Comments on September 27-28 Stakeholder Call Discussion

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

The ISO is planning to evaluate the following transmission projects to support the 2031 resource development:

Some of these projects will increase deliverability but most projects will not. For example, the Colorado River 500/230kV transformer bank upgrade will do nothing for FCDS as all the generation interconnecting Colorado River 230kV or 500kV will still be contributing to the Serrano-Alberhill-Valley 500kV deliverability constraint. So unless a study region is fully addressed to remove all the overlapping deliverability constraints, we will not see an increment in FCDS assignments.

We request CAISO to consider the ADNUs identified in the C13P1 study and remove all overlapping deliverability constraints around the region of the identified network upgrade. In C13PI, major network upgrades identified cost  >1 billion dollars. The ADNUs identified in the North of Lugo Area seem cost effective:

1. Existing Kramer – Victor 115kV line is looped into Roadway 115kV substation and the Kramer – Victor 230kV line No. 1 and 2 are reconductored to higher ratings -$110M
2. Victor – Lugo 220kV Upgrade- $225M

We request CAISO consider ADNUs like the ones above to unlock FCDS by removing overlapping deliverability constraints. Priority should be given to removing all the overlapping deliverability constraints in an area as opposed to proposing network upgrades in multiple areas leaving other deliverability constraints in those areas unadressed leading to 0 MW increment in FCDS.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

ACP-California strongly supports the CAISO’s proposal to consider additional upgrades beyond those identified through analysis of the resource portfolios communicated for the policy case in the 2021-22 TPP. As the CAISO identified, and as multiple stakeholders have pointed out, the resource portfolios utilized in the 2021-22 TPP are stale given activities and events that have transpired since their development. The portfolios do not contain sufficient resources, and thus do not trigger the transmission upgrades needed, to place the state on a path to achieve its reliability and clean energy policy objectives. As CAISO highlighted, since the CPUC portfolios for the 2021-22 TPP were communicated to CAISO by the CPUC, a number of significant changes have occurred, including an order for 11.5 GW of Net Qualifying Capacity by the CPUC. These changes, along with the increasing levels of clean energy resources which will be included in subsequent portfolios, warrant approval of additional, cost-effective and relatively near-term transmission upgrades during the ongoing 2021-22 TPP.

Additionally, as ACP-California has highlighted in a variety of venues, completion of transmission upgrades and expansion projects will be critical to near-term reliability and long-term decarbonization. There are many renewable energy projects which could be available to meet California’s near-term and mid-term needs, including many that are “shovel ready” or in the late stages of development, but many of these projects are seeing their interconnection dates pushed back because of delays in their interconnection upgrades or due to the late-stage identification of additional system improvements that are required before these projects can come online. The challenges and long-lead times associated with completing necessary transmission and system upgrades to bring critical projects online are reason enough for CASO to expedite approval of cost-effective transmission upgrades in the current TPP. There is a need to begin the CAISO and applicable CPUC approval processes for these projects expeditiously, if they are going to be available to help fulfill mid-term procurement, reliability, and public policy needs.

The projects that CAISO has identified for consideration of approval in the current TPP are all relatively low cost, high-capacity upgrades that will enable additional Full Capacity Deliverability Status (FCDS) resources from locations where there is significant commercial interest. Given this, and the need to move forward with approval as quickly as possible so that these upgrades can begin moving through any necessary permitting and approval processes, ACP-California supports the approval of the projects identified by CAISO on slide 13 of the Day 2 TPP stakeholder meeting presentation.  Below, we review each proposed project and the key data points that suggest the project should move forward to approval in this cycle of the TPP. A summary table is also included at the end of the comments for convenience.

Antelope – Vincent 500 kV line rating increase

This upgrade project is highly compelling and should absolutely be approved by CAISO in the 2021-22 TPP, allowing it to move forward towards any permitting/regulatory approval and ultimately to construction. This project tis not only the lowest cost upgrade (in terms of $/MW of FCDS) that is identified in the CAISO’s transmission capability estimates efforts it is also has the shortest estimated time to construct. It is estimated to take 18 months to construct (which ties for the shortest project construction timeline with the internal San Diego area reconductoring project). This means that the Antelope-Vincent line rating increase could be providing additional, cost-effective transmission capacity to the CAISO system relatively soon. There is also substantial commercial interest in the zone where additional transmission capacity would be provided. According to the CEC’s quantification of current commercial interest in the SB 100 Starting Point for the 20-year Transmission Plan, there are >9,500 MW of commercial interest in Tehachapi (not including Cluster 14). Thus, if approved and advanced by CAISO, this project is well positioned to relatively quickly provide additional transmission capacity to support clean energy development and bring new capacity online to meet procurement requirements.

This project offers the following benefits, indicating it should be approved in the 2021-22 TPP:

• Provides the lowest cost per MW incremental FCDS ($5,556/MW-FCDS) of all transmission upgrades identified in CAISO’s transmission capabilities estimates to facilitate 2,700 MW of incremental FCDS
• Fastest estimated construction time (18 months) of all transmission upgrades identified in CAISO’s transmission capabilities estimates
• Substantial commercial interest of over 9,500 MW in the queue (pre-Cluster 14) in Tehachapi alone

Laguna Bell - Mesa line upgrade

The Laguna Bell – Mesa line upgrade is another project which offers a relatively low cost ($/MW-FCDS) transmission expansion opportunity to help meet California’s reliability and policy objectives. It also has a comparatively short construction timeline and will provide needed transmission access to projects already in the CAISO queue.

The Laguna Bell – Mesa line upgrade should be approved in the 2021-22 TPP because it offers the following benefits:

• Provides a relatively low cost per MW incremental FCDS ($44,681/MW-FCDS) which is the sixth lowest of all transmission upgrades identified in CAISO’s transmission capabilities estimates to facilitate 470 MW of additional FCDS
• Second fastest estimated construction time (27 months) of all transmission upgrades identified in CAISO’s transmission capabilities estimates
• Pre-Cluster 14 queue capacity of at least 900 MW in Ventura County (which would presumably be enabled by this project and there may be more project nearby that would also be able to utilize the additional FCDS capacity unlocked by this upgrade)

New Colorado River 500/230kV No. 3 transformer

The New Colorado River 500/230 kV No. 3 transformer project appears to offer substantial new transmission capacity (1,000 MW) to a highly constrained area where there is substantial commercial interest. And, if this project can provide additional capacity without further mitigations for the Desert Area constraint, then it would provide additional capacity to an area where there is large amount of development activity and potential. This project is a relatively low-cost opportunity to advance clean energy projects in the Riverside and Colorado River zones. There are at least 2,900 MW of capacity in the CAISO queue (pre-Cluster 14) according to the CEC SB 100 Starting Point for Riverside and an evaluation of the CAISO queue for project interconnecting at a Colorado River substation. But, additionally, Arizona solar (not in the CAISO queue) may be enabled by this upgrade and more than 2,300 MW of Arizona solar was included in the CPUC’s TPP Base Case portfolios and the CEC’s SB100 Starting Point resources. New Mexico wind imports, which are shown at >5,000 MW in the SB100 Starting Point scenarios, could potentially also be enabled through this upgrade. Thus, there are likely additional MW of commercial interest in interconnection queues of transmission providers adjacent to the CAISO which may be facilitated by this incremental transmission capacity.

The New Colorado River 500/230 No. 3 Transformer offers the following benefits, indicating that it should be approved in the 2021-22 TPP because it offers the following benefits:

• Provides a relatively low cost per MW incremental FCDS ($74,00/MW-FCDS) for 1,000 MW of incremental FCDS capacity on the CAISO system
• Can be constructed relatively quickly (42 months), but requires CAISO to move forward with approval quickly to help provide incremental transmission capability in the mid-term
• Pre-Cluster 14 queue capacity of at least 2,900 MW seeking to interconnect at a Colorado River location in the CAISO queue alone, but substantial additional commercial interest in queues adjacent to CAISO

New Lugo 500/230kV No. 3 transformer

The New Lugo 500/230 kV No. 3 Transformer Project is very similarly situated to the new Colorado River 500/230 kV No. 3 transformer project (discussed above). It has a similar cost per MW-incremental FCDS capacity and the same estimated timeline to construct. This project enables resources in the Inyokern North Kramer, Victor and Pisgah zones where there appears to be at least 2,000 MW of capacity of commercial interest in the identified by CEC in the Inyokern North Kramer, Victor North, and Pisgah zones.

The New Lugo 500/230 No. 3 Transformer offers the following benefits, indicating that it should be approved in the 2021-22 TPP because it offers the following benefits:

• Provides a relatively low cost per MW incremental FCDS ($71,429/MW-FCDS) for 980 MW of FCDS
• Can be constructed relatively quickly (42 months), but requires CAISO to move forward with approval quickly to help provide incremental transmission capability in the mid-term
• Pre-Cluster 14 queue capacity of at least 2,000 MW identified by CEC in the Inyokern North Kramer, Victor North, and Pisgah zones

New Eldorado 500/230 transformer

The CPUC has identified nearly 2,300 MW of solar in the Southern Nevada and Mountain Pass/Eldorado zones in the TPP Base Cases which could be supported by this project. Additionally, there is significant development interest in these areas. Moreover, this upgrade would provide additional capacity form the Eldorado region where several transmission projects that could provide regional wind would deliver. It also has the potential to deliver Nevada geothermal. Thus, this upgrade would help increase options for a diverse set of clean energy resources to serve CAISO.

• Provides a relatively low cost per MW incremental FCDS ($175,00/MW-FCDS) for 400 MW of incremental FCDS capacity on the CAISO system
• Can be constructed relatively quickly (42 months), but requires CAISO to move forward with approval quickly to help provide incremental transmission capability in the mid-term
• CPUC Portfolios communicated for the TPP Base Cases include nearly 2,300 MW of resources from these zones
• Could also help enable delivery of a diverse set of clean resources potentially including geothermal and regional wind

Silvergate - Bay Blvd 230kV 3-ohm Series Reactor

The Silvergate – Bay Blvd 230kV 3-ohm Series Reactor project is another highly compelling for approval in the 2021-22 TPP. It would provide 2,067 MW of incremental FCDS capacity for $14,998/MW, offering the third lowest cost ($/MW-FCDS) capacity of any project identified in CAISO’s transmission capability list. The zones that would be accessed by this upgrade show strong commercial interest of at least 3,800 MW in the Imperial zone (according to the CEC SB100 Starting Point).This project has a relatively long estimated time to construct, relative to the other projects CAISO has identified for potential approval in the 2021-22 TPP. The longer timeline for this project should underscore the need to begin moving forward with regulatory approval and any necessary permitting activity as quickly as possible.

The Silvergate – Bay Blvd 230kV 3-ohm Series Reactor project should be approved in the 2021-22 TPP because it:

• Provides the third lowest cost per MW incremental FCDS ($14,998/MW-FCDS) of all transmission upgrades identified in CAISO’s transmission capabilities estimates and would provide 2,067 MW of additional capacity
• Has a relatively long estimated construction timeline (72 months) which underscores the need to begin moving forward on approval and any necessary permitting for this project
• Substantial commercial interest of over 3,800 MW in the queue (pre-Cluster 14) in the Imperial zone alone

Woodland-Davis 115 kV Lines

The Woodland-Davis 115kV project offers the least amount of total incremental FCDS capacity of any of the project the CAISO put forward for consideration. However, it still offers a relatively low cost ($/MW-FCDS) transmission expansion opportunity to help meet California’s reliability and policy objectives, can be constructed in a comparatively short period of time and there is substantial commercial interest in the area that the project could support clean energy development in an area with at least 592 MW of commercial interest (pre-Cluster 14 according to the CEC SB100 Starting Point).

The Woodland-Davis 115 kV line should be considered for approval in the 2021-22 TPP because it:

• Provides a relatively low cost per MW incremental FCDS ($114,583/MW-FCDS) to facilitate 96 MW of additional FCDS
• Comparatively fast construction timeline (42 months)
• Pre-Cluster 14 queue capacity of 592 MW in Davis Area (Sacramento River)

Gates Transformer Bank # 13

The Gates Transformer Bank #13 project is another highly compelling which should, based on the information available, undoubtably be approved by CAISO in the 2021-22 TPP. The Gates Transformer Bank #13 upgrade is the second lowest cost upgrade (in terms of $/MW of FCDS) that has been identified by CAISO in the transmission capability estimates efforts. The project is estimated to take 48 months to construct, which is relatively short compared to all the projects in the transmission capability estimates. But given the four-year construction timeline, it is imperative that this project being to move forward as quickly as possible so that it can be completed and provide the CAISO grid with additional, deliverable clean capacity. There is significant capacity in the CAISO queue that could be advanced by this upgrade. The CEC’s SB 100 Starting Point found 3,650 MW of capacity in the Kern area and 3,621 MW in the Westlands area in the CAISO queue (pre-Cluster 14). Thus, there is significant development activity of clean energy projects that could be supported by this project.

The Gates Transformer Bank #13 offers the following benefits, indicating it should be approved in the 2021-22 TPP:

• Provides the second lowest cost per MW incremental FCDS ($8,983/MW-FCDS) of all transmission upgrades identified in CAISO’s transmission capabilities estimates and unlocks the most FCDS capacity (4,453 MW)
• Can be constructed relatively quickly (48 months), but requires CAISO to move forward with approval quickly to help provide incremental transmission capability in the mid-term
• Substantial commercial interest of over 7,200 MW in the queue (pre-Cluster 14) in the Kern and Westland zones

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

Alameda Municipal Power (AMP) offers the following comments regarding the Preliminary Reliability Assessment Results presented at the  2021-22 Transmission Planning Process Stakeholder Meeting on September 27-28, 2021.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

1.  Please update the system diagram for the East Bay Division to correctly represent the AMP transmission system. [1]
   1. Add Cartwright substation, supplied from Oakland C. 
   2. Jenney substation is supplied from Oakland J. Correct the spelling of Jenney Substation.
2. Is the CAISO still planning on the AMP load switching of Cartwright substation to Oakland J as a transmission line overload mitigation? When will the CAISO develop an operating procedure, incorporating input from AMP, for using this load transfer as a planned transmission overload mitigation?
3. The resource component of OCEI project appears to be uncertain at this time, since the arrangements between PG&E and Vistra have been unsuccessful. What are the CAISO’s contingency plans for the scenario without the OCEI resource component?
4. If the CAISO believes that the resource component of the OCEI is still viable, please provide the status of that project. What is the status of a system impact study for the interconnection and operation of this project?
5. FERC has ruled that, before implementing the OCEI project, PG&E must conduct a study to determine the potential for any adverse impacts to Alameda and any potential avoidance or mitigation measures.  City of Alameda v. PG&E, 176 FERC ¶ 61,013 (Jul. 15, 2021). And PG&E subsequently told FERC that “the existing fossil generator originally expected to retire in 2023 or 2024 had its reliability must run (“RMR”) contracts extended and is expected to continue to operate into the foreseeable future.” In light of PG&E’s statements indicating that the OCEI is not proceeding on schedule, and the additional time needed for the adverse impact study that PG&E is required to conduct, what is CAISO’s expectation of the OCEI project being completed in time to mitigate the overloads identified in its preliminary reliability assessment?
6. Please describe any scenarios for which the CAISO is planning on the SPS at Oakland C, which drops Cartwright Substation, as a mitigation for any overloads.
7. What is the scope/components of the North Oakland Area Reinforcement project? Please provide the status for each component of the project.
8. The report indicates that there are potential overloads on the CL cable in North Oakland for P2 and P6 contingencies in both the summer and winter with no mitigation identified. Please explain how the lack of a solution could affect the 115 kV supply to AMP.
9. The CAISO has indicated that it will monitor the load and load growth in the No. Oakland area. How does the load forecast in this cycle of the TPP compare to the load forecast previous years?

[1] CAISO, Greater Bay Area Preliminary Reliability Assessment Results,” 2021-22 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021, page 7.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

The Bay Area Municipal Transmission group (BAMx)^[1] appreciates the opportunity to comment during the development of the 2021-22 Transmission Plan.  The comments and questions below address the material presented at the CAISO Stakeholder meeting on September 27-28, 2021. 

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

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

Previously Approved PG&E Projects

BAMx applauds the CAISO’s efforts in confirming the need for the previously approved projects. For example, the Fresno Area Preliminary Reliability Assessment Results identified the continued need for the following four previously-approved projects.

1. Wilson 115kV Reinforcement Project;
2. Herndon-Bullard 115 kV Reconductor;
3. Reedley 70 kV Reinforcement (Dinuba Battery Energy Storage); and
4. Wilson-Oro Loma Reconductoring.

However, this list excludes another project, namely Oro Loma 70kV Area Reinforcement Project. Does this mean that Oro Loma 70kV area Reinforcement Project is not continued to be needed? Please see further discussion on this project below.

BAMx urges the CAISO to systematically and consistently review the continued need for the previously-approved projects in all the planning areas.

Ora Loma 70kV Reinforcement Project

Oro Loma 70kV Reinforcement Project was approved in the 2011-2012 TPP. The original scope of the project included building a new 230/70kV substation near Mercy Springs Junction and converting a single-pole line into a double circuit tower line to create a new 70kV line from Mercy Springs to Canal.[1] Based on the information presented by PG&E as part of the Stakeholder Transmission Asset Review Process (STAR) process, the scope of the project has been reduced to reconductoring 2.4 miles of Los Banos-Livingston Jct-Canal 70kV line and reconductoring of 10.8 miles of Mercy Springs-Canal-Oro Loma line.[2]

The latest identified reliability need for the project is a thermal overload on Mercy Springs-Canal 70kV for the loss of Los Banos-Livingston Jct-Canal 70kV and a thermal overload on Los Banos-Livingston-Canal 70kV circuit for the loss of Mercy Springs-Canal 70kV.[3] However, this overload is not identified in any of the CAISO’s preliminary reliability results for 2021-2022 TPP including the sensitivity cases. Moreover, when BAMx removed the proposed project from the 2031 Summer Peak Base Case for the Central Valley area and applied the identified contingencies, the post contingency loadings on Los Banos-Livingston-Canal 70kV and Mercy Springs-Canal 70kV circuits were 87% and 103%, respectively. Since these circuits are not overloaded in the 1-year-out (2023) and 5-year-out (2026) cases and show only a marginal overload in the 10-year-out case, BAMx suggests the CAISO reevaluate the need for the project and whether preferred resources, such as battery storage, could be used as an alternative mitigation measure.

Midway-Temblor 115kV Line and Voltage Support

The Midway-Temblor 115kV Line and Voltage Support reinforcement project was approved in the 2012-2013 Transmission Planning Process (TPP). The scope of the project is to reconductor approximately 15 miles of Midway-Temblor 115kV line and install 45MVAR of shunt capacitors at Temblor substation.

