitigation that will be relied upon for each applicable reliability constraint prior to completion of the long-term projects.

In developing such interim mitigation measures, SVP requests that CAISO avoid reliance on involuntary curtailment or interruption of existing load as a mitigation for reliability constraints that are not caused by SVP facilities or projects.  To the extent CAISO determines that load curtailment is necessary to satisfy applicable reliability criteria, SVP requests that CAISO identify the specific reliability constraint, the circumstances under which curtailment would be required, and the basis for assigning such curtailment to SVP load, and evaluate feasible transmission, operational, or other mitigation measures before relying on load curtailment.

[1] CAISO September 23^rd Presentation, p. 27

[2] CAISO Memorandum to the Board of Governors, Update to the 2025-2026 Transmission Plan (August 2026).

[3] CED 2025 Local Reliability with Known Loads LSE and BAA Tables

[4] SVP provided changes to CAISO in June of 2026

[5] Board Approved 2025-2026 Transmission Plan, May 19, 2026, p.47, 86, 69

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 projects presentation

PG&E’s Proposed North San Jose & De Anza 230 kV System Import Reinforcement Project May Impact SVP’s Reliability

PG&E presented the conceptual North San Jose & De Anza 230 kV System Import Reinforcement project during the September 24 meeting[1]. Under Alternative 1, PG&E proposes a new NSJ Midpoint–De Anza SS 230 kV line along the Newark–NRS 230 kV path. Alternative 1 would also establish a new Los Esteros–NSJ Midpoint 230 kV path using the Los Esteros–Nortech 115 kV right-of-way. Given the electrical proximity of the proposed reinforcement to SVP’s NRS substation, the addition of these new 230 kV sources may increase available fault current and exacerbate existing short-circuit duty concerns at SVP facilities. As noted above, the 115 kV breakers to be installed in 2029 at NRS are already at the highest commercially available rating, so any further increase in fault current at NRS would need to be mitigated through bus reactors or system reconfiguration.

SVP requests that PG&E evaluate the short-circuit impacts to SVP facilities as the project alternatives are further developed, share the results with SVP before the project scope is finalized, and coordinate with SVP regarding the assumptions, study results, and any identified impacts before an alternative is selected and approved. Where an alternative is found to adversely impact SVP facilities, SVP requests that necessary mitigation measures at impacted SVP facilities be incorporated into the overall project evaluation, scope, and cost, so that each alternative can be reviewed with a complete understanding of its impacts.

PG&E’s Proposed Metcalf and East San Jose Reconfiguration Project May Impact SVP

PG&E’s conceptual Metcalf and East San Jose Reconfiguration Project proposes significant changes in and around the Metcalf and San Jose area substations.[2] Because these facilities supply the 230 kV paths into Santa Clara, SVP requests that PG&E coordinate with SVP as the alternatives are refined and demonstrate that the selected alternative will have no more than de minimis steady-state and short-circuit impacts on the SVP system.

SVP Supports PG&E’s Proposed Newark–NRS 115 kV Line Capacity Upgrade and Recommends a 3,000 A Target Rating

PG&E identified the Newark–NRS #1 and #2 115 kV Line Capacity Balancing project as a capacity upgrade associated with the Serial SJ-1 load interconnection, which would super-bundle the two Newark–NRS 115 kV lines (Line Nos. 1 and 2) and remove limiting components to achieve a 2,000 A rating.[3] SVP supports this project. A single, robust 115 kV circuit between Newark and NRS would provide a more reliable and operationally flexible import path to SVP than the two lower-capacity circuits that exist today. The Newark–NRS 115 kV lines are also among the facilities identified in Table 4 as overloaded in the near term.

However, SVP recommends that the target rating be increased to at least 3,000 A rather than 2,000 A. The Newark–NRS 115 kV lines are relatively long, and super-bundling them will require substantial work along the entire route. Given the scale of that effort, the incremental cost of achieving a 3,000 A rating is likely to be modest relative to the cost of returning to upgrade the same facilities again as load in the area continues to grow. In addition, the higher-capacity upgrade could provide an interim mitigation for overloads occurring before previously approved TPP projects can be placed in service, as discussed earlier in SVP’s response to Question 1.