The latest identified need for the project is to mitigate a thermal overload on Midway-Temblor 115kV due to N-1-1 outage of Gates-Midway 500kV line and Gates 500/230kV bank. The voltage support portion of the project also mitigates low voltages at Temblor due to an N-1 outage of Midway-Temblor 115kV.[4] However, the overloads identified by PG&E were not observed in the latest Preliminary Reliability Results for years 2023 and 2026 posted by the CAISO for the 2021-2022 Transmission Planning Process. BAMx believes that the new second 500/230kV transformer at the Gates substation[5] that is currently operational potentially mitigates the identified N-1-1 or P6 overload on the Midway-Temblor substation. BAMx requests the CAISO to re-evaluate the continued need for the project. If the project is found to be needed, the CAISO should identify the contingencies and the related overloaded transmission facilities driving the continued need for the project.

Morgan Hill Area Reinforcement Project

The Morgan Hill Reinforcement project was originally approved in the 2013-2014 TPP cycle. Through project re-evaluation, the scope of the project has changed, and the latest approved project scope is to “Rebuild Metcalf-Green Valley 115kV into the Green Valley-Morgan Hill 115kV and convert Morgan Hill 115kV bus to a BAAH configuration”.[6]

The latest identified needs for the project are driven by the thermal overloads on Metcalf-Llagas 115kV circuit which are mitigated by the line re-arrangement associated with the Morgan Hill Area Reinforcement project. The justification for rebuilding the Morgan Hill 115kV substation into a breaker-and-a-half configuration is unclear. If PG&E needs an additional breaker position for the newly built Green Valley-Morgan Hill 115kV circuit, the existing substation configuration should be modified. BAMx requests the CAISO to reevaluate the need for rebuilding the Morgan Hill substation into a breaker-and-a-half configuration. If such a need is not identified, the scope of the project should be adjusted to exclude the rebuild of the Morgan Hill substation. BAMx requests the CAISO to reevaluate the need for rebuilding the Morgan Hill substation, a distribution substation, into a breaker-and-a-half configuration ?which is contrary to the enhanced-loop or the ring bus configuration as specified in PG&E's design standards.

[1] Oro Loma 70kV Area Reinforcement Project, Request Window Submission, Page 1.

[2] PG&E Stakeholder Transmission Asset Review Process Stakeholder Meeting, August 3, 2021, – Page 54 of 58.

[3] Ibid.

[4] PG&E Stakeholder Transmission Asset Review Process Stakeholder Meeting, August 3, 2021, – Page 58 of 58.

[5] CAISO 2020-2021 Transmission Plan, February 1, 2021, Table 8.1-2: Status of Previously-Approved Projects Costing $50 M or More, shows that the Gates #2 500/230 kV Transformer Addition project has been completed.

[6] PG&E Stakeholder Transmission Asset Review Process Stakeholder Meeting, August 3, 2021, – Page 53 of 58.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

  No comments at this time.

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

  No comments at this time.

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

    See BAMx comments in response to Q.12.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

   See BAMx comments in response to Q.11.

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

No comments at this time.

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

No comments at this time.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

 No comments at this time.

10. Provide your organization’s comments on the SCE Reliability Alternatives:

 No comments at this time.

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

SDG&E’s New 500kV Miguel-Suncrest Circuit Project

SDG&E has proposed the New 500kV Miguel-Suncrest project. The scope of the project is to construct approximately 33 miles of new 500kV line between Miguel and Suncrest substations. The identified cost estimate of the proposed project is $335 million to $600 million. The justification for the project is a P3 overload identified in the 2023 Summer Peak base case and a P1 overload identified in the Peak Load and Heavy Renewables sensitivity case. BAMx questions if sufficient justifications exists for the approval of the project. The identified P3 violation is 105%. Per CAISO’s planning standards, the P3 types of contingencies allow system readjustment between the first and second contingencies. Additionally, the CAISO has already developed a potential mitigation measure to mitigate the P3 and P6 overloads.[1]

BAMx did not find any evidence as to why  system readjustments and operational actions are not capable of mitigating the P3 and P6 overloads identified in the 2023 Summer Peak case. The other P1 contingency is only for a sensitivity case and is not observed in any of the base cases. The reliability justifications for the proposed projects are not clear, and therefore the CAISO should not approve the new 500kV Miguel-Suncrest Circuit project at this time.

[1] CAISO, San Diego Gas & Electric Area Preliminary Reliability Assessment Results,  2021-2022 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021 – slides 9-12.

12. Provide your organization’s comments on the GLW Reliability Alternatives:

GridLiance West Upgrade

GridLiance West has proposed a project (GLW Project, hereafter) to mitigate overloads on the VEA system identified in the 2031 Spring Off-Peak case.[1] The scope of the project includes rebuilding multiple circuits across the VEA system to 230kV voltage class, adding a second 230kV circuit from Innovation to Desert View, adding 500/230kV transformer at Sloan Canyon substation and looping the Harry Allen to Eldorado 500kV line at Sloan Canyon substation. The estimated cost of the project is $213 Million. GridLiance has identified economic benefits of $67 million annually as well as additional policy benefits from the proposed project.

Since the reliability overloads are identified exclusively in the 2031 Spring Off-Peak case with relatively low system load as compared to the Summer Peak case, the overloads are likely driven by surplus generation as opposed to inability to serve load. As the CAISO has identified in its Preliminary Reliability Assessment, the overloads identified in the 2031 Spring Off-Peak needs to be further evaluated in the policy study for potential upgrades.[2] BAMx believes that it is premature to consider the GLW project as a reliability-driven project at this time, and supports the CAISO’s assessment that it needs to evaluate policy and economic benefits of the project for further consideration in the current TPP cycle.

[1] GridLiance West Project Proposal for the 2021-2022 TPP Reliability Request Window, September 27-28, 2021, page 2.

[2] See CAISO, Valley Electric Association Preliminary Reliability Assessment Results, 2021-2022 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021, page 8.

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

CAISO Net Export Limit Assumption

The net export limit for the CAISO system is considered in CAISO’s production cost simulation studies and in CPUC’s IRP studies. BAMx agrees with the CAISO that the net export limit is neither a transmission constraint, nor a market constraint imposed by the CAISO in operation.[1] Although BAMx supports the CAISO’s decision to expand the CAISO net export limit to 5000 MW in the 2031 planning PCM for the 2021-2022 transmission planning study, BAMx questions why it should be limited to 5,000 MW. After all, historical data shows increasing levels of export limits well in exceedance of 2,000 MW. Having CPUC’s IRP and CAISO’s renewable studies use a 5,000 MW limit in and itself should not be the reason for the CAISO to restrict it to 5,000 MW.

[1] CAISO, “Economic Assessment Assumption Update for 2021-2022 Planning Cycle,” 2021-2022 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021, page. 5.

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

Transmission Needed for To Accommodate Increasing Procurement and Capacity in Portfolios

During the September 28th presentation, the CAISO identified transmission needs with the increasing procurement and future portfolios. It included a list of transmission projects identified in the CAISO transmission capability estimates as shown in Table 1 below.

Table 1: Transmission Projects Identified in CAISO Transmission Capability Estimates[1]

It is not clear to BAMx whether the projects identified in Table 1 are needed to accommodate the Base and/or any of the two Sensitivity portfolios in the current transmission planning cycle. BAMx notes that additional transmission projects were identified in the CAISO’s white paper on the transmission capability estimates for CPUC’s resource planning process.[2] The RESOLVE model used to develop the 2021-2022 TPP resource portfolios did not take into account the scope and cost associated with the transmission projects listed in Table 1. Had it incorporated this information, it would not have selected certain resources in specific renewable zones. Therefore, even if the list of projects in Table 1 are identified to be needed to accommodate the CPUC IRP portfolios, BAMx urges the CAISO not to approve these projects as part of the current planning cycle, and reassess their need as part of the subsequent TPP cycles, where the need for additional transmission upgrades will inform the IRP portfolios.

[1] CAISO, Increasing procurement and capacity in portfolios, 2021-2022 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021, page 4.

[2] See Table 3-1. http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=82442AF7-0A68-4BFC-86FD-AAE1B066AE5E

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

CAISO Transmission Access Forecasting Model

BAMx appreciates the continued work of the CAISO in keeping the stakeholders updated about the likely impact of its decision to approve transmission projects affecting the High Voltage (HV) Transmission Access Charge (TAC). BAMx appreciates the opportunity to comment on the CAISO’s 2020-2021 HV TAC Estimating Model (“TAC Model” hereafter) that was posted on the CAISO website on September 23, 2021.  We hope that the CAISO addresses the issues raised by BAMx in the next update of the TAC Model.

1. Caveat the TAC forecast as it does not provide an accurate signal for the outer years, i.e., 2024-2029, and does not address additional wildfire mitigation costs

BAMx notes that the tapering of the CAISO’s HV TAC forecast in the outer years, that is, during 2027-2035, is primarily driven by the very low (or no) levels of transmission capital expenditures assumed in the HV TAC forecasting model. As shown in Figure 2, the HV TAC forecasting model assumes that the HV capital expenditures[1] will occur during the years 2023-2028, which is primarily driven by the CAISO-approved reliability-driven transmission projects.

Figure 2: A Comparison of the CAISO’s HV TAC ($/MWh) and Assumed Capital Expenditures (M$)

Clearly, one of the major reasons for a lower level of capital expenditures assumed in the outer years (2028-2035) in the TAC Forecasting Model is that they do not include the capital expenditures in the CAISO’s upcoming TPP cycles. In other words, the HV TAC rates, especially for years 2028-2035,  are likely going to be higher than those depicted in the current version of the HV TAC Forecasting Model. Furthermore, there needs to be a recognition that the HV TAC rates would be significantly greater upon the incorporation of the direct costs associated with the wildfire mitigation programs[2] and potential higher return on equity allowed for the participating transmission owners as a result of the wildfire risk adder[3].

There is substantial uncertainty surrounding the plans for costs associated with greater levels of return on equity and future investments to mitigate the consequences of wildfires, but it is appropriate to include components for those potential fire hazard mitigation costs. It is important to recognize that not adding anything to the forecast for these issues is a projection that assumes that they will have no impact. 

BAMx appreciates the CAISO providing a separate spreadsheet comprising the capital costs documented for several capital projects with high voltage components[4]. This spreadsheet (Capital Costs Estimates) helps the CAISO and stakeholders to easily modify the transmission projects, their commercial operation dates and related capital costs going forward.

2. Capital projects questions

In addition to the issues surrounding costs for wildfire mitigation and potential raises in return on equity, BAMx has the following questions and comments on some of the capital transmission projects included in the TAC Model. We hope that the CAISO addresses them in the next revision of the TAC Model.

• Calcite: In the most recent TAC Model, the CAISO has added two new transmission projects, i.e., Red Bluff 2nd 'AA' Bank and Calcite. Both these projects are identified as the “Non-RTPP Driven.”[5] Please provide some background on the Calcite project as it appears to be a generation interconnection driven project and, unlike the West of Devers Reconductoring project, there is almost no information available about this project in the 2020-2021 or any of the prior transmission plans.
• Riverside Transmission Reliability Project (RTRP): We noticed that the TAC model did not include the capital expenditure associated with Riverside Transmission Reliability Project (formerly Jurupa 230kV Sub). According to SCE’s AB 970 quarterly report (Q1 2021), this project was approved by the CAISO in 2007 with a current planned in-service date of 10/15/2026. A Certificate of Public Convenience and Necessity (CPCN) for this project was granted on 03/12/2020 and indicates that its capital cost is approximately $450M. Please provide an explanation of why the capital expenditures associated with the RTRP were excluded from the TAC Model.
• Alberhill Transmission Project: The TAC model assumes the capital cost of $314M. This amount needs to be updated to $545M to reflect SCE’s most updated cost estimate.[6]
• Reliability projects “On Hold” are included: The TAC model assumes the capital expenditures of $130M and $140M each in the years 2027 and 2026 for the Midway-Andrew 230 kV and Wheeler Ridge Junction Station projects, respectively, will be made. Since both of these projects are on hold and likely cancelled conditional upon the effectiveness of battery storage alternatives that were identified in the 2019-2020 Transmission plan[7], why are these capital expenditures included in the TAC Model?

BAMx looks forward to continuing the dialog with the CAISO staff and other stakeholders in trying to build a more meaningful forecast of the CAISO HV TAC.

Conclusion

BAMx appreciates the opportunity to comment on the 2021-22 Transmission Plan Reliability Assessment Results and the PTO Request window submissions and acknowledges the significant effort of the CAISO and PTO staffs to develop this material. 

[1] Any capital expenditures after the in-service year are added to rate base in the year of expenditure in the HV TAC forecasting model. Source: California ISO TAC Model Operating Instructions.

[2] Pursuant to Senate Bill 901 and the OIR to Implement Electric Utility Wildfire Mitigation Plans in R.18-10-007 of the CPUC, PG&E submitted its Wildfire Safety Plan on February 6, 2019.

[3] On April 18, 2019, SCE submitted its latest TO2019A formula rate filing, proposing a return on equity (ROE) of 17.12%, which is calculated at 11.12% plus a 6.0% adder for wildfire risk (not including other potential adders). On April 23, 2019, PG&E requested to raise its ROE from 10.25% to 16%.

[4] 2020-2021 Transmission Plan High Voltage Transmission Access Charge Capital Costs (2020-2021TransmissionAccessCharge-HighVoltageCapitalCostEstimates.xlsx)

[5] Ibid.

[6] See CPUC, A.09-09-022, Second Amended Application of Southern California Edison Company (U 338-E) For A Certificate Of Public Convenience And Necessity For The Alberhill System Project, May 11, 2020, P.7.

[7] CAISO 2020-2021 Transmission Plan, March 24, 2021, p.2, p. 114, p. 118.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

Responding to only question 14 

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

Slide 14.  “Comments or potential other transmission projects to be considered for advancement are to be submitted with comments to be submitted by October 12” 

Berkshire Hathaway Energy Renewables (BHER) strongly supports the CAISO’s effort to study and potentially approve in this TPP cycle network upgrades that provide deliverability of resources required to meet CPUC procurement decisions. The CAISO should consider the fact that geothermal resources in the Imperial Irrigation District (IID) service territory are highly likely to be procured by CAISO load serving entities (LSEs) in the 2026 timeframe.  CPUC Decision 21-06-035, Requiring Procurement to Address Mid -Term Reliability (2023-26), provides for the replacement of firm capacity from the retirement of Diablo Canyon Power Plant and once-through-cooling  (OTC) power plants with new capacity from zero-emitting generation.  Targeted procurement of at least 2,000 MW from new or incremental long lead-time (LTT) resources must be online by June 1, 2026.  LLT resources are those with extended development timelines, such as geothermal, biomass or long-duration storage.  To qualify to meet the 2026 LLT procurement requirement, the resource must be online by June 1, 2026.  LSEs may request that the June 1, 2026 online deadline be extended up to June 1, 2028.  The request must be made by February 1, 2023 and must be supported by evidence demonstrating a good faith effort to satisfy the procurement mandate.  At least 1,000 MW must be procured from firm resources that are either zero onsite emission resources or 2) RPS eligible resources with a capacity factor of at least 80 percent, and that are not use limited or weather dependent.  D. 21-06-035 specifically contemplates that geothermal resources can be used to meet these procurement requirements.  

The largest known untapped geothermal resource within California is located in the Salton Sea Known Geothermal Resource Area (KGRA).  This region has over 70% of the state’s potential for new geothermal development.  The CAISO should study the potential need for additional transmission from IID service territory to enable sufficient import allocation rights to support that procurement. If those projects don’t start now, there will not be sufficient deliverable geothermal resources to support compliance with LSE procurement obligations by the 2026 deadline.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

Borrego would like to thank the CAISO for the opportunity to comment on the 2021-2022 Transmission Planning Process Stakeholder Meeting on September 27 and 28 of 2021. Borrego is currently following several potential transmission upgrades on the Pacific Gas and Electric (PG&E) system that would improve the deliverability outlook for several of our projects currently in the CAISO Generator Interconnection Process (GIP) queue. 

During the “Increasing Procurement and Capacity in Portfolios” presentation by CAISO Director of Transmission Infrastructure Planning, Jeff Billington, the CAISO outlined eight (8) transmission projects along with the Incremental FCDS values, Time to Construct, and Estimated Cost. 

One of these upgrades, the Gates Transformer Bank #13, is a critical system upgrade needed to achieve Full Capacity Deliverability Status  (FCDS) for many of our projects in the Central Valley. As shown in the stakeholder meeting presentation by Jeff Billington, as well as the “Transmission Capability Estimates for Use in the CPUC’s Resource Planning Process” white paper (July 19, 2021), this upgrade offers one of the highest levels of incremental deliverability per estimated cost when compared with other upgrades on the system.

The CAISO 2021 Transmission Plan Deliverability Allocation Report (March 15, 2021) further supports the need for this upgrade. The report identified that only 294.6 MW of deliverability was allocated to queued projects, while over 1289 MW in projects were eligible to receive an allocation. Meaning that 995 MW of eligible projects did not receive an allocation due to this constraint. Borrego is pleased to see that this upgrade is receiving visibility by the CAISO, and encourages its approval in the 2021-2022 TPP either as a reliability or a policy driven upgrade.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

 No comments at this time.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

 No comments at this time.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

 No comments at this time.

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

 No comments at this time.

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

 No comments at this time.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

 No comments at this time.

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

 No comments at this time.

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

CalCCA reiterates its appreciation from previous comments on the CAISO’s efforts to develop the 20-year Transmission Outlook and commends the CAISO for its collaboration with the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) in the IRP, SB 100, and Integrated Energy Policy Report (IEPR) processes.[1] Coordination with these processes will ensure resource procurement and new transmission build aligns. Forward planning with a long enough lead time will be critical in ensuring the state is prepared to meet SB 100 goals that require renewable energy and zero-carbon resources to supply 100 percent of electric retail sales to end-use customers by 2045. The CAISO should consider how the 20-year Transmission Outlook could be incorporated into the existing Transmission Planning Process (TPP) to consider what transmission build will need to occur and in what timeframe to meet policy goals. Given the time required to develop new transmission, the 10-year look ahead in the TPP can result in transmission projects coming online just in time to meet an identified reliability need.

CalCCA is encouraged that the 20-year Transmission Outlook will utilize the Starting Point scenario based off the SB 100 Core scenario for 2040. Recognizing that decarbonization goals necessitate significant resource build, it is prudent to use this scenario to inform potential transmission projects so that new clean resources do not get stranded behind transmission constraints. Considering the large number of resources expected to come online to meet state policies, the TPP could benefit from the insight of a longer planning horizon provided by the 20-year Transmission Outlook to inform policy-driven transmission projects. The 20-year Transmission Outlook should be used to inform the TPP of transmission needs driven by clean energy policies like SB 100 so that projects approved in the TPP also contribute to meeting policy goals that will be realized beyond 10 years out.

CalCCA also supports the 20-year Transmission Outlook’s consideration of key environmental and land use impacts provided by the CEC. It may be valuable for the CAISO and the CEC to incorporate such impacts to the normal TPP cycle as well. Land use and habitat concerns can create serious delays or project cancellations if not incorporated into site evaluation from the start. By incorporating these considerations into transmission planning, the CAISO, the Commission, and the CEC can help steer projects to less sensitive areas and avoid potentially serious delays or cancellations of transmission projects needed to integrate future resource procurement.

[1]             CalCCA Comments on July 27, 2021 Transmission Planning Stakeholder Call, August 10, 2021.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

 No comments at this time.

10. Provide your organization’s comments on the SCE Reliability Alternatives:

 No comments at this time.

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

 No comments at this time.

12. Provide your organization’s comments on the GLW Reliability Alternatives:

 No comments at this time.

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

 No comments at this time.

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

CalCCA generally supports the CAISO’s intention to consider additional upgrades beyond those identified in the analysis for this planning cycle but requests additional clarification on how such upgrades will be selected. The CAISO’s presentation indicates that it intends to consider additional upgrades to reflect the increase in resource procurement and provide flexibility for resources not currently in the base portfolio.[1] Transmission and resource build are inextricably linked and identifying additional upgrades now in anticipation of increased resource build could provide the necessary signals to resources as to where to site new resource build necessary to meet resource procurement targets and SB 100 goals. CalCCA looks forward to additional discussion on this topic in future stakeholder calls.

[1]             CAISO Day 2 Presentation at 12.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

No comments at this time.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

CPUC staff appreciates the overview of preliminary results of the CAISO’s reliability assessment.  As the CAISO is conducting ongoing analysis and considering requests for additional upgrades, we look forward to thorough explanation of the final study results to be posted early next year in the 2021-2022 Transmission Plan.

CPUC staff would appreciate a deeper focus on the timing of the reliability need, costs, mitigation options and rationale for major upgrades such as possible new 230 kV lines in PG&E’s San Jose area and the Valley Electric Association area.

We also encourage the CAISO’s robust analysis of alternative mitigation options which may reduce costs to ratepayers while addressing reliability needs, especially non-transmission alternatives that may delay or obviate the need for previously approved projects. 

We note that the 2020-2021 Transmission Plan identified two storage projects as alternatives to previously approved transmission projects deemed necessary for reliability.  This appears to be the first time the CAISO (and not a PTO) has identified storage as an alternative to previously approved transmission projects.  CPUC staff is reviewing stakeholder comments in the IRP proceeding (R.20-05-003) on ways to ensure these projects are developed in these specific locations.  CPUC staff strongly supports the CAISO’s identification of non-transmission alternatives, and we encourage the CAISO’s continued efforts and analysis on ways to enhance the transmission system in the least expensive manner.  

CPUC staff also notes the CAISO’s preliminary reliability assessment did not include the Humboldt area.  It would be helpful to clarify the reason why – whether it’s because the CAISO determined that no reliability assessment for that area was needed within this TPP, or because any reliability needs within the Humboldt area could be adequately assessed as part of the off-shore wind sensitivity study being conducted, for which preliminary results will be presented in November.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

CPUC staff would appreciate a deeper focus on the timing of the reliability need, costs, mitigation options and rationale for major upgrades such as possible new 230 kV lines in PG&E’s San Jose area and the Valley Electric Association area.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

CPUC staff would appreciate a deeper focus on the timing of the reliability need, costs, mitigation options and rationale for major upgrades such as possible new 230 kV lines in PG&E’s San Jose area and the Valley Electric Association area.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

CPUC staff appreciates the CAISO’s collaboration in developing the Starting Point scenario for this 20-Year Outlook.  The Day 1 presentation (slides 262-281) cogently reflect the informational document put together by staff from the California Energy Commission, the CPUC and the CAISO following a series of public workshops.  CPUC staff reiterates support for the assumptions for assessing gas retirements and the proposed approach for assessing gas plants associated with Aliso.

More generally, this 20-Year Transmission Outlook is a valuable new addition to the set of transmission planning analyses that CAISO produces.  It will be useful to multiple state agencies and stakeholders.  We hope the CAISO will continue to enhance and update this 20-Year Transmission Outlook on a regular basis.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

The CAISO’s short presentation focused on a potential change in the assumption for the net export limit used within the CAISO’s production cost model (PCM), which assesses the economic value of certain proposed transmission projects.  CPUC staff notes that the Final Study Plan (posted March 31, 2021) indicates four developers requested the CAISO’s economic evaluation of their projects within this TPP cycle.  

The presentation indicated that CAISO is considering increasing the assumed net export level from 2,000 MW to 5,000 MW based on observed historical trends.  It is not clear when the CAISO will make this decision to increase the assumed net export level, or when stakeholders will learn if the CAISO is implementing this proposal.  Preliminary results of the economic evaluations for these submitted projects are expected at the TPP stakeholder meeting in November.

CPUC staff offers these clarifying questions on this potential update to the PCM:

• Is this potential change limited to the year 2031 within the PCM?
• What is the likely impact of increasing the net export limit?  Would economic projects be more or less likely to demonstrate positive economic value?

 CPUC staff encourage further explanation on this potential change and its impact on the PCM results.

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

The CAISO has invited stakeholder input or proposals on additional transmission expansions beyond those driven by IRP portfolios including policy-driven needs, reliability needs, and/or those identified as economic.  

CPUC staff seeks clarification on the criteria or standards by which CAISO would recommend such additional upgrades.  CPUC staff expects further discussion on this at the November stakeholder meeting.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

Slide 14 noted that the CAISO has posted the transmission access forecast charge model from the 2020-2021 transmission planning process.  In previous years the CAISO has also offered a presentation on the use of this model, which is an important tool in the consideration of transmission costs.  CPUC staff encourages a presentation or fuller explanation on this model to enhance visibility and understanding of estimated project costs and TAC impacts.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

The following are comments from the Public Advocates Office at the California Public Utilities Commission (Cal Advocates).  Cal Advocates is an independent consumer advocate with a mandate to obtain the lowest possible rates for utility services, consistent with reliable and safe service levels, and the state’s environmental goals.[1]   Cal Advocates comments are primarily focused on the utilities’ proposed projects to respond to identified reliability issues.  For this reason, Cal Advocates does not have any comments on the overview of key issues included in the CAISO’s Reliability Assessment Results presentation provided on September 27, 2021. 

[1] Cal. Pub. Util. Code § 309.5.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

Cal Advocates does not have a comment on this topic at this time.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

Please refer to Cal Advocates’ response to Pacific Gas and Electric Company’s reliability assessment results provided in our reply to question 9.

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

Please refer to Cal Advocates’ response to the CAISO’s southern California reliability assessment results provided in our reply to question 10.

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

Please refer to Cal Advocates’ response to Valley Electric Association’s reliability assessment results provided in our reply to question 12.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

Please refer to Cal Advocates response to San Diego Gas & Electric Company’s reliability assessment results provided in our reply to question 11.

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

The Draft 2021-2022 Wildfire Impact Assessment Study Scope states that the CAISO will identify critical facilities and approve projects that could reduce fire risk.  CAISO plans to examine different scenarios of de-energized transmission lines in Public Safety Power Shutoff (PSPS) events to identify where potential new upgrades could help reduce the risk of fire impact.[1]  The CAISO also plans to use Spring 2023 off-peak and Summer 2026 peak load study base cases to model a variety of PSPS events and fire scenarios.[2]

Cal Advocates recommends the CAISO provide information and clarity on the expected outcomes and the objectives of the study.  Cal Advocates seeks to understand whether the CAISO will examine if critical facilities and approved projects could reduce the likelihood of PSPS events in addition to fire ignitions.  Specifically, Cal Advocates requests that the CAISO compare the results of its impact study with any utilities’ planned mitigations (e.g., covered conductor, vegetation management, line undergrounding) listed in the utilities’ Wildfire Mitigation Plans[3] to ensure that any proposed study upgrades are not functionally duplicative of fire risk mitigations already planned by the utilities.

Cal Advocates also recommends that the CAISO clarify why it has decided to use Spring 2023 off-peak base cases to assess the impacts of PSPS events.  Generally, weather conditions that cause the utilities to execute PSPS events occur in the late summer and early fall, and often coincide with high heat loads justifying the use of a summer peak base case).[4]  There seems to be a disconnect between the CAISO’s proposed spring off-peak scenario study and the high heat loads that occur in the summer.  Therefore, Cal Advocates would like to understand the CAISO’s reasoning for using the spring off-peak scenario.  

[1] CAISO 2021-2022 TPP PSPS/Wildfire Impact Assessment Study Scope – Southern California, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, September 27, 2021, page 4.

[2] CAISO 2021-2022 TPP PSPS/Wildfire Impact Assessment Study Scope – Southern California, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, September 27, 2021, pages 7-8.

[3] PG&E 2021 Wildfire Mitigation Plan, p. 598. PG&E Plans to apply system hardening to the top 20 percent of the riskiest circuit segments as defined by PG&E's 2021 Wildfire Distribution Risk Model for system hardening. 

[4] Since 2019, PG&E, SCE, SDG&E, and PacifiCorp have filed a total of 58 PSPS post-event reports at the CPUC. 39 of these reports were on events executed in the months of August, September, October, and November.

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

For the 20-year Transmission Outlook studies, the CAISO assumes that 5,215 megawatts (MW) of out-of-state (OOS) wind is available in New Mexico through new transmission.[1]

Cal Advocates recommends that the CAISO confirm the New Mexico wind capacity that could be available to meet California’s resource goals in 2025 and 2032 through a combination of existing and new transmission.  Based on recent power purchase agreements, the delivery of New Mexico wind capacity is possible through firm transmission deliverability rights on existing and new transmission.[2]  Cal Advocates requests the CAISO confirm whether or not it is considering the most cost-effective option to access OOS wind, which is through existing transmission lines between California and New Mexico.

Cal Advocates also continues to recommend that the CAISO, as the California regional transmission planning system operator, evaluate all the benefits and beneficiaries of interregional transmission lines for cost allocation coordination with other regional planning organizations in the western interconnection.[3]  The Federal Energy Regulatory Commission (FERC) recently solicited feedback on the current interregional transmission planning coordination process between regional transmission planning organizations and the cost allocation outcomes with the following questions in an Advanced Notice of a Proposed Rulemaking (ANOPR): [4]

1. Whether or not FERC should provide alternative pathways for transmission facilities that benefit multiple regions to assign cost allocation to customers across the multiple regions that benefit?[5]
2. Whether or not FERC should require transmission providers to establish a broader set of transmission benefits for cost allocation than those currently in use?[6]

Thus, this ANOPR has the potential to alter the current western interregional transmission planning coordination and cost allocation benefits and beneficiaries considered currently.  For this reason, the potential outcome of this rulemaking should be factored into any CAISO recommendations provided on the identified interregional transmission projects in the 20-Year Transmission Outlook Study.

[1] CAISO 20 Year Transmission Outlook SB100 Starting Point Scenario, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021 (Presentation), September 27, 2021, slide 17.

[2] Comments of Southern Power Group II, LLC and Pattern Energy Group LP on the Administrative Law Judge’s Ruling Seeking comments on Proposed Preferred System Plan, Rulemaking 20-05-003, May 7, 2020, pp. 7-8.

[3] Cal Advocates comments on the July 27, 2021, stakeholder call discussion on the 2021-2022 Transmission Planning Process, August 11, 2021, pp 2-3.

[4] FERC RM21-17-000, Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generation Interconnection (FERC RM21-17-000), July 15, 202.

[5] FERC RM21-17-000, Item 63, p. 47

[6] FERC RM21-17-000, Item 94, p. 68

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

Cal Advocates lists its recommendations for Pacific Gas and Electric Company’s (PG&E) reliability project analysis and alternatives below:

1. Provide Cost Assumptions for Provided Energy Storage Integrations Costs

Cal Advocates recommends PG&E provide more information on the assumptions used to determine energy storage integration costs for the project alternative analysis in their CAISO transmission planning process (TPP) presentations. 

Specifically, for the potential overloads at the Weber 60 kilovolts (kV) substation within the next 10 years, PG&E recommends that energy storage not be considered since the cost to integrate energy storage would be between $13 million to $26 million.[1]   Cal Advocates requests that PG&E elaborate on how it arrived at this cost estimate and provide comparisons to similar projects and more details on the upgrades needed. 

Similarly, to increase the Borden-Coppermine 70 kV line capacity, PG&E recommends that energy storage not be considered since energy storage would trigger a bus upgrade with a cost range of $35 million to $70 million.[2]   Cal Advocates requests PG&E explain the factors that would trigger additional upgrades with energy storage installations in TPP meetings.  With this analysis, stakeholders could confirm whether or not energy storage could assist with the currently observed overloads in a shorter time frame than the proposed line reinforcement project, which is scheduled for implementation in 2027.[3]

2. Consider the CAISO’s lower costs long-term solutions

Upgrade the Transformer Bank #1 to Address and Remaining Issues at the Cortina Substation

For the potential overloads in the Sacramento area at the Cortina substation, the CAISO recommends implementing an existing operating procedure to avoid the loss of Bank #4 at the Cortina substation.[4]  As noted in PG&E’s presentation, with the implementation of this existing operating procedure overloads are no longer expected under a P3 contingency, and overloads are dramatically reduced from 37.5% to 2.2% under a P1 contingency in 2023.[5]  To address any remaining overload potential in the Cortina system area, the CAISO recommends upgrading the transformer Bank #1 for the long-term.[6]  In contrast, PG&E proposes a long-term solution of replacing Bank #1 at the Cortina substation with two new transformer banks with a total project cost of $21 million to $42 million.[7]  Since implementing the existing operating procedure seems to mostly solve the observed overload issues in the Cortina system area, PG&E’s more drastic and costly proposed long-term solution does not seem justified.  Cal Advocates recommends PG&E evaluate upgrading Bank #1 as a long-term solution versus replacing it.  Cal Advocates also recommends that the CAISO not approve PG&E’s proposed long-term solution for the Cortina substation.

Consider a Combination of Energy Storage and Wire Solutions to Address San Jose Load Growth

To address the anticipated load increase in the San Jose area within the next 10 years,[8] the CAISO recommends a new 230 kV or 500 kV source in San Jose.[9]  This forecast of  increased load growth is primarily due to extremely large-scale data centers expected in the Silicon Valley Power (SVP) service area.[10]  In response to this anticipated load growth, PG&E presented only capital transmission solutions and recommended both reconductoring and replacing lines in the San Jose sub-area. 

Cal Advocates recommends PG&E evaluate and provide cost estimates for the following two additional alternative projects to determine the lowest cost solution: 

• Alternative #1: Install energy storage in the project area and reconductor the Los Esteros – Nortech – NRS 115 kV line. 
• Alternative #2: Install energy storage and a reactive support device as well as reconductor the Los Esteros – Nortech – NRS 115 kV line. 

Cal Advocates anticipates that the forecasted data centers will be required to comply with the state’s new building code requirements.[11]  New buildings are required to reduce their load through on-site generation and energy efficient upgrades.  These data centers will also be subject to time-of-use rates to reduce the total demand on the electric system.  As a result, the actual load for these data centers will likely be less than the currently forecasted load.  Therefore, Cal Advocates recommends that the CAISO only approve low-cost solutions to address the anticipated load growth in San Jose at this time and consider the need for more expensive long-term solutions when there is more certainty on the data center load ramping needs.

[1] PG&E’s 2021 Request Window Proposals, CAISO 2021-22 Transmission Planning Process (Presentation), PG&E, September 28, 2021, slide 7.

[2] PG&E’s 2021 Request Window Proposals, CAISO 2021-22 Transmission Planning Process (Presentation), PG&E, September 28, 2021, slide 25.

[3] PG&E’s 2021 Request Window Proposals, CAISO 2021-22 Transmission Planning Process (Presentation), PG&E, September 28, 2021, slide 25.

[4][4] Central Valley Area Preliminary Assessment Results, 2021-22 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, CAISO, September 27, 2021, page 8.

[5] PG&E’s 2021 Request Window Proposals, CAISO 2021-22 Transmission Planning Process (Presentation), PG&E, September 28, 2021, slide 18.

[6] Central Valley Area Preliminary Assessment Results, 2021-22 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, CAISO, September 27, 2021, page 8.

[7] PG&E’s 2021 Request Window Proposals, CAISO 2021-22 Transmission Planning Process (Presentation), PG&E, September 28, 2021, slide 19.

[8] PG&E’s 2021 Request Window Proposals, CAISO 2021-22 Transmission Planning Process (Presentation), PG&E, September 28, 2021, slide 40 and slides 45-47.

[9] Greater Bay Area Preliminary Reliability Assessment Results, 2021-22 Transmission Planning Process Stakeholder Meeting (Presentation), CAISO September 27-28, 2021, slide 15.

[10] Silicon Valley Power CEO’s Letter to the CAISO Board of Governors, March 22, 2021.

[11] 2022 Building Energy Efficiency Standard Summary at 2021 Building Energy Efficiency Standards Summary (ca.gov).

10. Provide your organization’s comments on the SCE Reliability Alternatives:

The CAISO and Southern California Edison Company (SCE) expect overloads between 4% and 17% above system capacity in SCE’s metro area starting in 2023 with the state’s proposed resource portfolio changes and anticipated load growth.[1]  To address these overloads, the CAISO recommends dispatching available resources, utilizing 30-minute emergency ratings, and adding more resources or a fourth transformer bank at the Serrano substation, if necessary.  SCE only evaluated adding a new 4AA 500/230 kV transformer bank, at an estimated cost of $120 million at the Serrano substation to address the potential overloads in the SCE metro area.[2]  Cal Advocates requests SCE explore CAISOs recommended solutions and provide cost estimates for these solutions, including implementing the suggested operational changes and installing energy storage and assessment of their effectiveness.  Cal Advocates also recommends that the CAISO not approve the proposed fourth transformer bank at the Serrano substation in this TPP cycle because sufficient reasons for this expense were not provided.

[1] CAISO SCE Main System Preliminary Reliability Assessment Results, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, September 27, 2021, Slide 10.

[2] Proposed SCE Submittals into the 2021-22 Transmission Planning Process, 2021-2022 CAISO TPP, September 15, 2021, slide 2.