SVP requests that PG&E be required to (1) evaluate and report the incremental cost and feasibility of a 3,000 A rating for the proposed Newark-NRS 115 kV line capacity upgrade; (2) coordinate with SVP on the design, construction schedule, and outage planning for this work, given the importance of these lines to SVP’s import capability; and (3) evaluate the short-circuit impacts of the upgrade at NRS 115 kV consistent with SVP’s request above.

[1] PG&E September 24^th Presentation, pp. 82-86

[2] PG&E September 24th Presentation, pp. 76-81

[3] PG&E September 24th Presentation, pp. 93-94

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

 No comments at this time.

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

 No comments at this time.

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

 No comments at this time.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

 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 continued work identifying reliability needs in Northern California, and in particular its continued study of winter peak and winter off-peak conditions to this cycle's assessmen. SCP's comments focus on the North Coast and North Bay (NCNB) area, which SCP serves, and on the deliverability constraints in the PG&E North of Greater Bay Area (NGBA) that SCP has raised consistently in its 2025-2026 and 2026-2027 TPP comments. The North area results presented on September 23 show a pattern SCP has observed for several cycles: reliability overloads, local congestion and deliverability scarcity are concentrated on the same facilities. SCP urges CAISO to treat these as linked problems with shared solutions, rather than addressing reliability needs through operating measures while deliverability needs go unmet.

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 projects presentation

SCP appreciates that PG&E's stated objectives for this cycle include right-sizing existing assets and rescoping previously approved projects to provide broader long-term value. SCP has encouraged this approach since its October 2025 comments, and offers the following project-specific comments.

Clear Lake-Lower Lake 60 kV Area Reinforcement

SCP supports PG&E's rescope, which establishes a new 115/60 kV source at Lower Lake for approximately $31 million less than the two previously approved projects it replaces. SCP asks that the final design be evaluated against Geyserville-Hopland congestion and Geysers #3-Cloverdale loading, so that the new source also reduces local congestion affecting resources in Lake and Mendocino counties.

Contra Costa-Newark 230 kV Corridor Reinforcement

Consistent with SCP's October 2025 request that upgrades near Newark be reviewed for deliverability benefits, SCP asks that each of PG&E's three conceptual alternatives be scored on NGBA deliverability relief, including the Birds Landing-Contra Costa constraint, and not on reliability performance alone. If minor adjustments to scope could unlock additional TPD, those alternatives should be pursued.

Advanced Conductors

SCP reiterates that PG&E should evaluate advanced conductors in all planned and future reconductoring projects. Their higher thermal limits and reduced sag can increase capacity and deliverability in constrained areas while supporting wildfire mitigation goals.

Large Load Interconnection

Two Load Cluster 2025 projects interconnect on facilities that bind NGBA deliverability. LC25-PS1 is a 1,500 MW load on a new switching station on the Tesla-Table Mountain 500 kV line, with an estimated $1.15 billion interconnection cost, a $100 million STATCOM, and a pending California-Oregon Intertie affected system study and RAS restudy. LC25-29 is a 150 MW load on a new switching station on the Peabody-Birds Landing 230 kV line, with no capacity upgrades identified.

Large new loads at these locations will change flows on the paths that limit NGBA deliverability. Depending on location and operating profile, they could absorb local generation and relieve constraints, or consume transfer capability that generation needs. SCP asks CAISO and PG&E to report how these loads affect deliverability behind the Collinsville and Birds Landing constraints, and to consider whether co-located or nearby generation could serve them while reducing the need for new transmission. SCP also notes that PG&E rejected energy storage as an alternative for LC25-PS1 due to charging constraints, which underscores the importance of the energy-only and charging deliverability analysis discussed in SCP's response to Question 1.

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

No comments at this time.

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

No comments at this time.