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

Recommendations for SDG&E’s Reliability Project Analysis and Alternatives

To address the changes in the resource portfolio and load in the San Diego Gas & Electric Company (SDG&E) area that contribute to overload issues on the Suncrest – Sycamore 230 kV line, the CAISO recommends reducing and dispatching generation, curtailing imports, and other system adjustments, including using existing remedial action schemes.[1]  In contrast, SDG&E proposes constructing a new 33-mile 500 kV line between the Miguel and Suncrest substations at an estimated cost of $335 million to $600 million.[2]  SDG&E provided no evidence of why system readjustments and operational actions are not capable of mitigating the P3 and P6 overloads identified in the 2023 summer peak case.  Since SDG&E provides little support for this drastic and expensive new line, Cal Advocates recommends SDG&E  further evaluate the lower cost solutions that the CAISO identified to address potential P3 and P6 overloads on SDG&E’s system.[3]  Cal Advocates also recommends that the CAISO not approve the proposed 33-mile 500kV line between the Miguel and Suncrest substations in this TPP cycle because SDG&E provided no evidence of why system readjustments and operational actions are not capable of mitigating P3 and P6 overloads.

[1] San Diego Gas & Electric Area Preliminary Reliability Assessment Results, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021 (Presentation), September 28, 2021, slide 9.

[2] TPP 2021-22 CAISO Stakeholder Presentation September 2021, SDG&E, slide 5.

[3] CAISO, San Diego Gas & Electric Area Preliminary Reliability Assessment Results, 2021-2022 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021 – slides 9-12.

12. Provide your organization’s comments on the GLW Reliability Alternatives:

Recommendation for Gridliance West Reliability Project Proposals

During the 2021-2022 Transmission Planning Process (TPP) stakeholder meetings on September 27-28, 2021, Gridliance West (GLW) proposed a series of high-voltage (230 kV) upgrades to the Valley Electric Association (VEA) system in southwestern Nevada.  GLW presented its upgrades as projects to address a combination of grid reliability, economic benefit, and policy needs.  These upgrades include: (1) rebuilding three 230 kV double circuits; (2) adding a new 230 kV circuit, and (3) adding a new 500/230 kV transformer.  The proposed in-service date for these projects is December 31, 2021, at an estimated cost of $213 million.

GLW proposed similar upgrades in past TPP reliability assessments and project windows.[1]  In 2017 and 2018, Cal Advocates responded to these requests by noting that GLW did not demonstrate that the existing VEA system failed to meet the North American Reliability Corporation (NERC) reliability planning standards.  Cal Advocates also recommends GLW provide a formal cost-benefit analysis of the proposed upgrades in order to comply with these standards.[2]^{, [3]}

During the September 28, 2021, TPP meeting, GLW and CAISO staff clarified that expected increases in solar and other resource developments totaling over 2,000 MW are the drivers for this year’s VEA system upgrades projects.[4]  Given that the focus of the September 28, 2021 TPP meeting was the CAISO’s reliability assessments and possible solutions, and that the driver for the proposed GLW projects is not reliability, Cal Advocates recommends that the CAISO complete a formal cost and benefit analysis as outlined in the CAISO Planning standards to determine the potential economic justifications for the projects GLW proposes.  To confirm if the GLW projects are needed to meet the state’s policy goals, there should be a reassessment of procurement in VEA’s area based on GLW’s estimated transmission upgrade costs to determine if this procurement is cost effective. 

In addition, based on the August 2021 Integrated Resource Plan (IRP) ruling, RESOLVE selects only a partial upgrade in the VEA area to access only 221 MW of resources.[5]    Given that RESOLVE selected a partial upgrade and the limited procurement amount, Cal Advocates recommends further evaluation to determine when and if these GLW-proposed upgrades are necessary to meet the state’s policy needs.  The CAISO should coordinate this evaluation with the busbar mapping exercises that it conducts jointly with the California Public Utilities Commission and California Energy Commission.

Cal Advocates several other concerns with GLW’s project proposals for the 2021-2022 TPP Reliability Project Request Window are listed below:

• GLW claims that its projects increase capacity to “allow for CPUC 2,024 MW portfolio”[6] without identifying the resource developments in the VEA area that are dependent on the proposed projects and would support this portfolio and the IRP preferred system portfolio.  Before the CAISO considers these projects further, GLW should provide details on relevant resource developments in the VEA area.
• GLW also claims that the upgrades would generate CAISO net payment benefits of $67 million annually with no corresponding evidence.[7]  GLW should be required to provide the assumptions and methods used to arrive at its net payment benefit claims.
• Regarding grid reliability, as Cal Advocates stated in past TPPs,[8] GLW should provide evidence of its claim that the existing system design fails to meet the required NERC planning standards and therefore requires these transmission upgrades.  In their September 2021 TPP presentation, GLW states that the rebuild of the 230 kV double circuit from Pahrump to Gamebird to Trout Canyon substations would addresses a P6 contingency, which, per NERC standards, involves two overlapping contingencies and allows for non-sequential load loss and interruption of firm service, if necessary.[9]  The CAISO should clarify if NERC standards require upgrades for this contingency.
• These projects would represent a serious burden to CAISO ratepayers.  Using the CAISO’s Transmission Access Charge (TAC) Forecast Model and the GLW project cost estimates of $213 million,[10]  Cal Advocates forecasts that the transmission revenue that GLW is set to collect from CAISO ratepayers in 2021 could almost double by 2027 if their projects are approved (see the reply to question 15 in these comments for more information on this forecast).[11]  Given these ratepayer impacts, there must be corresponding benefits to Californians.  However, GLW has not provided a demonstration of either the projects’ necessity or the benefits to California ratepayers.
• Because the projects would be constructed in Nevada, they also may not need California Public Utilities Commission (CPUC) approval.  This would deny California ratepayers, the proposed funders of the projects, the ability to have the CPUC decide if the project represents their public convenience and necessity.  As such, it is critical that the CAISO provide a high level of scrutiny on project need and costs.

[1] Gridliance West Transco’s 2018 Request Window Proposal CAISO 2018/2019 Transmission Planning Process, September 20-21, 2018, September 21, 2021, slides 2-7.

[2] The Office of Ratepayer Advocates’ Comments of the California Independent System Operator (CAISO) Transmission Planning Process (TPP) Presentations and Meetings on September 21-22, 2017, p. 4.

[3] Comments of the Public Advocates Office on the California Independent System Operator’s 2018-2019 Transmission Planning Process – Preliminary Results September 20-21, 2018, Presentations and Stakeholder Meetings, p. 4.

[4] California (CAISO) 2021-22 Transmission Planning Process Meeting – Day 2 PTO Proposed Reliability Alternative and CAISO Economic Study Update, Customized Energy Solution, September 28, 2021, p. 9.

[5] CPUC R.20-05-003, RESOLVE Preferred System Plan (PSP) Modeling Results Presentation, August 2021, slide 25.

[6] GridLiance West Project Proposal for the 2021-22 TPP Reliability Request Window.  September 27-28, 2021.  Available at http://www.caiso.com/InitiativeDocuments/GLWPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf.

[7]GridLiance West Project Proposal for the 2021-22 TPP Reliability Request Window.  September 27-28, 2021.  Available at http://www.caiso.com/InitiativeDocuments/GLWPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf.

[8] Comments of the Public Advocates Office on the California Independent System Operator’s 2018-19 Transmission Planning Process.  October 5, 2018.   P.3.

[9] Standard TPL-001-4 — Transmission System Planning Performance Requirements.  Available at https://www.nerc.com/files/TPL-001-4.pdf.

[10] Transmission Access Charge Forecast Model.  The California Independent System Operator. Available at http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=7A2CFF1E-E340-4D46-8F39-33398E100AE7.

[11] July 2021 TAC Rates.  The California Independent System Operator.  Available at http://www.caiso.com/Documents/HighVoltageAccessChargeRatesEffectiveJul12-2021.pdf.

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

Cal Advocates does not have a comment on this topic at this time.

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

For its reliability assessment and transmission plan, the CAISO typically responds to the current Integrated Resource Plan (IRP) portfolios.  This year, the CAISO presented additional transmission upgrades in response to the draft IRP preferred system plan (PSP) for 2032.  This draft PSP plan for 2032 includes 18,833 MW of solar, 3,553 MW of in-state wind, 1,500 MW of out-of-state (OOS) wind, and 1,708 offshore wind.[1]  

The additional information on the procurement costs for the draft 2025 and 2032 PSP is helpful.  The majority of the identified transmission upgrades listed would increase full deliverability capacity status (FCDS) for solar developments based on the CAISO White Paper on Transmission Capacity Estimates for CPUC Resource Planning (Transmission Capacity White Paper).[2]  The costs of these transmission upgrades should be incorporated in the 2022-2023 TPP cycle to determine if these upgraded transmission costs modify the draft PSP resource selections.  In other words, the CAISO should not decide on the presented additional transmission upgrades for the draft PSP for 2025 and 2032 this 2021-2022 TPP cycle for the following reasons.

1. The CPUC states that most of the solar selected in its 38 million metric ton (MMT) Core scenario is energy only,[3] so it is not clear that upgrades for FCDS are necessary.

2. The RESOLVE model results that supported the 2021-2022 PSP did not consider the scope and cost associated with the transmission projects identified in the CAISO’s transmission capability estimates.[4]  Had RESOLVE incorporated this transmission cost data, it may not have selected certain resources in specific renewable zones.  Therefore, Cal Advocates recommends that the CAISO not consider these transmission projects for approval in the 2021-2022 TPP cycle and instead allow the CPUC IRP process to reassess the need for these projects in subsequent planning cycles.

3. The potential impact of increased commercial interest in solar plus storage projects was not currently fully considered in the 2021 PSP, and this combination could reduce the need for additional transmission infrastructure.  To explain, the Senate Bill (SB) 100 report identified limitations with the RESOLVE model including failing to evaluate hybrid resources such as solar plus storage.[5]  The most recent RESOLVE model update states that the interaction between solar and storage is still not modeled and thus “cost reductions from shared infrastructure are not modeled.”[6]  For this reason, Cal Advocates requests proper evaluation of solar plus storage resources to eliminate consideration of potentially unnecessary transmission investments.

The costs of the proposed upgrades also vary widely with respect to their impact on increased transmission capacity.  For this reason, some upgrades do not seem cost effective.  For example, the Gates Transformer Bank #13 upgrade would provide 4,453 MW of FCDS capacity for $40 million, while the Woodlands-Davis 115kV Lines result in an increase of only 96 MW of FCDS for $11 million.[7]

The new Eldorado 500/230 transformer upgrade with an estimated cost of $70 million to access 400 MW of FCDS capacity[8] seems to be triggered with the procurement of new resources such as, Wyoming wind.  For this reason, the cost of this upgrade should be evaluated along with the total new OOS transmission cost to access Wyoming wind to determine if procurement of Wyoming wind through new OOS transmission is cost effective. 

If the Eldorado upgrade is found to be needed only to access solar development and not OOS wind as suggested in the Transmission Capacity White Paper, the estimated Mountain Pass El Dorado area’s commercial solar interest capacity of only 248 MW[9] would not justify the proposed upgrade.

[1] CAISO Increasing Procurement and capacity portfolios, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, CAISO, September 28, 2021, Slide 2.

[2] Transmission Capability Estimates for use in the CPUC’s Resource Planning Process White Paper, CAISO, July 19, 2021, p. 5

[3] CPUC R.20-05-003, Proposed PSP (38 MMT Core Portfolio) with LSE Plans (presentation), August 2021, slide 30.

[4] CAISO, Increasing procurement and capacity in portfolios, 2021-2022 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021, page 4.

[5] 2021 SB 100 Joint Agency Report, Achieving 100 Precent Clean Electricity in California: An Initial Assessment, California Energy Commission, March 2021, p. 66.

[6] CPUC R.20-05-003, RESOLVE Preferred System Plan (PSP) Modeling Results (Presentation), August 2021, slide 9.

[7] Increasing Procurement and capacity portfolios, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, CAISO, September 28, 2021, Slide 4.

[8] Increasing Procurement and capacity portfolios, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021, CAISO, September 28, 2021, Slide 4.

[9] CAISO’s 20 Year Transmission Outlook SB100 Starting Point Scenario, 2021-2022 Transmission Planning Process Stakeholder Meeting September 27-28, 2021 (Presentation), September 27, 2021, slide 14.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

Cal Advocates has two additional recommendations for the TPP, which are described below.

1. Provide the impact of proposed transmission investments on the High Voltage Transmission Access Charge for California ratepayers. 

Cal Advocates recommends that the CAISO quantify, analyze, and consider the impact that these proposed projects will have on ratepayers. Specifically, the CAISO should quantify the increase in the transmission revenue that the participating transmission owners (PTO) would collect with approval of all of these projects through ratepayers in the CAISO Balancing Authority Area (BAA).[1]  Cal Advocates has performed a back-of-the-envelope calculation of that impact below.

Facilities over 200 kilovolts (kV) are recovered via a “postage-stamp” rate, which is common across the CAISO Balancing Authority Areas (BAA).[2]  In their presentations on September 28, 2021, PG&E, SCE, SDG&E, and GLW proposed close to $1 billion in potential transmission upgrades of 200 kV and above ($970,700,000) by 2025.[3]  A summary is below.

Table 1 - Over 200 kV Reliability Projects Proposed in the 2021-22 Transmission Planning Process[4]

Should all of these projects be approved by the CAISO and all agencies having jurisdiction, their impact on each PTO’s Annual Transmission Revenue Requirement (TRR) would depend on several factors, including, but not limited to, each PTO’s authorized return on equity and the useful life of the asset.  Using the CAISO’s publicly available Transmission Access Charge Forecast Model,[6] Cal Advocates estimated the annual TRR increases based on the estimated costs of these projects.  Cal Advocates then applied those estimates to the most recently reported TRRs[7] to determine their incremental impact in the short term.  These estimates do not adjust for inflation and are based on several assumptions, one of which is that as the TRRs remains unchanged from July 2021 except for the projects list above (this allowed Cal Advocates to isolate the impact of these projects).

SDG&E’s proposed $5.5 million Friars-Doublet Tap Reconductor would go into service in 2022,[8] with an estimated $400,000 increase in SDG&E’s TRR in 2022.  In 2023, SDG&E’s 500 kV Miguel-Suncrest and SCE’s Devers and Victor 230 kV Reconfigurations and Laguna Bell-Mesa 230 kV Line Rating Increase would go into service for a total of $621 million in capital costs.[9]  This would lead to an increase in both SCE’s and SDG&E’s TRR; SDG&E’s increase would be $38 million in 2023, $87.4 million in 2024, and onward. 

The $213 million GLW Projects[10] would go into service in 2025 and almost double GLW’s current TRR by 2026, with an estimated annual TRR increase of about $31 million.  As mentioned, the GLW projects have unproven direct reliability, economic or policy procurement benefits to California, so the projects’ related TRR impact of $31 million is of great concern.

These preliminary estimates show that the annual TRR impact of these projects would decline over a number of years, depending on the useful lives of the projects.  However, the proposed projects would dramatically exacerbate rapidly rising transmission costs, and be applied to all ratepayers in the CAISO BAA, many of whom may not directly benefit from these proposed projects.  A recent CPUC report found that “transmission revenue requirements have risen a total of 38.1 percent from 2016 to 2021 across the three IOUs.”[11]  Cal Advocates recommends the CAISO evaluate the estimated costs of these proposed projects and the impact to CAISO ratepayers, including the benefits commensurate with the costs per the cost causation principles.

2.         Provide references to the CAISO reliability assessments in the PTO presentations.

To improve the transparency and user-friendliness of the CAISO Reliability Assessment stakeholder meetings, the utilities’ proposed projects discussed during Day 2 of the Reliability Assessment meetings should cross-reference the specific slides in the Day 1 CAISO Reliability Assessment presentation that discuss the related reliability issues and possible solutions.

[1] PG&E, SCE, SDG&E, and GLW are all currently participating transmission owners that collect revenue via the HV-TAC.

[2]“The current approach uses a “postage-stamp” rate (i.e., a common rate across the ISO BAA) to recover the costs associated with regional or high-voltage transmission facilities under ISO operational control (i.e., facilities rated at or above 200 kV), and utility-specific rates in each of the investor-owned utility (IOU) service areas to recover the costs of local or low voltage facilities (i.e., facilities rated less than 200 kV) under ISO operational control.”  Review Transmission Access Charge Structure.  Revised Straw Proposal.  The California Independent System Operator. April 4, 2018. Available at https://www.caiso.com/Documents/RevisedStrawProposal-ReviewTransmissionAccessChargeStructure.pdf.

[3] These figures assume the upper range of the estimates included in the September 28 presentations, and PG&E’s estimates assumed a 100% contingency.  (PG&E’s 2021 Request Window Proposals. CAISO 2021-2022 Transmission Planning Process.  September 28, 2021.  Available at http://www.caiso.com/InitiativeDocuments/PG-EPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf.)

[4] Presentations available at https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/2021-2022-Transmission-planning-process.

[5] SDG&E did not provide an in-service date for the new 500 kV Miguel Suncrest but given that it is meant to address overloads projected for 2023, Cal Advocates assumed an in-service date of that year.  (TPP 2021-22 Stakeholder Presentation.  San Diego Gas & Electric Company. September 2021.  Available at http://www.caiso.com/InitiativeDocuments/SDGEPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf.)

[6] The Transmission Access Charge Forecast Model is available at http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=7A2CFF1E-E340-4D46-8F39-33398E100AE7. These estimates kept the assumptions the CAISO included in the model, including a 2.5% depreciation rate, an 11% cost of equity, a 6% cost of debt, and a 50-50 debt/equity split.

[7] The most TRRs are available at http://www.caiso.com/Documents/HighVoltageAccessChargeRatesEffectiveJul12-2021.pdf.

[8] TPP 2021-22 Stakeholder Presentation.  San Diego Gas and Electric. September 2021.  Available at http://www.caiso.com/InitiativeDocuments/SDGEPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf

[9] Proposed SCE Submittals into the 2021-22 Transmission Planning Process.  2021-22 CAISO TPP.  September 15, 2021.  Available at http://www.caiso.com/InitiativeDocuments/SCEPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf.

[10] GridLiance West Project Proposal for the 2021-22 TPP Reliability Request Window.  September 27-28, 2021.  Available at http://www.caiso.com/InitiativeDocuments/GLWPresentation-2021-2022TransmissionPlanningProcess-Sep27-28-2021.pdf.

[11] Utility Costs and Affordability of the Grid of the Future.  The California Public Utilities Commission.  May 2021.  P. 11. Fn 14.  Available at https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/office-of-governmental-affairs-division/reports/2021/senate-bill-695-report-2021-and-en-banc-whitepaper_final_04302021.pdf.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

CAISO 2021-22 TPP and 20 Year Outlook September 27 - 28, 2021 Stakeholder Meeting

California Western Grid, LLC - Stakeholder Comments

October 12, 2021

California Western Grid Development, LLC (California Western Grid) appreciates this opportunity to submit comments and recommendations that arise from the September 27-28, 2021, Stakeholder Meeting.  We offer these comments and questions in the spirit of supporting the work of the CAISO. However, we also explain why the CAISO must do more in this 2021-22 TPP, more to allow for a reasonable transition to California’s SB 100 future and stop ”kicking the can down the road”, with regard to developing transmission needed by 2045.  In short, the CAISO must take the initiative and move forward to identify and approve least regrets long lead time transmission projects immediately.

It has become clear to California Western Grid that the CPUC IRP Preferred Resource Portfolio is inadequate to allow the CAISO and the state of California to properly prepare for California’s SB 100 future.  One of the CPUC’s stated goals for its Preferred Resource Portfolio is to maximize use of the existing grid and minimize transmission build-out.[1]  This CPUC objective is a short sighted view which will lead to certain disaster in the long-run.  As the CAISO well knows there is a 10 year or more lead time to plan, permit and build major new transmission projects.  The CAISO must take independent action now, identify needed least regrets long term transmission solutions, and approve those projects in this 2021-22 TPP.  The CAISO has the authority and obligation under section 24.4.6.6 of its tariff to approve Category 1 transmission that is needed for the State of California to meet its stated Public Policy goals.[2]

Given the CPUC portfolio, constructed to minimize transmission additions, it is not surprising the CAISO reliability analysis presented on September 27 – 28, reveals very few transmission system upgrades and no major transmission developments needed for reliability by 2031.  CWG is also disappointed the CAISO used a mid-point load forecast, despite the clear state policy for high electrification of other sectors. 

Fortunately, the CAISO did present a “Starting Point” scenario for the 20-year transmission outlook studies on September 27 that contains significant fossil generation retirements, significant new preferred resource additions and it will be based on a high electrification load forecast.  California Western Grid strongly supports this initiative by the CAISO.  We urge the CAISO to use the 20-year transmission outlook in the 2021-22 TPP to identify one or more key least regrets transmission projects and approve those projects in this 2021-22 TPP cycle.

In summary, CWG believes the agenda and scope of the September 27-8 TPP Stakeholder Meeting fell short in addressing the critical need for the CAISO to identify and approve long lead time transmission Public Policy driven projects immediately, projects that meet reliability needs and are required to meet the State Public Policy as articulated in SB 100.  The analysis done by the CAISO so far also fails to address the special need for new transmission to meet the reliability needs of Location Constrained Reliability Areas (LCRAs).  Transmission to LCRAs that will reduce the dependence on of fossil generation in those urban load centers to address not only SB 100, but also environmental justice, and other State Policies related to clean air, electrification of transportation and buildings, and wildfire mitigation.[3]

Cal-Western is encouraged by the statement on page 3 of the day 2 presentation on Increasing procurement and capacity in portfolios that the CAISO may approve projects in this 2021-22 TPP that don’t directly fall out of the CPUC preferred resource portfolio. The CAISO is uniquely situated as the only authority that fundamentally understands the California grid, how it operates and what will be needed as we head to a zero-carbon future.  The CAISO needs to provide leadership in its area of expertise, authority, and responsibility.  The CAISO needs to start approving least regrets long lead-time transmission projects now, before decarbonization progress is stymied for lack of needed transmission and/or bulk system reliability failures.  

California Western Grid is looking forward to the November Stakeholder meeting and the results of the economic and public policy analysis. We appreciate the CAISO 2021-22 TPP Phase 1 Study Plan includes evaluation of an under-sea transmission project that can meet reliability needs, bring clean preferred resources from the 500KV backbone transmission system in central California directly to the West LA LCRA where it can reduce dependence on gas plants within the LA Basin, allow recharging of batteries with zero emission resources while also provide other benefits including reducing wildfire risk. 

On October 15, 2021, California Western Grid will make a CAISO Request Window Submission with updates on its proposed Pacific Transmission Energy Project (PTE).  We will explain why the PTE should be studied and approved in the 2021-2022 TPP as a Public Policy Category One Project pursuant to Section 24.4.6.6 of the CAISO’s tariff.  We will also provide: (1) an updated description of the proposed PTE transmission project, including interconnection points, proposed route, and various technical specifications, (2) The rational for why this project should be approved in the 2021-22 TPP as a Public Policy Category One Project pursuant to Section 24.4.6.6 of the CAISO’s tariff. (3) Economic analysis that shows the proposed PTE also has a positive benefit cost ratio, and (4) an analysis that shows PTE solves four separate reliability needs identified by the CAISO at the 9/27-28 CAISO Stakeholder Meeting.

California Western Grid comments on specific presentations and slides from Day 1:

Presentation on 2021-2022 TPP PSPS/Wildfire Impact Assessment Study Scope – Southern California

California Western Grid noted the statement on page 2 of the presentation on Increasing procurement and capacity in portfolios: “The objective of the assessment is to study different scenarios to provide insight into the potential range of load impacts if different combinations of transmission lines within fire threat zones are included in the scope of PSPS event.”

California Western Grid urges the CAISO expand the objective of this study and develop a way to quantify the impact of wildfires that can be used in the CAISO TEAM analysis.  As the CAISO knows the TEAM analysis does not currently quantify wildfire risk for economic analysis comparing transmission and non-transmission alternatives.  This is a significant omission in TEAM analysis which should be addressed. At a minimum the CAISO should evaluate fire risk in a qualitative fashion when comparing project alternatives.  Especially when comparing transmission project alternatives for bringing new renewable resources into the LA Basin.

In this regard we fully support the statement at slide 6 of the presentation where the CAISO will “Identify potential new upgrades that could help reduce risk of fire impact”

Presentation on 20 Year Transmission Outlook SB100 Starting Point Scenario

While California Western Grid strongly supports the CAISO Starting Point Scenario for the 20-year outlook, we believe the study assumption of 15,000 MW of fossil generation retirements by 2040 is still likely shy of retirements that could be needed by 2040 to meet SB 100 targets.  In essence the CAISO should consider a retirement schedule that does not back-end load retirements into the final 5 years

California Western Grid supports both CAISO criteria for gas plant retirements shown on page 6:

• “…that the oldest natural gas power plants retire first, with a priority on those that are in and adjacent to disadvantaged communities (DAC)”
• “…that at least 3,000 MW of the 15,000 MW of retirements are assigned to gas power plants that rely on the Aliso Canyon storage facility as provided by the agencies, with a priority on the oldest power plants and those that are in and adjacent to DACs.”

Finally, the September 27 presentation did a good job explaining the starting point for the 20-year outlook, but it is still not clear to California Western Grid what the final or desired output of the 20-year outlook will be.  We strongly recommend that the CAISO analysis (1) identify least regrets transmission that should be approved in this 2021-22 TPP and (2) develop a road map of least regrets transmission that is needed to not only interconnect the resource portfolio described in Starting Point Scenario, but also deliver the output of those resources to load centers.  Specifically, to LCRA / urban load centers such as LA that are transmission constrained and currently dependent on fossil fired generation to meet load.

Cal-Western comments on specific presentations and slides from day 2:

Presentation on Increasing procurement and capacity in portfolios

California Western Grid finds the table on page 2 to be very instructive.  The rapid escalation in just a few years of CPUC procurement orders and preferred portfolios from the CPUC demonstrate the CPUC strict adherence to “just in time” procurement.  Since development of new preferred resources can be done quickly, often with lead times of 3 years or less, the CPUC “just in time” approach can work for generation projects.  However, long lead-time transmission needs a longer time horizon. The table on page 2 makes it clear that the CAISO needs to independently develop a 20-year outlook and approve long lead time least regrets transmission projects based on that 20-year outlook.

The statement on page 3 of this presentation is encouraging, specifically, we are heartened by the CAISO statement:

“The CAISO is intending to consider additional upgrades beyond those identified through in the analysis in this planning cycle using the base portfolio…”  

We fully support the CAISO taking this step. As we said in our introduction, the CAISO needs to provide leadership in its area of its expertise, authority, and responsibility.  The CPUC preferred resource portfolios will not help in identifying the long lead transmission projects that will be needed to meet the California’s SB100 goals. We desperately need the CAISO to take a leadership role.

Once again, we appreciate the opportunity to comment and look forward to moving forward on transmission that is badly needed on multiple levels.

Respectfully Submitted:

                          California Western Grid Development LLC

By: Martin Walicki

Dated: October 12, 2021

[1] See or example page 13 CPUC Proposed 8/17/21 Ruling in RM20-05-003 in describing CPUC approach in developing its preferred resource portfolio: “Transmission upgrade limits were enforced to limit transmission build to CAISO-determined levels”.

[2] Section 24.4.6.6 provides (emphasis added): 

Once the CAISO has identified reliability-driven solutions, LCRIF projects eligible for conditional or final approval, solutions needed to maintain long-term CRR feasibility, qualified Merchant Transmission Facilities, and needed LGIP Network Upgrades as described in Section 24.4.6.5, the CAISO shall evaluate transmission solutions needed to meet state, municipal, county, or federal policy requirements or directives as specified in the Study Plan pursuant to Section 24.3.2(i). Policy-driven transmission solutions will be either Category 1 or Category 2 transmission solutions. Category 1 transmission solutions are those which under the criteria of this section are found to be needed and are recommended for approval as part of the comprehensive Transmission Plan in the current cycle. Category 2 transmission solutions are those that could be needed to achieve state, municipal, county, or federal policy requirements or directives but have not been found to be needed in the current planning cycle based on the criteria set forth in this section. The CAISO will determine the need for and identify such policy-driven transmission solutions that efficiently and effectively meet applicable policies under alternative resource location and integration assumptions and scenarios, while mitigating the risk of stranded investment.

[3] SB100 is not the only State Public Policy that the CAISO should address under the requirements of CAISO Tariff Section 24.4.6.6.  For Example: (1) Executive Order N-79-20, establishing a statewide goal of phasing out the sale of new gasoline-powered cars and trucks in California, (2) Governor Newsom’s July 9, 2021 letter request to the Commission to establish a more ambitious greenhouse gas electricity target in the IRP process, to ensure that state efforts are driving toward achieving emissions reductions as soon as possible (3) ‘California’s Electricity Grid of the Future’ report issued by Governor Newsom on July 30, 2021 which states at page 3 “The electricity system has also been a contributor to recent disasters, with ignitions from electricity infrastructure sparking some of the state’s largest and most devastating wildfires…... The electricity system of the future must [be]… clean, safe, reliable and resilient”

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

Presentation on 2021-2022 TPP PSPS/Wildfire Impact Assessment Study Scope – Southern California

California Western Grid noted the statement on page 2 of the presentation on Increasing procurement and capacity in portfolios: “The objective of the assessment is to study different scenarios to provide insight into the potential range of load impacts if different combinations of transmission lines within fire threat zones are included in the scope of PSPS event.”

California Western Grid urges the CAISO expand the objective of this study and develop a way to quantify the impact of wildfires that can be used in the CAISO TEAM analysis.  As the CAISO knows the TEAM analysis does not currently quantify wildfire risk for economic analysis comparing transmission and non-transmission alternatives.  This is a significant omission in TEAM analysis which should be addressed. At a minimum the CAISO should evaluate fire risk in a qualitative fashion when comparing project alternatives.  Especially when comparing transmission project alternatives for bringing new renewable resources into the LA Basin.

In this regard we fully support the statement at slide 6 of the presentation where the CAISO will “Identify potential new upgrades that could help reduce risk of fire impact”

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

Presentation on 20 Year Transmission Outlook SB100 Starting Point Scenario

While California Western Grid strongly supports the CAISO Starting Point Scenario for the 20-year outlook, we believe the study assumption of 15,000 MW of fossil generation retirements by 2040 is still likely shy of retirements that could be needed by 2040 to meet SB 100 targets.  In essence the CAISO should consider a retirement schedule that does not back-end load retirements into the final 5 years

California Western Grid supports both CAISO criteria for gas plant retirements shown on page 6:

• “…that the oldest natural gas power plants retire first, with a priority on those that are in and adjacent to disadvantaged communities (DAC)”
• “…that at least 3,000 MW of the 15,000 MW of retirements are assigned to gas power plants that rely on the Aliso Canyon storage facility as provided by the agencies, with a priority on the oldest power plants and those that are in and adjacent to DACs.”

Finally, the September 27 presentation did a good job explaining the starting point for the 20-year outlook, but it is still not clear to California Western Grid what the final or desired output of the 20-year outlook will be.  We strongly recommend that the CAISO analysis (1) identify least regrets transmission that should be approved in this 2021-22 TPP and (2) develop a road map of least regrets transmission that is needed to not only interconnect the resource portfolio described in Starting Point Scenario, but also deliver the output of those resources to load centers.  Specifically, to LCRA / urban load centers such as LA that are transmission constrained and currently dependent on fossil fired generation to meet load.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

Presentation on Increasing procurement and capacity in portfolios

California Western Grid finds the table on page 2 to be very instructive.  The rapid escalation in just a few years of CPUC procurement orders and preferred portfolios from the CPUC demonstrate the CPUC strict adherence to “just in time” procurement.  Since development of new preferred resources can be done quickly, often with lead times of 3 years or less, the CPUC “just in time” approach can work for generation projects.  However, long lead-time transmission needs a longer time horizon. The table on page 2 makes it clear that the CAISO needs to independently develop a 20-year outlook and approve long lead time least regrets transmission projects based on that 20-year outlook.

The statement on page 3 of this presentation is encouraging, specifically, we are heartened by the CAISO statement:

“The CAISO is intending to consider additional upgrades beyond those identified through in the analysis in this planning cycle using the base portfolio…”  

We fully support the CAISO taking this step. As we said in our introduction, the CAISO needs to provide leadership in its area of its expertise, authority, and responsibility.  The CPUC preferred resource portfolios will not help in identifying the long lead transmission projects that will be needed to meet the California’s SB100 goals. We desperately need the CAISO to take a leadership role.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

California’s road to 100% decarbonization of its electricity sector relies on the exponential increase in VRE resources. This herculean task will be immediately followed by the electrification of transportation and buildings. These important mandates lead to a transmission grid issue that despite all the improvements and refurbishing of the existing California grid system, will still require at least one, entirely new, additional transmission grid buildout to handle the load/generation mix by 2045.  Out of state (“OOS”) resources can mitigate this enormous challenge. 

The CAISO should study adding the fully permitted LS Power SWIP-N transmission line with its north terminus being Midpoint as not only a potential OOS resource path, but as a California transmission asset. Importantly, the modeling must include generation and storage projects at the end of the north terminus, specifically the 980 MW Cat Creek Energy & Water Storage Renewable Power Station (“CCEW”). The facility provides 87,120 MWh of long duration energy storage. 

Examination of CCEW’s role will reveal the economic and decarbonization benefits of this at-scale transmission connected generation and storage asset. The transmission needs analysis should model Resource Adequacy, Flexible Capacity, and Ancillary Services, along with capacity of up to 980 MW per hour of South to North transmission from California to charge/absorb in energy storage up to 87,120 MWh of total storage capacity. The results will show that CCEW is an innovative, safe, multi-faceted, reliable asset that provides assurance of a smooth transition to decarbonization because CCEW offers all the services to the California grid of that which a utility must offer for resilient and reliable resource adequacy and for 100 years. 

CCEW’s 87,120 MWh of energy storage can provide 720 MW continuously for five days (121 hours).  Of more import is the ability to provide uninterrupted service during normal operations since CCEW can draw on VRE resources not necessarily CAISO dependent, in proximity of CCEW.  It is uniquely able to provide carbon-free energy during multi-day weather events such as the extreme heat that spiked demand and forced curtailments/outages in California in August 2020. CCEW can instantaneously reply to demand during those unexpected, yet predicted to increase in frequency and intensity, events while providing a wealth of other energy, capacity, and flex services in addition to unprecedented storage capacity.  CCEW may be dispatched for load following, peaking or baseload modes over extended periods for grid integrity and demand. The advent of a completed CAISO system SWIP-North line makes for an effective transport and transfer of these attributes. CCEW can provide a home for currently curtailed VRE resources in California and return them in a baseload mimicking form.

Further investigation into the SWIP-North transmission line to Midpoint, ID would stabilize this critical path by increasing shifting of overproduction of VRE resources and relieving transmission congestion both north to south and south to north. The addition of shovel ready transmission assets that can quickly provide California with OOS resources will increase reliability and ensure the grid has resources that can be depended on up to and after California reaches its 2045 mandate of 100% Decarbonization in its electricity sector.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

As California moves to meet SB 100 goals, there is increasing recognition of the sheer scale of renewable energy infrastructure and corresponding transmission required and the land base necessary to support these projects.  The achievement of the goals set forth under SB 100 will result in significant land conversion and development in California and the West. As shown in the August 12, 2021, SB 100 Joint Agency workshop on resource mapping, over 813,000 acres of land will need to be converted and developed in California with solar, wind, and geothermal resources under the high electrification scenario by 2045.

We appreciate the CAISO staff's continued focus on developing and refining the 20 Year Transmission Outlook (Outlook).  Effective planning for California's energy future depends on deep coordination between the CAISO, the California Energy Commission (CEC), and the California Public Utilities Commission (CPUC) to identify generation and transmission needs and, equally important, how to avoid and minimize environmental impacts.  Section 454.53(b)(2) of the California Public Utility Codespecifically requires consideration of environmental costs and environmental protection. It directs that the Commission and all other state agencies shall take "…into full consideration the economic and environmental costs and benefits of renewable energy and zero-carbon resources."  Therefore, the Outlook process should prioritize generation potential, avoiding impacts to natural and cultural resources, benefiting disadvantaged communities, and achieving greenhouse gas emission reduction goals.  

The CPUC’s Busbar mapping and the CEC’s SB 100 Starting Point mapping and the Starting Point scenario provide the granularity and opportunity to connect energy planning with land use and natural resources in a way that could support both the state’s energy goals and biodiversity and climate resilience goals.  The environmental and land use layers in the Busbar and the SB 100 Resource Build mapping are essential tools for understanding how land use impacts vary across scenarios and assessing the relative environmental effects in different areas to avoid or mitigate environmental impacts and maximize environmental impact co-benefits.