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

Geysers 115 kV Reinforcement

The CPUC portfolio maps approximately 410 MW of geothermal to Geysers and Lake County area buses in the 2036 base case: Redbud (241 MW), Cloverdale (112 MW), Rincon (50 MW) and Eagle Rock (7 MW). Delivering this capacity depends heavily on the 115 kV network between the Geysers, Cloverdale, Ukiah, and Cortina. SCP understands that one of the more significant upgrades needed on this network is a Local Deliverability Network Upgrades (LDNUs) assigned to an interconnection project that has not yet executed a Generator Interconnection Agreement (GIA). That leaves the deliverability of the CPUC's geothermal portfolio in this region contingent on the commercial decisions of a single developer. If that project withdraws from the queue, the upgrades go with it, and long-lead-time resources the CPUC has specifically prioritized would again face a multi-year wait for deliverability.

The preliminary reliability results reinforce the need for a durable solution. Geysers #3-Cloverdale 115 kV overloads under P6 contingencies starting in the mid-term; Cortina-Mendocino 115 kV diverges under a P2-3 contingency and overloads under P6; Mendocino-Redbud 115 kV overloads under P6 from the mid-term; and Ukiah-Hopland-Cloverdale 115 kV overloads under P6 in the long term. CAISO's proposed mitigation is an operating solution for Geysers #3-Cloverdale, and the others are listed as under review or to be monitored. The same results also identify non-redundant relay exposure at Cloverdale, Eagle Rock and Mendocino 115 kV. Taken together, the corridor has reliability, deliverability and congestion needs at once.

SCP also notes an inconsistency in how similar needs have been treated across cycles. The Eagle Rock-Fulton-Silverado 115 kV reconductoring was approved as a TPP project in 2024-2025, while comparable Geysers 115 kV upgrades in the 2025-2026 cycle were classified as LDNUs funded by interconnection customers. Consistent with SCP's December 2025 comments, SCP requests that CAISO:

1. Identify which Geysers-area 115 kV upgrades are currently LDNU-dependent, and the status of the interconnection agreement for the project they are assigned to.

2. Evaluate expanded TPP solutions for the corridor that do not depend on LDNUs, including advanced reconductoring of Geysers #3-Cloverdale, Ukiah-Hopland-Cloverdale and Mendocino-Redbud 115 kV, and consider them for policy-driven eligibility given the CPUC's designation of geothermal as a long-lead-time resource.

3. Explain how CAISO would preserve deliverability for the CPUC's geothermal portfolio in this area if the LDNU-funding project withdraws.

4. Evaluate long-term strategic solutions for the region, including expansion of the 230 kV system, so that reliability, deliverability and congestion needs in the Geysers, Lake County and Mendocino area are addressed together rather than through successive 115 kV fixes. This evaluation should account for the region's growing winter load (2,448 MW gross in the 2041 North Coast and North Bay winter peak case), the geothermal and other resources mapped in the CPUC portfolios, and coordination with the staging of the Humboldt–Collinsville 500 kV line, which could provide a new 500/230 kV source to the region.

Local Congestion Between Geyserville and Hopland

SCP observes pervasive congestion on the  transmission system between Geyserville and Hopland, including both the 115 kV and 60 kV facilities. This congestion already affects resources operating in SCP's service area. SCP is also pursuing several development opportunities in Mendocino County, and those opportunities are at risk if congestion on this path persists. These are the kinds of local, diverse resources the CPUC portfolio relies on in the NCNB area, and their viability depends on transmission that can move their output to load.

The facilities driving this congestion overlap with those showing reliability overloads in this cycle's results. SCP therefore asks that any policy-driven transmission in this area, and PG&E's proposed Clear Lake-Lower Lake 60 kV Area Reinforcement, be designed to relieve congestion between Geyserville and Hopland in addition to meeting the identified reliability need. SCP further asks that CAISO reflect this local congestion in its economic assessment, so that the benefits of relieving it are counted when evaluating upgrades in the corridor.