The SB 100 Starting Point Mapping can contribute to the Outlook process by identifying areas of high generation potential and low environmental conflict.  Consideration of land use and environmental opportunity and constraints is foundational to enable effective transmission planning that reduces risks of unintended impacts, conflicts, and disputes and ensures timely build-out. As shown in Slide 273 of the workshop presentation, this approach has been used to develop the Starting Point scenario for utility-scale solar to consider lower implication lands in the allocation to transmission zones. This level of analysis and planning is necessary to identify strategies to avoid, minimize or mitigate environmental impacts and maximize environmental co-benefits.  This approach should be used for allocating in-state wind resources and long-duration storage, particularly the 2,400 MW of pumped storage and 1,600 MW of unconstrained long-duration energy storage shown in Slide 272 of the workshop presentation. Unlike battery projects, pumped hydro storage projects have fixed locations, require very specific geographical settings, and require thousands of acres of development that can have substantive land availability and environmental implications.  When developers choose project locations in high environmental implication/conflict areas or in locations that are legally incompatible with the proposed development (e.g., designated wilderness areas), the likelihood of such projects being built is low to non-existent. 

Project failure is a significant concern in meeting SB 100 goals, and one only needs to look at projects that have failed due to siting conflicts with natural resources or litigation, or both.  Siting a generation or transmission project that conflicts with high-value natural resources such as endangered species and their habitats will likely result in increased permitting uncertainty, increased mitigation costs, project development delays, litigation, and/or project failure.  Avoiding and minimizing conflicts with high-value natural, agricultural, and cultural resources is the simplest and most cost-effective way to reduce project failure. 

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

Thank you for the opportunity to provide comments on the Workshop and the next steps to plan transmission to serve the SB 100 resource build.  We appreciate the CAISO’s time at the workshops and their hard work on moving forward with the 20 Year Outlook.  Please contact Kate Kelly at kate@kgconsulting.net with any questions. 

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

EDF-R appreciates this opportunity to provide brief comments on the 2021-2022 Transmission Planning Process in advance of the economic and policy components of the study. EDF-R appreciates the challenge of setting study assumptions for a study of this magnitude, even in “normal times” the inputs and variables are ever changing. When this topic came up on the stakeholder call the CAISO indicated that it is bound to use assumptions adopted the CEC’s IPER on January 25, 2021. EDF-R suggests now is the time for CAISO to revisit the CAISO-CPUC-CEC alignment.

EDF-R encourages the CAISO to seek agreement from the joint agencies to adopt a more agile approach. The CPUC’s urgent procurement done in the first half of 2021 does not fit neatly into the joint agencies alignment plan. But this procurement was necessary in order to respond to the supply issue that is the most urgent in recent history. CAISO’s summary of the increasing procurement levels planned by agencies and in legislation between now and 2040 indicate that major transmission projects will be required to support a level of procurement well beyond what was expected when the CEC IPER set assumptions 9 months ago. EDF-R encourages the CAISO to weight heavily its commitment to reflect the increase in resource procurement and consider the realities of commercial Interest when performing the study.

EDF-R also suggests the CAISO add the goal of reducing curtailment for generation online, especially renewable generation. Ongoing reliance on redispatch, operating procedures, and Remedial Action Schemes (RAS) to resolve reliability issues is a driver of renewable curtailment. While RAS solutions allow are generally quicker and less expensive to implement than than many transmission upgrades, and the allow for increased utilization scarce transmission resources associated with the RAS, they have the negative impacts of increasing operating and outage complexity, and potentially mask transmission needs. The TPP is the appropriate place to correct “transmission scarcity” that is driving renewable curtailment. EDF-R suggests that in the policy portion of the 2021-2022 TPP the CAISO consider the integration of renewables as a policy goal, and identify transmission needs that would be recommended if RAS were a solution of last resort, or only proposed as temporary by design to allow for generator interconnection until a permanent transmission solution could be constructed.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

 EDF-R appreciates GLW’s forward thinking solution proposal to address overloading throughout the GLW and surrounding transmission system. Holistic, least-regret upgrades that a combination of reliability, economic, and policy needs and leave room for future development are critical at this juncture, given the permitting and construction timelines for large transmission projects.  

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

GLW and VEA appreciate the CAISO’s hard work in developing the 2021-2022 TPP Assessment. Our comments refer to pdf page 229 or Valley Electric Association Preliminary Reliability Assessment Results slide 9:

Under the mitigation column, the CAISO recommends, “radializing” the system in a number of contingencies including to protect Armargosa 230/138kV transformer or the Sandy-Armargosa 138kV line overloads under a N-1-1 outages. Radializing is also mentioned as a mitigation strategy for low voltage conditions (See, pdf slide 230). Radializing  means opening one or more circuit breakers remove a section of the grid from the network which removes power flow due to generation or load from other parts of the grid.

Comment 1. GLW/VEA recommend CAISO operations dispatch down existing generation before radializing any lines. Radializing lines leaves the grid vulnerable compared to a network and increases the probability of dropping load. Reducing generation, if effective mitigation, maintains reliability of a grid network.

Comment 2: If radializing is maintained as an option, then please explain why this is the best operational solution and specify which lines would be radialized, so GLW/VEA operations can prepare for such events.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

GLW appreciates the update on the 20-Year study and publishing of the Starting Point portfolio. GLW requests that the CAISO consider updating the Starting Point buildout in the GLW footprint to include at least 500 MWs of geothermal resources and additional solar and wind resources able to be supported by GLW-system upgrades being studied this cycle. The current Starting Point buildout in the GLW area is overly limited by legacy transmission limitations that will likely be lifted with upgrades currently being studied. To keep GLW resources limited at these historical levels is counter-productive to the goals of finding the most cost-effective solutions to SB100 renewable goals.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

GLW appreciates the CAISO’s response to stakeholder questions during the Day 1 meetings related to the GLW-proposed upgrades. The CAISO pointed out that the upgrades being contemplated were studied under last cycle’s policy and economic studies and that the upgrades were found to be needed and were not approved at that time due to an affected neighboring system issue that has since been resolved.

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

GLW supports the CAISO’s proposal regarding considering accelerating additional upgrades beyond those considered in the base case analysis. Of particular interest to GLW is the Eldorado 500/230kV transformer which currently limits the buildout of renewables in Southern Nevada, including the additional development of wind and geothermal resources.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

GLW and VEA appreciate the CAISO’s diligent work on the planning process and appreciates opportunity to submit these comments on the CAISO’s September 27-28 TPP meetings.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

Golden State Clean Energy (“GSCE”) continues to support the ISO undertaking the 20-year transmission outlook as a crucial element to California meeting its SB 100 goals. The state is in strong need of the leadership the ISO is providing through this process, but we urge the ISO to design the 20-year outlook so that it is not just a planning exercise but one that leads to action in the near-term. The 20-year outlook should seek to translate its findings into project approval, which could be done by taking select transmission projects from the 20-year outlook and feeding them into the tariff-based transmission planning process’s study process for assessment and potential approval in the following planning cycle. GSCE has recently submitted a proposed initiative to the ISO that reflects this comment, to allow stakeholders to engage on the future of the 20-year outlook and how to allow it to maximize its potential to benefit state policy.

Although a number of single-line bulk transmission projects have been discussed in the 20-year outlook, the ISO should ensure it is able to assess the combination of transmission upgrades that may be needed to effectuate the policy benefits these bulk transmission projects seek to provide. The 20-year outlook may not be the right setting for conducting this analysis, as it is intended to provide higher level technical studies to test feasibility of alternatives, and not the detailed level of comprehensive analysis that underpins the 10-Year Transmission Plan. But to better understand the transmission projects being studied in the 20-year outlook and to better inform decision-makers, further analysis will be needed. That is another reason we suggest the ISO consider feeding some of its more promising results from the 20-year outlook into the TPP or otherwise create a process that more rigorously analyzes transmission needs beyond the TPP’s current 10-year planning horizon. GSCE appreciates that the ISO may have limited bandwidth to study projects in addition to its existing TPP analysis, but we share the concern of many stakeholders that limiting transmission approval to only those projects found needed within the next 10 years poses a serious hurdle to meeting SB 100 goals.

Finally, the 20-year outlook has the potential to provide additional transmission planning benefits in the form of a different method of resource mapping than the mapping being done in the IRP-TPP process. The 20-year outlook’s assumptions for resource locations are more focused on least-regrets renewable zones as provided by the Energy Commission. This focus on unlocking the potential of renewable energy zones may represent a process improvement over the busbar mapping done for the TPP, or at the least it provides alternative study results to compare against the resource mapping process in the TPP. The ISO has also experienced issues with the resource portfolios not reflecting commercial realities.^[1]  The ISO should look to develop transmission to renewable resource areas rather than rely entirely on the California Public Utilities Commission’s resource portfolios and the current interconnection queue to inform the commercial interest that the IRP’s busbar mapping considers. The SB 100 report’s resource mapping and land use planning has essentially taken this view of developing transmission to renewable resource areas, and that mapping exercise is what has fed into the 20-year outlook to inform the location of future resources.

[1] Preliminary Issue Paper, 2021 Interconnection Process Enhancements, at 9, Sept. 30, 2021, available at: http://www.caiso.com/InitiativeDocuments/PreliminaryIssuePaper-InterconnectionProcessEnhancements2021.pdf (“The CAISO has developed transmission expansion plans to meet the generation capacity, technologies and locations of the CPUC generation expansion portfolios, including the level of deliverability approved by the CPUC . . . However, based on the limited visibility the CAISO has into the procurement activities of the load serving entities (LSEs), many projects obtaining power purchase agreements (PPAs) are projects that are located outside of the portfolio area where they first require various network upgrades to go into operation. This exacerbates the time required for new generation that have a PPA to go into operation and results in transmission capability that was built to accommodate the new generation required to maintain system reliability not being fully utilized, which increases costs to ratepayers.”).

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

Golden State Clean Energy (“GSCE”) strongly supports the ISO looking beyond the results driven by this transmission planning process cycle’s base case in anticipation of even more resources being included in future portfolios. We have previously expressed concern over the IRP understating the total resource need, and it is unfortunate that this is now coming to a head and putting the ISO in a difficult position. GSCE generally supports the ISO being proactive in transmission planning and appreciates its willingness to think more broadly and proactively as it assesses the infrastructure needed for a reliable grid.

The ISO noted some initial projects it is considering that could address the rapid growth in resource portfolio capacity. These projects come from a larger list of area delivery network upgrades (“ADNUs”) that the ISO discussed in a recent white paper on transmission capabilities. GSCE is supportive of these ADNUs being considered in this context for approval in the current TPP cycle.

GSCE believes the ISO should also look beyond these ADNUs when assessing transmission needs in response to increasing procurement and capacity in resource portfolios, and we agree with stakeholder comments made during the September workshops that proposed the ISO do so. The crucial factor driving the ISO to look beyond its base case-driven results is timing, and if a transmission project can come online before the end of the decade, then the ISO should give it serious consideration for approval. The 2022-23 TPP cycle can further assess transmission needs in the 10-year timeframe, but the key issue now is getting ahead of mid-decade needs that currently exist but that the IRP-TPP process will not allow to be studied and approved until March of 2023.

GSCE proposes that the ISO consider projects like the San Luis Transmission Project (“SLTP”), in conjunction with other upgrades, as a transmission project that meets the need for mid-decade transmission upgrades. This cost-effective, in-state project could unlock significant additional capacity in California. It aligns with the significant transmission build-out needed for California to meet its SB 100 goals. As part of its 20-year transmission outlook, the ISO is about to assess 12,655 MW of solar in the Westlands transmission zone alone, and we think that SLTP could provide a start to unlocking the renewable energy potential in the Central Valley where the ISO is already experiencing transmission congestion.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

We support CAISO’s 20-year transmission outlook initiative. Regarding the Out-of-State (OOS) wind assumptions for the study, Page 17 of the presentation (slide 278 of 283) lists only Wyoming and New Mexico as OOS Wind locations on new transmission, but fails to acknowledge that OOS wind from Idaho is a viable option that should be studied as well. Note that in the California Energy Commission (CEC) report “SB 100 Starting Point for the CAISO 20-year Transmission Outlook,” the CEC clearly lists “Wyoming/Idaho” for OOS wind.[1] Further, the California Public Utilities Commission has appropriately recognized that Idaho wind is an effective alternative to Wyoming wind. In the Commission’s 2021-22 TPP Modeling Assumptions it states, “Although CPUC staff refers to Wyoming wind here, CPUC staff acknowledges that various resource types from various states may inject at this substation. This mapping is not intended to indicate a preference for Wyoming Wind.”[2]  CAISO should include Idaho wind in the documentation and ensure it is studied for transmission needs as a viable location for OOS.

[1] CEC, “SB 100 Starting Point for the CAISO 20-year Transmission Outlook”, docket 21-SIT-01, September 13, 2021. https://efiling.energy.ca.gov/GetDocument.aspx?tn=239685&DocumentContentId=73101

[2] CPUC R.20-05-003, “Attachment A: Modeling Assumptions for the 2021-2022 Transmission Planning Process,” February 2021, Page 26, footnote 17

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

CAISO is seeking comments on the transmission projects that could be advanced to meet transmission needs for these resource procurements. LS Power’s Southwest Intertie Project –North (SWIP-North) could provide a ~1100 MW new transmission path to deliver OOS wind and other renewables from Idaho and Nevada into CAISO. SWIP-North is an advanced development project, and if approved in the current 2021-22 TPP it could be online by the end of 2024. CAISO should initially consider projects to deliver OOS wind that have completed required NEPA/CEQA, can be online as early as 2024 (when Diablo Canyon is scheduled to go offline), and provide a mix of reliability, economic and policy benefits to California ratepayers.  SWIP-North is a “no regrets” option that should be approved in the current TPP cycle.  SWIP-North will provide hundreds of jobs for skilled workers employed by contractors that are signatory to IBEW Local 1245 based in Vacaville.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

We appreciate the CAISO work to improve the TPP and the ongoing critical inter-agency coordination.  We also thank the staff of the CAISO, PG&E, SCE, SDG&E and VEA for all the work creating the material for the two-day presentations. 

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

We are appreciative that the CAISO is adapting the scenarios to include wildfire assessments and requests additional flexibility in the modeling to address the growing resiliency needs at the local and system wide level throughout the state.  

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

For one, if a stakeholder does not have the best application open, the page numbers don't match.  Adding the page numbers on the actual slide deck would provide better coordination (each section starts - it is not additive) for the comment sections and for easier reference. 

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

We support the iincreasing procurement of renewable energy and storage. We recommend improvements to the modeling to incorporate diversity of technologies and expansion of resiliency metrics such as n-5 and n-10.  We also support the CEC scenarios focusing on gas retirements and lowering the GHG input to 30 MMT in the portfolios. 

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

We recommend the continued adaption and balance of land conservation and clean energy infrastructure.  We also ask the CAISO to ensure efficient right-of-way use to maximize use of corridors while minimizing land impacts. 

We support changes like the "Antelope - Vincent 500kV line rating increase" and recommend upgrades consider more transmission path increases as well as upgrading 230 kV transmission lines to 500kV lines in existing ROWs.

We thank the CAISO for their work and look forward to working together on advancing TPP planning in each step of the process. 

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

LS Power does not have any comments at this time.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

LS Power recommends that CAISO take a forward-looking approach in developing mitigation options rather than simply relying on RAS and methods that require operator intervention. Heavy reliance on operating procedures and RAS will push these problems to the operating horizon and is a risky proposition given the pace of system changes (e.g., significant amounts of resource procurements, generation retirements and increasing load in certain areas) in coming years. Presentation material[1] for CAISO’s RAS Guidelines Update Initiative shows there are 69 RAS’s in the bulk electric system (BES) in the CAISO footprint and 36 additional RAS’s have been proposed for the future. CAISO acknowledges it relies far more on the use of RAS in lieu of transmission upgrades compared to other ISO/RTOs in the country. As CAISO is already aware, high utilization of RAS is concerning and should be reconsidered. LS Power also requests CAISO to resume its RAS Guidelines Update initiative so that the required updates could be made to the ISO Planning Standards before the next TPP cycle studies.

As CAISO presented on Day 2, the need for grid connected resources is escalating quickly and the portfolio has grown from 10,387 MW in 2020-21 to 27,695 MW in 2021-22 (~167% increase) and is expected to increase to 42,690 MW by 54%. It is likely that a significant amount of transmission upgrades would be required to support increasing portfolios. This is another reason LS Power encourages CAISO to begin identifying transmission improvements considering long-term system needs and anticipating reliability issues instead of adding more RAS and system adjustments which are more of a temporary band-aid fix to address near term reliability issues.

[1] http://www.caiso.com/InitiativeDocuments/Presentation-PlanningStandards-RASGuidelinesUpdate-Jun242021.pdf

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

LS Power does not have any comments at this time.

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

LS Power requests CAISO to avoid excessive reliance on RAS and system adjustments for the reasons described in Comment #2 above and identify robust system improvements instead to mitigate near term and anticipated reliability concerns.

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

LS Power does not have any comments at this time.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

LS Power requests CAISO to avoid excessive reliance on RAS and system adjustments for the reasons described in Comment #2 above and identify robust system improvements instead to mitigate near term and anticipated reliability concerns.

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

LS Power supports the direction CAISO is taking in performing the wildfire assessment. However, LS Power cautions the ISO in relying too much on historical data. As we all know, wildfires in the west have become more severe and more frequent in recent years. While reviewing historical data is prudent, it may not necessarily help in projecting the future. Further, the assessment will provide little value if proper mitigation plans are not identified. LS Power encourages CAISO to develop mitigation options within this scope of work including new transmission facilities, keeping the long-term planning vision in mind.

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

LS Power applauds CAISO’s initiative in evaluating the 20-year transmission outlook. This important study will inform future TPP cycles in meeting the needs of transmission for growing procurement needs in the state.

Regarding the Out-of-State (OOS) wind assumptions for the study, Page 17 of the presentation (slide 278 of 283) lists only Wyoming and New Mexico as OOS Wind locations on new transmission, but fails to acknowledge that OOS wind from Idaho is an option that should be studied as well. Note that in the California Energy Commission (CEC) report “SB 100 Starting Point for the CAISO 20-year Transmission Outlook,” the CEC clearly lists “Wyoming/Idaho” for OOS wind.[1] Further, the California Public Utilities Commission has appropriately recognized that Idaho wind is an effective alternative to Wyoming wind. In the Commission’s 2021-22 TPP Modeling Assumptions it states, “Although CPUC staff refers to Wyoming wind here, CPUC staff acknowledges that various resource types from various states may inject at this substation. This mapping is not intended to indicate a preference for Wyoming Wind.”[2] LS Power requests CAISO ensure that Idaho wind is included in documentation and is studied for transmission needs as another location for OOS.

[1] CEC, “SB 100 Starting Point for the CAISO 20-year Transmission Outlook”, docket 21-SIT-01, September 13, 2021. https://efiling.energy.ca.gov/GetDocument.aspx?tn=239685&DocumentContentId=73101

[2] CPUC R.20-05-003, “Attachment A: Modeling Assumptions for the 2021-2022 Transmission Planning Process,” February 2021, Page 26, footnote 17

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

LS Power does not have any comments at this time.

10. Provide your organization’s comments on the SCE Reliability Alternatives:

LS Power does not have any comments at this time.

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

LS Power does not have any comments at this time.

12. Provide your organization’s comments on the GLW Reliability Alternatives:

LS Power’s affiliate DesertLink is the PTO of the Harry Allen – Eldorado (HAE) 500 kV line. The HAE loop-in portion of Gridliance’s proposed project will pose several engineering challenges which will need to be adequately reviewed. DesertLink looks forward to coordinating with Gridliance West and CAISO as this proposed project moves forward.

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

LS Power supports CAISO’s proposal to increase the net export limit for the CAISO system in PCM.

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

LS Power agrees with CAISO that grid-connected resource needs are increasing exponentially. Further, transmission development will have to keep up to support these procurements. LS Power supports CAISO’s intention to consider additional upgrades beyond base portfolio given that it will be very challenging to bring on the necessary amount of resources with normal transmission planning cycles. Timely identification and approval of upgrades will be critical in maintaining system reliability given the rapid increase in procurement.

CAISO is seeking comments on the transmission projects that could be advanced to meet transmission needs for these resource procurements. As stated in our previous comments, LS Power’s Southwest Intertie Project –North (SWIP-North) could provide a ~1100 MW new transmission path to deliver OOS wind and other renewables from Idaho and Nevada into CAISO. SWIP-North is an advanced development project, and if approved in the current 2021-22 TPP it could be online by the end of 2024. The Federal National Environmental Policy Act (NEPA) process is complete for SWIP-North, including having BLM Rights-of-Way secured, Construction/O&M Plan approved, and Conditional Notice to Proceed with Construction issued. No California Environmental Quality Act (CEQA) permits are required, private real estate acquisition is substantially complete, System Impact Studies are complete for transmission interconnections and Facilities Studies will commence soon.

On slide 11 of the presentation material on this topic, the table shows zero OOS wind in Draft Preferred System Plan (2025). In LS Power’s Opening Comments to Commission on September 27, 2021 on the Proposed Preferred System Plan[1], LS Power submitted RESOLVE model runs after correcting the outdated assumptions for Idaho wind and OOS transmission costs. Also the assumption for first available year for OOS wind which was hard coded to 2026 was changed to 2024 to reflect commercial development timeline for Idaho wind and SWIP-North transmission project. LS Power’s analysis demonstrated that 1,893 MW of Idaho wind gets selected by RESOLVE model in 2025 and this leads to an overall cost savings of $360 million (net present value 2022-2045). A summary of these RESOLVE model runs is included as an attachment to these comments. LS Power recommends that CAISO review this analysis and not delay OOS wind projects that could be available to meet California reliability, policy, and economic needs in the near term

[1] R.20-05-003, LS Power Opening Comments on the Administrative Law Judge’s Ruling Seeking Comments on the Proposed Preferred System Plan, September 27, 2021. Pages 11-12. https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M409/K928/409928747.PDF

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

LS Power does not have any comments at this time.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

LSA & SEIA’s comments cover two main areas:

• Mixed-purpose upgrades:  Several of the new Network Upgrades recommended by the PTOs for reliability purposes could also improve new-resource deliverability for the same areas, either directly or through modifications.  LSA & SEIA urge the CAISO to consider these additional benefits and potential modifications in its evaluation of the PTO proposals.

• CAISO portfolio analysis expansion:  LSA & SEIA strongly support the CAISO’s stated intent in its Day 2 presentation entitled “Increasing Procurement and Capacity in Portfolios,” to consider recommendations and approval of upgrades beyond those triggered by the base portfolio, for the reasons stated by the CAISO and additional reasons added in our response to Question 14 below.  (That CAISO presentation is referred to as the “Day 2 Presentation” in the remainder of these comments.)

Note that our responses below contain references to two other recent CAISO documents:

• Transmission Capability Estimates for use in the CPUC’s Resource Planning Process, issued July 19, called the “Capability Report” in the remainder of these comments.

• 2021 Transmission Plan Deliverability Allocation Report – Final Report, issued March 15, called the “TPD Report” in the remainder of these comments.

The reminder of our comments are contained in the Attachment, since the graphics in those comments do not translate well into the CAISO's Comment Tool.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

500kV Contingency Definition Correction:

PG&E supports the overall findings from CAISO’s preliminary reliability assessment results.  In the PG&E Bulk Preliminary Reliability System Assessment Results, CAISO recommended projects (modification to Path 26 RAS and upgrading terminal equipment at Rio Oso substation) as mitigation to thermal violations caused by P6 and P7 contingencies on the Midway-Whirlwind #3, Midway-Vincent #1 and #2 500 kV lines and several 500 kV lines in the North of the PG&E area. Upon further review, PG&E confirmed that the referenced P7 contingencies (simultaneous outage of Midway-Vincent # 1 and 2  500 kV and Table Mountain -Vaca Dixon and Table Mountain-Tesla 500 kV) are in fact Extreme Events as per the definition in TPL-001-4. Therefore, the recommended mitigations are not required for these Extreme Events based on the requirements in TPL-001-4. Additionally, as the thermal violations observed from the P6 contingencies can be mitigated by controlling the system flow within normal and outage operating limits, system upgrades are not necessary as the recommended mitigation. PG&E would like to request that CAISO further evaluate the necessity of requiring the recommended projects (modification to Path 26 RAS and upgrading terminal equipment at Rio Oso substation.)

OCEI Clarification

As PG&E stated during Day Two of the September stakeholder meeting, there is some confusion with regard to the current status of the Oakland Clean Energy Initiative (OCEI), which PG&E hopes to dispel. OCEI was originally proposed by PG&E and approved by CAISO in the 2017-18 TPP as an innovative combination of both wire and non-wire solutions to meet local reliability needs and allow for the retirement of aging fossil generation.  CAISO approved the wire components and evolved to where CAISO encouraged PG&E to seek CPUC authorization for the non-wire (battery) procurement portion of the project.  

While PG&E’s proposed procurement application was withdrawn from the CPUC earlier this year, progress continues with regard to the other aspects of the overall project.  Meanwhile, Vistra has executed a Large Generator Interconnection Agreement (LGIA) for up to 55 MW and communicated to CAISO that it is moving forward with battery development at the power plant site, with a different commercial offtake agreement structure.  Therefore, all components of OCEI continue to be progressing.  

At the end of 2020, CAISO released Unit 2 of the Dynegy Oakland Power Plant (owned by Vistra) from RMR.  Once the approved combination of substation upgrades and battery storage are in service, CAISO will consider releasing additional units from RMR.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

PG&E applauds again the CAISO’s 20-Year Transmission Outlook effort, which is expected to be highly valuable in informing long-term infrastructure and resource planning for California and the West. PG&E appreciates the updates on the SB100 Starting Point scenario with detailed rationale. Resource scenarios are a critical element in assessing future transmission requirements driven by the shifting resource mix.

To better engage in and support the 20-Year Transmission Outlook, PG&E requests the CAISO provide further details to stakeholders on the two subjects below.

1. In addition to resource assumptions, the load forecast is another critical element in identifying future transmission requirements. PG&E requests that CAISO share the load forecast scenarios to be studied and how key factors will be considered, such as electrification, charging needs of storage, identified geographic areas or sectors with heavy load growth, etc. Additional sensitivities should be developed to explore other likely futures and evaluate the robustness of the overall plan.

2. PG&E also requests CAISO share more details of the study scope. For example, will the study focus on bulk system only or also consider local area systems? What system operating conditions will be studied? What types of studies (steady-state, stability, production cost simulation) will be included? PG&E encourages CAISO to share these details and engage stakeholders to provide feedback.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

PG&E appreciates the update and discussion by CAISO during the 2021-2022 TPP stakeholder meeting regarding increased resource procurement needs in recent and future portfolios.  In the presentation CAISO also highlighted a number of potential transmission upgrades that may be considered for advancement to support the increasing procurement.  The list of upgrades includes two potential upgrades in the PG&E system, the Woodland-Davis 115 kV Line and the Gates Transformer Bank #13.  PG&E would like to note that the specified costs for these projects appear to be on the low end and should be validated.  The overall costs for each project should consider updated information such as recent upgrades installed, expansion needed or any other equipment required to enable these potential upgrades.  PG&E recommends CAISO work with PG&E in updating the cost estimates for these two projects.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

The Renewable Energy Buyers Alliance (“REBA”) writes in support of CAISO’s study of out-of-state transmission alternatives, such as the Southwest Intertie Project North (“SWIP-North”) line, in the 2021-2022 Transmission Planning Process. REBA’s members include 270 companies that employ 14 million people and are currently deploying 42 GW of renewable energy.

 REBA supports expansion of transmission into CAISO, as such projects will enable access to significant, new, diverse renewable resources in the mountain West. New out-of-state transmission will enhance regional grid resiliency and reliability and will help California meet its renewable energy and greenhouse gas reduction goals. Corporate customers with a significant investment presence in California require new transmission alternatives such as SWIP-North to unlock access to renewable energy resources.

More broadly, REBA supports greater interregional coordination across the West, including transmission planning. Transmission planning that increases transfer capability across the West will help meet west-wide clean energy goals and enhance system reliability for the entire western grid.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

Salt River Project Agricultural Improvement and Power District (SRP) respectfully submits comments on the Transmission Planning Process (TPP) to increase our understanding of any potential influence the TPP may have over the External Load Forward Scheduling Rights Process (ELFSRP) initiative.

SRP requests the CAISO identify what studies or processes, if any, under the TPP that would need to take place to determine the amount of transmission available under a potential transmission request/reservation framework developed under the ELSFRP initiative. 

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

 No comment

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

 No comment

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

 No comment

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

 No comment

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

 No comment

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

 No comment

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

No comment

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

 No comment

10. Provide your organization’s comments on the SCE Reliability Alternatives:

 No comment

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

 No comment

12. Provide your organization’s comments on the GLW Reliability Alternatives:

 No comment

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

 No comment

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

 No comment

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

 No comment

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

SDG&E encourages expanding the 10-year study horizon in light of expected policies that will have a high impact on the TPP results. These policies will take place shortly after study horizon (Gov Newsom’s 100% new EV law in 2035 and SB100 in 2045). It is important to study these scenarios early due to the long lead times associated with transmission development, should it be identified as mitigation.  

Regarding Gov Newsom’s 100% new EV law, it is highly likely that the forecasts being used in the TPP do not consider any increased EV demand because this law was passed in the fall of 2020. Therefore, there would not have been sufficient time to integrate this into the IEPR. To address this gap, SDGE recommends increasing the EV load based on input from the respective California IOUs or an independently developed EV forecast for 2031. It is important to note that although the law is not effective until 2035, increased adoption and new EV offerings from major car manufacturers will likely have some effect on load. Further, it will be important to ensure that 24-hour charging studies are performed to ensure that there are enough resources to accommodate these EVs. 

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

SDG&E cautions against the prevalence of RAS, as these solutions may lead to an overly complex system which may lead to inadvertent reliability issues. Further, complex RAS that requires a nomogram can degrade system reliability hence not meeting system performance criteria if the RAS fails or inadvertently operates.  

The amount of generation tripped by a single RAS should be limited. As we diversify our resource portfolio, resource resiliency will become key to system reliability. However, replacing large gen drop RAS with several smaller gen drop RAS is also not conducive to a reliable system because additional RAS will make the system overly complicated for grid operators. This may result in reliability issues if operators are unable to keep track of the resulting system that is unnecessarily complex. 

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

SDG&E commends the CAISO for taking initiative in including wildfire assessment scenarios as part of TPP cycle. We understand the system performance under contingency events of PSPS is beyond the minimum requirement of NERC mandatory reliability standards and CAISO planning standards. We look for guidance on how to proceed once new upgrades are identified to reduce future PSPS event and/or wildfire potential impact on critical facilities. 

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

LDES:  SDG&E encourages exploration and discussion behind what LDES implementation would look like and how this would differ from the operational treatment of today’s 4-hour batteries. Specifically, consideration should be given to mechanisms that allow LDES resources to be available for their full forecasted/scheduled duration. Storage charging requirements and their effects on the surrounding transmission system would need to be considered appropriately. The timing/coordination of battery resources without causing transmission overloads or interfering with load demand will need to be managed. SDG&E appreciates and supports further integration of CAISO’s previous “Load Serving Capability w/ Energy Storage” analyses in this regard. 

OOSW: SDG&E appreciates, and agrees with, CAISO/Neil Millar’s comments at JA SB100 Transmission Workshop regarding the need for transmission from the California border to load centers should Out of State Wind be selected as a solution. SDG&E would also like to point to the unresolved issues around Out of State Wind regarding cost allocation and availability of transmission from the wind centers to California. These issues and costs should be counted when considering Out of State Wind. 

SDG&E encourages CAISO to consider approving transmission projects based on the results of the 20-Year Outlook analysis. The scale of some of these projects may pressure permitting/construction schedules that are already tight in the regular 10-year TPP. 

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

?SDG&E encourages CAISO to consider grid resiliency and diversity of resource location when situating the resources identified in slide 11. As wildfires or other disasters become a larger risk to the grid, it may become more reliable to situate resources closer to load centers. Further, as we go about this task, ensuring that there is sufficient deliverability for these resources will be important. One possible solution could be an additional sensitivity scenario that will inform the IRP 

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

Project submittals for consideration as part of the 20-year outlook study: 

1. HVDC Conversion Project coupled with SDG&E Southern California LCR reduction project. These projects were previously submitted to the CAISO during the 2017/2018 TPP and the 2018/2019 TPP. 

2. The Imperial Valley to Serrano 500 kV line that SDG&E and the CAISO has identified in the generation interconnection studies.  

Accompanying files are attached 

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

The City of Santa Clara dba Silicon Valley Power (SVP) appreciates the opportunity to comment during the 2021-2022 Transmission Plan development.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

SVP has reviewed the results of the CAISO reliability assessment for the SVP/San Jose areas. SVP appreciates CAISO and PG&E staff’s tremendous efforts in identifying mitigations solutions to the SVP/San Jose areas driven by rapid load growth expected in the near future. Figure 1 developed by the CAISO staff best depicts the multiple reliability violations identified under the 2021-2022 Transmission Planning process (TPP) in the San Jose sub-area.[1] Figure 1 shows that some of the reliability violations are expected to occur as early as 2023 (see transmission overloads identified in yellow), which is extremely concerning to SVP.

PG&E has identified potential short-term mitigation measures as part of its South Bay 115 kV Reinforcement Conceptual Project[2] request window application submitted in the 2021-2022 TPP. They include reconductoring Los Esteros-Nortech 115 kV and Nortech-NRS 115 kV lines. SVP has concerns about completing these projects in time to prevent load interruption during the multiple contingencies as documented by the CAISO as early as 2023. Since time is of the essence, SVP requests the CAISO management approve the transmission upgrades costing less than $50 million in December 2021 required to address the SVP/San Jose area’s short-term reliability issues. SVP appreciates the CAISO’s objective to develop short-term mitigation solutions that align with the long-term solutions it plans to develop in coordination with PG&E. But priority needs to be given to feasible and timely solutions that minimize the chances of load interruption during contingencies. To that extent, SVP is open to supporting PG&E-proposed or any other alternative solution proposed in the current planning cycle that would effectively address SVP’s short-term needs until a longer-term solution is deployed.

Figure 1: Multiple Transmission Upgrades Are Required to Address Multiple Transmission Upgrades Triggered During the Period of 2023-2031.

PG&E has also identified certain long-term solutions that provide Newark substation as a strong source for meeting SVP’s increasing demand. The three alternatives proposed by PG&E[3] are

1. Reconductor the two existing Newark-NRS 115 kV lines with conductor rated for 1500 Amps or higher;
2. Rebuild the two Newark-NRS 115 kV lines as two 230 kV with conductor rated for 1144 Amps or higher; or
3. Build a new 230 kV line from Newark to NRS with a conductor rated for 2200 Amps or higher.

During the September 27 stakeholder meeting, the CAISO indicated that they would like to work on developing long-term solutions that add either a new 230kV or a new 500kV source into the San Jose sub-area over multiple planning cycles. Past history shows it often takes significant time to complete approved projects. In SVP’s comments on the 2020-2021 TPP Study Plan, dated February 28, 2020, we provided a table identifying examples of PG&E projects with long implementation lead times in the range of 6 to 15 years. Since the long-term transmission solutions, including those proposed by PG&E, require a long lead-time to have these projects built by 2026 (see transmission overloads identified in green in Figure 1 above), the CAISO Board should approve a long-term solution in the current TPP.

In summary, since any reinforcement of the transmission in the SVP/San Jose area will probably take significant time to construct, it is critical for CAISO to approve both the short-term and long-term mitigation projects in the current planning cycle.

[1] CAISO, Greater Bay Area Preliminary Reliability Assessment Results,” 2021-22 Transmission Planning Process Stakeholder Meeting, September 27-28, 2021, page 15.

[2] PG&E’s 2021 Request Window Proposals, September 28, 2021, CAISO 2021-2022 Transmission Planning Process, pp.37-48.

[3] Ibid.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

No comments at this time.

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

No comments at this time.

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

No comments at this time.

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

No comments at this time.

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

No comments at this time.

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

No comments at this time.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

See SVP’s comments in response to Q.2.

10. Provide your organization’s comments on the SCE Reliability Alternatives:

 No comments at this time.

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

 No comments at this time.

12. Provide your organization’s comments on the GLW Reliability Alternatives:

 No comments at this time.

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

 No comments at this time.

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

 No comments at this time.

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

 SVP appreciates the opportunity to comment on the 2021-2022 Transmission Plan Reliability Assessment Results and acknowledges the significant effort of the CAISO and PG&E staffs to develop this material.

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

SCE appreciates the opportunity to provide comments on the CAISO’s September 28, 2021 TPP stakeholder meeting.

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

On slide #150, titled “Previously approved transmission projects modelled in base cases”, of the CAISO’s day 1 presentation, it shows the expected ISD for Moorpark-Pardee No. 4 230 kV Circuit as June-21.  The latest revised expected ISD for Moorpark-Pardee No. 4 230 kV Circuit is December-21.