Winter Conditions and Load Data in the NCNB Area

The NCNB area is trending toward a winter peak. Gross load in the 2041 winter peak case reaches 2,448 MW, compared with 1,290 MW in the 2028 winter peak case and 2,189 MW in the 2036 summer peak case, the latest summer peak case studied for the area. The growth is driven by building electrification (613 MW in 2041 winter) and transportation electrification (566 MW). In its October 2025 comments, SCP noted that the scope of 2040 winter peak overloads in the NGBA was much larger than in summer or earlier years. This cycle's load assumptions confirm that trend.

Transmission Plan Deliverability (TPD) and Full Capacity Deliverability Status (FCDS), which underpin resource adequacy, interconnection and transmission planning, remain focused on summer high system need hours. As the region's peak shifts to winter, a deliverability framework built around summer conditions risks undervaluing resources that perform well in winter, such as geothermal and northeast California wind, and overlooking winter constraints. SCP reiterates its request that CAISO work with the CPUC on a holistic approach to reflect winter needs across the reliability assessment, policy portfolio, interconnection process and resource adequacy program.

Unaccounted-for TPD in the NGBA

SCP's objective for this TPP is straightforward: a plan that provides sufficient TPD for both in-flight projects and the CPUC's modeled portfolio. For the past three years, TPD has been effectively unavailable in the NGBA, which has stalled renewable development and complicated procurement of geothermal, long-duration storage and other long-lead-time resources for Northern California load-serving entities. The CPUC's unaccounted-for TPD adjustment was intended to close this gap by ensuring that TPD held by in-flight projects outside the portfolio is reflected in the studies, so that upgrades are sized for both.

The adjusted unaccounted-for TPD tables presented on September 24 total approximately 11,803 MW in PG&E areas for 2036. All of it is listed under the Greater Bay, Fresno and Kern areas, including Moss Landing 500 kV (1,500 MW), Tesla 500 kV (900 MW), Tesla 230 kV (726 MW) and Pittsburg 230 kV (675 MW). Only 111 MW appears at Birds Landing 230 kV, listed under the Greater Bay Area, and no NGBA substation is listed at all. This is despite a CPUC portfolio of 5,467 MW in the NGBA in 2036 (6,347 MW in 2041), including roughly 3,170 MW of geothermal, which is precisely the resource category the CPUC scoped the unaccounted-for TPD allocations to protect. SCP raised this same discrepancy in its March 2026 comments, and the September materials did not resolve it. The CPUC's final busbar mapping dashboard for the base case identifies approximately 3,127 MW of unaccounted-for TPD behind the Collinsville-Tesla 500 kV constraint in 2036 (about 2,703 MW in 2041). It finds that, with this TPD included, the constraint is exceeded by approximately 4,339 MW in 2036 and 5,705 MW in 2041, against an on-peak capability of 3,379 MW. Of that total, about 356 MW sits at six NGBA substations: Cortina 115 kV (161 MW), Pit 1 230 kV (103 MW), Gold Hill 115 kV (50 MW), Fulton 230 kV (25 MW), Geysers 12 230 kV (13 MW) and Tulucay 60 kV (4 MW). CAISO's adjusted tables carry forward every Greater Bay Area substation behind the same constraint at the CPUC's values, including Moss Landing, Tesla 230 kV, Pittsburg and Birds Landing, but none of these six NGBA substations.

If unaccounted-for TPD in the NGBA was netted out because portfolio resources exceed TPD allocations behind the same constraints, the result could be upgrades sized for the portfolio alone. Those upgrades would then be absorbed by in-flight projects that already hold queue positions, leaving the portfolio undeliverable and repeating the zero-TPD outcome of recent cycles. To make sure the policy study avoids this outcome, SCP requests that CAISO provide, before the November 18 meeting:

1. For each binding NGBA constraint (Collinsville-Tesla, Birds Landing-Contra Costa, and the Geysers 115 kV system), the TPD held by in-flight projects, the portfolio MW behind the constraint, and the unaccounted-for TPD modeled.

2. An explanation of how unaccounted-for TPD in the NGBA was netted or removed, and the basis for doing so.

3. Confirmation that, where in-flight projects hold the available TPD, the policy study will identify upgrades sufficient to deliver the portfolio on top of them.

4. An estimate of TPD availability in the NGBA after the recommended policy-driven upgrades, and if it remains at or near zero, a strategy to close the gap between TPP upgrades and the interconnection process.

Hilltop

The CPUC deliberately mapped capacity at Hilltop, not Malin, for the 2026-2027 TPP. That choice reflects an understanding that the Hilltop/Madeline area provides access to three resource types of particular value to California: northeast California wind, which is winter-peaking and complements the state's solar-heavy portfolio and the NCNB area's emerging winter peak; in-state geothermal; and Northern Nevada resources.

CAISO's busbar mapping diagrams do not reflect this choice. In every case CAISO presented, the capacity appears at Malin, labeled as out-of-CAISO imports, and Hilltop does not appear in the materials at all. In the 2036 base case, CAISO maps 2,293 MW of geothermal and 873 MW of wind at Malin; in the 2041 base case, 2,293 MW of geothermal and 1,148 MW of wind; and in the 2036 and 2041 sensitivity cases, 2,302 MW of geothermal with 402 MW and 1,148 MW of wind, respectively. SCP recognizes that Hilltop sits outside the CAISO system today, but representing these resources as imports at Malin assumes the very delivery path the CPUC's mapping was designed to avoid.

Mapping these resources at Malin has practical consequences. Delivery at Malin adds wheeling costs across other transmission providers' systems and requires resources important to California's climate and reliability targets to compete with the infrastructure demands of other states, as the Joint CCAs noted in April 2026. It also adds load to an already stressed corridor: the preliminary results show near-term Malin-Round Mountain overloads managed through RAS and nomograms, high voltage response on the Table Mountain-Malin corridor, and a pending California-Oregon Intertie affected system study for the 1,500 MW LC25-PS1 load on the Tesla-Table Mountain 500 kV line.

SCP urges CAISO to respect the CPUC's guidance by modeling these resources at Hilltop and including a CAISO expansion to Hilltop/Madeline in its policy-driven transmission design, rather than relying on wheeling through Malin. SCP asked CAISO to evaluate this expansion at a high level in the 2025-2026 TPP so that an actionable project could advance in this cycle, and the CPUC's mapping now provides a clear basis to do so.

Humboldt 500 kV Reconfiguration

The New Humboldt-Collinsville and New Humboldt-Fern Road 500 kV lines are modeled in this cycle's base cases with a 2034 in-service date, as approved for offshore wind integration. Their corridors traverse a region where the CPUC has also mapped geothermal and onshore wind, and they connect to the same Collinsville and northern 500 kV system that limits NGBA deliverability. SCP believes these projects can do more than serve offshore wind if they are staged or reconfigured.

SCP asks CAISO to make staging and reconfiguration of these projects a priority in this cycle's policy option studies. Options could include an earlier first phase built out from the Collinsville 500 kV substation (modeled for 2028), a phased configuration through Vaca Dixon as SCP suggested in December 2025, or additional interconnection points for local resources along the route. Each option should be evaluated for the incremental TPD it creates for local geothermal and wind, while preserving the projects' offshore wind function. SCP has raised this in each of its last three filings and encourages CAISO to maintain momentum on it in this cycle.

Distributed Generation Deliverability at Calpella

The CPUC busbar mapping shows 4 MW of distributed solar at Calpella in the NCNB area. Small distributed projects like this one depend on the distributed generation deliverability process to obtain deliverability, and are particularly exposed to the local congestion and TPD scarcity described above. SCP asks CAISO and PG&E to confirm that this capacity will be studied and made available as TPD through the distributed generation deliverability process, and to indicate the expected timing of that allocation.

 

PG&E Bulk System and Path 26

The PG&E bulk system results show significant 2036 summer peak overloads that CAISO attributes mostly to heavy south-to-north Path 26 flow. These include Gates 500 kV facilities at up to approximately 148% under P6 contingencies, Manning-Gates 500 kV at up to approximately 147%, Manning-Harlan 500 kV at up to approximately 139%, and the Tesla-Metcalf-Moss Landing 500 kV loop at up to approximately 116%. Separately, Table Mountain-Tesla 500 kV overloads to approximately 109% in 2041 for the combined loss of Olinda-Tracy and Collinsville-Tesla 500 kV.

These results support SCP's December 2025 and April 2026 comments that Path 26 must be fully represented in IRP modeling, and that additional deliverability in Northern California can reduce the system's reliance on long-distance transfers. They also connect to the Path 15 congestion that CAISO's own production cost modeling has identified as the most costly in California. SCP asks CAISO to evaluate, in the November policy and economic results, whether TPD upgrades in the NGBA (at Collinsville, Delavan, Tesla and Birds Landing-Contra Costa) can reduce these overloads and Path 15 congestion, and to quantify marginal congestion reduction, increased TPD and reduced CRR underfunding.

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

10. Provide your organization's comments on the Energy-Only Resources Assessment Preliminary Findings discussion.

Energy-Only Resources Assessment

SCP supports this assessment, which the Joint CCAs requested in April 2026, and appreciates CAISO's use of the 2036 summer off-peak case to test whether energy-only resources can reliably support battery charging. The preliminary findings are encouraging. Only two study areas, Fresno and Central Coast/Los Padres, show energy-only curtailment under normal (P0) system conditions. Many areas show no curtailment under P1 or P7 contingencies either, including Humboldt, North Valley, Central Valley, Tehachapi/Big Creek, North of Lugo and Metro. Most notably, SCE Eastern, with 12,777 MW of energy-only solar installed, shows no curtailment under any contingency category.

SCP offers four requests for the November results. First, FCDS curtailment will be essential context. If FCDS resources are curtailed under the same conditions as energy-only resources, CAISO should explain whether a meaningful distinction remains between the two for purposes of battery charging sufficiency. Second, results should report the magnitude and frequency of curtailment, not only whether it occurs, since contingency-driven curtailment of short duration has different implications than curtailment under normal conditions. Third, SCP requests a version of the assessment that minimizes the dispatch of FCDS fossil generation for battery charging. CAISO developed the 2036 summer off-peak scenario with high dispatch of solar and other FCDS resources, and the PG&E bulk generation assumptions show thermal generation dispatched at 10,445 MW of 10,803 MW installed in that case while storage charges at about 4,015 MW. With the renewable build-out in the CPUC portfolio, California should not need fossil generation to charge batteries in 2036. A case that limits fossil dispatch to the units needed for local reliability, voltage support or system stability, and relies on renewable output for the remainder, would show whether renewables can reliably charge storage on their own and where transmission limits that. CAISO's 2028 off-peak heavy renewable and minimum gas generation sensitivity offers a precedent for this approach.Fourth, SCP notes that the NCNB area models no energy-only solar, so these results do not yet show the potential of energy-only resources in the north. If the schedule allows, SCP requests that CAISO extend the assessment to a winter condition, consistent with the region's shift toward a winter peak.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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

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 23-24 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 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, the CRATS is at increased risk of experiencing overloads.  These increases are observed in both 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.

In addition, on the result table there are numerous diverged power flow cases, and it is unclear to MWD if these are numerical solution issues or divergence caused by severe reliability limit violations. These issues need to be identified and mitigated if they are reliability criteria violations.    

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 Bulk Electric System (BES).

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

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.

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

Viridon California (“Viridon”) appreciates the opportunity to comment on the preliminary reliability results presented during the September 23-24, 2026 Transmission Planning Process (“TPP”) Stakeholder Meeting. Viridon offers the following comments regarding certain study assumptions and preliminary results affecting the PG&E 500 kV system.

1. Data center load assumptions

The CAISO cases model data center load from the CEC forecast, scaled by utilization factors. These assumptions may reflect different load levels and locations than the projects being studied through the load interconnection process. Understanding how these different assumptions relate to one another would help stakeholders interpret the TPP study results and inform their own modeling efforts. Examples from the 2026-2027 cases:

• LC25-PS1: PG&E studied 1,500 MW on a new switching station on the Tesla-Table Mountain 500 kV line, with a proposed in-service date of 2030 (PG&E presentation, slide 102[1]). The CAISO cases model this load at 54-460 MW, starting in 2031
• Mustang 230 kV: The CAISO cases include up to 600 MW of data center load at Mustang, which connects directly to Gates. This load is introduced in the current TPP cycle but is not identified in PG&E’s load interconnection presentation
• Manning 500 kV: Data center load at Manning is modeled at about 300 MW, compared to about 900 MW in the 2025-2026 cases.

Given the size of these loads, differences in the assumptions can materially affect modeled flows and thermal results on the 500 kV system. The 2036 and 2041 summer peak cases also serve as the basis for the transmission models used in the economic assessment (CAISO September 24 presentation, slide 33[2]). Additional context on the following would help stakeholders better understand the assumptions underlying the TPP study results and appropriately reflect them in related modeling and analysis:

• The data center and large load assumptions in each study case, by bus, including any factors applied;
• How TPP large load assumptions relate to loads being evaluated by PG&E and other PTOs through their respective load interconnection processes; and
• How information from the load interconnection process is considered in developing TPP assumptions, including as those assumptions evolve across planning cycles.

2. Timing of new generation in the study cases

Darden (Q1949, 1,150 MW of solar and storage at the Harlan 500 kV switching station) appears in the TPP cases for the first time this cycle, shortly before its expected in-service date. The preliminary results show 2036 summer peak overloads of up to approximately 148% on the Los Banos-Gates #3, Manning-Gates, Manning-Harlan, Harlan-Midway and Gates-Midway 500 kV facilities (September 23 CAISO presentation, slides 135-137[3]). Metcalf-Moss Landing 500 kV reaches about 116% for the loss of Manning-Metcalf and Tesla-Los Banos (September 23 CAISO presentation, slide 134). The CAISO attributed these to south-to-north Path 26 flow.

In light of these significant overloads across several 500 kV facilities identified in these preliminary results, additional information on how CAISO expects to evaluate and address these overloads as the 2026-2027 TPP progresses would help stakeholders understand the implications of the preliminary results, including how much of the identified 2036 overloads is attributable to Darden dispatch versus broader Path 26 flow, and how Darden will be dispatched in the final results.

These findings are also relevant in the context of the policy-driven assessment, which identifies significant unaccounted-for Transmission Plan Deliverability (“TPD”) at several of the same 500 kV buses, including Moss Landing (1,500 MW), Manning (782 MW), Los Banos (668 MW), Midway (582 MW) and Gates (541 MW) (CAISO September 24 presentation, slides 23-25). The overlap between these reliability findings and policy-driven transmission needs presents an opportunity to evaluate potential solutions that could address multiple needs across the 500 kV system.

Viridon appreciates CAISO’s continued work on the 2026-2027 TPP and the opportunity to provide comments on the preliminary reliability results, and looks forward to continued engagement as the TPP cycle advances.

[1] https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-PGandE-2026-2027-Transmission-Planning-Process-Sep-24-2026.pdf

[2] https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2026-2027-Transmission-Planning-Process-Sep-24-2026.pdf

[3] https://stakeholdercenter.caiso.com/InitiativeDocuments/Presentation-2026-2027-Transmission-Planning-Process-Sep-23-2026.pdf

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 projects presentation

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

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

6. Provide your organization's comments on SDG&E proposed reliability projects 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 Energy-Only Resources Assessment Preliminary Findings discussion.

11. Provide any additional comments your organization has on the Sept. 23-24 2026-2027 Transmission Planning Process Meetings.