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

During the meeting on September 28, CAISO presented a concept of investigating projects that could be beneficial proactive investments towards helping meet California’s resource portfolio goals. Many of the proposed projects in SCE territory provide additional benefits beyond the cited incremental megawatts of Full Capacity Deliverability Status (FCDS). We are providing some additional project details along with these other benefits for your consideration. In addition to the projects raised at the September 28 stakeholder meeting, SCE recommends that a project to upgrade the 66 kV circuit breakers at Antelope Substation be evaluated as part of this effort. This project does not directly impact FCDS, but it is needed to maintain system safety and reliability with increasing amounts of renewable resources in the area. The cost and time duration to upgrade these circuit breakers to 50 kA has historically shown to be an effective deterrent to new generation in this area. Performing this upgrade would allow for increased accommodation of the renewables potential in the Antelope 66 kV area.

Project Name:           Laguna Bell-Mesa No. 2 230 kV Line Rating Increase

Submission Date:        10/12/21

Project location and interconnection point(s): Los Angeles County, CA; Laguna Bell 230/66 kV Substation and Mesa 500/230/66 kV Substation

Description of the project:

SCE recently proposed a reconductor of the existing Laguna Bell-Mesa No. 1 230 kV Transmission Line due to a reliability issue under P3 and P7 conditions. The parallel Laguna Bell-Mesa 230 kV No.2 Transmission Line does not show a reliability concern within the 10-year forecast, but CAISO has indicated that reconductoring both lines could generate an incremental 470 MW of FCDS. The proposed scope is to increase the line rating of the Laguna Bell-Mesa No.2 230 kV Transmission Line by reconductoring approximately 5 miles of the existing line with ACCC Fort Worth conductor. Upgrading both lines at the same time would generate cost efficiencies for a lower total project cost below the sum of each individual project. The estimated cost for this project is $15M.

Proposed In-Service Date:      7/1/2024

Project Name:           Antelope-Vincent 500 kV Terminal Equipment Upgrade

Submission Date:        10/12/21

Project location and interconnection point(s): Antelope 500/230/66 kV Substation and Vincent 500/230 kV Substation

Description of the project:

The California Tehachapi area has considerable forecast generation in the CPUC portfolio, but a key constraint to bringing this power to the southern CAISO grid is a limitation of the circuit breaker rating on both ends of the Antelope-Vincent 500 kV No. 1 and No. 2 transmission lines. Upgrading these circuit breakers to allow each line to operate at its full rating would generate approximately 2,700 MW of FCDS according to the CAISO analysis. In addition to FCDS, this line is a limiting component for the Tehachapi CRAS tripping criteria and can cause pre-emptive generation curtailment. The proposed scope is to upgrade the 500 kV line terminal equipment at each end of both the Antelope-Vincent No.1 and No. 2 500 kV Transmission Lines. Upgrading the terminal equipment to enable full use of the line rating will add FCDS in-line with the CPUC portfolio and mitigate need for RAS curtailment and tripping. The estimated cost for this project is $15M.

Proposed In-Service Date:      7/1/2024

Project Name:           Antelope 66 kV Circuit Breaker Upgrade

Submission Date:        10/12/21

Project location and interconnection point(s): Antelope 500/230/66 kV Substation

Description of the project:
This project proposes to upgrade the existing Antelope 66 kV switchrack to a 50 kA short circuit duty rating by replacing (41) 66 kV circuit breakers, (101) 66 kV ground disconnect switches, (45) 66 kV potential transformers, performing a ground grid study, and removing (15) steel lattice structures and installing (15) new dead-end structures. The existing circuit breakers are currently operating at 96% of their 40 kA short circuit duty rating and our preliminary analyses show that adding the CPUC portfolio generation at the Antelope Substation 230 kV bus alone will trigger the need for circuit breaker replacement. The large number of circuit breakers and resultant need for outage coordination result in this upgrade being estimated at 45 months, which is longer than the time for interconnection facilities in many cases and would therefore represent the critical path upgrade to installation of new generation in the Tehachapi area. The estimated cost for this project is $55M.

Proposed In-Service Date:      1/1/2026

Project Name:           Colorado River No. 3 500/230 kV Transformer Bank

Submission Date:        10/12/21

Project location and interconnection point(s): Colorado River 500/230 kV Substation

Description of the project:

Colorado River Substation was built to serve as a collector station for area renewable generation and the station 500/230 kV transformer banks are the only path from the area into the rest of the CAISO system. There is one 500/230 kV transformer bank installed and another in construction, but even with both transformers the RAS tripping limitation criteria of 1,150 MW for an N-1 event of one bank will result in congestion management. This project proposes to relieve this constraint by adding a new No. 3 500/230 kV transformer bank in parallel with the existing two 500/230 kV banks. The proposed scope is to add four (4) single phase transformer units to create a new 500/230 kV transformer bank, extend the 230 kV bus, equip a new breaker-and-a-half position at each of the Colorado River 500 kV and Colorado River 230 kV switchracks, and update the existing West of Colorado River Centralized Remedial Action Scheme (CRAS). A new 500/230 kV transformer bank will not only add deliverability to the area by providing a better tie to the rest of CAISO, but reduce the need for pre-emptive RAS curtailment through congestion management and reduce the generation lost in a contingency event. The estimated cost for this project is $75M.

Proposed In-Service Date:      10/1/2025

Project Name:           New Eldorado No. 6 500/230 kV Transformer Bank

Submission Date:        10/12/21

Project location and interconnection point(s): Eldorado 500/230 kV Substation

Description of the project:

The SCE-owned and joint-owned Eldorado 230 kV buses were developed to bring new procurements to the rest of the CAISO system. There is currently only one 500/230 kV transformer bank on the SCE-owned 230 kV bus. As a result of existing CAISO planning standards, generation within the Eldorado/Mountain Pass 230 kV area is limited to 1,150 MW and all generation is tripped due to a RAS action upon loss of that transformer bank. This project proposes to add a new No. 6 500/230 kV transformer bank in parallel with the existing 500/230 kV bank. The proposed scope is to add three (3) single phase transformer units to create a new 500/230 kV transformer bank, equip a new breaker-and-a-half position at each of the Eldorado 500 kV and Eldorado 230 kV switchracks, and update the area RAS. A new bank will (1) add 400 MW of incremental FCDS, (2) significantly reduce the need for RAS curtailments, and (3) eliminate the need to trip generation following the loss of a single Eldorado 500/230 kV transformer bank. In addition, the new transformer bank would allow SCE to continue serving load, such as the planned Brightline West High Speed Rail, after a P1 contingency. Taking into account the planned Brightline West High Speed Rail, loss of the single Eldorado 500/230 kV transformer bank under the existing configuration would result in non-consequential load loss, which would be a reliability violation of NERC TPL-001-5. The estimated cost for this project is $60M.

Proposed In-Service Date:      10/1/2025

Project Name:           New Lugo No. 3 500/230 kV Transformer Bank

Submission Date:        10/12/21

Project location and interconnection point(s): Lugo 500/230 kV Substation

Description of the project:

The North of Lugo area, which encompasses Victor, Kramer, and Control sub-areas, is connected to the rest of the SCE system through two existing 500/230 kV transformer banks. These banks represent a well-known constraint in the area and this project proposes to relieve this constraint by adding a new No. 3 500/230 kV transformer bank in parallel with the existing two 500/230 kV banks. The proposed project scope is to add four (4) single phase transformer units to create a new 500/230 kV transformer bank, extend the 230 kV operating bus, and equip a new breaker-and-a-half position at each of the Lugo 500 kV and Lugo 230 kV switchracks.  The additional Lugo transformer bank would (1) add an estimated 980 MW of incremental FCDS, (2) significantly reduce the need for RAS curtailments, (3) reduce the need to trip generation on N-1 and N-2, and (4) provide increased operational and outage flexibility. The additional bank would also improve reliability for the North of Lugo area load by maintaining service under a P6 event. The estimated cost for this project is $70M.

Proposed In-Service Date:      10/1/2025

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

As developers of New Mexico wind on new transmission, Southwestern Power Group (SWPG) and Pattern Energy simply point out that both the 2040 SB 100 Core and Starting Point scenarios show large amounts of out-of-state wind, with the Starting Point showing 5,215 MW of New Mexico wind in particular. Therefore SWPG and Pattern encourage consideration of long-term CAISO upgrades needed to integrate this valuable resource, along with others.

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

SWPG/Pattern are aware of the East of Miguel constraints and the limitations of the existing Southwest Power Link and the Sunrise Power Link towards San Diego County. However the proposed Imperial Valley to Serrano 500kV line cost is significant for the FCDS MW’s gained (~$3.7B for 1,412 FCDS MW). SWPG therefore proposes that more cost-effective alternatives be explored. For example the 500kV system between SCE and SDG&E could in theory be strengthened through the following combination of projects:

• New Suncrest to Serrano 500kV line
• New Imperial Valley to IID Highline 500kV line (a component of the proposed North Gila – Imperial Valley #2 Project)
• New 500KV line from Highline towards the Red Bluff – Devers 500KV corridor; coupled with CAISO’s proposed Devers - Mira Loma - Mesa 500KV line

The above combination of projects would create a “ring” solution that could alleviate the E. of Miguel constraint while meeting additional regional objectives more cost-effectively than a new Imperial Valley to Serrano 500kV line.

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

SWPG/Pattern agree that CAISO needs to consider proactive upgrades needed to accommodate expected increases in resource procurement, beyond those identified through analysis of the resource portfolios from the 2021-22 TPP policy case. As CAISO highlighted several significant changes have occurred since those portfolios were communicated by the CPUC to the CAISO.

SWPG/Pattern also point out to CAISO that there are several flaws in the CPUC’s modeling of out-of-state (OOS) wind, including hard-coded exclusions which mask the potential of the resources to deliver before 2028 and therefore do not send the appropriate signal to CAISO to prepare for these imports before then[1]. For example slide 11 of day 2 shows that the CPUC’s Draft Preferred System Plan (PSP) has 0 MW of OOS wind in 2025 while Pattern alone will be onboarding 1,050 MW of New Mexico wind on new transmission in December 2021 (~700MW of which to CAISO), and is developing an additional ~2 GW of New Mexico wind for delivery to California customers in 2025 through the SunZia Transmission Project. None of these OOS wind projects on new transmission have been forecasted to occur in any CPUC portfolios but they are real projects the import of which need to be considered in CAISO’s transmission planning.

To that end, SWPG/Pattern support the CAISO’s consideration of the eight (8) transmission projects listed on slide 13 of day 2 for near-term approval, but also suggest the CAISO consider additional projects in its economic and policy analysis which will enable deliverability of high-quality New Mexico wind along with other valuable resources. The three (3) specific projects are listed below, with previous caveat on the Imperial Valley -Serrano 500kV line noted in Question 11.

* Refer to more cost-effective alternatives suggested under Question 11.

[1] SWPG/Pattern expound on these modeling flaws and present alternative results in their comments on the Draft PSP Ruling filed on September 27, 2021: https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M410/K467/410467249.PDF

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

The Transmission Agency of Northern California (“TANC”) appreciates this opportunity to provide comments on the California Independent System Operator’s (“CAISO”) 2021-2022 Transmission Planning Process (“TPP”) preliminary reliability assessment results and proposed mitigations as presented at stakeholder meetings on September 27 and 28, 2021.

TANC, through its members, is the primary owner of the California-Oregon Transmission Project (“COTP”) and a party to the Federal Energy Regulatory Commission jurisdictional California-Oregon Intertie (“COI”) Owners Coordinated Operations Agreement (“OCOA”) and the COI Path Operator Agreement. TANC and the other COI owners jointly monitor planned projects that may adversely impact the transfer capability of the COI and provide guidance to the CAISO for the operation of the COI towards the common goal of optimizing and maintaining the operational and rated COI transfer capability. TANC is pleased with the coordination of the CAISO in the California Operations Studies Subcommittee, where alongside the other owners of the COI substantial improvement have been achieved to the operation of the COI. TANC and its members are vigilant in their review of new transmission and generation projects to assure that the terms of the OCOA and the CAISO generator interconnection process to protect affected systems and to not adversely impact COI and COTP transfer capability are faithfully honored and that mitigation measures are appropriate.

TANC’s primary focus is to preserve and look for opportunities to maximize the transfer capability in both directions of the COTP and the COI. In recent years maintaining high transfer capability on the COI has become more important to the balancing authorities (“BA”) in Northern California and the Pacific Northwest. This will continue to be important as the number of variable energy resources continues to increase as more dispatchable and baseload generation gets retired, and as new challenges arise that are driven by climate change. The intent of these comments is to provide the CAISO with TANC’s perspective and an option for proactive transmission planning efforts necessary to preserve and enhance the transfer capability of the COI. TANC believes the CAISO should continue to proactively evaluate options in its TPP stakeholder process to maintain and enhance the transfer capability of the COI. TANC and its members would like to have the opportunity to provide feedback in processes and support coordinated efforts with the CAISO and other regional entities to improve the bi-directional transfer capability of the COI, such as the efforts in progress to increase the COI transfer limit under the WECC Path Rating Process.

1. As an option TANC recommends the CAISO consider a regionally coordinated transmission project or collection of projects to enhance renewable import options that also preserve the Total Transfer Capability (“TTC”) of the COI at or near full capacity under all normal conditions. While the COI can provide effective mitigation for many constraints and a reduction of COI transfers is often an effective mitigation action for many constraints within the CAISO BA, it may adversely impact Northern California reliability. COI reductions, when shared with the TANC members not located within the CAISO BA area, the Balancing Authority of Northern California may face impacts to its ability to serve load, even if such COI reductions do not affect the CAISO BA service to load in its BA. In the recent past the CAISO has found it difficult to serve its load, such as during the heat-storm of August 2020. Under these conditions, and conditions reflected in the TPP planning study case, reducing the COI TTC is not advisable, as this would require a capacity strapped region to search for more resources, potentially relying on load shedding as was the case in 2020. Rather than proposing COI TTC reductions in many of the solutions for overloads within the CAISO system, and in consideration of the addition of renewables north and south of the Oregon-California border, keeping COI fully available at its maximum capability would best serve the interest of overall California reliability. As an option TANC recommends the CAISO consider a regionally coordinated transmission project or collection of projects to enhance renewable import options that also preserve the TTC of the COI at or near full capacity under all normal conditions.
2. COI flow reduction should be excluded as a mitigation option for T-1 outage of the Round Mountain 500/230-kV bank overloading the Olinda 500/230-kV bank. In the California Operations Studies Subcommittee meetings, it was decided that COI would not be used as a mitigation for T-1 of Round Mountain 500/230-kV bank overloading the Olinda 500/230-kV bank. This decision was made since COI is less than 5% effective in the S-N flow on the banks. This mitigation option has been removed from the current COI nomogram for winter 2022 release of CAISO 6110 procedure, and therefore should not be referenced as a mitigation option in the TPP study plan, studies, and report. Instead, existing mitigation obligations on local and more effective generation on the 230-kV system that ties into the Round Mountain and Olinda 230-kV Substation should be used in the short-term. For a long-term solution, a good option would be adding a second 500/230-kV bank at or near Round Mountain or Olinda for managing heavy hydro conditions in combination with expansion of renewable generation into the area.
3. The CAISO’s mitigation solutions should reference the WECC Project Review Group study that is ongoing for the Statcom project and a RAS is required to help mitigate for the overloads. Adding the Statcom project at the location 11 miles south of Round Mountain exacerbates the overloads of the parallel line into or out of Fern Road and a RAS is required to help mitigate for the overloads. Since a WECC Project Review Group study is ongoing for this project these contingencies should reference that effort in the mitigation solutions since that is the objective of this study group.
4. TANC would like more details of the modeling of the contingencies and Remedial Action Schemes (“RAS”) setup. Some of the contingencies seem to not model the RAS that exists to mitigate overloads noted in the report. TANC is not sure if the criteria for the category is set up correctly; therefore, including a detailed description of the modeling of the contingencies and associated RAS actions used is a must. The relevant contingencies, mitigation actions and flowgates include the following:
   • Malin-Round Mtn#1 or #2 500-kV Line contingencies;
   • Round Mtn-Table Mtn #1 or #2 500-kV Line (Including the Stacom) contingencies;
   • Operation of the Cascade thermal overload RAS to mitigate the thermal overload on the Delta-Cascade 115-kV Line flowgate;
   • Operation of the Metcalf RAS for the 2 or the 3 Metcalf 500/230-kV banks contingency; and
   • Readjustment to bring COI back to 4800 MW before applying the second contingency for the P6 contingencies for the COI.

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion:

1. Provide your organization’s comments on the overview and key issues, as described in slides 4-16 of the ISO’s day 1 presentation:

2. Provide your organization’s comments on the preliminary reliability assessment results for the northern areas, as described in slides 17-118 of the ISO’s day 1 presentation:

(Northern areas include the Greater Bay Area, Northern CA Bulk System, Central Coast & Los Padres Area, Kern Area, Fresno Area, North Coast & North Bay Area, North Valley Area, and Central Valley Area)

3. Provide your organization’s comments on the high voltage assessment results for the PG&E area, as described in slides 119-143 of the ISO’s day 1 presentation:

4. Provide your organization’s comments on the preliminary reliability assessment results for the southern areas, as described in slides 144-220 of the ISO’s day 1 presentation:

(Southern areas include the SCE main and bulk systems, the SCE – Eastern Area, SCE – North of Lugo, SCE – East of Lugo, and SCE – Big Creek Corridor)

5. Provide your organization’s comments on the preliminary reliability assessment results for the VEA areas, as described in slides 221-232 of the ISO’s day 1 presentation:

6. Provide your organization’s comments on the preliminary reliability assessment results for the SDG&E areas, as described in slides 233-253 of the ISO’s day 1 presentation:

7. Provide your organization’s comments on the wildfire assessment scenarios, as described in slides 254-261 of the ISO’s day 1 presentation:

8. Provide your organization’s comments on the updates related to the 20-Year Transmission Outlook, as described in slides 262-281 of the ISO’s day 1 presentation:

9. Provide your organization’s comments on the PG&E Reliability Alternatives:

10. Provide your organization’s comments on the SCE Reliability Alternatives:

11. Provide your organization’s comments on the SDG&E Reliability Alternatives:

12. Provide your organization’s comments on the GLW Reliability Alternatives:

13. Provide your organization’s comments on the economic assessment update, as described in slides 1-9 of the ISO’s day 2 presentation:

14. Provide your organization’s comments on increasing procurement and capacity in portfolios topic, as described in slides 10-14 of the ISO’s day 2 presentation:

15. Additional comments on the September 27-28, 2021 stakeholder call discussion: