Comments on Draft 2021-2022 Transmission Plan

2021-2022 Transmission planning process

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Comment period
Feb 04, 04:00 pm - Feb 22, 05:00 pm
Submitting organizations
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American Clean Power - California
Submitted 02/22/2022, 07:20 pm

Contact

Danielle Mills (danielle@renewableenergystrategies.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

ACP-California appreciates the significant effort that CAISO has put into completing the 2021-22 Draft Transmission Plan. CAISO has clearly put a great deal of effort into the successful completion of a large number of analyses and studies in this cycle’s planning process. This year, the Draft Transmission Plan required not only the traditional studies, but also offshore wind sensitivities, out-of-state wind sensitivities, and the completion of the 20-Year Outlook. These efforts, and the significant dedication it took to complete them should be commended.

 

ACP-California appreciates that the efforts CAISO has taken to begin a more forward-looking and proactive transmission process, such as the 20-Year Outlook. This is the type of forward-looking transmission approval that can be informed by the work undertaken in the 20-Year Outlook, where approving a different transmission alternative may provide strategic future value and help situate transmission approvals to reduce total ratepayer cost. Furthermore, we suggest that the CAISO consider any additional upgrades contained in the draft 20-Year Outlook that either should be included in the 2021-2022 TPP cycle due to their long lead times or trigger expansions of upgrades contained in this TPP. We hope, going forward, that the information from the 20-Year Outlook can continue to be used to inform near-term transmission approvals.

 

As part of the 2021-22 Transmission Planning Process, CAISO is also proposing to take additional steps to assess the interest in regional wind resources. In light of an economic study request and a lack of a “subscriber” business model for transmission to deliver Idaho wind, CAISO is proposing an “open season-type process to assess the market interest and level of competition that exists for accessing Idaho resources.” ACP-California looks forward to working with CAISO as it further develops the specifics of this process and hopes CAISO provides stakeholders with an opportunity to be involved in the development of additional details around this new process. Specifically, it would be helpful to know whether the market interest would come from generators seeking to use the transmission to deliver Idaho wind or from load-serving entities (LSEs) with procurement interests. We encourage CAISO to consider broadening and expanding this process to evaluate a broader set of diverse resources, considering not only Idaho, but also New Mexico and Wyoming. If structured appropriately, the “open season-type” process that CAISO conducts could be a useful model for future evaluation of potential transmission alternatives to reach a broader set of resources. Such an expanded/broadened process could be a useful platform for CAISO (and stakeholders) to inform how future projects, such as those that would be necessary under the 20-Year Outlook, may be able to move forward for approval.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

NA

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

NA

4. Comment on chapter 3 Policy-Driven Need Assessment:

NA

5. Comment on chapter 4 Economic Planning Study:

NA

6. Comment on chapter 5 Interregional Transmission Coordination:

NA

7. Comment on chapter 6 Other Studies and Results:

NA

8. Comment on chapter 7 Special Reliability Studies and Results:

NA

9. Comment on chapter 8 Transmission Project List:

NA

Bay Area Municipal Transmission group (BAMx)
Submitted 02/22/2022, 04:01 pm

Submitted on behalf of
Silicon Valley Power and City of Palo Alto Utilities

Contact

Paulo Apolinario (papolinario@svpower.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

The Bay Area Municipal Transmission group (BAMx)[1] appreciates the opportunity to comment on the Draft 2021-2022 Transmission Plan (Draft Plan, hereafter), dated January 31, 2022.  The comments and questions below also address the material presented at the CAISO Stakeholder meeting on Feb 7, 2022. BAMx acknowledges the significant effort of the CAISO staff to develop the Draft Plan. BAMx recognizes the tremendous amount of work the CAISO staff has completed in this planning cycle. BAMx also believes the CAISO staff must be allowed a corresponding amount of time to engage the stakeholders to explain the staff’s work.

 

In these comments, BAMx raises some major concerns about the skyrocketing CAISO transmission access charges (TAC) and the CAISO’s financial fiduciary responsibilities to Californians and grid users. BAMx comments should be construed as attempting to assist the State in its journey to achieve its climate goals and not as any opposition in taking the necessary steps. Further, BAMx recognizes that electric rates may continue to rise as a necessary outcome in achieving the State’s climate goals. That said, it is imperative and incumbent on the CAISO to design and develop an appropriate and cost-effective electric grid to accomplish those goals.

 

In order to understand the TAC impact of the projects the CAISO management may recommend for approval as part of the current planning process, BAMx developed an HV TAC forecast for the period of 2023-2031. BAMx’s forecast shows that the HV TAC would rise to more than $22/MWh in 2031 relative to the existing level of $16.6/MWh, a staggering 33% increase in less than ten years.

 

Out of the $22/MWh of forecasted HV TAC in 2031, more than 38% of the increase is solely attributed to the nearly $3 billion transmission projects the CAISO is considering for approval in the current TPP cycle. BAMx’s HV TAC projections show the tremendous impacts these potential project approvals will have on the ever-increasing CAISO-wide HV TAC. As detailed in the remaining BAMx comments,  the CAISO and stakeholders must complete thorough reviews and analyses to ensure the “right” projects are proceeding forward while eliminating excessive or unnecessary projects.

 

BAMx recognizes that the combination of the dramatically increasing pace of renewable generation and load forecast growth are driving an increase in transmission requirements under certain portfolio scenarios. However, the CAISO and the stakeholders must refrain from rushing to approve projects without allowing adequate time to complete the appropriate evaluation of each proposed project.

 

In some cases, it appears the transmission alternatives have not yet been fully developed, screened, and analyzed. Alternatives are often discussed qualitatively but never quantitatively compared with the proposed alternative. For instance, the stakeholders do not have access to any “change” power flow cases for the policy-driven transmission analysis and documentation underlying the recommended projects’ needs.

 

Furthermore, the CAISO typically posts its responses to past stakeholder comments before issuing the Draft Plan. Previous TPPs included posted responses to comments on preliminary reliability assessment in mid-November. As of February 2022, the CAISO still has not posted its responses to stockholders’ comments dated October 10, 2021 and December 6, 2021. BAMx finds it extremely challenging to respond and comment on certain aspects of the Draft Plan without knowing the CAISO’s responses to prior concerns raised by BAMx and other stakeholders.

 

In a nutshell, some of the transmission projects that the CAISO has recommended for approval in this planning cycle need to be studied more extensively in the next cycle, or at the very least their approval needs to be delayed until later in this cycle after the Board approval of the Plan in March 2022.

 


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

2. Comment on chapter 1 Overview of the Transmission Planning Process:

BAMx agrees with the CAISO that the role of battery storage is expected to continue to grow as a complement to the renewable generation and also as a key source of capacity to meeting both system capacity needs and local needs.[1] Ultimately, storage resources will be available to meet energy needs during most periods when renewable resources are not available to generate. BAMx agrees with the conclusion that only the incremental interconnection cost for the storage should be compared to transmission costs when the batteries are located in local constrained areas.

 

BAMx applauds the CAISO staff’s efforts in relying on the implementation of Remedial Action Schemes (RAS) and storage solutions in its Preliminary Policy Assessment. As shown in Table 1 compiled by BAMx below, the CAISO has effectively and rightfully utilized the existing/planned RAS dispatching portfolio battery storage in charging mode, and also includes new battery storage

as mitigations wherever applicable to mitigate the contingency overloads.

 

 

Table 1: Recommended Non-Wires Mitigations*

image(26).png

 

*Source: November 18th Presentation, “2021-2022 TPP Policy-driven Assessment,” pp. 30-55.

 

BAMx encourages the CAISO to transfer such valuable feedback to the California Public Utilities Commission (CPUC) and California Energy Commission (CEC) so that it is incorporated as part of the battery storage mapping exercise in the next Transmission Planning Process (TPP) cycle.

 


[1] Draft Plan, p.31.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

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.

 

Although this list excludes another project, namely Oro Loma 70kV Area Reinforcement Project, the Draft Plan includes it in the list of previously approved projects.[1]

 

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

 

Ora Loma 70kV Reinforcement Project

The 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.[2] 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.[3]

 

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.[4] However, this overload is not identified in any of the CAISO’s preliminary reliability results for the 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.[5] 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[6] that is currently operational potentially mitigates the identified N-1-1 or P6 overload on the Midway-Temblor line. 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”.[7]

 

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. 

 

CAISO-Recommended Reliability-driven Projects in the Draft Plan

 

San Jose Area HVDC Lines

BAMx appreciates CAISO’s attention and seeking solutions to address significant long term issues in the SVP/San Jose area.[8]

 

Table Mountain 500/230 kV Transformer Bank #2 Project

The need for a second 500/230kV transformer at Table Mountain was identified in real-time operations due to high voltage issues at Table Mountain and Palermo 230kV areas when the existing Table Mountain 500/230kV transformer is taken out of service for maintenance conditions, which is usually conducted around the October/November timeframe.[9] With Rio Oso Static VAR Compensator (SVC) going into service, the high voltage issue shifts from P0 under maintenance to P1 under maintenance conditions[10]. BAMx requests the CAISO to investigate whether the maintenance outages could be scheduled during other months outside of October and November and provide additional information on the duration and frequency of the maintenance outages of Table Mountain 500/230kV transformer before the project is approved.

 

Additionally, the CAISO has indicated there are remaining high voltage issues in the area that will likely require mitigation[11]. If additional mitigations are approved and constructed in future TPP cycles, some of these mitigation measures could potentially allow for additional opportunities to obtain maintenance outages on the existing Table Mountain 500/230kV transformer bank. BAMx urges the CAISO to review the need for the new Table Mountain Bank in consideration of other voltage mitigation projects that could materialize around the Table Mountain and Palermo 230kV areas.

 

Cortina 230/115/60 kV Bank #1 Replacement

Cortina 230/115/60kV Bank #1 was identified to be overloaded for a P1 loss of Cortina 230/115kV Bank #4 and a P3 contingency for the loss of the same Cortina 230/115kV Bank #4 and Wadham Generator #1. The total load served radially by the Cortina 60kV substation is approximately 73.6MW. The emergency rating of Cortina 230/115/60kV transformer bank is 84MVA, and the bank can reliably support all the load even with the Wadham units off-line. The overloads identified by PG&E are due to impedance imbalance causing a flow of approximately 65.1MW from Cortina 60kV to Cortina 115kV substation through the 115kV/60kV transformer as identified on diagram below.

 

image(28).png

 

 

 

The identified overloads on Cortina 230/115/60kV #1 bank can be avoided by keeping either Cortina 230/115/60kV #1 bank or Cortina 115/60kV bank normally open. This configuration will avoid replacing Cortina 230/115/60kV #1 bank, and Cortina 60kV substation will still be reliably served since the transformer kept normally open could be utilized to restore Cortina load in case of failure of the primary transformer. Therefore, BAMx recommends against approving the Cortina 230/115/60 kV Bank #1 Replacement Project at this time.

 


[1] Draft Plan, Table 8.1-1: Status of Previously Approved Projects Costing Less than $50 M, p.374.

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

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

[4] Ibid.

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

[6] 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

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

[8] Reliability Assessment Recommendations –PG&E Area, Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting, February 7, 2022, slides #3 & #4.

[9] Reliability Assessment Recommendations –PG&E Area, Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting, February 7, 2022, slide #7.

[10] Appendix B, Draft 2021-2022 Transmission Plan Page B-86

[11] Appendix B, Draft 2021-2022 Transmission Plan Page B-84

4. Comment on chapter 3 Policy-Driven Need Assessment:

During the February 7th stakeholder meeting, the CAISO presented seven (7) Policy-Driven Projects, for a total cost estimate of $1.5 billion, and the Draft Plan recommends them for Board approval. In the interest of transparency and meaningful stakeholder feedback, BAMx strongly urges the CAISO to provide the following additional details for each of these policy projects.

 

  • Load flow results supporting the need for the project(s);
  • Change file modeling of the proposed project(s); and
  • Contingency files corresponding to each project.

 

Without this information, the stakeholders will not be able to gauge the effectiveness of the proposed upgrades in mitigating the deliverability constraints or suggest any cost-effective alternatives to the proposed project(s). Moreover, most of these projects were not introduced or discussed in detail during the previous 2021-2022 TPP stakeholder meetings. It would be challenging to analyze such extensive network upgrades and provide meaningful comments during the current two week period. Approving these projects now would not allow enough time for stakeholders to conduct their independent analysis and provide feedback.

 

 

PG&E Area CAISO-Recommended Policy-Driven Projects in the Draft Plan

 

Collinsville 500/230 kV Substation Project

The CAISO’s recommendation of the Collinsville 500/230 kV Substation Project is driven by multiple potential overloads on the 230 kV corridor between Contra Costa and Newark under normal, N-1, and N-2 contingency conditions in baseline and sensitivity scenarios in the on-peak deliverability assessment.[1] The specific deliverability constraints that can potentially be addressed by the proposed Collinsville 500/230 kV Substation Project are[2]

  1. Cayetano-North Dublin 230 kV line on-peak deliverability constraint;
  2. Lone Tree-USWP-JRW-Cayetano 230 kV line on-peak deliverability constraint; and
  3. Las Positas-Newark 230 kV line on-peak deliverability constraint.

 

However, reconductoring each of the above-mentioned 230kV lines could address the above-mentioned constraints and is expected to be an effective and adequate mitigation solution. The combined cost of the three reconductoring projects are in the range of $145.2M – $188.7M, which is less than one-third the cost of $475M – $675M associated with the New Collinsville 500 kV substation. BAMx recognizes that the Collinsville 500 kV substation could be a superior alternative to the 230kV reconductoring projects, which offers additional supply from the 500 kV system into the northern Greater Bay Area to increase reliability to the area and advance additional renewable generation in the northern area. However, BAMx is not convinced that it is the least cost way of achieving the State policy goals as envisioned per the CPUC-provided renewable resource portfolios studied in the current planning cycle. A synergy of the Collinsville 500/230 kV Substation with the transmission needed to accommodate offshore transmission development as studied in a single scenario under the 20-Year Transmission Outlook[3] should not, by itself, be used as a justification to approve the Collinsville project at this time. Therefore, BAMx urges that CAISO to delay the approval of the Collinsville 500/230 kV Substation Project as a policy-driven project until a rigorous reliability and economic analysis[4] of the competing alternatives is performed.

 

Manning 500/230 kV Substation Project

The CAISO’s recommendation of the Manning 500/230 kV Substation Project is driven by potential overloads on the Borden-Storey 230 kV lines under normal and N-1 contingency

conditions in baseline and sensitivity scenarios in the on-peak deliverability assessment.[5]

 

However, reconductoring of the Borden-Storey #2 230kV line is expected to be an effective and adequate mitigation solution. The cost of the reconductoring is in the range of $24.24M – $31.5M, which is less than 7 percent of the cost of $325M – $485M associated with the New Manning 500/230 kV substation. BAMx recognizes that the New Manning 500/230 kV substation could be a superior alternative to the 230kV reconductoring project, which provides benefit in allowing for the advancement of renewable generation within the Westlands/San Joaquin area. However, additional analysis should be performed to demonstrate that it is the least cost way of achieving the State policy goals as envisioned per the CPUC-provided renewable resource portfolios studied in the current planning cycle. A synergy of the Manning 500/230 kV Substation with the transmission needed to accommodate transmission development as studied in a single scenario under the 20-Year Transmission Outlook[6] cannot in itself be used as a justification to approve the proposed project at this time. Therefore, BAMx urges that CAISO to delay the approval of the Manning 500/230 kV Substation Project as a policy-driven project until a rigorous reliability and economic analysis[7] of the competing alternatives is performed.

 

Southern California CAISO-Recommended Reliability-driven Projects in the Draft Plan

 

GLW/VEA Area Upgrades Project

During the 2021-2022 TPP request window submission process, the GridLiance West (GLW) LLC submitted the GLW Upgrade project. The project scope includes rebuilding Desert View – Northwest 230kV, Pahrump – Gamebird 230kV, Gamebird – Trout Canyon 230kV and Trout Canyon – Sloan Canyon 230kV to double circuit lines; adding a second Innovation –Desert View 230 kV line; adding a 500/230 kV transformer at Sloan Canyon and looping in the Harry Allen – Eldorado 500kV line; an upgrade to WAPA’s Amargosa 230/138 kV transformer and a tentatively planned NV Energy (NVE) upgrade on the Mercury SW – Northwest 138 kV tie line. The estimated cost of this project is $213M with an in-service date of 2025. The CAISO has recommended an expanded version of the GLW project to include rebuilding the Innovation –Pahrump 230 kV line and installing a 138kV phase shifter at Innovation on the planned tie-line to NVE, which increases the project costs to $278M.

 

The overloads driving the GLW Project are identified only in the 2031 Off-Peak scenario, as shown in the GLW/VEA area off-peak deliverability constraint summary table included below.[8] The need for the GLW project is only identified in the Base portfolio. In contrast, the combination of existing Innovation RAS and Sloan Canyon RAS, and 100MW of battery storage are adequate under the two sensitivity portfolios.

 

image-20220222154607-2.png

 

Per the CAISO’s FERC-approved tariff, a Category 1 policy-driven transmission solution has to be identified to be needed “in the baseline scenario and at least a significant percentage of the stress scenarios.”[9] Since the GLW project is not identified to be needed under any of the two sensitivity portfolios, it clearly does not satisfy the criteria for Category 1 transmission, and therefore should not be approved as such. The CAISO could approve the project as Category 1 on the basis of the need under the baseline portfolio only if “the CAISO finds that sufficient analytic justification exists to designate them as Category 1 transmission solutions.”[10] However, CAISO has not provided such additional justification.

 

The GLW project meets the criterion for Category 2 as it is identified to be needed under the baseline portfolio. Therefore, BAMx requests approving the GLW project only as a Category 2 project to be studied further in the future planning cycles, and not be recommended as Category 1 policy-driven to the CAISO Board at this time.

 


[1] Policy Assessment Recommendations –PG&E Area, Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting, February 7, 2022, slide #5.

[2] Draft Plan, pp.192-195.

[3] Draft 20-Year Transmission Outlook,  2021-2022 Transmission Planning Process Stakeholder Meeting

February 7, 2022, slide #1.

[4] BAMx appreciates the economic analysis performed by the CAISO, which shows that the production benefits for CAISO ratepayers of the Collinsville Upgrade is $10 million per year in the Base portfolio (Draft Plan, p. 302), and encourages CAISO to perform such economic analyses for the base and sensitivity portfolios in the next planning cycle.

[5] Policy Assessment Recommendations –PG&E Area, Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting, February 7, 2022, slide #6.

[6] Draft 20-Year Transmission Outlook,  2021-2022 Transmission Planning Process Stakeholder Meeting

February 7, 2022, slide #12.

[7] BAMx appreciates the economic analysis performed by the CAISO, which shows that the production benefits for CAISO ratepayers of the Manning substation is $15 million per year in the Base portfolio (Draft Plan, p. 301), and encourages CAISO to perform such economic analyses for the base and sensitivity portfolios in the next planning cycle.

[8] Draft Plan, p.274

[9] CAISO Fifth Replacement FERC Electric Tariff, Effective as of January 1, 2022, 24.4.6.6 Policy-Driven Transmission Solutions.

[10] Ibid.

5. Comment on chapter 4 Economic Planning Study:

Out-of-State Wind Study

 

All portfolios provided by the CPUC called for at least 1,062 MW of Out-Of-State (OOS) wind to be brought into California. Thus, the CAISO compared the effectiveness of the different transmission and resource options against each other as opposed to a “no out-of-state” case.[1] The New Mexico OOS wind resources were selected as the reference case against which other alternatives were compared, as they provided the least amount of direct interaction with transmission facilities impacted by other different alternatives, and possible transmission upgrades in New Mexico and Arizona, such as the SunZia Transmission Project (SunZia), may be moving forward on a subscriber basis. BAMx finds this aspect of the CAISO’s OOS wind study reasonable.

 

The economics of the OOS transmission should be based upon the Seller’s ability to access existing transmission or purchase transmission from developers of that transmission. To perform a systematic comparison of the transmission cost impact of the OOS transmission, the following transmission cost allocation principles should be applied. The fundamental principle for cost allocation is that it should be allocated in a way that is commensurate with benefits. In particular, the LSEs within the Local Regulatory Authorities (LRAs) approving resource procurement that are benefiting from the OOS resources should pay for that transmission delivering those resources to the CAISO border. BAMx believes that having the supplier build in its cost of delivering its product to the CAISO will also improve its ability to optimally deliver its product to the WECC-wide grid. This mechanism ensures that buyers of the remote generation will have the transmission costs outside of the CAISO captured in the power purchase agreement (PPA) pricing. This will also help accomplish the first principle of FERC Order 1000, that is, costs are allocated in a way that is roughly commensurate with benefits. Broadly, LSEs voluntarily procuring resources using transmission should pay for the cost of delivery. One such example is SunZia accessing the New Mexico wind, which is not seeking CAISO Transmission Access Charge (TAC) cost recovery to deliver its product to the CAISO boundary point.[2] In other words, the costs of new transmission outside CAISO are captured in the PPA pricing with LSE off-takers who are procuring New Mexico wind energy and will not be borne by all the CAISO-wide TAC payers.

 

BAMx supports the CAISO analysis that distinguishes between those OOS transmission projects seeking CAISO TAC-based recovery versus those that do not seek to recover their costs through the CAISO TAC. The Draft Plan states that the TransWest Express (TWE) project is being developed on a subscriber basis, without the need for CAISO transmission plan approval, to provide transmission service to resources seeking access to California markets.[3] However, this statement is only partially true. Out of the three segments of the TWE project, only half of two of the segments would use a subscriber model. In other words, out of nearly $2.18 billion, nearly $1.71 billion would ultimately be recovered from the CAISO ratepayers.[4] BAMx suggests that the CAISO should clarify in all references to TWE in the Draft Plan that TWE would only “partially” use a subscriber model.

 

The Draft Plan includes the benefit to cost ratio (BCR) of the three candidate transmission upgrades, viz. SWIP-North, Cross Tie, and TWE, with different out-of-state wind scenarios and different phase shifter setups.[5] In particular, the Draft Plan Table 4.10-4 shows that the BCRs for all three projects are well below 1.0. In other words, the candidate projects are not found to be economically viable. In addition to this base assessment, CAISO also calculated an alternative benefit to cost ratio for each project and alternative configuration assuming an added benefit of avoiding half of the cost of the SunZia project - as a proxy for the cost of delivering New Mexico wind generation to Pinal Central.[6] In the benefit to cost ratio calculations, the present value of the annualized revenue requirement for a 1,500 MW share of the SunZia project was considered as the avoided cost. Although the CAISO base method to calculate the BCRs of the candidate OOS projects is reasonable and intuitive, the alternative method does not seem to have a logical substantiation. The logic of providing avoided cost credit of half of the Sunzia capital cost to the candidate OOS transmission projects without netting its benefits is fundamentally flawed. After all, SunZia is not seeking any CAISO ratepayer recovery for any portion of its 3,000MW capacity. Therefore, it is inaccurate to attribute any portion of its cost avoidance to the remaining candidate OOs transmission projects. The CAISO’s alternative BCR calculations incorrectly overestimate the economic value of the candidate OOS projects, as shown in the last column of Table 4.10-4 in the Draft Plan, which is misleading. Therefore, BAMx urges the CAISO to exclude any discussion and BCR findings associated with alternative configuration assuming an added benefit of avoiding half of the cost of the SunZia project in the final transmission plan.

 

Economic Assessment

 

GLW/VEA Area Upgrades Project

BAMx appreciates CAISO’s detailed production cost modeling (PCM) simulation economic assessment results presented in this planning cycle, which demonstrated that the GLW Upgrade has a 1.81 benefit to cost ratio. However, this analysis was performed only for the baseline portfolios and not the sensitivity portfolios. An analysis based upon a single baseline scenario as modeled in the CAISO’s PCM is inconsistent with CAISO’s Transmission Economic Assessment Methodology (TEAM) principles to account for risk and uncertainty.[7] Therefore, the GLW Upgrade project should not be recommended for approval as an economic-driven project in this planning cycle.

 


[1] Draft Plan, p.7.

[2] See Southwestern Power Group and Pattern Energy Group Joint Reply Comments on Administrative Law Judge’s Ruling on Portfolios for the 2021-2022 Transmission Planning Process, November 20, 2020, p.1. Southwestern Power Group (SWPG) is developing SunZia Transmission Project, a 520-mile independent transmission project to deliver New Mexico wind to Pinal Central (Palo Verde area) to serve Arizona and California markets.

[3] Draft Plan, p.7.

[4] Draft Plan p. 306.

[5] Draft Plan p. 313-314.

[6] This represents a 1,500 MW share of the 3,000 MW, $2.6 billion SunZia project, or $1.3 billion capital cost.

[7] The CAISO TEAM 2017, available at

https://www.caiso.com/Documents/TransmissionEconomicAssessmentMethodology-Nov2_2017.pdf

6. Comment on chapter 5 Interregional Transmission Coordination:

No comments at this time.

7. Comment on chapter 6 Other Studies and Results:

No comments at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

No comments at this time.

9. Comment on chapter 8 Transmission Project List:

The Draft Plan does not include an estimate of future High Voltage Transmission Access Charge (HV TAC) rates at this time. We understand that the CAISO is currently in the process of updating the “starting point” for the HV TAC estimating tool to January 1, 2022.[1] Given the need for urgency to show the TAC impact of the projects the CAISO has recommended for approval as part of the current planning cycle, BAMx developed an HV TAC forecast for the period of 2023-2031 as shown in the figure below. In this analysis, BAMx used the last version of the CAISO’s TAC Estimating model developed for the 2020-2021 TPP, and updated the model to include the CAISO January 01, 2022, TAC Rates (updated as of February 8, 2022). The newly added capital expenditures associated with the transmission projects and their schedule was based on the transmission projects found to be needed in the 2021-2022 TPP as per the Draft Plan.[2] That is, those included in

  • Table 8.2-1: New Reliability Projects Found to be needed;
  • Table 8.2-2: New Policy-driven Transmission Projects Found to be needed; and
  • Table 8.2-3: New Economic-driven Transmission Projects Found to be needed

 

 

Transmission Capital Expenditures and HV TAC Projections: 2023-2031

image(27).png

As shown in the figure above, the HV TAC is expected to be more than $22/MWh in 2031 relative to the existing $16.60MWh, a 33% increase in less than a 10-year timeframe. Out of the $22/MWh HV TAC in 2031, more than $2/MWh is solely attributed to the nearly $3 billion transmission projects[3] the CAISO has recommended for approval in the current TPP cycle. These HV TAC projections show the tremendous impact these approvals will have on the ever-increasing CAISO-wide HV TAC and further justify the need to avoid approving excessive transmission projects without further review and analysis.

 


[1] Draft Plan, p.382.

[2] Draft Plan, pp.377-378.

[3] Compared to the average over the last five years of $217 million.

California Community Choice Association
Submitted 02/22/2022, 04:12 pm

Contact

Shawn-Dai Linderman (shawndai@cal-cca.org)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

The California Community Choice Association[1] (CalCCA) appreciates the California Independent System Operator’s (CAISO’s) work on the 2021-2022 Transmission Plan. In these comments, CalCCA makes the following recommendations for the CAISO to incorporate into the 2022-2023 Transmission Plan. 

Consideration of Long-Lead-Time Resources

It is critical the Transmission Planning Process (TPP) reflect current geographic and market information to allow for the development of significant amounts of cost-effective resources in line with the California Public Utilities Commission’s (CPUC’s) procurement requirements and to avoid stranded resource investments. CalCCA’s Reply Comments[2] to the CPUC’s Proposed Decision Adopting the 2021 Preferred System Plan[3] urged the CPUC to update the PSP Core Portfolio to reflect the availability and location of cost-effective resources (i.e., “long-lead-time resources” that can fulfill the CPUC’s Mid-term Reliability (MTR) requirements), including geothermal resources, in Nevada.

The 20-Year Outlook includes roughly 2 gigawatts (GW) of geothermal from IID, but only 320 megawatts (MW) of geothermal in southern Nevada. The busbar mapping in the PSP Decision[4] increases the amount of geothermal in southern Nevada to 440 MW.  At a minimum, the CAISO should reflect this increase in their 2022-2023 TPP and in the next iteration of the 20-Year Transmission Outlook.  However, given the timeframe of the 20-Year Transmission Outlook, the CAISO should include the full potential for growth in Nevada geothermal that far exceeds 440 MW. CalCCA requested the CPUC update the Preferred System Plan (PSP) to plan for at least 2,000 MW of further incremental renewable resources imported from Nevada. The CAISO should study the full 2,000 MW, requested by CalCCA in its comments to the PSP, in the 2022-2023 TPP cycle and the next iteration of the 20-year Transmission Outlook to allow the CAISO to evaluate necessary import expansion or transmission upgrades needed to deliver Nevada geothermal resources to California. 

Given the significant resource development opportunities out-of-state, the CAISO should also provide additional transparency on how transmission upgrades identified in the TPP will affect maximum import capability (MIC) needed for load-serving entities (LSEs) to show resources out of state as resource adequacy (RA). LSEs must secure MIC at the right nodes to be able to use out-of-state resources like Nevada geothermal to provide RA capacity. Understanding how the TPP and 20-year plan will affect import capability at specific nodes would significantly improve LSEs’ ability to make decisions around contracting and arranging transmission for potential projects to serve California load as RA. This transparency will minimize the risk of planned projects failing to materialize and minimize costs associated with the uncertainty around available MIC.

Policy-Driven Assessments in Local Areas

CalCCA appreciates the CAISO’s consideration of local area needs in its policy-driven assessments. CalCCA reiterates its position from previous comments that the CAISO should consider how to incorporate policy-driven assessments in local areas in the next TPP cycle. As the fleet of resources evolves, the potential for a local constraint to become binding will increase. A policy-driven assessment should be performed to identify transmission upgrades or alternatives that facilitate retirements for fossil fuel plants on a timeline that maintains reliability in local areas and makes progress on state environmental requirements including minimizing air emissions in disadvantaged communities.[5]

In the next TPP cycle, the CAISO should incorporate a policy-driven assessment into its evaluation of transmission upgrades or alternatives needed to address local needs. As the state works towards achieving a zero-carbon electric system by 2045, more renewable resources and storage will necessarily come online creating opportunities for existing fossil fuel plants to retire. However, if an existing fossil fuel plant is in a locally constrained area, the resource retirement will not occur until the transmission constraint is eliminated or enough carbon-free resources are built in the local area to fulfill the local need. This could result in delays in meeting environmental standards if transmission capacity or other alternatives are not built to address the local need. The CAISO should consider transmission upgrades and potential alternatives to alleviate local area transmission constraints that would allow fossil fuel plants to retire to meet the State’s green-house gas (GHG) mandate reliably.

 


[1]             California Community Choice Association represents the interests of 23 community choice electricity providers in California: Apple Valley Choice Energy, Central Coast Community Energy, Clean Energy Alliance, Clean Power Alliance, CleanPowerSF, Desert Community Energy, East Bay Community Energy, Lancaster Choice Energy, Marin Clean Energy, Orange County Power Authority, Peninsula Clean Energy, Pico Rivera Innovative Municipal Energy, Pioneer Community Energy, Pomona Choice Energy, Rancho Mirage Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power, San José Clean Energy, Santa Barbara Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power, and Valley Clean Energy.

[2]             California Community Choice Association Reply Comments on the Proposed Decision Adopting 2021 Preferred System Plan, Jan 19, 2022 (Rulemaking (R.) 20-05-003): https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M443/K010/443010067.PDF.  

[3]             Proposed Decision Adopting 2021 Preferred System Plan, Dec 22, 2021 (R.20-05-003): https://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=434547053.

[4]             Decision Adopting 2021 Preferred System Plan, Attachment A Modeling Assumptions 2022-2023 TPP, Feb. 10, 2022 (R.20-05-003) (PSP Decision): https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M451/K485/451485713.PDF

[5]             See Public Utilities Code § 454.52(a)(1)(h).

 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

CalCCA has no additional comments at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

CalCCA has no additional comments at this time.

4. Comment on chapter 3 Policy-Driven Need Assessment:

CalCCA has no additional comments at this time.

5. Comment on chapter 4 Economic Planning Study:

CalCCA has no additional comments at this time.

6. Comment on chapter 5 Interregional Transmission Coordination:

CalCCA has no additional comments at this time.

7. Comment on chapter 6 Other Studies and Results:

CalCCA has no additional comments at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

CalCCA has no additional comments at this time.

9. Comment on chapter 8 Transmission Project List:

CalCCA has no additional comments at this time.

California Energy Storage Alliance
Submitted 02/22/2022, 04:01 pm

Contact

Jin Noh (cesa_regulatory@storagealliance.org)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

CESA expresses our general support for the Draft 2021-2022 Transmission Plan, which found the need for 24 projects totaling $2.944 billion, including 16 reliability-driven projects ($1.412 billion), 7 policy-driven projects ($1.512 billion), and 1 economic-driven project ($20 million). Compared to recent past Transmission Planning Process (TPP) cycles, CESA finds this draft plan as a milestone for identifying and approving a range of policy-driven projects to support future generation resources as identified in the California Public Utilities Commission (CPUC) Integrated Resource Planning (IRP) process. In our recollection, there have been minimal or no policy-driven projects approved in some time, so CESA is encouraged to see the Draft 2021-2022 Transmission Plan begin to realize the transmission investments needed to better align procurement processes with transmission buildout and generator interconnections – issues that have been identified in the CAISO’s Interconnection Process Enhancements (IPE) Initiative and are being acted upon with the development of the Draft 20-Year Transmission Outlook.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

CESA has no comments at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

CESA has no comments at this time.

4. Comment on chapter 3 Policy-Driven Need Assessment:

CESA has no comments at this time.

5. Comment on chapter 4 Economic Planning Study:

CESA has no comments at this time.

6. Comment on chapter 5 Interregional Transmission Coordination:

CESA has no comments at this time.

7. Comment on chapter 6 Other Studies and Results:

CESA supports the continued focus on studying and forecasting frequency response performance as part of the annual transmission planning cycle. For the 2021-2022 TPP, the CAISO shared the first study of how battery energy storage systems (BESS) as an inverter-based resource (IBR) in aiding frequency response and generally concluded that BESS can meet the CAISO’s Frequency Response Obligation (FRO) in the study scenarios[1] Since most BESS have been procured and is or will be installed with frequency response capabilities pursuant to Order No. 842 and represent the greatest share of incremental capacity additions, the CAISO found that BESS with the appropriate control parameters can increase its MW to provide inertia response.

CESA is generally supportive of the study and the conclusions, which assessed situations where the CAISO grid will rely more heavily on IBRs and less on operational conventional gas units (i.e., spring off-peak case). However, as the CAISO explains, the study focused on BESS in charging mode when there is more headroom, whereas the next iteration of the study will need to look at IBRs in net discharging mode as well in assessing and forecasting frequency response performance.[2] CESA wholly agrees with continued study of frequency response performance in different situations, but we also request that, in the next planning cycle, the CAISO commit to considering non-BESS technologies (e.g., compressed air and liquid air energy storage) that have the capability of providing inertia with less or minimal headroom, thereby potentially better optimizing utilization of system resources. The headroom for IBRs, for example, may be less if a system resource portfolio with different characteristics is available. Furthermore, building on this study, CESA also recommends that the CAISO launch a new stakeholder initiative that explores and develops market products to procure these frequency response capabilities from IBRs in a market-efficient way, given that there are opportunity costs associated with the provision of frequency response and the potentially differential performance of various BESS, IBRs, and other generation/storage resources in providing these services.  

 


[1] Draft 2021-2022 Transmission Plan at 346 and 353.

[2] Ibid at 349-350.

8. Comment on chapter 7 Special Reliability Studies and Results:

CESA has no comments at this time.

9. Comment on chapter 8 Transmission Project List:

CESA has no comments at this time.

California Public Utilities Commission
Submitted 02/22/2022, 04:56 pm

Contact

Karolina Maslanka (karolina.maslanka@cpuc.ca.gov)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:
  1. CPUC staff appreciates the CAISO’s broad consideration of high-voltage direct current (HVDC) and other combinations of transmission technologies for resolving reliability issues. CPUC staff suggests the Transmission Plan recognize that the CPUC has ordered procurement of two storage projects that the CAISO has previously identified as alternatives to approved transmission projects. (See question #3)
  2. CPUC staff thanks the CAISO staff for their hard work and thoroughness in completing the draft policy-driven need assessment. Staff seeks additional information on the upgrades identified as needed in the base and sensitivity portfolios, including for offshore wind, to enable more effective incorporation into IRP’s planning and model work. (See question #4)
  3. CPUC staff sees both benefit cost ratio (BCR) metrics as useful for the purpose of comparing transmission projects, but requests the CAISO clarify how the two BCR metrics are intended to be used. Should one, the other, both or neither be used to economically justify the approval of transmission expansion? (See question #5)
  4. CPUC staff supports the CAISO’s proposed market test intended to gauge interest in Idaho wind resources. (See question #5)
  5. CPUC staff encourages the CAISO to continue to consider ways to improve the Interregional Coordination Process through federal efforts such as the Advanced Notice of Proposed Rulemaking, Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection and the upcoming NOPR. Additionally, we support the CAISO’s initiative to pursue other avenues to progress opportunities for delivering out-of-state resources to the CAISO load, such as the proposed Idaho wind market test. (See question #6)
2. Comment on chapter 1 Overview of the Transmission Planning Process:

No comment at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

CPUC staff commends the CAISO for its usual comprehensive analysis of reliability needs. For this TPP the CAISO has clearly strived to consider different technologies (including series compensation devices and HVDC lines) or innovative combinations of technologies, as potential mitigation to reliability issues. CPUC staff appreciates these efforts and recognizes the potential benefits to ratepayers in the CAISO’s consideration of a broad range of solutions.

CPUC staff suggests the Transmission Plan recognize that the CPUC has ordered procurement of two storage projects that the CAISO has previously identified as alternatives to approved transmission projects.

CPUC staff notes Section 2.5.8.3 mentions that the previously approved North of Mesa transmission upgrade remains on hold pending resolution of the CAISO’s recommendation of a 50 MW 4-hour storage facility at the Mesa 115 kV substation. CPUC staff notes that procurement of this storage facility as well as the project at the Kern-Lamont substation has been ordered (D.22-02-004) within the Commission’s Integrated Resource Panning rulemaking (R.20-05-003) via Commission vote on February 10, 2022. 

CPUC staff appreciates that the title for Section 2.3.4.2 has been upgraded to “IRP Portfolio Resources” to reflect the current CPUC process for planning the accelerated pace of renewable resource development within California.

4. Comment on chapter 3 Policy-Driven Need Assessment:

CPUC staff thanks the CAISO staff for their hard work and thoroughness in completing the draft policy-driven need assessment. Staff supports and appreciates the CAISO’s work in identifying transmission upgrades necessary to support the resources identified in the portfolios provided by the CPUC.[1] Staff also appreciates the CAISO’s effort to identify “low risk” upgrades such as the new Manning and Collinsville substations upgrades. These more expansive upgrades would not only address the exceedances identified in the base portfolio but will also enable significantly more renewables, beyond those mapped in the base case portfolio, to interconnect to the grid that long-term SB 100 and the 20-year transmission outlook efforts by the CPUC, CEC, and the CAISO have shown as needed. CPUC staff also notes that the upgrades identified in the policy-drive assessment align with areas of transmission constraint exceedances likely needing transmission upgrades that have been identified during the CPUC led busbar mapping process for the 38 MMT with 2020 IEPR high EV base case portfolio being transmitted for the 2022-23 TPP.

CPUC staff suggests the CAISO include more details regarding the benefits of the three proposed “low-risk” upgrades, if possible, including information regarding estimates on how much additional transmission these upgrades would provide for future renewables, the projects’ alignment with the CAISO’s 20-year study, whether the smaller upgrades not recommended will still be needed in the future, and how much deferring these alternative upgrades are saving ratepayers. Additionally, staff asks if the CAISO considered the transmission project development timelines when comparing the upgrade options and any potential impacts on the deliverability of new resources interconnecting pursuant to IRP procurement requirements?

Staff appreciates CAISO staff’s continued collaboration and seeks support in incorporating these study results, particularly the potential upgrades and their transmission capacity expansion abilities identified in the base portfolio and both sensitivities (the 38 MMT and the offshore wind portfolios), into ongoing and future IRP modeling and planning activities. In order to do so effectively, this information would ideally include construction timing and cost, and additional information on the projects identified such as the estimated amount they would expand transmission capacity and what areas/existing constraints are improved by the upgrades, if such information is known. Such information would enable CPUC staff to more readily incorporate these upgrades into IRP planning and modeling work.

CPUC staff especially appreciates the explanation of analysis on the transmission implications of large amounts of offshore wind resources in the central and north coast areas (Sensitivity 2). This initial CAISO study is a significant boost to the efforts of state agencies and stakeholders seeking to develop wind resources off the California coast. The CAISO’s consideration of various transmission technologies, deliverability and curtailment assessments and the advantages of various options for new transmission will certainly enhance future IRP analysis of offshore wind as well as the development of the state’s strategic plan for offshore wind as required under AB 525. 

CPUC staff is beginning to consider suitable procurement frameworks for offshore wind resources and we look forward to further coordination to analyze and plan the sequencing of transmission projects through application of a well-defined “least-regrets” approach.   

 


[1] See page 6 of The Draft 2021-22 Transmission Plan

5. Comment on chapter 4 Economic Planning Study:

CPUC staff sees both benefit cost ratio (BCR) metrics as useful for the purpose of comparing transmission projects, but requests the CAISO clarify how the two BCR metrics are intended to be used. Should one, the other, both or neither be used to economically justify the approval of transmission expansion?

CPUC staff recognizes the difficulty in capturing the costs and benefits of the various permutations on transmission development that currently exist for out-of-state (OOS) wind and are thankful for the CAISO’s efforts to incorporate these disparate costs and benefits. CPUC staff finds the “BCR considering avoided cost of Sunzia” to be a useful metric considering that costs of both TAC-recovered transmission projects and merchant transmission projects would ultimately flow through to ratepayers. We appreciate that the CAISO provided two BCR metrics to serve as bookends when comparing the OOS transmission projects.

However, our understanding is that because of the unique circumstances and challenges with studying and comparing the OOS transmission projects, neither the regular BCR nor the “BCR considering avoided cost of Sunzia” is intended to be used for project approval at this point in time. Therefore, we find the following statement confusing “Based on the benefit to cost ratio results in the Base portfolio out-of-state wind study, none of the transmission alternatives had sufficient economic justification.”[1]

Although both BCR metrics provide useful information, neither is appropriate for determining which of the OOS transmission projects should be approved solely on an economic basis. The standard BCR metric is comparing to a scenario that presumes that transmission to deliver New Mexico wind has been built and thus may not accurately capture the full benefits of any single project. On the contrary, the second BCR metric cannot be used for project approval because it would double count the same benefit across multiple projects. In other words, when accounting for the benefit of the $1.3 billion in capital costs that would be avoided by not having to deliver 1500 MW of New Mexico wind to Pinal Central via the SunZia line, the SWIP North project is economic under all three phase shifter settings, as is the Cross-Tie project. The TransWest Express project is economic under one of the phase shifter settings. However, we know that multiple projects could not avoid the same cost. If SWIP North were to be approved/developed and would remove the need for Sunzia, the next project would no longer be avoiding the need for Sunzia. For these reasons, we see both BCR metrics as useful for the purpose of comparing projects but seek that the CAISO clarify if they should be used for economic justification, and if so, how.

CPUC staff supports the CAISO’s proposed market test intended to gauge interest in Idaho wind resources.

The SWIP North project appears to be most economical when using the BCR considering the avoided cost of Sunzia. However, as the CAISO noted, there is less data available about market interest in Idaho wind as compared to Wyoming and New Mexico resources, both of which have already been assessed from a market interest perspective via open access solicitation processes. We are eager to learn more about how the CAISO plans to conduct this market test. For example, will it assess load serving entity (LSE) interest in contracting OOS wind resources or developer interest in selling them?

 

 


[1] See page 313

6. Comment on chapter 5 Interregional Transmission Coordination:

As expected, the Interregional Coordination Process was not a major part of the 2021-22 TPP cycle since no interregional transmission projects were recommended in the 2020-21 TPP cycle.  As we look ahead CPUC staff appreciates the CAISO’s leadership within this coordination process. We encourage the CAISO to continue to consider ways to improve the Interregional Coordination Process through federal efforts such as the Advanced Notice of Proposed Rulemaking, Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection and the upcoming NOPR. Additionally, we support the CAISO’s initiative to pursue other avenues to progress opportunities for delivering out-of-state resources to the CAISO load, such as the proposed Idaho wind market test.

7. Comment on chapter 6 Other Studies and Results:

  No comment at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

  No comment at this time.

9. Comment on chapter 8 Transmission Project List:

  No comment at this time.

California Public Utilities Commission - Public Advocates Office
Submitted 02/24/2022, 11:29 am

Contact

Kanya Dorland (kanya.dorland@cpuc.ca.gov)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

The following are comments from the Public Advocates Office at the California Public Utilities Commission (Cal Advocates) to the California Independent System Operator Corporation (CAISO).  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]    

Background

The Draft 2021 Transmission Plan (Draft Plan) uses the California Public Utilities Commission’s (CPUC) 2021 electric resource procurement portfolios.  These portfolios are intended to meet the state's renewable portfolio standard (RPS) target of 60% renewable resources portfolio and greenhouse gas (GHG) emission reduction target of 38 million metric ton (MMT) by 2031.[2],[3]

The CPUC provides the CAISO with a base resource portfolio and two resource sensitivity portfolios.  The CPUC’s 2021 base portfolio includes 27,695 megawatts (MWs) of renewable resources, which is nearly three times the quantity proposed in prior years (~10,387 MW).[4]  Subsequently, the Draft Plan recommends approval of $2.9 billion in new transmission investments, which is ten times higher than the average annual Transmission Planning Process (TPP) approval over the last five years.[5]

The resources of concern for ratepayers in the base and sensitivity portfolios are as follow:

  • Base portfolio includes 1,062 megawatts (MW) of out-of-state wind on new transmission.
  • Sensitivity 1 portfolio includes 1,500 MW of out-of-state wind on new transmission from Wyoming and New Mexico.
  • Sensitivity 2 portfolio includes 1,500 MW of out-of-state wind on new transmission from Wyoming and New Mexico, as well as 8,300 MW of offshore wind.[6]

These resources are of concern because significant transmission investments are required to access these resources and more information is needed on the proposed transmission investments to determine that they are reasonable.  These resources may also not be needed to meet the state’s 2031 resource portfolio target.[7]

Comments regarding transparency and stakeholder engagement

Cal Advocates recommends that the CAISO continue to improve the TPP, by increasing transparency and stakeholder participation.  The CAISO has publicly stated their commitment to the principle of full transparency.[8]   Cal Advocates, as a ratepayer advocate participating in the CAISO’s TPP, submitted comments during this 2021 TPP cycle regarding the proposed Draft Plan policy and reliability projects.[9],[10]  In previous TPP cycles, the CASIO responds to stakeholder comments prior to issuing the Draft Plan.  To date, the CAISO has not responded to comments on the proposed Draft Plan projects.  Thus, it is unclear whether the Draft Plan is informed by previous stakeholder comments. 

Also, the CAISO did not provide adequate time (two-weeks) for stakeholders to thoroughly review the 24 recommended projects, of which twelve were not discussed as recommended projects prior to the February 7, 2022, TPP stakeholder meeting.  In short, there is insufficient information to justify the $2.9 billion in transmission investments recommended in this TPP cycle.

Cal Advocates recommends that the CAISO record and post all TPP meetings in a publicly accessible location.  This is consistent with its practice for other CAISO stakeholder engagement initiatives and workshops.  TPP meetings serve as the only forum in which the CAISO provides important information to stakeholders.  Publicly posting the recordings of all TPP meetings would assist stakeholders who are unable to attend.

Essential Information Necessary for Recommended Transmission Projects

The CAISO Board of Governors should be provided sufficient basis upon which to approve a transmission project.  Therefore, Cal Advocates recommends the CAISO  provide the following essential information for recommended transmission projects:

  1. Detailed information regarding project alternatives.  Currently, the TPP process does not provide sufficient detail for project alternatives.  Cal Advocates recommends that the CAISO include a more substantive assessment (including costs) of grid enhancing technologies that could address the identified issues the proposed projects seek to address.  Cal Advocates also recommends that the incumbent utilities cost information for project alternatives be vetted by the CAISO or a third party hired by the CAISO to confirm the costs for project alternatives. 
  1. Detailed project cost information.  Typically, the TPP includes rough project costs or book-end project costs.   Cal Advocates recommends that the CAISO include a more substantial breakdown of the major project components’ and contingencies.  To illustrate, for the proposed Collinsville 500/230 kilovolt (kV) substation project only a total project cost ranging between $475 to $675 million was provided.  The proposed scope for this project includes a new substation looping in the Vaca Dixon – Tesla 500 kV line as well as two new 500/230 kV transformers with 1,500 mega volt-amp (MVA) ratings, and two new  230 kV cables between Collinsville and Pittsburg 230 kV substations.[11] Without this essential project information, the CAISO Board and stakeholders cannot confirm whether the proposed projects are justified based on their costs.

 


[1] Cal. Pub. Util. Code § 309.5.

[2] Senate Bill (SB) 100 (De Leon) Stats. 2018, Ch 312., revised the previous established goal of to achieve the 50 percent renewable resources target by December 31, 2030.

[3] SB 350 (De Leon ) Stats. 2015. Ch 547, the Clean Energy and Pollution Reduction Act, established greenhouse gas reductions goals including reducing GHG emission to 40 percent below 1990 levels by 2030 and to 80 percent below 1990 levels by 2050. California Air Resource Board, in coordination with the CPUC and CEC, as directed by S B 350 establishes the state’s GHG target that would meet or exceed the SB 350 target.

[4] 2021-2022 TPP Policy-driven Assessment, 2021-2022 Transmission Planning Process Stakeholder Meeting (Presentation), November 18, 2021, page 11.

[5] CAISO Draft 2021-2022 Transmission Plan, January 31, 2022 (Draft Plan), p. 5.

[6] CPUC Modeling Assumptions for the 2021-2022 Transmission Planning Process, February 9, 2021, p. 67.

[7] The California Load Serving Entities (LSE) did not select OOS wind on new transmission lines in their 10-year system portfolios submitted on September 1, 2020.  Instead, LSE selected wind resources from New Mexico and the Pacific Northwest on existing transmission. Administrative Law Judge’s Ruling Seeking Comments on Proposed Preferred System Plan, CPUC R.20-05-003, August 17, 2021, p. 48.

[8] California State Legislature, State Assemble Committee on Utilities and Energy, Mid-August Heat Storm Joint Preliminary Report by California Energy Commission, California Public Utilities Commission, California Independent System Operator, October 12, 2021. Statement from CEO Elliot Mainzer.

[9] Public Advocates Office’s Comments on the September 27-29, 2021, CAISO stakeholder meeting, October 12, 2021, pp-4-9.

[10] Public Advocates Office’s Comments on the November 18, 2021, CAISO Stakeholder Meeting, November 6, 2021, pp.4-6, and 11.

[11] Draft Plan, p. 193.

 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

Focus of the 2021 TPP process should be on projects that are needed by 2031.

It is premature for the CAISO to propose extensive system upgrades in the Draft Plan in response to untested, unvetted, and unapproved resource portfolios.[1]

Specifically, in the Draft Plan, the CAISO proposes additional reliability and policy projects to accommodate the Senate Bill (SB) 100 Starting Point scenario based on load forecast and resource portfolio assumptions from the CPUC and the California Energy Commission (CEC).  The SB 100 Starting Point scenario is intended to meet the state’s RPS policy directive of a 100% renewable portfolio by 2045.[2]

However, the CPUC and the CEC have not tested the SB 100 Starting Point scenario for reliability or fully vetted the scenario nor have they approved the Starting Point scenario.[3]  Moreover, the CAISO acknowledges that the SB 100 Starting Point scenario is intended as “informational only and should not be used, in itself, to support approval of near-term infrastructure investments.”[4]  Therefore it is premature to approve transmission projects to support the SB 100 Starting Point scenario within the 2021 Transmission Plan. 

Cal Advocates recommends that the CAISO limit its consideration to transmission needs that support the CPUC 2021 resource portfolio in its 2021 Transmission Plan.  To this end, Cal Advocates recommends that the CAISO exclude proposed projects that are not needed within the 10-year time frame and or are not the confirmed lowest cost solution.  The projects that should be excluded because they are not needed to meet the state’s 10-year policy target are the: (1) San Jose High Voltage Direct Current line projects, (2) Antelope 66 kV Short Circuit Duty Mitigation project, (3) Collinsville 500/230 kV substation project and (4) Manning 500/230 kV substation project.  These recommended projects to meet SB 100 goals have a combined cost of $2.3 billion.

[1] Draft Plan, p. 11.

[2] The state is required to study portfolios to achieve the State 100% clean energy goal by 2045.

[3] “this initial [Starting Point scenario ] portfolio is not an endorsement of any particular resource or potential transmission solution.” Draft 20-Year Transmission Plan, January 31, 2022, pp. 15-16.

[4] CAISO Draft 20-Year Transmission Outlook, January 31, 2022, p. 1.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

a. Cortina 230/115/60 kilovolt (kV) Transformer Bank No. 1 Replacement Project

The CAISO determined that potential overloads could occur in the Sacramento area at the Cortina substation by 2021.  To address these overloads, the CAISO recommends implementing an existing operating procedure to avoid the loss of Bank #4 at the Cortina substation.[1]  As noted in Pacific Gas and Electric Company’s (PG&E’s) presentation, with the implementation of this existing operating procedure, overloads would no longer be expected under a P3 contingency, and overloads would be dramatically reduced from 37.5% to 2.2% under a P1 contingency in 2023.[2] To address any remaining overload potential in the Cortina system area, the CAISO recommends upgrading the transformer Bank #1 for the long-term.[3]

In contrast, PG&E proposes a more expansive solution of replacing Bank #1 at the Cortina substation with two new transformer banks at a total project cost of $21 million to $42 million.[4]  Because implementing the existing operating procedure largely addresses the observed overload issues in the Cortina system area, PG&E’s more costly alternative is not justified. 

Cal Advocates recommended, in its October 12, 2021, comments, that PG&E evaluate upgrading Bank #1 as a long-term solution rather than replacing it.[5]  Cal Advocates also recommended that the CAISO exclude PG&E’s proposed solution for the Cortina substation.  Cal Advocates continues to recommend that the CAISO’s more cost effective solution be adopted rather than PG&E’s proposed Transformer Bank Replacement project.

        b.  Manteca-Ripon-Riverbank-Melones Area 115kV Line Reconductoring

The CAISO recommends potentially reconductoring a section of the Manteca – Ripon and Melones – Valley Home 115 kV line to address observed overloads starting in 2023 or an operating measure for the short-term.  PG&E proposed reconductoring 4.2 miles of the Manteca-Ripon 115 kV line with an estimated  project cost estimate ranging between $6.8 to $13.6 million.[6]

Recommendation: Cal Advocates requests additional evaluation of lower-cost alternatives for this project for the following reasons:

  1. PG&E’s power flow results presentation did not provide the impact on overloads in the area when utilizing its operating action plans.[7]  The CAISO’s Draft Plan states that the project area will rely on operating action plans in the interim.[8]
  2. The alternative analysis did not state whether grid enhancing technologies were considered to address the identified overload issues.
  3. PG&E’s presentation demonstrates that overloads are expected to increase significantly by 2026 in the Manteca Stanislaus project area but then decreased by 2031.  PG&E should be required to explain the reason for the forecasted decrease in overloads.[9]
  4. There is a larger line reconductoring project in the project area that includes a majority of the lines between the Manteca and Stanislaus substations. However, the CAISO did not provide analysis regarding whether this larger reconductoring project will significantly address the potential overload issues.[10]

c. Coppermine 70 kV Reinforcement Project

The CAISO determined that there are overloads and lower voltages occurring under normal system conditions on the Coppermine-Tivy Valley 70 kV line.  To address these issues, PG&E proposes a project, costing between $21.8 and $43.6 million, that could be in service by 2027.[11]  The project includes the following components: (1) reconductoring lines between Borden and Cassidy substations and the Cassidy and Coppermine substation (2) removing any limiting components and (3) installing a 20 MVAR voltage support.[12]  Unfortunately, PG&E provided no cost estimates for the project components described — only a total project cost.  Without additional detailed information regarding the project components and associated costs, it is unclear whether the project is justified, including whether the costs are reasonable.

Recommendation: Since there are reliability issues already occurring within the project area, Cal Advocates recommends that the CAISO provide additional information on solutions that could be implemented within an early timeframe.  PG&E recommends against using energy storage, which could likely be installed within an early timeframe,   because PG&E claims that installing energy storage would trigger a bus upgrade with an estimated cost between $35 million and $70 million.[13]  However, there is no confirmation that PG&E’s estimated integration costs are reasonable.  The CAISO stated at the November 18, 2021, TPP Policy and Economic stakeholder meeting that it does not perform a cost comparison between the estimates that PG&E provides for installing energy storage and for similar integration projects.[14]  Without verification of the project cost and cost of alternatives, it is not possible to determine if lower cost alternatives would be more cost effective than PG&E’s proposed line reinforcement project.

d. Weber-Mormon Jct Line Section Reconductoring Project

In response to the potential overloads at the Weber 60 kV substation by 2023 and in real-time operations, PG&E recommends a line reconductor project with a cost ranging from $9.3 million to $18.6 million.[15]  PG&E only assessed energy storage as an alternative to address the noted reliability issues and recommended against it because PG&E claimed the cost to integrate energy storage would be between $13 million to $26 million.[16]  

Recommendation:  Similar to our recommendation for the Coppermine 70 kV reinforcement project, Cal Advocates recommends that the CAISO provide more details on the upgrades needed and confirmation on the cost estimate to assist with determining whether energy storage is a feasible alternative solution.  Additionally, Cal Advocates recommends that CAISO consider other potential lower-cost grid enhancing technologies, such as Smart Wires, to address observed overload issues prior to recommending approval for PG&E’s recommended project.

e. San Jose Two High-Voltage Direct Current Line Projects

To address an anticipated load increase in the San Jose area within the next 10 years,[17] the CAISO recommends a new 230 kV or 500 kV source.[18]  The anticipated increase in load in the San Jose area is primarily due to extremely large-scale data centers expected in the Silicon Valley Power (SVP) service area.[19]  As illustrated in PG&E’s presentation, SVP’s load growth is expected to increase significantly between 2021 and 2026.  In response to this anticipated load growth, PG&E recommends building two new high-voltage direct current (HVDC) lines in the San Jose sub-area for an expected total cost ranging between $750 million and $1.125 billion.[20]

Recommendation: In our September 2021 TPP comments, Cal Advocates recommended that the CAISO instruct PG&E to evaluate and provide cost estimates for lower cost alternative projects to meet SVP load growth needs.[21]   

Cal Advocates continues to recommend that the CAISO consider lower cost alternatives.  These alternatives include:

  • Alternative 1: Install an energy storage facility with a capacity no greater than 375 MW (theoretical limit of energy storage capacity in the load area).[22]
  • Alternative 2: Install a 375-MW energy storage facility and a reactive support device, as well as reconductor the Los Esteros – Nortech – NRS 115 kV line.[23]

Regarding Alternative 2, the CAISO states in its Draft Plan that “adding about 2 ohms reactors on the Los Esteros-Nortech 115 kV line would be the optimal solution along with running the Silicon Valley Power (SVP) phase-shifter transformer at its limit and energy storage addition in the SVP system.”[24]  The CAISO estimates that this alternative project would cost between $10 and $15 million with an in-service date of 2023.[25]  The CAISO proposes this project for approval under the project name Series Compensation on Los Esteros-Nortech 115 kV line.  Cal Advocates supports further consideration of Alternatives 1 and 2.

Cal Advocates also questions the load growth assumptions for the proposed new data centers.  New data centers permitted before 2023 are required to comply with the 2019 Building Energy Efficiency Standard (BEES), which requires solar generation on site and energy efficient design to reduce load and manage load through demand response devices.  Data centers permitted after December 31, 2022, must comply with 2022 BEES, which requires solar generation and storage installations on new commercial buildings as well as more aggressive energy efficient design.  The new data centers in San Jose would be subject to BEES and also be subject to time-of-use rates to reduce their demand on the electric system during peak hours.  Thus, the anticipated load growth from the new data centers in the San Jose area could be much less than previously anticipated.  During the February 7, 2022, CAISO stakeholder meeting CAISO staff did not confirm whether the 2019 and 2022 BEES changes were considered in the forecast used for the current TPP cycle. 

In addition, California is served by only three HVDC transmission lines which include: (1) the 3,100 MW Pacific Intertie; (2) the 2,400 MW Intermountain Power Project (Path 27), and (3) the 400 MW Trans Bay Cable.  For this reason, Cal Advocates requests that the CAISO further evaluate the schedule and costs for the proposed HVDC lines.  Given the state’s limited experience with HVDC lines, choosing an HVDC alternative could result in cost over-runs and/or project delays.  For example, the Transbay Cable line’s original estimate of $200 million and later increased to $303 million.[26] Ultimately, the final project cost was $571.9 million, which exceeded the 50% project cost cap.[27]

Cal Advocates recommends that the CAISO consider the project cost estimates and likely project issues further prior to recommending the project for approval.

  1. Table Mountain 500/230 kV Transformer Bank #2 Project

PG&E provided a cost estimate ranging between $38.4 million and $76.8 million for a proposed second 500/230 kV transformer at the Table Mountain substation with an expected completion date of 2027.[28]  According to the CAISO a second transformer would address observed high voltage issues that occur when the existing Table Mountain transformer is taken out of service for maintenance (~ October/November time-frame).[29]  However, the CAISO did not explain why rescheduling the transformer maintenance outages to a lower demand timeframe is not an option.  The CAISO considered an alternative reactive support device to address the noted issues, but did not provide the cost for this option.[30]  

Recommendation: Cal Advocates recommends the CAISO provide cost information on the alternatives considered and further examine the transformer maintenance schedule to determine if maintenance can occur at a different timeframe to reduce impacts to the system.

  1. Antelope 66 kV Short Circuit Duty Mitigation Project

The CAISO proposes to upgrade the existing Antelope 66 kV switchrack to a 50 kiloampere (kA) short circuit duty rating for $55 million to accommodate the anticipated new renewable resources at the Antelope 230 kV substation.  Southern California Edison Company (SCE) did not present this project at the CAISO’s September 2021 TPP reliability assessment meetings, and instead presented the project in SCE’s filed comments on the September 2021 TPP reliability assessment meetings.[31]  In its comments, SCE described this project as a proactive investment to assist with meeting the state’s resource portfolio goals.  The CAISO 2021 Draft Plan explains that the base portfolio from the CPUC will trigger the need for circuit breaker replacements at the Antelope Substation.[32]  

This proposed project, however, is much more extensive than replacing circuit breakers, and neither the CAISO nor SCE provided justifications for the additional project components.  The project presentation was also unclear on whether the additional project components are necessary to support the CPUC 2031 base case resource portfolio or future resource portfolios. 

Recommendation: Cal Advocates recommends that the CAISO and SCE provide sufficient justifications for all project components and a complete analysis that compares the Antelope 66 kV switchrack project with the 41 circuit breakers replacement alternative.  Also, the CAISO should study the impact of the 2021 CPUC base case resource portfolio on the Antelope 66 kV switchrack.

The other components of this project that were not sufficiently explained are:

  • Replacing 101 of the installed 66 kV ground disconnect switches;
  • Replacing 45 of the installed 66 kV potential transformers;
  • Performing a ground grid study;
  • Removing 15 steel lattice structures; and
  • Installing 15 new dead-end structures.[33]

 


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

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

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

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

[5] Public Advocates Office Comments on September 27-28 Stakeholder Call Discussion 2021-2022 Transmission Planning Process, October 12, 2021, p. 5.

[6]PG&E’s 2021 Request Window Proposals CAISO 2021-2022 Transmission Planning Process, September 28, 2021, slide 14.

[7] PG&E’s 2021 Request Window Proposals CAISO 2021-2022 Transmission Planning Process, September 28, 2021, slide 11.

[8] Draft Plan, p. 96.

[9] PG&E’s 2021 Request Window Proposal, CAISO 2021-2022 Transmission Planning Process, September 28, 2021, (Presentation), PG&E, September 28, 2021, slide 9.

[10] PG&E’s 2021 Request Window Proposal, CAISO 2021-2022 Transmission Planning Process, September 28, 2021, (Presentation), PG&E, September 28, 2021, slide 9.

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

[12] CAISO Draft 2021-2022 Transmission Plan, p. 110

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

[14] California ISO (CAISO) 2021-2022 Transmission Planning Process Meeting CAISO Preliminary Results Policy and Economic Assessment, November 18, 2021, Customized Energy Solutions, November 22,2021, p. 12.

[15] Draft Plan, p. 95-96.

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

[17] 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.

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

[19] Silicon Valley Power CEO’s Letter to the CAISO Board of Governors, March 22, 2021, pp. 1-2..

[20] Draft Plan, p. 377.

[21] Public Advocates Office comments on September 27-28 Stakeholder Call Discussion 2021-2022, Transmission Planning Process, October 12, 2021, p. 6.

[22] CAISO Reliability Assessment Recommendations – PG&E Area Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting (Presentation), February 7, 2022, slide 5.

[23] Public Advocates Office comments on September 27-28 Stakeholder Call Discussion 202102022Transmission Planning Process, October 12, 2021, p.6.

[24].Draft Plan, p. 105.

[25] Draft Plan, p. 105.

[26] 2005 Transmissional Letter, Transbay Cable LLC, FERC Docket No. ER05-985-000, May 19, 2005, p. 5.

[27] An Introduction to Trans Bay Cable, (Presentation), February 2011, SteelRiver Infrastructure Partners, slide 13.

[28] Draft Plan, p. 123.

[29] Draft Plan, p. 124. 

[30] CAISO Reliability Assessment Recommendations – PG&E Area Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting, February 7, 2022 (Presentation), CAISO, February 7, 2022, slide 7.

[31] Southern California Edison’s Comments on the September 27-28 Stakeholder Call Discussion 2021-2022 Transmission Planning Process, October 12, 2021, p. 3.

[32] Draft Plan, p.135.

[33] Draft Plan, p. 135.

4. Comment on chapter 3 Policy-Driven Need Assessment:

Cal Advocates recommends the CAISO conduct its Transmission Economic Assessment Methodology (TEAM) on the proposed policy projects and consider all three of the 2021 CPUC resource portfolios in its analysis.  Based on the information provided in the CAISO’s TPP, Cal Advocates provides the following recommendations regarding the proposed policy projects.  

  1.   Delevan Cortina 230 kV Line Reconductoring Project

The CAISO recommends reconductoring the Delevan Cortina 230 kV line to address possible overloads on the line with the 2021 CPUC resource portfolios under the highest system need scenario.[1]  These portfolios would add 437 MW of new resources to the area and result in 479 to 713 MW of undeliverable baseline resources.[2]

Recommendation: Cal Advocates recommends that the CAISO consider other grid enhancing technologies, such as energy storage, series reactors, or Smart Wires rather than the proposed reconductoring project which has an estimated cost between $17.7 million and $35.4 million.[3]  The provided alternative analysis is insufficient, stating only that a remedial action scheme was considered.  Cal Advocates requests that the CAISO and PG&E consider grid enhancing technology alternatives to be further explored prior to recommending this project for approval.

  1. Rio Oso-SPI Jct-Lincoln 115 kV line Reconductoring Project

The CAISO recommends reconductoring the Rio Oso-SPI Jct-Lincoln 115 kV line to address possible undeliverable resource capacity ranging between 368 to 615 MW on the line with the 2021 CPUC resource portfolios.  These portfolios would add 152 MW of new wind to the project area.[4]  The CAISO only considered a remedial action scheme as a project alternative.[5]

Recommendation: Cal Advocates recommends that the CAISO and PG&E further examine addressing the identified overload issues with energy storage or other grid enhancing technologies that would likely be considerably less expensive than the proposed line reconductoring project which has an estimated cost range between $10.6 million and $21.2 million.[6]  

  1. Collinsville 500/230 kV Substation Project

During the November 2021 CAISO TPP stakeholder meeting, the CAISO noted that overloads could occur with 2021 CPUC resource portfolios on the 230 kV corridor between Contra Coast and Newark.[7]  To address these issues and reduce reliance on gas generation in the Greater Bay Area, the CAISO proposes adding a new Collinsville 500/230 kV substation, loop in the Vaca Dixon – Tesla 500 kV line and 230 kV connecting lines to allow additional supply from the 500 kV system such as offshore wind from Humboldt Bay to the Greater Bay Area.[8]

Approval of this project at this time is premature because it would accommodate a resource identified in the unvetted SB 100 Scenario rather than the required 2021 CPUC resource portfolios.  Also, the CAISO’s analysis regarding options to integrate Humboldt Bay offshore wind favor an alternative integration point other than the proposed new Collinsville substation.  At the November 2021 TPP stakeholder meeting, the CAISO presented three options for integrating Humboldt offshore wind, which included an option at the Fern Road substation that is expected to be in service by June 2024 and at the new proposed Collinsville substation.  Both options require upgrades to transmission lines to bring Humboldt wind to load centers and address congestion.  The Fern Road substation option had the least impact on Humboldt wind curtailment among the options considered.  Thus, Cal Advocates recommends the CAISO conduct further analysis and allow for more stakeholder discussion on the Fern Road substation option to confirm whether it is the most reasonable and cost effective option for integrating offshore wind at Humboldt Bay.

Also, the amount of offshore wind considered in the CPUC resource portfolios has changed.  As mentioned above, the 2021 CPUC sensitivity 2 resource portfolio included 8,351 MW of offshore wind by 2031.[9] Whereas, the 2022 CPUC resource portfolio only includes 1,708 MW of offshore wind to meet the state’s 2031 resource targets.  Specifically, the 2022 CPUC resource portfolio for study in the CAISO 2022 TPP cycle considers only 1,588 MW of offshore wind at Morro Bay and 120 MW of energy only offshore wind at Humboldt Bay by 2032.[10] 

Recommendation:

To address the reliability issues noted on the 230 kV corridor between Contra Costa and Newark, Cal Advocates suggests the CAISO consider lower cost alternatives.  The anticipated amount of new renewable portfolio MW generation on the 230 kV Corridor is 102 MW of wind and the undeliverable generation along sections of the 230 kV corridor ranges between 201 MW and 642 MW for the 2021 CPUC resource portfolios.[11]  The higher quantity of undeliverable generation is due only to the 8,300 MW of offshore wind considered in the 2021 CPUC sensitivity 2 resource portfolio.   

Given the quantity of undeliverable existing resources and the changing CPUC resource portfolio, the proposed HVDC line project is not justified, at this time.  Cal Advocates recommends that the CAISO and PG&E consider grid-enhancing technologies to address reliability issues and impact of any gas retirements in the area.

If lower-cost grid enhancing technologies are found not cost-effective, Cal Advocates recommends consideration of the proposed three line reconductoring projects at the Cayetano-North Dublin 230 kV line, Lone Tree-USWP-JRW Cayetano 230 kV line, and the Las Positas-Newark 230 kV line with the caveat that the CAISO delay approval of these projects until the transmission needs for the 2022 CPUC resource portfolio are confirmed.  For reference, these alternative line reconductoring projects have an estimated total cost that is less than half the price of the proposed Collinsville project with a total estimated cost ranging between $145 and $189 million.[12] 

  1. Manning 500/230 kV Substation Project

The CAISO proposes a new 500/230 kV substation with an estimated cost ranging between $325 million and $485 million to access Westland’s renewable generation.[13]  The CAISO also identifies the new Manning 500 kV substation as a mitigation for potential overloads on the Borden Storey #2 230 kV Line based on the 2021 CPUC resource portfolios.  The estimated quantity of undeliverable resources is between 44 and 181 MW on the Borden Storey 230 kV line.[14]  To address these overloads, the CAISO previously considered a line reconductoring project at Borden Storey #2 with a cost ranging from $24.24 to $31.5 million.[15]  

For reference, of the 733 MW of solar resources proposed for integration in the area, between 552-659 MW would be deliverable without any transmission investments.[16]  The only mitigation considered for the estimated overloads in the project area is a remedial action scheme.  No other potentially lower-cost grid enhancing technologies were considered as project alternatives. 

Recommendation: Because the proposed project has an extremely high cost ranging from $325 to $485 million and there is a relatively small number of resources that would be undeliverable without it, Cal Advocates recommends that this project be deferred and studied in the next TPP cycle.  The CAISO has not demonstrated that this project is needed to serve the 10-year transmission needs or provided an adequate alternative analysis that considers lower-cost grid enhancing technologies.  If the CAISO demonstrates that the lower-cost grid enhancing technologies are not cost-effective, Cal Advocates supports further consideration of the alternative Borden-Storey line reconductoring project in the CAISO 2022 TPP cycle as this alternative project has an estimated cost that is less than one-tenth the proposed project cost.

  1. Laguna Bell-Mesa No. 1 230 kV Line Rating Increase Project

The CAISO recommends reconductoring five miles of the Laguna Bell Mesa No.1 230 kV line to address possible overloads with the 2021 CPUC resource portfolios.  The CAISO also estimates that up to 3,000 MW of new capacity would be undeliverable due to overloads on the Mesa-Laguna Bell No.1 230 kV line. 

Recommendation: Cal Advocates recommends consideration of the Smart Wires’ Laguna Bell – Mesa Series Compensation project estimated at $6.7-$8 million[17] as a possible mitigation rather than the proposed line reconductoring project, which has a cost estimate of $17.3 million.  Cal Advocates also recommended this in our comments on the November TPP presentations and stakeholder meeting.[18]  Because the amount of resources to be integrated in the area is 500 MW of energy storage,[19] Cal Advocates also requests that the CAISO provide information on the gas generation in the project area and its retirement date, if known.

  1. Gridliance West Area Upgrades

Cal Advocates opposes the CAISO’s approval of this project in the 2021 Transmission Plan.  The CAISO found that the proposed Gridliance West (GLW) upgrades are only necessary in the 2021 CPUC base resource portfolio, and not the CPUC sensitivity 1 and 2 resource portfolios.[20]  Section 24.4.6.6 of CAISO’s Comprehensive Transmission Planning Process Tariff states that “[t]ransmission solutions that are included in the baseline scenario, but which are not included in any of the stress scenarios or are included in an insignificant percentage of the stress scenarios, generally will be Category 2 transmission solutions.”[21] Therefore, the proposed GLW Area upgrades are a Category 2 project.  Additionally, the CAISO did not provide an in-service date for this project as the Eldorado Substation requires some short-circuit duty mitigation before the GLW Area upgrades can be put in-service.[22]  Thus, it is unclear when ratepayers would begin to benefit from this project.  Proposed projects should have a reasonable in-service date within the 10-year time frame for the given TPP cycle.

Recommendation: Cal Advocates opposes approval of GLW project in the 2021 Transmission Plan and recommends the CAISO further study this project as Category 2 project in the 2022 TPP cycle.

 


[1] CAISO 2021-2022 TPP Policy-Driven Assessment, 2021-2022 Transmission Planning Process Stakeholder Meeting November 18, 2021 (Presentation), November 18, 2021, Slide 54.

[2] Draft Plan, p. 191.

[3] CAISO Policy Assessment Recommendations – PG&E Area Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting February 7, 2021 (Presentation), Slide 3.

[4]  Draft Plan, p. 197.

[5] ibid.

[6] ibid

[7] CAISO Policy Assessment Recommendations – PG&E Area Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting February 7, 2021 (Presentation), Slide 5.

[8] CAISO Policy Assessment Recommendations - PG&E Area Draft 2021-2022 Transmission Plan, 2021-2022 Transmission Planning Process Stakeholder Meeting February 7, 2021 (Presentation), Slide 5.

[9] CPUC Modeling Assumptions for the 2021-2022 Transmission Planning Process, February 9, 2021, p. 18.

[10] CPUC Modeling Assumptions for the 2022-2023 Transmission Planning Process, CPUC Staff Report, February 15, 2022, pp. 61 and 63.

[11] Draft Plan, pp. 192-196.

[12] Draft Plan, pp. 192-196.

[13] Draft Plan, p. 6.

[14] Draft Plan, p. 198.

[15] Draft Plan, p. 198.

[16] Draft Plan, p. 198.

[17] CAISO 2021-2022 TPP Policy-Driven Assessment, November 18, 2021, p. 88.

[18] Public Advocates Office’s Comments on November 18, 2021, stakeholder meeting 2021-2022 Transmission Planning Process, p.3.

[19] Draft Plan, p. 179.

[20] Draft Plan, p. 248.

[21] California Independent System Operator Corporation, Fifth Replacement FERC Electric Tariff, Section 24, 24.4.6.6.

[22] Draft Plan, p. 214.

5. Comment on chapter 4 Economic Planning Study:

General comment regarding all economic evaluated projects (screening factor)

The CAISO uses the phrase “Applying the CAISO’s screening factor of 1.3 to convert the capital cost of a project to the present value of the annualized revenue requirement, referred to as the “total” cost.”[1]  The CAISO should explain how the screening factor of 1.3 converts the capital cost of a project to the present value of the annualized revenue requirement to arrive at the “total cost.”  Typically, for transmission projects submitted to the CPUC for a Certificate of Public Convenience and Necessity (CPCN), 50 years of total cost is greater than a factor of 1.3 when including projected 50 years of operation and maintenance costs plus original capital costs.  The capital cost to revenue requirement multiplier of 1.3 is inconsistent with the CAISO’s own assumptions and may underestimate the cost of new transmission facilities.

Section 4.3.1 of the Draft Plan describes how the CAISO coverts the capital cost of a facility to the present value of the revenue requirement that the transmission owner will collect from ratepayers associated with that facility using a ratio of 1.3.  The resulting figure constitutes the “total cost” of a project in the CAISO’s cost-benefit analysis.[2]  However, the CAISO’s reliance on a ratio of 1.3 is contradicted by the CAISO’s own publicly available TAC Forecast Model.[3]  While the TAC Forecast Model uses the same financial assumptions (cost of debt and equity, tax rates, etc.), the ratio is higher than the capital cost to revenue requirement multiplier.[4]  

To illustrate, if a hypothetical new project is entered into the model with a capital cost of $200 million, an in-service date of 2023, and an assumed 50-year economic life,[5] the net present value of the annualized revenue requirement – assuming the CAISO’s 7% discount rate – is $304 million. This is greater than 1.5 times the capital cost, and this ratio holds for multiple capital cost assumptions.

Recommendation:  Given that this ratio underpins the CAISO’s cost-benefit analyses, CAISO staff should, in a revised draft, address this discrepancy and justify the 1.3 ratio using historical data that compares annualized revenue requirements of transmission facilities with its CPUC-approved capital costs.

Section 4.8 Economic Planning Study Requests:

      a. GridLiance West/VEA Congestion and Mitigations Proposed Projects

The CAISO uses TEAM to quantify the economic benefits of a proposed transmission project.[6]  According to its tariff, the CAISO must consider the degree to which, if any, the benefits of the transmission solutions outweigh the costs.  If a transmission solution generates a benefit-cost-ratio greater than 1.0, the CAISO finds that its benefits outweigh its costs.

The CAISO’s TEAM framework for economic assessments requires an analysis of the effects of uncertainty on the Proposed Project’s expected economic benefits.  This requirement recognizes that a project’s benefits may change in the future based on certain factors, including load, natural gas prices, new power plants, retired power plants, plant locations, and the future growth of the electrical network.  The CAISO conducted only one uncertainty analysis that used the CPUC’s 2021 base resource portfolio for its economic project studies.[7] Cal Advocates recommends that the CAISO perform its TEAM analysis using all the CPUC provided resource portfolios for study in the 2021-2022 TPP cycle.

  1. PG&E Moss Landing – Las Aquilas 230 kV Series Reactor Proposed Project

This project is proposed to address congestion on the Moss Landing -  Las Aguilas 230 kV line.  In this TPP cycle, the CAISO observed congestion “mainly under emergency conditions with P1 or P7 contingencies.”[8]  The only exception is that the Moss Landing – Las Aguilas 230 kV line also was congested under normal conditions for 26 hours over the course of a year.[9] 

Recommendation:  To demonstrate the need for this project, Cal Advocates recommends the CAISO provide the following basic project information:

  • Information on the total number of hours annually that the Moss Landing – Las Aguilas 230 kV line experiences an N-1 condition. 
  • Confirmation that a Benefit-to-Cost evaluation was performed for the Moss Landing – Las Aguilas 230 kV line under normal conditions (i.e., not during N-1 conditions).
  • Details on the sensitivity case studies performed on this project to comply with the CAISO TEAM as mentioned in the background section.  Cal Advocates recommends that the CAISO perform the analysis for Moss Landing – Las Aguilas 230 kV line experiencing an N-1 condition using the CPUC Sensitivity Case 1 and provide the Benefit-Cost Ratio.
  • Cal Advocates recommends that the CAISO request proposals for solutions to address congestion resulting from the overload of the Moss Landing – Las Aguilas 230 kV line to be technology neutral.  The proposed solution for the Moss Landing – Las Aguilas 230 kV line experiencing an N-1 condition is an evaluation of potential benefits due to addition of a “series reactor.”  This proposal appears to be a technology prescriptive solution.  A solicitation using the term “series compensation,” which may include both active and passive solutions, should be proposed.  Cal Advocates recommends that the CAISO solicit a technology neutral request for proposals for competitive bids from suppliers and that the proposals should be evaluated on the ability to reduce the greatest amount of congestion with the lowest cost solution under normal conditions and under an N-1 contingency.
  • The grid issues on the Moss Landing 230 kV line should also be reassessed with the current energy storage capacity expected in the Moss Landing area.  During the discussion of this project at the February 7, 2021, TPP Meeting, the CAISO acknowledged that it had not evaluated the Vistra Energy Moss Landing energy storage expansion project announced in January 2022.[10]  The original energy project at Moss Landing is complete and is a 400 MW facility.  Vistra Energy recently signed a resource adequacy agreement with PG&E to expand its existing Moss Landing energy storage facility to 1,500 MW by 2026. 
  1. GridLiance West/VEA Congestion and Mitigations Proposed Projects

For the GLW/VEA project, the CAISO claims to be following TEAM, yet the CAISO economic analysis was not performed for either of the two policy-driven sensitivity portfolios provided by the CPUC for study purposes.  This extremely limited evaluation differs significantly from the multiple scenarios the CAISO is required to perform for sensitivity analysis under TEAM.  The CAISO has neglected its own process rules to study a broad range of sensitivities.

Recommendation:  Cal Advocates opposes approval of the GLW VEA project as a reliability, policy, or economic project in the 2021 Transmission Plan.  The CAISO did not sufficiently demonstrate that the GridLiance West/VEA project is cost effective.  The CAISO only considered the base case scenario in its TEAM analysis.  For studies on this project, Cal Advocates recommends that the CAISO perform the sensitivity case studies that satisfy the TEAM requirements and provide details and results on a range of sensitivity case studies as required under TEAM and provide the benefit to cost ratios.

  1. Rerating Midway-Whirlwind and Bypassing Series Capacitor Project

The CAISO states it is following TEAM for its project evaluations. [11] However, TEAM requires a range of sensitivities to be performed.[12]  Cal Advocates notes that the analysis for this project did not evaluate the impact with the CPUC sensitivity 1 and 2 portfolios.

Recommendation:  To meet the TEAM requirements, Cal Advocates recommends the CAISO perform its TEAM analysis for Rerating Midway-Whirlwind and Bypassing Series Capacitor considering all the submitted CPUC resource portfolios and provide benefit to cost ratios.
      e. Southwest Intertie Project-North Project

The Southwest Intertie Project-North (SWIP-North) project is a proposed 500 kV transmission line from the Midpoint substation in Idaho to the Robinson substation in Nevada.  The proposed project could provide approximately 1,000 MW of bi-directional transmission capacity between Midpoint and Harry Allen and assist with providing transmission access to Idaho wind from the California border.  This proposed project has an estimated cost of $636 million in 2020 dollars,[13] and was studied as a transmission upgrade alternative in the out of state wind study discussed in section 4.10 instead of as an economic project.
 

Out of State Wind Production Cost Modeling

Based on the CAISO’s analysis, “all transmission alternatives studied had a benefit to cost ratio less than 1.0” thus “there was not sufficient economic justification” to approve the SWIP-North, Cross-Tie or TransWest Express projects in this TPP cycle.[14]  

In its analysis, the CAISO used the New Mexico out of state (OOS) transmission project as the reference against which the other alternatives were compared.  The analysis also compared the costs and benefits of the Cross-Tie, SWIP-North, and TransWest projects to determine if they avoided the costs of the Sunzia project.  However, this analysis did not consider the benefits of receiving 1,500 MW of New Mexico wind via the Sunzia project in the cost to benefit analysis. 

Recommendation:  For future out of state transmission studies, Cal Advocates recommends that the CAISO consider the avoided costs and benefits of the New Mexico transmission projects.  As mentioned, the CAISO calculated the benefit of the studied projects based on avoiding half the cost of the Sunzia project.[15]  This approach does not consider the benefits from the New Mexico wind project and the different cost recovery mechanisms proposed for the studied projects.

The Sunzia transmission project is one of the transmission lines that would provide California access to New Mexico wind.  Sunzia has 3,000 MW of transmission capacity, and half of this capacity is currently being offered on a subscriber basis.  California load serving entities (LSEs) can purchase wind power now from New Mexico through Power Purchase Agreements (PPA) with the Sunzia project developer, which is Pattern Energy.  These PPAs include transmission rights on existing transmission lines and the new Sunzia transmission line from Pattern Energy’s wind farms in New Mexico to the California border, as well as wind energy. 

SWIP-North Special Study in the 2021 Transmission Planning Process

The CAISO received an economic study request regarding the SWIP North project. The CAISO indicates it intends to engage further with industry participants to gauge interest in accessing Idaho resources under alternative cost recover approaches.  The CAISO intends to consider the additional process as an extension of the 2021-2022 transmission planning cycle, rather than shifting it to the next 2022-2023 planning cycle.[16]

Recommendation: The CAISO should study SWIP-North during the 2022 TPP planning cycle.  The CAISO’s recommendation to continue analyzing SWIP-North as an “extension of the existing 2021 transmission planning cycle,”[17] risks subverting standard stakeholder engagement, which would violate the CAISO’s Tariff and Business Practices Manual (BPM).  In the event the special study of SWIP-North continues, Cal Advocates recommends that the CAISO initiate a transparent process to revise its TEAM methodology to address this issue. 

Analyses of subscriber-based facilities should include specific knowledge of the facility’s off-takers.

The CAISO’s TEAM documentation specifies “what should be included in the benefit and cost calculation depends on who ultimately funds the project and who benefits from the project.”[18]  Identifying beneficiaries is a key first step in the CAISO’s TEAM analysis[19] and, as such, any analysis of a merchant project should start with knowledge of the subscribers to a transmission facility. 

This issue highlights the inadequacies in the Draft Plan’s approach to comparing rate-based and subscriber-based projects.  In Section 4.10.5, the CAISO assesses interregional lines relative to the avoided cost of the merchant SunZia line.[20]  The CAISO assumes a 1,500 MW share of the 3,000 MW line, but this assumption is erroneous without confirmation that CAISO ratepayers would truly benefit from that 1,500 MW share. The CAISO’s commitment to “gaug[ing] interest in accessing Idaho resources”[21] should  be clarified to identify SWIP-North’s confirmed off-takers.

Limitations in assessing subscriber-based transmission costs

During the February 7, 2022, call on the Draft Plan, the CAISO discussed the difficulties of assessing the full cost to ratepayers of subscriber-based facilities.  While the CAISO has the jurisdiction and the capability to assess the cost of TAC-based facilities, determination of the final costs of subscriber-based facilities may be beyond the scope of the TPP.  For example. the cost of subscriber-based transmission can be built into the cost of accessing a particular generation source.[22]

An LSE that procures subscriber-based generation is weighing it against other available sources, which can apply market pressure on  the transmission provider.  If that LSE is deemed to have overpaid for that generation/transmission package, it is accountable to its Board and constituents (if it is a public utility or a CCA) or its Board and regulator (if it is an investor-owned utility).

The CAISO is well-equipped to calculate the cost of TAC-based transmission and the value of the congestion revenue rights allocated to merchant projects.[23]  However, it should recognize the extent to which the total financial impact associated with subscriber-based projects may fall outside of the scope of the CAISO’s TPP.

Sources and detailed modeling assumptions for SWIP-North are necessary

In its comments on the November 18, 2021, TPP Presentation, LS Power states that SWIP-North and Idaho wind provide $121M in annual benefits.[24]  LS Power presented similar figures in the CPUC’s Integrated Resource Plan proceeding,[25] but in neither case did LS Power provide detailed modeling assumptions or verifiable sources to support these estimates. 

Recommendation: The CAISO should require LS Power to corroborate these figures with 1) the modeling assumptions used to produce them and 2) verifiable sources supporting those assumptions. 

 


[1] Draft Plan., p. 261.

[2] Ibid.

[3] Available at http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=7A2CFF1E-E340-4D46-8F39-33398E100AE7.

[4] These assumptions are listed in Table 4.3-1 of the Draft Plan.

[5] This is the economic life used by the CAISO in the Draft Plan, see Section, 4.3.2.

[6] The CAISO Transmission Economic Assessment Methodology (TEAM), Nov 2, 2017. p. 1 and 7.

[7] CPUC Decision 21-02-008, Ordering Paragraph No., p. 41.

[8] Draft Plan, p. 295.

[9] Draft Plan, p. 295.

[10] California ISO 2021-2022 Transmission Planning Process – Draft Plan and Draft 20-Year Transmission Outlook Meeting, Customized Energy Solutions, February 9, 2022, p. 14.

[11] The CAISO Transmission Economic Assessment Methodology, November 2, 2017. p. 1.

[12] The CAISO Transmission Economic Assessment Methodology, November 2, 2017  p. 26.

[13] Draft Plan, p. 306.

[14] Draft Plan, p. 329.

[15] Draft Plan, p. 314.

[16] Draft Plan, p. 329.

[17] Draft Plan, p.330.

[18] Transmission Economic Assessment Methodology. CAISO. November 2, 2017 . Section 2.4.1. P. 21. Available at https://www.caiso.com/Documents/DraftTransmissionEconomicAssessmentMethodology.pdf.)

[19] “We believe the key elements of any economically driven transmission investment decision are identifying potential beneficiaries of investments...” (Transmission Economic Assessment Methodology. CAISO, November 2, 2017. Section 2.2.1. P.14. Available at https://www.caiso.com/Documents/DraftTransmissionEconomicAssessmentMethodology.pdf.)

of the investment

[20] Draft Plan., p. 314.

[21] Draft Plan, p. 329.

[22] See the Western Spirit wind projects in New Mexico, more information available at https://patternenergy.com/news/news/pattern-begins-construction-1050-mw-wind-capacity-new-mexico.

[23]“The merchant is eligible to receive an allocation of 30-year option CRRs (Merchant CRRs) in a quantity that reflects the incremental capacity the merchant project adds to the CAISO grid.” (Fink et al. A Survey of Transmission Cost Allocation Methodologies for Regional Transmission Organizations. The National Renewable Energy Lab. P. 14. Available at https://www.nrel.gov/docs/fy11osti/49880.pdf.)

[24] LS Power’s Comments on November 18, 2021, Stakeholder meeting, 2021-2022 Transmission Planning Process, December 6, 2021, p. 3. are available at https://stakeholdercenter.caiso.com/Comments/AllComments/97a24911-d1e6-4d36-8cfe-a29d9de4e50b#org-1e320a80-f8fd-477e-897a-5a2d280001be.

[25] “SWIP-North and Idaho wind yields an annual benefit of $121 Million compared to a portfolio with no additional OOS wind, providing net economic benefits to California ratepayers…” (Reply Comments of LS Power Development, LLC on the Proposed Decision Adopting the 2021 Preferred System Plan. R.20-05-003. January 19, 2022. P. 3. Available at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M442/K975/442975840.PDF.)

6. Comment on chapter 5 Interregional Transmission Coordination:

Cal Advocates has no comment on this topic at this time.

7. Comment on chapter 6 Other Studies and Results:

PG&E Area Wildfire Assessment

In the update to the 2020 PG&E Area Wildfire Impact Assessment, the CAISO states that its goal is to model “the potential range of load impacts if different combinations of transmission lines within fire threat zones are included in the scope of [a] PSPS [public safety power shutoff] event.”[1]  To do this, the CAISO uses the year 2023 summer peak for the North Coast North Bay planning area.[2]

Use of the summer peak may be appropriate to model the impact of annual system peak load, but it is not likely to accurately represent the power flow conditions, congestion, or amount of lost load during the period in which PSPS events are likely to occur.  Per recent findings, most PSPS events occur in autumn.[3]  In fact, of 17 PSPS events which took place in 2021,[4] only four occurred[5] between June and September.  Using only a summer peak base case may lead to unrealistic conclusions for transmission needs to mitigate PSPS impacts. 

Recommendation: Cal Advocates recommends the CAISO use an autumn base case as the priority base case for modeling PSPS impacts and determining transmission solutions.

Southern California Wildfire Impact Assessment

The CAISO’s Southern California wildfire impact assessment also seeks to model both PSPS and large wildfire scenarios.[6]  To do so, the CAISO uses two base cases, Summer 2026 peak and Spring 2023 off-peak.  The CAISO states the choice of these base cases is “based on the season in which a PSPS or the wildfire event occurred or was deemed likely to occur in previous years.”  However, out of 12 PSPS events which took place in Southern California Edison Company (SCE) and San Diego Gas & Electric Company’s (SDG&E’s) service territories in 2021, only two occurred between June and September, and only one event occurred in spring (April).  In comparison, eight PSPS events occurred in SCE and SDG&E’s territory between the months of September to November. 

A summer peak base case is more appropriate for modeling the impact of wildfires rather than for PSPS events.  In 2020,[7] CAL FIRE identified 72 incidents in Southern California, and of these 56 started between June and September.[8]  In contrast, the data shows that spring is not a good choice as a base load case for modeling wildfires.  CAL FIRE identifies only five total incidents in Southern California that took place in the period between March and May of 2020 (less than 7 percent of the total for the year).

Though wildfire events are more common in the summer season, an autumn load base case is likely the best choice for modeling the impacts of large disruptive wildfires.  In recent years, the largest wildfires in SCE’s and SDG&E’s territories have occurred in October through December.  The Witch and Rice Fires ignited on October 21 and 22, 2007.  The Thomas Fire ignited on December 4, 2017.  The Woolsey Fire ignited on November 8, 2018.  In 2020, the largest wildfires started between August and November.[9] 

Recommendation: Cal Advocates recommends that the CAISO conduct modeling for base load cases during time periods that have been affected by large wildfires to determine necessary wildfire mitigation upgrades.  

Cal Advocates also recommends that the CAISO revise its methodology for wildfire impact assessments by adopting load scenarios that more accurately reflect conditions in which PSPS events and major wildfires are likely to occur.  The CAISO should conduct additional wildfire impact assessments using autumn load cases to reflect likely PSPS conditions prior to finalization of the 2021 Transmission Plan.  The assessments using the autumn load cases should provide more reasonable and useful results in considering transmission upgrades for wildfire impact mitigation.  Results based on the CAISO’s current set of assumptions may not reflect the impact of PSPS events or major wildfires and could lead to misallocation of resources for wildfire impact mitigation. 

 

Frequency Response Assessment and Data Requirements

Cal Advocates supports the CAISO’s efforts to model frequency response capability in the projected resource scenarios presented in the TPP.  Cal Advocates recommends that the CAISO expand their modeling methods to consider potential control instability of inverter-based resources under the given resource portfolios, which may have transient periods dominated by power generation by inverter-based resources such as wind, solar, or battery energy storage systems (BESS).  This modeling is required to fully understand how much frequency response can be reliably provided by inverter-based resources without the use of grid-forming inverters (GFMI) or synchronous machines.[10]

The Western Electricity Coordinating Council (WECC),[11] Electric Power Research Institute (EPRI),[12] and National Renewable Energy Lab (NREL)[13]  have started a process to identify GFMI requirements and costs.  The CAISO should consider limitations of current inverter technology as well as the potential cost impacts of GFMI in future modeling for frequency response and voltage support.

Recommendation: Cal Advocates recommends that the CAISO expand its modeling methods to consider potential control instability of inverter-based resources under the given resource portfolios, which may have transient periods dominated by power generation by inverter-based resources such as wind, solar, or BESS.

Furthermore, Cal Advocates supports the CAISO’s recommendation to perform a similar frequency response assessment with a comparable load case but with BESS in net discharging rather than charging mode.  This is a necessary sensitivity analysis for a grid reliability function. 

 


[1] Draft Plan, p. 354.

[2] Draft Plan, p. 356.

[3] Data from CPUC list of 2021 PSPS Post Event Reports, retrieved from https://www.cpuc.ca.gov/consumer-support/psps/utility-company-psps-post-event-reports

[4] Draft Plan, p. 366.

[5] CPUC 2021 PSPS Post Event Reports.

[6] Draft Plan, p. 362.

[7] 2020 is the last year for which complete CAL FIRE incident data is available. For this data set, CAL FIRE defines an incident as “a major CAL FIRE jurisdiction incident,” which “could include large, extended-day wildfires (10 acres or greater), floods, earthquakes, hazardous material spills, etc.” Of the 256 incidents included in CAL FIRE’s 2020 data, 254 are identified as wildfires.  Retrieved from https://www.fire.ca.gov/incidents/

[8] Data from CAL FIRE list of 2020 incidents, retrieved from https://www.fire.ca.gov/incidents/2020/

[9] In 2020, the five largest CAL FIRE incidents statewide, all in Northern California, accounted for nearly 80 percent of acres burned. These five incidents started between August 20 and November 11.  The five largest Southern California wildfires that year accounted for about 4 percent of total acres burned, and started between August 12 and October 26.

[10] Lin, Yashen, Joseph H. Eto, Brian B. Johnson, Jack D. Flicker, Robert H. Lasseter, Hugo N. Villegas Pico, Gab-Su Seo, Brian J. Pierre, and Abraham Ellis. 2020. Research Roadmap on Grid-Forming Inverters. Golden, CO: National Renewable Energy Laboratory. NREL/TP-5D00-73476. https://www.nrel.gov/docs/fy21osti/73476.pdf

[11] Grid-Forming Inverter Based Resources Workshop. Western Electricity Coordinating Council. October 13, 2021.

[12] Grid Forming Inverters: EPRI Tutorial. EPRI, Palo Alto, CA: 2020. 3002018676.

[13] Lin, Yashen, Joseph H. Eto, Brian B. Johnson, Jack D. Flicker, Robert H. Lasseter, Hugo N. Villegas Pico, Gab-Su Seo, Brian J. Pierre, and Abraham Ellis. 2020. Research Roadmap on Grid-Forming Inverters. Golden, CO: National Renewable Energy Laboratory. NREL/TP-5D00-73476. https://www.nrel.gov/docs/fy21osti/73476.pdf.

 

8. Comment on chapter 7 Special Reliability Studies and Results:

Cal Advocates has no comment on this topic at this time.

9. Comment on chapter 8 Transmission Project List:

Additional projects to submit for competitive solicitation

Cal Advocates supports the CAISO’s recommendation to submit four projects for competitive solicitation,[1] though Cal Advocates recommends that additional projects also be considered.  Research indicates that competitive solicitation of transmission projects can lower costs for ratepayers,[2] and given rapid escalating transmission charges,[3] it is critical that all projects eligible for competitive solicitation undergo this process.  The Brattle Group estimates that competitive solicitation can reduce a project’s costs by 20-30%.[4]

The criteria by which the CAISO determines if a project is eligible for competitive solicitation is dictated by the CAISO Tariff and federal regulations.  FERC Order 1000 removed the right of incumbent transmission providers to construct transmission facilities,[5] but allowed exemptions that include upgrades or additions to existing facilities and “local” transmission facilities, which the CAISO defined as under 200 kV and entirely with the footprint of a transmission owner.[6]

Recommendation: While Cal Advocates opposes approving the GLW/VEA upgrade in this cycle, we recommend that it be submitted for competitive solicitation if it moves forward.  The GLW/VEA upgrades include the Innovation-Desert View 230 kV line and a new 500/230 kV transformer at Sloan Canyon which would not qualify for an exemption to competitive bidding.  The transmission developer, Gridliance West, is bound by the same FERC Order 1000 regulations as the CAISO and cannot be granted the right of first refusal to construct and own these facilities.

Should the CAISO approve these projects, it should submit them for competitive solicitation or provide a tariff-based rationale for not doing so.           

Additionally, Cal Advocates recommends that the CAISO and PG&E consider competitive bidding for the 500/230 kV Transformer Bank at the Table Mountain Substation, if this project is approved.  However, Cal Advocates opposes this project approval in the 2021 Transmission Plan because additional analysis is needed to determine if this project is needed (as described in response to question 3 above).  PG&E and the CAISO appear to classify this project as an addition to an existing facility and therefore exempt from competitive solicitation.  However, given the high cost of this project ($38.4M - $76.8M) and the fact that the projects recommended in the Draft Plan total almost $3 billion,[7] the CAISO and PG&E should take every measure to limit ratepayer impact.

Approval of CAISO Recommended Transmission Projects could increase the Transmission Access Charge (TAC) by 11%

To improve the CAISO TPP stakeholder process, Cal Advocates recommends that the CAISO provide the costs and ratepayer impacts for all transmission projects recommended for approval in the given TPP cycle.  The CAISO should analyze and formally present ratepayer cost impacts, such as cumulative additions to regional and local transmission revenue requirements and impacts to the TAC, when discussing proposed projects.  Merely providing estimated capital costs does not facilitate meaningful stakeholder engagement regarding ratepayer impacts.

Using the project capital cost and in-service date estimates provided in the 2021-2022 Transmission Draft Plan, Cal Advocates estimates that the transmission projects proposed for approval will have the following impacts to the Transmission Revenue Requirement (TRR) and TAC.  TRR impacts are provided both in dollars and in net present value (NPV) These TAC and TRR impacts are summarized in Table 1, Ratepayer Impact of Proposed High Voltage Transmission Projects, and Table 2, Ratepayer Impact of Proposed Low Voltage Transmission Projects.  Approval of all the proposed high voltage transmission projects in Table 1 would result in an estimated high voltage (HV) TAC increase of 11%.  Approval of all the proposed low voltage transmission projects in Table 2 would result in an estimated low voltage (LV) TAC increase of 0.72%, if costs were recovered regionally (see Table 2 footnote).

                        Table 1: Ratepayer Impact of Proposed High Voltage Transmission Projects 

High Voltage (>200kV) Projects 

Estimated Project Costs ($ million) 

Average Annual HV TAC Increase 

40-yr TRR Contribution ($ million) 

40-yr TRR Contribution, NPV ($ million) 

Contra Costa PP 230 kV Line Terminals Reconfiguration Project 

$10 

0.04% 

$40 

$14 

Cortina 23011560 kV Transformer Bank No. 1 Replacement Project* 

$21 

0.08% 

$85 

$28 

Vasona-Metcalf 230 kV Line Limiting Elements Removal Project 

$1.2 

0.00% 

$5 

$2 

San Jose Area HVDC Line (Newark - NRS) 

$510 

2.02% 

$2,059 

$692 

San Jose Area HVDC Line (Metcalf – San Jose) 

$615 

2.43% 

$2,482 

$834 

Metcalf 230 kV Substation Circuit Breaker #No 292 Upgrade 

$1.35 

0.01% 

$5 

$2 

Table Mountain second 500/230 kV transformer 

$76.8 

0.30% 

$310 

$104 

Atlantic 230/60 kV transformer voltage regulator* 

$5 

0.02% 

$20 

$7 

Devers 230 kV Reconfiguration Project 

$6 

0.02% 

$24 

$8 

Victor 230 kV Switchrack Reconfiguration 

$5 

0.02% 

$20 

$7 

Laguna Bell-Mesa No. 1 230 kV Line Rating Increase Project 

$17.3 

0.07% 

$70 

$23 

Reconductor Delevan-Cortina 230kV line 

$35.4 

0.14% 

$143 

$48 

New Collinsville 500 kV substation 

$675 

2.67% 

$2,725 

$916 

New Manning 500 kV substation 

$485 

1.92% 

$1,958 

$658 

Re-rate the PG&E segment of the Midway–Whirlwind 
500 kV line 

$0 

GLW/VEA area upgrades** 

$278 

1.10% 

$1,122 

$377 

Installing 10 ohms series reactors on the PG&E’s Moss Landing – Las Aguilas 230 kV line 

$20 

0.08% 

$81 

$27 

Total 

2,762 

11% 

$11,149 

$3,747 

* The Cortina 23011560 kV Transformer Bank No. 1 Replacement Project and the Atlantic 230/60 kV transformer voltage regulator have both high voltage and low voltage components. This analysis assumes half the estimated project costs presented in the Draft Plan will be recovered from each the high voltage transmission access charge and low voltage transmission access charges.  

** The projected in-service date for the GLW/VEA area upgrades was not provided in the Transmission Draft Plan.  An in-service year of 2026 was used as a placeholder value.  

Table 2: Ratepayer Impact of Proposed Low Voltage Transmission Projects 

Low Voltage (<200kV) Projects 

Estimated Project Costs ($ million) 

Average Annual TAC Increase** 

40-yr TRR Contribution ($ million) 

40-yr TRR Contribution, NPV ($ million) 

Manteca-Ripon-Riverbank-Melones Area 115 kV Line 
Reconductoring Project 

$14 

0.05% 

$55 

$18 

Coppermine 70 kV Reinforcement Project 

$32 

0.12% 

$128 

$43 

Weber-Mormon Jct Line Section Reconductoring Project 

$19 

0.07% 

$76 

$25 

Series Compensation on Los Esteros-Nortech 115 kV 
Line 

$15 

0.06% 

$61 

$20 

Cooley Landing Substation Circuit Breaker No #62 Upgrade 

$1 

0.00% 

$5 

$2 

Antelope 66 kV Short Circuit Duty Mitigation Project 

$55 

0.22% 

$224 

$75 

Reconductor Rio Oso–SPI Jct–Lincoln 115kV line 

$21 

0.08% 

$86 

$29 

Cortina 23011560 kV Transformer Bank No. 1 Replacement Project* 

$21 

0.08% 

$85 

$28 

Atlantic 230/60 kV transformer voltage regulator* 

$5 

0.02% 

$20 

$7 

Total 

$182 

0.72% 

$738 

$247 

* The Cortina 23011560 kV Transformer Bank No. 1 Replacement Project and the Atlantic 230/60 kV transformer voltage regulator have both high voltage and low voltage components. This analysis assumes half the estimated project costs presented in the Draft Plan will be recovered from each the high voltage transmission access charge and low voltage transmission access charges. 

** Cal Advocates presents the average annual TAC for low-voltage projects as a placeholder value to show the order of magnitude of ratepayer impacts. The cost of projects with a rated voltage of <200kV is recovered through the Local Transmission Revenue Requirement (LTRR) and is paid for entirely by loads within the incumbent utility’s service area. The values presented show the average annual TAC increase for each project if the costs were collected regionally (as done for projects with a rated voltage of >200kV) 

A recent CPUC white paper found that the high voltage TAC ($/MWh) has increased 255% since 2009; this increase is a key driver of rising electricity bills.[8]  If these high voltage and low voltage projects recommended in the Draft Plan are all approved as proposed, Cal Advocates estimates an approximate NPV of $4 billion dollars will be added transmission revenue requirements, resulting in an additional ~11% high voltage TAC increase for ratepayers.

Furthermore, in Table 8.1-1: Status of Previously Approved Projects Costing Less than $50 M and Table 8.1-2: Status of Previously-Approved Projects Costing $50 M or More in the Draft Plan, the CAISO lists projects that have been approved in previous TPP processes.  Using the cost estimates provided by the CAISO in previous transmission planning cycles,[9]  Cal Advocates estimates more than $3 billion dollars of additional capital projects are not currently fully accounted for in the TAC, but will be recovered from ratepayers if and when these projects become used and useful.  Recovery of costs for these transmission projects will result in further impact to ratepayers regardless of any project approvals in this year’s TPP, further escalating rising utility bills.  This estimate of $3 billion dollars is likely an underestimate of the capital costs of the previously approved but in progress projects in the CAISO’s TPP.  The capital costs for the transmission projects listed in Table 8.1-1 and Table 8.1-2 and approved in transmission planning cycles prior to the 2012-2013 cycle are not accounted for because the CAISO does not provide publicly available data on transmission planning cycles prior to the 2012-2013 cycle.

Recommendation: Cal Advocates recommends that the CAISO analyze and discuss ratepayer impacts, including potential impacts to the TAC, when proposing projects for approval in future TPP cycles.  Transmission cost recovery is a significant portion of ratepayer utility bills, and the projects approved for approval in the 2021-2022 TPP cycle alone are projected to result in an 11% increase in the high voltage TAC, not accounting for the additional $3 billion dollars in previously approved transmission projects which have not fully initiated cost recovery.  The CAISO draft 20-year Transmission Outlook estimates a further $30.5 billion of transmission spending,[10] indicating more significant transmission spending to come.  All ratepayer impacts must be transparently and formally addressed in the TPP, and the CAISO must make a concerted effort to identify and approve least-cost transmission solutions to mitigate these ratepayer impacts.   

 


[1] The four projects selected were the new Collinsville 500 kV substation, the new Manning 500 kV substation, and two HVDC lines in San Jose (Newark – NRS and Metcalf – San Jose). (2021-2022 Transmission Plan. The California Independent System Operator. January 31, 2022. Pp. 380-381.)

[2] “Based on the experience with competitive projects in the U.S. to date, we estimate that the potential cost savings from expanding competitive processes could range from approximately 20% to 30%.” (Cost Savings Offered by Competition in Electric Transmission. The Brattle Group. April 2019. P. 1. Available at https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf.)

[3] Utility Costs and Affordability of the Grid of the Future. Between 2016 and 2021, the transmission rate base for the three large California IOUs has increased by 49.9% (SDG&E), 24.3% (SCE) and 45% (PG&E). (Utility Costs and Affordability of the Grid of the Future. May 2021. Table 8: Transmission Rate Base. P. 38. 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.) 

[4] See Footnote 2.

[5] FERC Order 1000. Section 253. Issued July 21, 2011. P.199. Available at https://www.ferc.gov/sites/default/files/2020-04/OrderNo.1000.pdf.

[6] Ibid. Appendix A.

[7] “The CAISO found the need for 24 projects totaling $2,944 million.” Draft 2021-22 Transmission Plan and Draft 20-Year Transmission Outlook. The California Independent System Operator (Presentation), February 7, 2022,. p. 10. Available at http://www.caiso.com/InitiativeDocuments/Presentation-Draft2021-2022TransmissionPlan-Feb072022.pdf.)

[8] Utility Rates and Affordability of the Grid of the Future: An Evaluation of Electric Costs, Rates, and Equity Issues Pursuant to P.U. Code Section 913.1.  California Public Utilities Commission. May 2021.

[9] CAISO Board-Approved 2012-2013 Transmission Plan, CAISO Board-Approved 2013-2014. Transmission Plan, CAISO Board-Approved 2014-2015 Transmission Plan, CAISO Board-Approved 2015-2016 Transmission Plan, CAISO Board-Approved 2016-2017 Transmission Plan, CAISO Board-Approved 2017-2018 Transmission Plan, CAISO Board-Approved 2018-2019 Transmission Plan, CAISO Board-Approved 2019-2020 Transmission Plan, CAISO Board-Approved 2020-2021 Transmission Plan.

[10] CAISO Draft 20-Year Transmission Outlook, January 31, 2022, p. 3.

 

California Western Grid Development, LLC
Submitted 02/22/2022, 04:07 pm

Contact

Stephen Metague (smetague1@gmail.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

California Western Grid Development LLC Comments on the Draft 2021-2022 Transmission Plan

California Western Grid Development, LLC (“California Western Grid”) hereby submits comments on the January 31, 2022, Draft: 2021-2022 Transmission Plan (“21-22 Transmission Plan”); and 20-YEAR TRANSMISSION OUTLOOK (“20-YEAR OUTLOOK”). California Western Grid is developing the proposed Pacific Transmission Expansion Project (“PTE Project” or “PTEP”)[1]and appreciates the opportunity to submit comments on the important issues addressed in those reports.

  

We applaud the CAISO on its first ever 20-Year OUTLOOK and commend the CAISO for collaborating on it with the California Public Utilities Commission (“CPUC”) and California Energy Commission (“CEC”).[2] This 20-YEAR OUTLOOK fills a need that has hampered the CAISO’s ability to plan and approve the long-lead time transmission that is necessary to deliver new remote clean energy to the major urban load centers located on the coast. And, in this regard, the 20-YEAR OUTLOOK must be read in conjunction with the March 2021 Joint Agency Report to the legislature (“Joint Agency Report”)[3] that determined the amount of new clean energy needed over the longer term to implement SB 100 as well as the types of clean energy needed.

 

The Joint Agency Report was prepared and filed with the Legislature in 2021 by the CPUC, CEC and California Air Resources Board (“CARB”). The Joint Agency Report concludes that we must triple the resources available to the CAISO grid to meet SB 100 goals.[4]  The Joint Agency Report also identified the types of clean resources needed to meet this enormous need. This identification of the public policy requirement for new clean energy has, in turn, allowed the CAISO to identify the transmission needed to deliver these resources from the remote areas where they exist, or can be developed, to the urban load centers on the coast that are currently transmission constrained. Importantly, the combination of the Joint Agency Report that identifies the SB 100 Public Policy Need and the 20-YEAR OUTLOOK allows the CAISO for the first time to plan and approve the specific long-lead time transmission needed for the CAISO to meet its tariff obligation to plan and approve transmission to meet State Public Policy requirements.[5] 

 

Up until now, the CAISO lacked a clear picture of the magnitude and timing of the long-term SB 100 State Public Policy need. And the portfolios of resources previously provided to the CAISO were limited to resources needed over a 10-year period. In contrast the Joint Agency Report provides the long-range forecast of resources needed to meet the State SB 100 Public Policy requirements that, in turn, allows the CAISO in its 20-YEAR OUTLOOK to identify the long-lead time transmission that can accommodate those resources. For example, the CAISO’s 20-YEAR OUTLOOK concluded that the PTE HVDC line from Diablo to LA is one of the projects that will be needed.[6]

 

Importantly, the CAISO, starting in the 2022-2023 Transmission Planning Process (“TPP”), will be able to plan and approve the specific long-lead time transmission facilities that are needed to deliver new clean energy to transmission constrained areas like the Los Angeles Basin (“LA”) that are currently required to rely completely on local fossil units.

 

In the 21-22 Transmission Plan the CAISO has set the stage by approving $1.5 billion of significant public policy  transmission  projects along with  two HVDC projects in the San Francisco Bay Area that are above and beyond the short-term transmission solutions that have been relied on in the past.[7]  As the CAISO indicated in its 20-YEAR OUTLOOK, the 21-22 Transmission Plan is a “transitional” plan[8] leading to a new era of longer-term transmission planning that is essential to implement SB 100 and other State Public Policy Requirements.

 

Now, in the 2022-2023 TPP the CAISO, for the first time, can turn to long-lead time projects needed in areas like LA that are transmission constrained. The CAISO has confirmed once again that the long 10 year or more lead- time needed to plan, approve, permit, and construct transmission requires that the CAISO act now to plan and approve new transmission identified in its 20-YEAR OUTLOOK to ensure that it is available when needed. [9]  California Western Grid requests that the CAISO review and approve transmission projects identified in its 20-year transmission outlook beginning in the 22-23 TPP (and subsequent TPPs) to accommodate the resource needs reflected in the Joint Agency Report. Approving high priority long lead time transmission projects in the 2022-23 TPP is essential to allow an orderly transition to California’s zero carbon future.

 

The SB 100 and other important State Public Policies are transformative and extremely challenging. The CAISO 20-year outlook created in collaboration with the State agencies is a critical step forward to meet the challenge. California Western Grid appreciates the work of the CAISO and the State agencies and stands ready to assist as needed or appropriate.

Respectfully submitted

Martin Walicki

On behalf of California Western Grid                                                                     


[1] The PTE Project is a 2,000 MW controllable HVDC subsea transmission cable that the California Independent System Operator (“CAISO”) has found will allow new and existing supply available to the Diablo Canyon 500 kV switchyard or new offshore wind to be delivered to the West LA Basin to reduce local capacity requirements, potentially allowing for the replacement of up to 1,993 MWs of thermal plant generating capacity.  The PTE Project is more fully described in Section 4.8.2 of the 21-22 Transmission Plan pp. 278-279.

[2][2] 20-YEAR OUTLOOK pp. 1 and 11.

[3] https://www.energy.ca.gov/news/2021-03/california-releases-report-charting-path-100-percent-clean-electricity

[4] Joint Agency Report at Highlights.

[5] Section 24.4.6.6 of CAISO Tariff.

[6] 20-YEAR OUTLOOK pp. 48-49.

[7] 21-22 Transmission Plan at Table 8.2-2 pp. 377-378.

[8] 20-YEAR OUTLOOK pp. 6-7.

[9] Letter from Elliot Mainzer, Pres. & CEO of CAISO to Assemblymen Chad Mayes and Jordan Cunningham and Senator Melissa Hurtado (Aug. 18, 2021). “[W]e we must keep in mind that it can take ten plus years to plan and build new infrastructure so the time to act is now.” See also, CAISO Comments on Preliminary [CPUC] Scoping Memo, Rulemaking 20-05-003 (Filed May 7, 2020) p. 4.

 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

California Western Grid appreciates the overview of the Transmission Planning Process and especially welcomes the new 20-year transmission outlook as a much needed road map to support forward looking planning.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

In the 21-22 Transmission Plan the CAISO has set the stage by approving $1.5 billion of significant public policy  transmission  projects along with  two HVDC projects in the San Francisco Bay Area that are above and beyond the short-term transmission solutions that have been relied on in the past.  California Western Grid supports the approval of those projects and would like to commend the CAISO for postitioning the grid to meet not only the needs of the current 10 year reasource plan, but a longer horizon as well.

4. Comment on chapter 3 Policy-Driven Need Assessment:

In the 21-22 Transmission Plan the CAISO has set the stage by approving $1.5 billion of significant public policy  transmission  projects along with  two HVDC projects in the San Francisco Bay Area that are above and beyond the short-term transmission solutions that have been relied on in the past.  As the CAISO indicated in its 20-YEAR OUTLOOK, the 21-22 Transmission Plan is a “transitional” plan leading to a new era of longer-term transmission planning that is essential to implement SB 100 and other State Public Policy Requirements.

 

Now, in the 2022-2023 TPP the CAISO, for the first time, can turn to long-lead time projects needed in areas like LA that are transmission constrained. The CAISO has confirmed once again that the long 10 year or more lead- time needed to plan, approve, permit, and construct transmission requires that the CAISO act now to plan and approve new transmission identified in its 20-YEAR OUTLOOK to ensure that it is available when needed. California Western Grid requests that the CAISO review and approve transmission projects identified in its 20-year transmission outlook beginning in the 22-23 TPP (and subsequent TPPs) to accommodate the resource needs reflected in the Joint Agency Report. Approving high priority long lead time transmission projects in the 2022-23 TPP is essential to allow an orderly transition to California’s zero carbon future.

5. Comment on chapter 4 Economic Planning Study:

California Western Grid appreciates the update on expected congestion on the grid. California Western Grid remains concerned that the CAISO TEAM methodology under estimates the cost of congestion (and the benefits of relieving congestions) to the California energy consumers and encourages the CAISO to re-evaluate the TEAM methodology for future planning cycles.

6. Comment on chapter 5 Interregional Transmission Coordination:

California Western Grid has no comment on Chapter 5

7. Comment on chapter 6 Other Studies and Results:

California Western Grid appreciates the CAISOs thoughtful and thourough analysis of the Out of State Wind and Off Shore wind sensitivity portfolios. Those study results have provided important new insight into the significant transmission challenges facing California as we transition to a zero carbon future.

8. Comment on chapter 7 Special Reliability Studies and Results:

California Western Grid has not comment on the Special Reliability Studies

9. Comment on chapter 8 Transmission Project List:

In the 21-22 Transmission Plan the CAISO has set the stage by approving $1.5 billion of significant public policy  transmission  projects along with  two HVDC projects in the San Francisco Bay Area that are above and beyond the short-term transmission solutions that have been relied on in the past. California Western Grid supports and the proposed approval of those projects

California Wind Energy Association
Submitted 02/24/2022, 02:16 pm

Contact

Nancy Rader (nrader@calwea.org)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

In the 20-year Transmission Outlook study, the ISO improved on the deliverability methodology by assuming that energy storage resources do not produce under the SSN (gross peak) condition (when solar generation is high and storage resources will generally be charging). The ISO should likewise make this important modification to the on-peak deliverability assessment methodology in the current TPP cycle. While this modification is still insufficient, since all non-wind and non-solar resources are still assumed to produce up to their full NQC, it should substantially increase available transmission capacity while maintaining system reliability.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

 No comment

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

We believe that CAISO should be proposing more incremental upgrades. CAISO should take into consideration potential upgrades that repeatedly arise in GIDAP studies and consider them as alternative, more cost-effective solutions to reliability or economic problems that are being addressed in the TPP.  An example is the Gates 500/230-kV transformer bank #13, which has shown up in GIDAP for many years, and would also address resource curtailments while providing RA capacity for many additional resources.  CAISO appears to have done something similar with its proposed Collinsville upgrade, which appears to be an expensive solution but also addresses long-term needs identified in the 20-year Transmission Outlook.

4. Comment on chapter 3 Policy-Driven Need Assessment:

The draft report is missing study assumptions for out-of-state wind and offshore wind in the policy deliverability assessment. Please provide the study assumptions and the rationale for them. Please also clarify which out of state resources are assumed to use existing import capability to deliver energy to California demand and which ones require deliverability beyond the existing import capability. 

Some recommended policy upgrades seem heavily oversized, apparently to align with the CAISO’s 20-year Transmission Outlook. As CalWEA explained in our comments on the 20-year Outlook, connecting the 20-year plan with the annual TPP cycle is important so that we continually make progress toward the long-term plan.  However, the ISO should provide clarification on this point and explain how these upgrades are “least regrets.”  

As CalWEA has commented previously, it is not sound to assume, in the SSN deliverability study, that all non-wind and non-solar resources produce up to their full NQC. CalWEA previously proposed that the SSN test be eliminated altogether.  In the 20-year Transmission Outlook, the ISO at least improved on the methodology by assuming that energy storage resources do not produce under the SSN condition. The ISO should make such modifications to the on-peak deliverability assessment methodology in the current TPP cycle and in GIDAP as well.

5. Comment on chapter 4 Economic Planning Study:

CalWEA supports the CAISO’s assumption (stated in response to a stakeholder question) that OOS transmission project costs (e.g., Sunzia) should be included in the analysis, even if covered by developers, to promote apples-to-apples comparisons, since ratepayers will pay one way or another.

6. Comment on chapter 5 Interregional Transmission Coordination:

  No comment

7. Comment on chapter 6 Other Studies and Results:

  No comment

8. Comment on chapter 7 Special Reliability Studies and Results:

  No comment

9. Comment on chapter 8 Transmission Project List:

  No comment

Cat Creek Energy, LLC.
Submitted 02/22/2022, 09:00 am

Contact

Peggy Beltrone, Public Policy Advisor, Cat Creek Energy

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Cat Creek Energy, LLC with its Cat Creek Energy & Water (“CCEW”) enhanced pumped storage hydro project near Mountain Home, Idaho, appreciates the CAISO decision to engage further with industry participants in accessing Idaho resources. Of note, we appreciate that the CAISO will consider the engagement as an extension of the 2021-2021 planning process as it underscores the importance of out of state resources to California’s decarbonization goals.

CCEW, at the north terminus of the SWIP-N [Great Basin HV Line], delivers a unique perspective for the CAISO in assessing both the need for Out of State (“OSS”) resources to fulfil the 2032 goals within the 2045 California clean energy mandate, and the viability of making the Great Basin HV line and Midpoint a California asset in the ISO system. 

The best case scenario for any transmission line is full utilization, regardless of if the line is being built for future expansion or not.  By having CCEW at the north terminus, up to 870 MW of overproduction California renewable energy, otherwise curtailed, can be sent north to its 87,120 MWhr capacity energy storage facility. In one action, the CAISO can add SWIP N transmission and simultaneously identify the CCEW energy storage as an accompanying non-transmission preference because with CCEW the line will bring at-scale benefits to California. This storage has no environmental mine to landfill LI-ion concerns, has no degradation during its design life of 100 years, and can cycle indefinitely even delivering energy services while in ‘charging’ mode.  

California needs the scale of energy storage CCEW provides. It is 72 times larger than Moss Landing’s “World’s Largest Battery.” CCEWs Long Duration is unmatched, storing its full output for up to 121 hours. But more important is its much greater efficiency and longer lifecycle, the absence of environmental hazards, and its ability to adapt to changing grid and reliability conditions over the course of the California transition to decarbonization by 2045.  

CCEW can perform at any level of integration [both charge and discharge] and influx changes intrahour without delay.  Its reaction time is in seconds, not minutes provided by NERC protocols for energy services.  Being able to send electrons north to CCEW makes importing energy much more efficient and gives more operational optionality to the CAISO to manage its grid. 

Given the flexibility of CCEW generation capabilities, the provision of all foreseeable energy services, and the reliability behind augmenting of the LS Power 1045 MW Lava Ridge wind park, results in a firm delivery product to California Load Serving Entities along with extraordinary Resource Adequacy, while integrating ancillary services and grid support into the ISO system.  

However, and we do not think it an overstatement that the need for resources in reaching the mandate set in California exceeds the state’s current capacity to do so given the permitting, interconnection, and other regulatory issues that inevitably lead to long turnaround times to get projects online. As it is becoming clearer, the order of magnitude of resources needed to enable the move to 100% decarbonization is unprecedented.  Therefore, when low hanging fruit like a half built and fully permitted transmission line that can resource dedicated wind [1,045 MW from Lava Ridge wind park] and can connect to dedicated resource adequacy and grid support from the 720 MW of CCEW ternary pumped storage combined with California sending oversupply of renewable energy up to the 87,120 MWhrs of CCEW energy storage capacity, the SWIP-N [Great Basin system] becomes a real game-changer in the effort to comply with the California mandates and continue to lead the country in the transition to clean and sustainable energy.  

Moreover, the lift to reach the horizon mandate of 2045 requires expenditures not seen in our lifetimes.  California will need to build its own grid capacities by up to an additional 150%, placing new weight on the challenges of new right of ways, and state/local permitting.  Grid management communications in the past dealt with a relative finite set of larger resources for load and grid management.  In the future, the penetration of demand response and distributed generation and energy storage, it is only logical for some major installations of VRE resources [such as Lava Ridge], LVLD energy storage, and large generator Resource Adequacy and other grid services [such as CCEW], capable of performing under all conditions, at large capacities, stand at the ready to be connected to the ISO grid to assure reliability, security, and resilience.   

Critically thinking about how to transition to net zero emissions has been a major theme for all the agencies in California.  Bringing resources online as Lava Ridge with its wind resource, and CCEW’s ability to offset up to 2,770,845 metric tons of CO2 annually, SWIP-N becomes a major offset resource in advancing California performance goals.  CCEW will carry these attributes through the transition horizon and well into the 22nd Century for the state.  

As the California grid increases its clean energy footprint, Load Serving Entities (“LSE”) will be challenged over and again to meet complicated capacity, firming, grid services, and RA service protocols under California rules and stipulations. Additionally, the impacts of all electric vehicles and electric HVAC buildings add pressure to Time of Day (“TOD”) delivery needing broad-based flexibility to counter these demands irrespective of TOD, overproduction, or Duck Curve demands.  CCEW delivers this broad flexibility in one facility to help address these moving targets during the transition period. 

Sometimes solutions can be less complicated as Seymour Cray of supercomputing once stated:   "If you were plowing a field, which would you rather use?  Two strong oxen or 1024 chickens?"

2. Comment on chapter 1 Overview of the Transmission Planning Process:

n/a

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

n/a

4. Comment on chapter 3 Policy-Driven Need Assessment:

n/a

5. Comment on chapter 4 Economic Planning Study:

n/a

6. Comment on chapter 5 Interregional Transmission Coordination:

n/a

7. Comment on chapter 6 Other Studies and Results:

n/a

8. Comment on chapter 7 Special Reliability Studies and Results:

n/a

9. Comment on chapter 8 Transmission Project List:

n/a

City of Palo Alto Utilities
Submitted 02/22/2022, 09:00 pm

Submitted on behalf of
City of Palo Alto Utilities

Contact

Jim Bujtor (jim.bujtor@cityofpaloalto.org)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

The City of Palo Alto Utilities (CPAU or the City) appreciates the opportunity to comment on the CAISO’s 2021-2022 Draft Transmission Plan (Draft Plan). The comments below address the Draft Plan posted by the CAISO on January 31, 2022.

CPAU had submitted Ames-Palo Alto 115 kV Line Project in the CAISO 2021-2022 TPP request window in October 2021, targeting thermal overloads on the Ravenswood-Cooley Landing 115 kV line and potential reliability concern for the loss of three 115 kV line feeding Palo Alto substation, i.e., N-3 contingency. The project includes building a new Ames-Palo Alto 115 kV line with an option to terminate the 115kV line at the CPAU’s Adobe Creek substation instead of the Palo Alto substation.

CPAU intends to work with Pacific Gas and Electric Co. (PG&E) and CAISO during the 2022-2023 transmission planning process (TPP) to study further the N-3 extreme event that took place on February 17, 2010. CPAU expects that these efforts will demonstrate that the benefits of the reliability improvement obtained from the proposed project will greatly exceed the modest cost of the project. CPAU is hopeful that this assessment will be sufficient to approve the proposed project under the CAISO’s extreme event reliability planning standard, leading to approval of the Ames-Palo Alto/Adobe Creek 115kV project.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No Comments at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

The PG&E system that the City is connected to, and continues to support through our transmission access charges, does not provide adequate reliability for the City and the critical regional facilities that the City serves. It is imperative that these facilities have reliable grid power to perform their daily operating routines without interruption. Although, over the years, several proposals have been considered by the CAISO, PG&E, and CPAU, the fundamental reliability issues faced by CPAU have remained unaddressed in the Draft Plan.

CPAU had submitted Ames-Palo Alto 115 kV Line Project in the CAISO 2021-2022 TPP request window in October 2021, targeting thermal overloads on the Ravenswood-Cooley Landing 115 kV line and potential reliability concern for the loss of three 115 kV line feeding Palo Alto substation, i.e., N-3 contingency. The project includes building a new Ames-Palo Alto 115 kV line with an option to terminate the 115kV line at the CPAU’s Adobe Creek substation instead of the Palo Alto substation. The Draft Plan determines that “the contingency of three 115 kV lines is an extreme event, which doesn’t result in an uncontrolled wide-area cascading,” and therefore does not approve the project.[1]

 

CPAU intends to closely work with PG&E and CAISO during the 2022-2023 transmission planning process (TPP) to further study the N-3 extreme event that actually took place on February 17, 2010. CPAU expects that these efforts will demonstrate that the benefits of the reliability improvement obtained from the proposed project will greatly exceed the modest cost of the project. CPAU is hopeful that this assessment will be sufficient to approve the proposed project under the CAISO’s extreme event reliability planning standard, leading to approval of the Ames-Palo Alto/Adobe Creek 115kV project.

 


[1] Draft Plan, p. 106.

4. Comment on chapter 3 Policy-Driven Need Assessment:

No Comments at this time.

5. Comment on chapter 4 Economic Planning Study:

No Comments at this time.

6. Comment on chapter 5 Interregional Transmission Coordination:

No Comments at this time.

7. Comment on chapter 6 Other Studies and Results:

No Comments at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

No Comments at this time.

9. Comment on chapter 8 Transmission Project List:

No Comments at this time.

City of San Jose
Submitted 02/22/2022, 04:37 pm

Contact

Marcos Santiago (marcos.santiago@sanjoseca.gov)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

The City of San Jose (CSJ or City) is monitoring the 2021-2022 transmission planning process as the Draft 2021-2022 Transmission Plan (Draft Plan) would have many impacts to local developments and the CSJ’s ambitious Climate Smart San Jose Plan, which includes over 1 GW of solar installations and increased electrification in the city’s territory to mitigate the impacts of climate change. In these comments the CSJ:

  • Expresses its strong support for new 230 kilovolt (kV) or 500 kV sources into the San Jose/Santa Clara area as an alternative to the piecemeal upgrades to the 60-year-old existing 115 kV system to facilitate the area’s aggressive goals for electrification and climate stabilization.
  • Expresses its strong interest in ensuring that these important infrastructure upgrades in the area proceed with utmost regard for environmental and equity impacts and considerations, and in strong partnership with state agencies and impacted local communities.
  • Urges the CAISO Board to direct CAISO staff provide the information listed below to the CSJ and other affected stakeholders.
  • Urges the CAISO Board to direct CAISO staff to immediately begin work with relevant state and local entities to plan for permitting and explore siting issues to maximize the likelihood of success and minimize potential adverse impacts on the environment and local communities.
  • Urges the California Independent System Operator (CAISO) Board to direct CAISO staff to regularly confer with the California Energy Commission (CEC) and major urban centers with ambitious greenhouse gas reductions goals to better anticipate associated load impacts and undertake early identification of transmission and other electric infrastructure needs required to support these efforts.
  • In addition, CSJ urges the CAISO to reformat the Local Capacity Technical Report to include in an executive summary a table of load forecasts and any dramatic changes from one study to the next.

 

 

As CJS executes Climate Smart San Jose[1], it is becoming acutely aware that the cumulative impact of its small electrification efforts and large new electric development projects will dramatically increase the electric load in the City.  The existing 60-year-old PG&E 115 kV transmission line serving CSJ’s territory would be significantly stressed to accommodate the City’s ambitious plan and similar initiatives from the region’s neighboring cities.

 

CSJ has been monitoring Pacific Gas and Electric Company’s (PG&E) “South Bay 115 kV Reinforcement Conceptual Project,” following the PG&E’s September 28, 2021 presentation[2].  This project was triggered by a “sudden” large load increase in the neighboring City of Santa Clara. This “conceptual proposal” would potentially impact electricity supply plans for specific CSJ projects and implicate land use considerations within the City’s limits as a result of PG&E’s proposed network upgrades to the regional grid. PG&E’s conceptual proposal includes multiple piecemeal upgrades to the existing 115 kV system and concludes with the following statement:       

The feasibility and cost evaluation of the alternatives are very complex due to routing limitations caused by proximity to environmentally sensitive locations and high population density areas. [3]

CSJ also noted the CAISO response to this PG&E proposal, questioning whether the PG&E piecemeal approach to upgrading the 115 kV system would be sufficient:

                Reliability Concern: Multiple

                Potential Upgrade: Potentially new 230 kV or 500 kV source into the area[4]

On February 1, 2022, the “conceptual” and “potential” technical discussion of future alternatives publicly emerged as a firm proposal to request Board approval to construct two 500 megawatt (MW) high-voltage, direct current (HVDC) lines into the region.  One line is from Newark to NRS to deal directly with the Santa Clara load increase and one is from Metcalf to San Jose B, to provide support for the Santa Clara load and other projected load increases in the region. These lines are to be operational by 2027. The project would be presented to the CAISO Board for approval at the March 16-17 Board Meeting.  If approved, the project would be put out to bid through a solicitation and financed through the Transmission Access Charge (TAC) as a reliability driven project.  It is in this context that the CSJ provides these comments on the $3 billion Draft Plan that was presented on February 7.

Although CSJ would have appreciated more than 22 days to respond to this ambitious and consequential proposal, it is supportive of both the objectives and the concept of siting the new Metcalf to San Jose B high-voltage line in the right of way (ROW) of the existing 115 kV line.  CSJ agrees that the lines and the 60-year-old San Jose B substation are “in close proximity to environmentally sensitive locations and high population density areas[5].”  CSJ supports both new high-voltage lines and efforts to reduce the environmental impacts of the proposed lines and the refurbishment of San Jose B.

CSJ is fully aware of both the urgency to deal with near term infrastructure upgrades to accommodate already planned and approved load growth, and the necessity to make these investments consistent with the long-term vision shared by both the State and the City for a reliable, resilient, affordable, and low-carbon electric grid.   CSJ supports the ~$3 billion Draft Plan to allow for efficient future growth instead of the current practice of upgrading transmission infrastructure on a piecemeal basis at the last possible minute.

More detailed comments on the specific aspects of the proposal to approve the ~$0.5 billion “San Jose Area HVDC Line (Metcalf-San Jose)” as a reliability driven project follow under the Chapter 2 heading.

 


[1] Climate Smart San Jose: A People- Centered Plan for a Low-Carbon City. https://www.sanjoseca.gov/home/showpublisheddocument/32171/636705720690400000

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

[3] Id., p. 48.

[4] CAISO Preliminary Reliability Assessment Results, 2021-2022 Transmission Process Stakeholder Meeting, September 27, 2021, p. 18.

[5] PG&E’s 2021 Request Window Proposals, CAISO 2021-2022 Transmission Planning Process, Sept 28, 2021, p. 48.

 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No Comment

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

CSJ is generally supportive of the proposal to approve the ~$0.4 billion “San Jose Area HVDC Line (Newark-NRS)” project. CSJ defers to its northern neighbor, the City of Santa Clara and its municipal utility Silicon Valley Power, for any specific comments on this project. Our comments here are focused on the ”San Jose Area HVDC Line (Metcalf-San Jose)” project.

Normally, at this stage of the Transmission Planning Process (TPP), more public information about a particular project would be available in the Draft TPP Plan to allow stakeholders to constructively engage and reach some conclusion prior to the issuance of the Final Plan and the Board vote. For a project of the magnitude and proximity to San Jose such as the San Jose Area HVDC Line, lack of information is critical. CSJ raised this concern during the February 7 Stakeholder call and was directed to formally request additional information via these stakeholder comments. CSJ requests the following:

  • Any available power flow results that would allow assessment of the effects on transmission line loadings under normal operations and during P1 contingencies in the vicinity of San Jose B due to the injection of 500 MW of energy at this location as well as potential loss of the DC connection under P2 and P6 contingencies.
  • Any available information about land use requirements at San Jose B to accommodate both the rebuilt/refurbished 115 kV Substation and the HVDC converter station. Include an assessment of the possibility of compact design alternatives for the converter station as currently utilized for e.g., offshore wind platforms in the North Sea or the Chicago and New York City HVDC links that serve a similar purpose as this project.
  • Confirmation that the 11.5 mile underground cable ROW contemplates the “standard” 3 feet (ft.) wide x 5 ft. deep trench with two ~6 inch conduits for the DC cables. Include an assessment of the possibility of locating this line in the existing 115 kV ROW.
  • An assessment of the temporary plan to deal with additional area load appearing prior to energizing this HVDC link and/or the companion Newark/NRS link.

 

CSJ understands and appreciates the critical nature and accelerated timeframe surrounding this project and in no way suggests that approval by the Board must be deferred pending receipt of this data and normal time for stakeholder review.  However, the sooner this information is available to all stakeholders, the more likely it is that this critical project could be executed in the required timeframe.

 

CSJ also believes that, if the CAISO Board chooses to approve the project, it should also direct CAISO staff to begin in earnest the process of planning for the permitting/CEQA approvals in collaboration with other state agencies, such as the California Public Utilities Commission (CPUC), as well as relevant local jurisdictions such as the CSJ. There is no reason to wait to begin this planning until after the competitive solicitation process has been completed and the winning bidder has filed a formal application.

 

CSJ supports additional long-term transmission planning and coordination with local governments.  This is important as the industry transitions from a long period of flat or declining load growth to one of rapid load growth. Title 24 building electrification standards, electric vehicle adoption rates, new data centers, among other initiatives in the framework of SB 100 would likely result in uneven and potentially dramatic load growth in particular locations.  The CEC load forecasting process and how that is applied in transmission planning should adapt or we will be in a continual state of last-minute reactions to unforeseen events.  CSJ urges the CAISO Board to direct CAISO staff to regularly confer with the CEC and major urban centers with ambitious greenhouse gas reductions goals to better anticipate associated load impacts and undertake early identification of transmission and other electric infrastructure needs required to support these efforts.

 

To illustrate the issue, Table 1 below shows recent area loads and load growth estimates that were used in the transmission planning process.

 

Table 1

Local Capacity Technical Report Load Forecasts

 

Year

San Jose Sub-Area Load, MW

Greater Bay Area 5 yr Load Growth Forecast, MW/yr

2020

2452[1]

-15[2]

2021

2543[3]

-9[4]

2022

2682[5]

201.25[6]

 

As Table 1 shows, the load planned to be served in the relevant time frame for transmission planning in just this part of Silicon Valley increased in one year by the equivalent of one Diablo Canyon nuclear reactor. However, this information was buried in two separate locations in a dense technical report with almost no mention in the Executive Summary of this report much less in any CAISO document meant for public consumption. To increase transparency and facilitate collaboration with local governments, CSJ urges the CAISO to reformat the Local Capacity Technical Reports to include in an executive summary a table of load forecasts and any dramatic changes from one study to the next.

 


[1] 2020 Local Capacity Technical Report, May 1, 2019, p. 78.

[2] Id., p. 162.

[3] 2021 Local Capacity Technical Report, May 1, 2020, p. 72.

[4] Id., p. 152.

[5] 2022 Local Capacity Technical Report, April 30, 2021, p. 69.

[6] Id., p. 148.

4. Comment on chapter 3 Policy-Driven Need Assessment:

No Comment

5. Comment on chapter 4 Economic Planning Study:

No Comment

6. Comment on chapter 5 Interregional Transmission Coordination:

No Comment

7. Comment on chapter 6 Other Studies and Results:

No Comment

8. Comment on chapter 7 Special Reliability Studies and Results:

No Comment

9. Comment on chapter 8 Transmission Project List:

No Comment

Fervo Energy
Submitted 02/22/2022, 03:55 pm

Submitted on behalf of
Fervo Energy

Contact

Phillip J. Muller (philm@scdenergy.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Fervo Energy supports the CAISO plans to undertake additional assessment regarding the SWIP North project but notes that the focus on Idaho wind alone could fail to capture the entire value that could be provided by some reliance on Idaho geothermal resources.  USGS has estimated that there is a 95% probability that over 500 MW of traditional geothermal can be developed in Idaho, even more in Nevada.  The same amount of GHG-free energy could be delivered from 500 MW of Idaho geothermal capacity using about a third of the transmission capacity needed to deliver the same amount of Idaho wind.  Fervo would be happy to support and inform the CAISO’s continuing assessment of SWIP North incorporating some of this potential resource.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No comment at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

No comment at this time.

4. Comment on chapter 3 Policy-Driven Need Assessment:

No comment at this time.

5. Comment on chapter 4 Economic Planning Study:

Fervo strongly supports further assessment of the SWIP North project and particularly wants to point out the potential for Idaho geothermal resources providing a valuable component of deliveries compared to lower capacity factor Idaho wind generation.

6. Comment on chapter 5 Interregional Transmission Coordination:

No comment at this time.

7. Comment on chapter 6 Other Studies and Results:

No comment at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

No comment at this time.

9. Comment on chapter 8 Transmission Project List:

No comment at this time.

Golden State Clean Energy
Submitted 02/22/2022, 05:00 pm

Submitted on behalf of
Golden State Clean Energy

Contact

Ian Kearney (ikearney@weawlaw.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Golden State Clean Energy (“GSCE”) appreciates the California ISO’s effort this past year to study the transmission system for the infrastructure needed to support the clean energy resources that will enable California to reach its GHG reduction goals. Our comment focuses on how the ISO’s annual transmission planning process can be improved by the 20-Year Transmission Outlook and highlights important transmission projects that are being recommended for approval this TPP cycle. Our hope is that the 20-year outlook can continuously maximize the benefits of the TPP by driving orderly development of the infrastructure needed to meet California’s SB 100 goals. Orderly development could be promoted by a long-term plan to phase the expected development of Central Valley and Central Coast energy infrastructure and by ensuring that future IRP mapping sufficiently aligns with the 2021 SB 100 Joint Agency Report and the 20-Year Transmission Outlook.

 

GSCE sees the 20-Year Transmission Outlook as already providing benefits to this cycle’s TPP by allowing the ISO to compare potential transmission solutions to a longer-term transmission vision. However, the process by which the 20-year outlook will continue to inform the TPP should be formalized. The ISO should immediately begin discussing how to facilitate the orderly development of transmission upgrades identified in the 20-year outlook, which may involve TPP reform and possibly corresponding interconnection queue reform. Transitioning from planning to development will allow the ISO to capture the value proposition of the 20-year outlook, and GSCE finds this especially true of the potential near- and long-term benefits that Central Valley solar and storage resources can provide.

 

GSCE urges the ISO to align IRP-TPP planning with the Central Valley’s long-term energy policy future by coordinating the 20-year outlook results with the CPUC and ensuring future IRP busbar mapping includes sufficient resources in the Central Valley. The 20-year outlook assumes the Westlands transmission zone alone will have 12.7 GW of solar interconnecting and the Central Valley will have 30 GW of solar overall,[1] not to mention the substantial amount of storage that will be paired with this solar. GSCE is confident that much of this solar and storage can be constructed quickly if the necessary transmission infrastructure is developed to increase the deliverability of Central Valley resources. Resources like long-duration storage should also be studied in the Central Valley so to be in closer proximity to future solar and offshore wind. However, we have been concerned that IRP-TPP planning in the Central Valley has not been sufficiently aligned with the longer-term policy picture painted by the SB 100 implementation report.

 

As an enhancement to traditional IRP-TPP thinking, the ISO should create a plan for how the development in the 20-year outlook could be done in phases. A phasing plan could facilitate orderly development of planned generation in areas like the Central Valley through many annual TPP cycles while also facilitating the interconnection of significant new storage-paired renewable resources that can support grid reliability in the near-term. For a phased transmission development plan to work in tandem with generator interconnection to help California efficiently reach its SB 100 goals, a separate interconnection queue for the Central Valley and other policy resource zones could help drive orderly, holistic development in these areas (e.g., a unique transmission upgrade funding process focused on the long-term transmission needs and involving a new deposit and application process). Such a process could provide a framework that satisfies some of FERC’s current planning desires as expressed in the 2021 transmission and generation interconnection ANOPR.[2]  This could also address some of the ISO’s concerns raised in the 2021 IPE initiative regarding policy-driven studies in the TPP that are not coordinated with interconnection requests seeking to utilize the transmission capacity being developed.

 

GSCE recognizes that crucial progress was made this past year. The Draft 2021-2022 Transmission Plan and its recommendation for a new Manning Substation represents the first TPP cycle where a significant first step has been taken toward realizing California’s long-term energy policy vision for the Central Valley.[3]  GSCE is very supportive of this new substation and the ISO’s thinking that led to it being recommended for approval. But more of this type of planning is needed, and the ISO needs to examine its processes to ensure it can continue this progress. The benefits the new Manning Substation provides will only increase as additional corresponding transmission infrastructure is developed, namely new high voltage lines such as a new 500 kV Diablo-Gates line that can facilitate Central Coast offshore wind and a Manning-Moss Landing 500 kV line that can provide the Bay Area with greater access to renewables and storage.[4]  The ISO should examine expediting these upgrades and assess the benefits of bringing these transmission lines online along the same timeline as the new Manning Substation.

 


[1] Draft 20-Year Transmission Outlook, at 28, Jan. 31, 2022, available at: http://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf.

[2] FERC docket RM21-17-000.

[3] Draft 2021-2022 Transmission Plan, at 199, Jan. 31, 2022, available at: http://www.caiso.com/InitiativeDocuments/Draft-2021-2022TransmissionPlan.pdf.  

[4] Draft 2021-2022 Transmission Plan, at 232 (discussing the Diablo-Gates line); Draft 20-Year Transmission Outlook, at 48 (discussing the Manning-Moss Landing line).

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No comment. 

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

No comment. 

4. Comment on chapter 3 Policy-Driven Need Assessment:

No comment. 

5. Comment on chapter 4 Economic Planning Study:

No comment. 

6. Comment on chapter 5 Interregional Transmission Coordination:

No comment. 

7. Comment on chapter 6 Other Studies and Results:

No comment. 

8. Comment on chapter 7 Special Reliability Studies and Results:

No comment. 

9. Comment on chapter 8 Transmission Project List:

No comment. 

GridLiance West
Submitted 02/22/2022, 03:01 pm

Submitted on behalf of
GridLiance West

Contact

Ellen Wolfe (ewolfe@resero.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

GLW very much appreciates the incredible body of work the CAISO completed this year with the TPP, including all of its scenario variants.

In these comments GLW offers feedback on a limited number of issues, including

  • Encouraging the CAISO to collaborate with the CPUC to increase the transmission capability on GLW system for additional expansion opportunities once these TPP projects are approved
  • Supporting the CAISO’s recommendation to approve the GLW Upgrade
  • Encouraging the CAISO to study transmission upgrades to the geothermal resources in the next TPP, and
  • Responding to concerns expressed that the GLW Upgrades may disadvantage one or more of the out-of-state wind transmission projects.
2. Comment on chapter 1 Overview of the Transmission Planning Process:

 GLW has no comments on the Overview section.

 


 

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

GLW has no comments on the Reliability Assessment section.

4. Comment on chapter 3 Policy-Driven Need Assessment:

The CAISO presents the deliverability assessment and the deliverability results in Section 3.5. The CAISO also summarizes the Policy-Driven needs assessment in Section 3.10, including noting the need for the GLW Upgrade. GLW appreciates this detailed analysis. GLW urges the CAISO to revise this analysis once the plan is final such that subsequent cycle’s analysis, as well as the CPUC’s planning activities, will be based on new potentials in all areas where such are warranted based on approved upgrade projects.  Not increasing the capabilities for use in the IRP process especially could result in significant planning assumption distortions.  

5. Comment on chapter 4 Economic Planning Study:

GLW appreciates the CAISO’s extensive analysis of the anticipated congestion in the GLW system resulting from renewable buildout. GLW believes the CAISO has conducted a thorough analysis of the GLW Upgrade project submitted in the economic study request process. In addition to the policy need for this Upgrade, GLW appreciates the CAISO quantifying that the Upgrade also exceeds the CAISO’s required benefit-to-cost ratio.  Additionally, GLW requests that CAISO post the Gridview change files to the NDA portal to allow stakeholders’ review and improvement of stakeholder future submittals.

Regarding economic study requests presented in Section 4.8, the GLW Upgrade project was listed as one of four economic study requests submitted. GLW wished to clarify that it also submitted a second economic study request to upgrade the facilities to reduce the curtailment for Southern Nevada Geothermal and provide a looped network for the Control Substation. The upgrades recommended for study in this second GLW economic study request would ensure delivery of the geothermal resources to load centers in California. The CAISO did not study these requested upgrades in this cycle, and the draft plan fails to mention the submitted request.

The portfolios for the 2022 – 2023 TPP have noted increases to the geothermal resources mapped to Southern Nevada, to a total of 440 MWs. GLW respectfully requests that the CAISO study this upgrade in 2022 – 2023.

With respect to Section 4.10, the CAISO’s out-of-state (OOS) wind study, GLW also wishes to commend the CAISO for its extensive analysis of the OOS wind options, including its presentation of comparative/relative benefits for the alternatives based on a wide array of sensitivity case runs the CAISO conducted. GLW wishes to respond to the aspects of the study that examine the impacts of the GLW Upgrades on the various alternative OOS wind solutions, especially in light of some of the questions raised during the CAISO’s TPP meeting that could be interpreted to suggest that the GLW Upgrades may adversely affect one or more of OOS wind projects. The CAISO specifically addressed this issue in its analysis and presents those results in Section 4.10.8. Noted by the CAISO in this section and during the meeting is the outcome that under the most beneficial scenarios (e.g., those with phase angle regulator settings which resulted in the highest benefits) the GLW Upgrades resulted in increased benefits of the OOS projects.

GLW compared CAISO Tables 4.10-4 and 4.10-14, which show that for the most beneficial configurations, the GLW Upgrades increase OOS wind project benefits by millions of dollars. (Annual impacts are on the order of $3 million to $17 million for such cases.) GLW has included with its submission a copy of this comparison. In short, the GLW upgrades enhance transmission flows in the area of Eldorado, Harry Allen, and through other GLW interconnections and are only synergistic with each of the various OOS alternatives.

6. Comment on chapter 5 Interregional Transmission Coordination:

 GLW has no comments on this section.

7. Comment on chapter 6 Other Studies and Results:

 GLW has no comments on this section.

8. Comment on chapter 7 Special Reliability Studies and Results:

 GLW has no comments on this section.

9. Comment on chapter 8 Transmission Project List:

 GLW has no comments on this section.

LS Power
Submitted 02/22/2022, 04:33 pm

Contact

Diwakar Tewari (dtewari@lspower.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

LS Power applauds CAISO’s effort to develop a draft transmission plan that is forward looking and takes into consideration the future system needs to integrate renewables in support of meeting the SB100 policy objectives.

LS Power appreciates CAISO continuing to work on the out-of-state (OOS) wind study and SWIP North evaluation as part of the current TPP under an open and transparent stakeholder process. Approval as part of the current TPP would facilitate SWIP North being in service in 2025 ahead of significant resource retirements in California. LS Power is looking forward to being actively involved in the stakeholder process as CAISO continues with this important study.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No comments at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

LS Power supports CAISO’s recommendations to address the South Bay overloads. As noted, the proposed solutions not only address the overloads but also provide benefits in reducing local capacity requirements in the San Jose subarea and overall Greater Bay Area that reduces reliance on the local gas generation. The new HVDC lines offer a creative solution that addresses the imbalance in natural flows while serving the other system needs at the same time.

4. Comment on chapter 3 Policy-Driven Need Assessment:

LS Power offers the following comments on Chapter 3:

  • LS Power supports the proposed Collinsville and Manning 500 kV substations as recommended solutions. These forward looking solutions are important to meet the SB100 policy objectives and will facilitate integration of renewables in addition to addressing the system needs identified in the current TPP cycle.
  • Chapter 3 still describes the Eldorado – McCullough 500 kV tie-line overload issue in the off-peak deliverability study for the base portfolio out-of-state (OOS) wind. However, footnote 132 on page 213 notes that this overload in the preliminary analysis was due to a modeling error and is no longer an issue. The final plan should address this discrepancy.
5. Comment on chapter 4 Economic Planning Study:

LS Power noted and appreciates CAISO’s recognition of additional benefits provided by transmission for OOS wind in the Draft Transmission Plan as compared to the draft results presented in November 2021, and for continuing its SWIP North analysis in this 2021-22 TPP cycle. LS Power offers the following comments for clarification and further refinement on the OOS study, and also suggests ways to gauge market interest from Idaho wind and other renewable resources that could use SWIP North for delivery of energy to California.

Benefit-to-Cost Ratio Methodology, Results and Interpretations

  • A review of the Benefit-to-Cost Ratio (BCR) results for OOS transmission projects shows that SWIP North ranks very high with a BCR greater than 1.0 (minimum required for a project to be economic) in every scenario (ID and WY wind, and three phase shifter operating scenarios) considered for the Base Portfolio as well as in every scenario considered for each of the Sensitivity Studies. Most importantly, SWIP-North was the highest performer with BCRs ranging from 2.30 to 2.49 for the Idaho wind scenarios with the expected phase shifter operating condition (-48 degrees). The production cost model (PCM) results demonstrate SWIP North as a truly “no-regrets” transmission project that can deliver WY and ID wind to CAISO with benefits significantly outweighing the cost.
  • LS Power applauds CAISO’s approach of looking at BCR rather than just raw production cost benefits. The production cost benefits identified in Section 4.10.5 (and Table 4.10-3) should not be compared directly as they do not account for significant differences in transmission costs. This is simply an intermediate step to support the BCR calculation which begins on page 313. Therefore, Figure 4.10-4 is somewhat misleading and should be removed from the report.
  • CAISO explains in the alternative BCR calculation methodology that it is important to recognize the cost of delivering NM wind to Pinal Central as this is the reference case that is being used to compare to the cases with ID/WY wind. The ID/WY OOS wind is modeled at the resource locations, whereas NM wind is modeled at Pinal Central which unduly advantages NM wind in the initial method of BCR calculation (column 7 of Table 4.10-4). Therefore, the initial method of BCR calculation and the conclusions drawn from it (i.e., that no project received over 1.0 BCR such that “none of the transmission alternatives had sufficient economic justification” (p. 314, para. 1) is incomplete and should be removed from the final report. CAISO addresses this issue in part in the alternate method by giving credit to ID/WY wind transmission projects for the avoided cost of transmission in AZ/NM resulting in more appropriate BCRs (column 9 of Table 4.10-4), but the stated conclusion  on the Base portfolio OOS wind BCR results should be updated in the final report for consistency.
  • On top of the avoided cost of SunZia transmission in column 9, the BCRs should also account for the avoided cost of additional transmission facilities (or wheels)[1] and transmission losses[2] required for SunZia and Cross-Tie sourced generation to reach the CAISO injection points at Palo Verde or Harry Allen.  Appropriately accounting for these costs will reinforce the value of SWIP North through even higher BCRs.

OOS Transmission Cost Assumptions

  • Section 4.10.2 notes that the SWIP South (Robinson Summit to Harry Allen, or ON Line) rating can be increased to 2000/2000 MW with the Cross-Tie upgrade. LS Power would like to reiterate that the SWIP South upgrades are part of the SWIP North Plan of Service pursuant to the FERC-approved Transmission Use and Capacity Exchange Agreement (TUA) between NV Energy and LS Power affiliates, enabling an increase in SWIP South capacity that is substantially reserved by LS Power. The cost for these upgrades are included in the SWIP North project cost estimate cited by CAISO. The Final report should remove the association of these upgrades with the Cross-Tie project and consider that Cross-Tie will require a new 231 mile transmission line from Robinson Summit to Harry Allen to deliver to CAISO and incur the costs associated therewith.

Clarifications and Recommendations for the Report

  • Section 4.10.2 identifies the capacity of SWIP North as 2000 MW in each direction, and the PCM enforces that 2000 MW interface limit with CAISO ownership at 50%. CAISO’s assumption is consistent with the 2020 Interregional Transmission Project filing for SWIP North.  However, LS Power submitted updated information to CAISO in August 2021 clarifying approximately 1100 MW of north-to-south capacity will be available for CAISO use[3]. This is further supported by the latest WECC Path Rating studies that have now established Phase 2B status for the project as of January 2022[4]. This higher capacity being made available to CAISO will increase PCM benefits for SWIP North compared to those in the Draft Transmission Plan.
  • Regarding the sensitivity study results presented in Tables 4.10-11 and 4.10-14, LS Power recommends CAISO perform one additional sensitivity case with Gateway West not in service in combination with the GLW Upgrade in service.  This is a realistic scenario that was not included in the analysis.
  • In the Summary and Recommendations section, Table 4.11-1 and the associated narratives seem to have some inconsistent information.  For example, Table 4.11-1 notes for the GLW Upgrade that PCM benefits are not sufficient for consideration, but yet there is economic justification for the project.  Also, regarding OOS transmission, the table indicates the PCM benefits are not sufficient, there is no economic justification, and paragraph 2 of page 329 notes that BCRs are substantially less than one.  This conclusion is not true for SWIP North as noted in the comments above.  SWIP North demonstrated a BCR well above 1.0 in all scenarios of the Base Portfolio studies and Sensitivity studies, with the most relevant scenarios in each of those studies ranging from 2.30 to 2.49, confirming SWIP North is economically justified with benefits that significantly outweigh its costs.
  • The Economic Study should include a comprehensive assessment of benefits, not just those related production costs. This approach is consistent with CAISO’s TEAM methodology and LS Power has previously submitted our detailed comments on this topic on pages 4-6 of our comments in response to the July 27, 2021 stakeholder call[5]

Market Interest for Idaho Renewable Resources

LS Power offers the following suggestions to CAISO for testing the market interest for Idaho renewable resources:

  • CAISO could review the generator interconnection queues in the region to identify resources that have filed for interconnection in the vicinity of the SWIP corridor, and could therefore deliver to CAISO via SWIP (including both SWIP North and LS Power’s capacity on SWIP South). LS Power’s review of the queues managed by Idaho Power, PacifiCorp, NV Energy and CAISO, identified over 8800 MW of non-solar clean energy resources (i.e. wind, geothermal, batteries, and pumped storage hydro) that could potentially sell energy into CAISO via SWIP.  It’s noteworthy that there are other projects being planned in the corridor that are not yet accounted for in the queues but intend to submit new interconnection requests to CAISO if SWIP North is approved for construction by CAISO in the TPP.  As such, commercial interest exceeds the resources actively in the interconnection queues.
  • CAISO could also initiate a request for information (RFI) process to collect necessary information from potential generators that wish to express their interest in accessing the CAISO market via the SWIP corridor. The RFI could request generator nameplate capacity, technology selection, development/permitting status, interconnection status, proposed commercial operation date, proposed point of interconnection, estimated capacity factor and representative production profile. The RFI should provide a method for CAISO to protect any information specific to a developer as strictly confidential. LS Power suggests the RFI be open to all resources to give CAISO a complete picture of available resource diversity, volume, and reliability implications. The goal will be to provide CAISO with confirmation that there is sufficient interest in utilization of the path to serve CA load by resources of interest.  Since 1062 MW of OOS resources are already in CPUC IRP base portfolio, it has already been established in the IRP proceeding that this is a more optimal solution as compared to other resource options. Once SWIP North is approved, LSEs will see OOS resources to be cost competitive during RFO processes.
  • CAISO could request the CPUC to advise on any of the above approaches, since CPUC directed CAISO to consider OOS wind from either Idaho or Wyoming, and recently reaffirmed that in the current IRP, designating 1062 MW of wind injection at Eldorado rather than Palo Verde.

 

 


[1] Transmission cost or wheeling charges to a) bring NM wind from Pinal Central to the CAISO injection point at Palo Verde for SunZia, and b) the cost of additional transmission and/or wheeling to bring WY wind from its resource location to Clover and to further deliver it from Robinson Summit to the CAISO injection point at Harry Allen for Cross-Tie.

[2] Transmission losses between the actual resource location in NM and Palo Verde injection point. Note that the losses are inherently captured in the PCM for ID/WY projects as generation is located behind the transmission at the actual resource locations.

[3] See LS Power’s comments to the July 27, 2021 Stakeholder Call: https://stakeholdercenter.caiso.com/Common/DownloadFile/05329c71-db32-43e6-8afb-1f0dc14c6734

 

[4] Subject to completion of Phase 2B studies, SWIP North path ratings are expected to be approximately 2070 MW north-to-south and 1920 MW south-to-north. SWIP South (ON Line) path ratings are expected to be 2335 MW north-to-south and 2245 MW south-to-north. Pursuant to the aforementioned TUA, this translates to an LS Power allocation of 1117.5 MW southbound and 1072.5 northbound (all to be dedicated for CAISO use) between Midpoint and Harry Allen, with the balance allocated to NV Energy.

[5] See LS Power’s comments to the July 27, 2021 Stakeholder Call: https://stakeholdercenter.caiso.com/Common/DownloadFile/05329c71-db32-43e6-8afb-1f0dc14c6734

6. Comment on chapter 5 Interregional Transmission Coordination:

No comments at this time.

7. Comment on chapter 6 Other Studies and Results:

No comments at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

No comments at this time.

9. Comment on chapter 8 Transmission Project List:

No comments at this time.

LSA/SEIA
Submitted 02/22/2022, 01:05 pm

Submitted on behalf of
Large-scale Solar Association (LSA) and Solar Energy Industries Association (SEIA)

Contact

Susan Schneider (schneider@phoenix-co.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Please see attachment

2. Comment on chapter 1 Overview of the Transmission Planning Process:

Please see attachment

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

Please see attachment

4. Comment on chapter 3 Policy-Driven Need Assessment:

Please see attachment

5. Comment on chapter 4 Economic Planning Study:

Please see attachment

6. Comment on chapter 5 Interregional Transmission Coordination:

Please see attachment

7. Comment on chapter 6 Other Studies and Results:

Please see attachment

8. Comment on chapter 7 Special Reliability Studies and Results:

Please see attachment

9. Comment on chapter 8 Transmission Project List:

Please see attachment

Pacific Gas & Electric
Submitted 02/22/2022, 03:14 pm

Contact

Matt Lecar (melj@pge.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

[Intentionally left blank]

2. Comment on chapter 1 Overview of the Transmission Planning Process:

[Intentionally left blank]

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

Two San Jose HVDC Projects:  

PG&E supports the approval of the two HVDC projects as a long-term solution to address the large amount of load growth forecast in the South Bay Area. Our comments focus on the following three aspects: 

Monitor the load forecast in South Bay Area  

According to the 2022 BUILDING ENERGY EFFICIENCY STANDARDS (Energy Code) - TITLE 24 adopted by The California Energy Commission (CEC), expansion of solar and battery storage will be applied to newly constructed buildings including data centers which drive the major load growth in the South Bay Area. With the behind-the-meter resources continuing to evolve in this area, the South Bay load forecast should be closely monitored in the future TPP cycles.  

Conduct more detailed technical studies 

PG&E recommends that CAISO perform more detailed studies before opening-up the two?HVDC projects for public solicitation, or build into the competitive process that the project scopes could be subject to change after being awarded based on the conclusion of the necessary studies mentioned above.     

In the CAISO 2021-2022 draft Transmission Plan, CAISO recommended the new Collinsville 500 kV project in the East Bay area as a policy driven project.  It addresses a few identified deliverability constraints in the PG&E area and provides an additional source of supply from the 500 kV system into the East Bay area. Since East Bay has direct 230 kV transmission connection to South Bay area, this Collinsville 500 kV project could bring higher power flow injection to Newark Substation, and therefore impact the flow distribution pattern for the South Bay area. PG&E suggests that the HVDC projects and Collinsville 500 kV project should be studied together to identify any potential interactions and adverse impacts under any contingencies on the 500 kV or below.  

PG&E also recommends the use of standardized HVDC models to run both steady-state and dynamic analysis to determine any possible adverse impacts from the transient stability perspective. 

In addition, some selected contingencies from neighboring entities other than PG&E in the area need to be studied to avoid any undesirable consequences from this project impinging on the neighboring systems, and to identify any potential affected system impact in an early stage. 

Interim plan 

The expected in-service date for the HVDC projects will be beyond year five. In the interim, PG&E will continue working with CAISO and SVP to scope and finalize the interim plan and ensure that the reliability issues in the South Bay Area can be temporally addressed according to the stage of projected load ramping before the HVDC projects are in-service. 

 

4. Comment on chapter 3 Policy-Driven Need Assessment:

Midway-Whirlwind re-rate Project: 

CAISO in the off-peak deliverability assessment of the policy study identified a pre-contingency overload on the Midway–Whirlwind 500 kV line. As the mitigation, CAISO recommends to re-rate the PG&E segment of the Midway–Whirlwind 500 kV line to 2146/2567 MVA normal/4-hour emergency rating. The CAISO will coordinate with PG&E and SCE to further investigate and implement the re-rate.   

Overall PG&E supports the CAISO’s effort to mitigate the overload observed in the off-peak deliverability assessment. However, the current rating of the segment of the line is 1503/3264 MVA normal/30 minutes emergency. The current emergency rating is significantly higher than the proposed rating. And such rating has been used in both Operations and all the past Planning studies. As the recommended rating will introduce a reduction in the current emergency rating, PG&E recommends the CAISO perform studies to evaluate if there is any potential reliability impact on Operations or in the Planning horizon before proceeding with the “rerate recommendation”. Alternatively, which is also preferred, PG&E recommends the CAISO evaluate the implementation of “dynamic ratings” on the Midway–Whirlwind 500 kV line. For example, when the emergency rating is more limiting, the current rating can be used, and when the normal rating is limiting, the recommended rating will be used.    

It also appears the recommended rating is already in the CAISO Transmission Register, specified as Rating D and E. PG&E recommends the CAISO further confirm if there is a need for re-rate. 

Manning and Collinsville Substation Projects: 

The CAISO, in its policy study, recommended the following projects:     

  • New Collinsville 500 kV substation   
  • New Manning 500 kV substation   

The recommended (2028) in-service dates for the above projects appear to be aggressive. PG&E recommends the CAISO coordinate with PTO(s) on the feasibility of the timeline to interconnect the projects once the project specifications are developed.     

PG&E appreciates the CAISO leveraging its policy study to develop major projects for meeting the state’s renewable energy and greenhouse gas (GHG) reduction targets. It appears the current policy study is limited to deliverability assessment and economic study with selected scenarios and selected contingencies. It is unclear if the Projects developed from such study process were tested in a full reliability assessment which includes studying all the TPL-001 required P0 through P7 contingencies in power flow, transient stability studies. Additionally, the potential Adverse Impacts on neighboring systems do not appear to be assessed, for example the potential impact from Collinsville to Path 66 and from Manning to Path 15. 

Recommended projects without complete assessments, can have unintended reliability impacts and/or potential Adverse Impacts on neighboring systems. Without confirming if there is any and what the mitigation would be for the reliability impact and neighboring system impact, the recommended scopes of these projects may be incomplete, and the cost estimate considered for the project justification may be too low.  PG&E recommends the CAISO complete the necessary studies for evaluating reliability impacts (steady state, transient stability, and voltage stability), neighboring system impacts, and any required studies from the applicable WECC process, before finalizing the project scopes for competitive solicitation. While it is critical to confirm the complete scopes of the projects, PG&E understands the recommended projects will take substantial time to implement. If the CAISO sees a strong need to approve the currently identified scopes for the projects, PG&E recommends the CAISO approve and build into the competitive process that the project scopes could be subject to change after being awarded based on the conclusion of all necessary studies.     

5. Comment on chapter 4 Economic Planning Study:

Moss Landing-Las Aguilas Series Reactor Project: 

According to PG&E’s preliminary feasibility review of the Moss Landing-Las Aguilas Series Reactor project, it is difficult to install the new series reactor at Moss Landing substation due to space limitation and environmental sensitivities associated with Substation expansion. However, while installing the reactor at Las Aguilas is feasible, station expansion or re-configuration will be required to provide space for the reactor as well as a bypass breaker. PG&E’s ballpark estimate for the total project cost is $30M-$40M, which is higher than the $26 million estimate shown in the Draft Transmission Plan on page 299. 

6. Comment on chapter 5 Interregional Transmission Coordination:

[Intentionally left blank]

7. Comment on chapter 6 Other Studies and Results:

[Intentionally left blank]

8. Comment on chapter 7 Special Reliability Studies and Results:

[Intentionally left blank]

9. Comment on chapter 8 Transmission Project List:

[Intentionally left blank]

PIOs/ CEAs
Submitted 02/25/2022, 12:41 pm

Submitted on behalf of
PIOs/CEAs: Brightline Defense, CEERT, EDF

Contact

Julia Prochnik (julia@jasenergies.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

see attached 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

see attached 

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

see attached 

4. Comment on chapter 3 Policy-Driven Need Assessment:

see attached 

5. Comment on chapter 4 Economic Planning Study:

see attached 

6. Comment on chapter 5 Interregional Transmission Coordination:

see attached 

7. Comment on chapter 6 Other Studies and Results:

see attached 

8. Comment on chapter 7 Special Reliability Studies and Results:

see attached 

9. Comment on chapter 8 Transmission Project List:

see attached 

Quanta Technology
Submitted 02/22/2022, 05:24 pm

Contact

Ali Daneshpooy (adaneshpooy@quanta-technology.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

No comment

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No Comment

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

We appreciates the transparent and detailed transmission process and the efforts of the CAISO team to provide valuable information on its findings.

The CAISO has recommended two HVDC transmission projects in the San Jose area for competitive bidding in the 2021-2022 transmission plan. We appreciate it if the CAISO review the following comments regarding these two projects.  

  1. The CAISO has considered three alternative projects in the selection process for these two HVDC projects. The question is, are three alternatives adequate to decide for $750M to $1.13B spending? Additional alternative projects to consider can include a phase-shifting transformer to address the imbalance between two sources in the AC connected network and to provide the required controllability. Additionally, hybrid solutions including energy storage systems can address reliability issues identified in the area.
  2. Typically HVDC is an economic solution for power transmission over long distances. The two proposed HVDC projects transmit power reportedly over 4 and 13 miles. Although HVDC systems have become more competitive, the underground cable will be an added cost to the HVDC systems. Does the CAISO believe that underground HVDC is a reasonable and economic choice to meet the reliability needs?
4. Comment on chapter 3 Policy-Driven Need Assessment:

No Comment

5. Comment on chapter 4 Economic Planning Study:

No Comment

6. Comment on chapter 5 Interregional Transmission Coordination:

No Comment

7. Comment on chapter 6 Other Studies and Results:

No Comment

8. Comment on chapter 7 Special Reliability Studies and Results:

No Comment

9. Comment on chapter 8 Transmission Project List:

Same comments as ones in section 3.

RWE
Submitted 02/22/2022, 04:59 pm

Contact

Jennifer Ayers-Brasher (Jennifer.Ayers-brasher@rwe.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

RWE Renewables Americas (RWE) appreciates the opportunity to participate in the CAISO stakeholder process.  RWE is active both in the US and across the globe in wind, solar, storage and offshore wind with over 5,000 MW of operating projects in the US and several coming online in the next couple of years in CAISO.  RWE is also a member of several industry groups active in CAISO representing wind, solar and storage.

 

RWE applauds the work put into transmission planning by CAISO and the long term assessment. Planning transmission for the CAISO grid and achieving the California future goals of renewable energy independence requires focus and dedication form all parties.  It is also a different grid than it was in the past and requires planning to support getting power to the loads reliably from all locations.

 

As mentioned, RWE develops all technologies and has active solar and storage projects in process in CAISO today.  We also appreciate the inclusion of the offshore opportunities and we look forward to the further development of the offshore potential connecting to the CAISO grid and the necessary transmission expansion for load to benefit. RWE strongly encourages CAISO to continue to review the expanded offshore portfolio potential.

 

The diverse portfolio of generation by type and by locations presents great opportunity to meet the necessary resource adequacy.  It will be important for CAISO to ensure that there is opportunity for all resources to play their integral role and transmission to be built to do so.

 

RWE encourages CAISO to continue and looks forward to participating in the future with CAISO and other stakeholders.  Identifying the best transmission, approving it and moving forward on the implementation in a timely manner is critical to meet the upcoming needs. 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

RWE will follow-up with further comments in future opportunities 

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

RWE will follow-up with further comments in future opportunities 

4. Comment on chapter 3 Policy-Driven Need Assessment:

RWE will follow-up with further comments in future opportunities 

5. Comment on chapter 4 Economic Planning Study:

RWE will follow-up with further comments in future opportunities 

6. Comment on chapter 5 Interregional Transmission Coordination:

RWE will follow-up with further comments in future opportunities 

7. Comment on chapter 6 Other Studies and Results:

RWE will follow-up with further comments in future opportunities 

8. Comment on chapter 7 Special Reliability Studies and Results:

RWE will follow-up with further comments in future opportunities 

9. Comment on chapter 8 Transmission Project List:

RWE will follow-up with further comments in future opportunities 

SDGE
Submitted 02/22/2022, 03:56 pm

Contact

Alan Soe (alansoe@gmail.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

<No Comment>

2. Comment on chapter 1 Overview of the Transmission Planning Process:

<No Comment>

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

SDG&E applauds CAISO’s approval of transmission projects in lieu of RAS in PG&E area and the recognition that RAS may be too complex in certain scenarios. This is a best practice that we support applying to the entire CAISO footprint more equitably. This may also be a good opportunity to continue discussion and development around the RAS guideline to ensure reliability of the system going forward. SDG&E further encourages a comprehensive review of all instances where system collapse may be an issue. If projects are being approved based on potential system collapses in one area, the same methodology should be used more equitably in the entire CAISO footprint. 

SDG&E notes that several of its RAS and non-BES schemes do not follow the current CAISO guideline and recommends that the CAISO, in collaboration with SDG&E, review existing RAS and ensure they comply with the CAISO RAS guideline. For instance, certain SDG&E RAS trip more than the 1100 and 1400 MW limits specified in the standard. Another example is, several SDG&E’s RAS require real-time operator actions to arm or disarm the RAS or change set points based on complex computations. We already have complex RAS today that arms a lot of generation that should be replaced by transmission projects to increase reliability. We have proposed a new Miguel – Suncrest 500KV line that will help in this regard. It replaces the current RAS that has proven to be ineffective in operations. We disagree with CAISO’s assessment that current operational actions, including the RAS, as sufficient to meet the needs in this area. 

SDG&E urges further consideration of the TL13810 reconductoring as a reliability and policy project. The benefits of this project will be observed in many areas, including the policy goals in the 20-Year Transmission Outlook. This will be a reliable solution that cuts down on the amount of complex RAS in our system. Further, it is a simple and inexpensive solution that can be implemented quickly. Lastly, we point out that this project has already been selected by RESOLVE as a transmission upgrade in their resource portfolio for the 22-23 TPP. This project is known as the “Internal San Diego Area Reconductoring” project that will include the TL13810 portion that we have previously recommended. 

SDG&E notes that transmission projects, specifically many of those identified in the TPP may have extremely long lead times. Based on our experience, HVDC lines require intricate planning and permitting where the 5-year lead time may not be feasible. Subsequently, it may be necessary to advance approval timeframe of these transmission projects. Given that loads and resources will gradually materialize on the electric grid to reach the levels forecasted, some of the transmission needs will be needed sooner. Having a 15-year policy aligned forecast from the CEC and used by the CAISO will help determine which transmission needs should be expedited. Furthermore, because it can take more than 10 years to build long-lead transmission projects, relying on the traditional 10-year TPP framework means that we might already be behind. 

4. Comment on chapter 3 Policy-Driven Need Assessment:

<No Comment>

5. Comment on chapter 4 Economic Planning Study:

<No Comment>

6. Comment on chapter 5 Interregional Transmission Coordination:

<No Comment>

7. Comment on chapter 6 Other Studies and Results:

<No Comment>

8. Comment on chapter 7 Special Reliability Studies and Results:

<No Comment>

9. Comment on chapter 8 Transmission Project List:

<No Comment>

Silicon Valley Power
Submitted 02/21/2022, 11:43 am

Contact

TU HU (Thu@SantaClaraCA.gov)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

The City of Santa Clara dba Silicon Valley Power (SVP) appreciates the opportunity to comment on the CAISO Draft 2021-2022 Transmission Plan (Draft Plan, hereafter). SVP appreciates the CAISO staff’s tremendous efforts throughout this planning, resulting in the CAISO recommending both short- and long-term solutions to address the SVP’s reliability issues. We appreciate the efforts of both the CAISO and PG&E to solve the reliability of service to the rapidly growing SVP load, chiefly due to tremendous interest in hyper-scale data centers to be located in the City of  Santa Clara.  In these comments, SVP seeks to clarify the CAISO-proposed transmission solutions while expressing concerns about the need to address SVP’s reliability issues until the long-term solution is implemented.

SVP strongly supports the CAISO’s recommendation to approve both the short-term and long-term mitigation projects in the SVP/San Jose area in the current planning cycle, but recommends the CAISO develop additional mitigations until the long-term solution is built.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No Comments at this time.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

As the Draft Plan states, “(T)his year’s load forecast included significant load increase of about 500 MW (~75 percent) in the Silicon Valley Power (SVP) area. As a result, multiple near-term and much more long-term overloads were identified in the San Jose 115 kV system. The near-term issues include overloads driven by P2, P6, and P7 category contingencies. However, the mid and long-term issues include overloads driven by P1 contingencies as well along with multiple overloads driven by other category contingencies.”[1] SVP endorses the Draft Plan’s overall rationale for recommending approval of the two HVDC lines in the area, that is, one 500 MW HVDC line from Newark 230 kV to SVP’s NRS 230 kV substation and another 500 MW HVDC line from Metcalf 500 kV to San Jose B 115 kV substation.[2]

 

SVP understands that the HVDC from Newark is envisioned to terminate at a DC terminal at the Los Esteros substation. Then, there would be a  dedicated 230kV AC circuit from Los Esteros to SVP’s NRS substation. On the contrary, the Draft Plan provides the impression that under the HVDC Newark 230kV to NRS 230 project, the HVDC line will terminate at the DC terminal at NRS. SVP requests the CAISO to include a corrected description of the HVDC project in the Final Transmission Plan presented to the CAISO Board, showing the HVDC line from Newark 230kV to Los Esteros in conjunction with a 230kV AC line from Los Esteros to the NRS 230kV bus. In addition, two additional 230/115kV transformers have been planned (rated 600MVA) at the NRS substation; thus, SVP recommends that the proposed 230kV AC transmission line from Los Esteros to NRS substation use a conductor with ratings of 600MVA. To match this rating, SVP requests that the HVDC line capacity be expanded from the currently envisioned 500 MW to 600 MW in the Final Transmission Plan.

 

The Draft Plan also states that “in the interim, to address the near-term critical, category P1 contingency driven, issues, the CAISO is also recommending approval of adding series compensation devices on the Los Esteros-Nortech 115 kV line.”[3] The Draft Plan adds that “Current studies show that adding about 2 ohms reactor on the Los Esteros-Nortech 115 kV line would be optimal solution along with running the Silicon Valley Power (SVP) phase-shifting transformer at its limit and energy storage addition in the SVP system.” SVP agrees with the CAISO that the 2-ohm series reactor, by itself, would not be adequate to address the near-term category P1 issues for the SVP system. Moreover, there are additional NERC and CAISO planning criteria, such as P6 and P7, which will be violated in the interim until the HVDC project is constructed.

 

We agree with the CAISO that energy storage by itself cannot be considered a mitigation solution. San Jose system has far less charging capacity compared to the size of energy storage needed to address all reliability issues identified in the area.[4] However, some additional mitigations, such as an amount of energy storage that is consistent with the charging capabilities of the area, would be effective mitigation in the interim to reduce the overloads, if not eliminate them. There is past precedence of the CAISO identifying energy storage as mitigation to address reliability needs. In the 2020-2021 TPP, CAISO identified two battery storage projects to replace two major previously approved transmission projects by considering only the incremental interconnection cost for battery storage.[5] SVP believes that battery storage within the SVP system and other appropriate mitigations would effectively reduce the need for load curtailment under contingencies conditions. In addition to the series compensation project, we urge the CAISO to evaluate further additional mitigations to meet the CAISO planning criteria as part of the short-term solution in the next planning cycle.

 

In summary, SVP strongly supports the CAISO’s recommendation to approve both the short-term and long-term mitigation projects in the SVP/San Jose area in the current planning cycle, but recommends the CAISO develop additional mitigations until the long-term solution is built. Again, SVP appreciates the opportunity to comment on the Draft Plan and acknowledges the significant efforts of the CAISO staff to develop proposed mitigations to address CAISO planning criteria violations which should reduce the probability of load curtailment by SVP.

 


[1] Draft Plan, p.103.

[2] Ibid.

[3] Draft Plan, p.105.

[4] Draft Plan, p.104.

[5] CPUC Decision Adopting 2021 Preferred System Plan, Rulemaking 20-05-003, December 22, 2021, pp. 153-1541. (1) A 95 MW 4-hour storage resource on the Kern-Lamont 115 kilovolt (kV) system eliminated the need for the Wheeler Ridge Junction Project; and (2) A 50 MW 4-hour storage resource at the Mesa 115 kV substation eliminated the need for the North of Mesa Project.

4. Comment on chapter 3 Policy-Driven Need Assessment:

No Comments at this time.

5. Comment on chapter 4 Economic Planning Study:

No Comments at this time.

6. Comment on chapter 5 Interregional Transmission Coordination:

No Comments at this time.

7. Comment on chapter 6 Other Studies and Results:

No Comments at this time.

8. Comment on chapter 7 Special Reliability Studies and Results:

No Comments at this time.

9. Comment on chapter 8 Transmission Project List:

No Comments at this time.

Smart Wires
Submitted 02/22/2022, 04:51 pm

Contact

Kaveh Aflaki (Kaveh.Aflaki@smartwires.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Smart Wires appreciates this opportunity to provide comments on the CAISO 2021-22 Draft Transmission Plan. Smart Wires commends the CAISO for the thorough and meticulous studies performed. The comments below address material presented at the CAISO Stakeholder meeting on February 7, 2022.

Smart Wires would like to recommend the CAISO to use the term “series compensation” or “power flow control device” instead of “series reactor” or “series capacitor” in the proposed projects that utilities such series devices.  While this may seem like a small change or even trivial change, Smart Wires believes it is an important datum to help convey that such proposed projects would allow the applications of other newer technology options to provide the same or better results.  There are newer technologies today, supporting the desired results with better and more flexible operating characteristics.  More new technologies will also become available in the future.  Therefore, Smart Wires respectfully suggests that the CAISO uses terms that are technology neutral in project names and projects descriptions to not leave impressions that can limit technology application options. 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

-

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

Section 2.2.5.3, on the Interim project for the South Bay Overloads, “Series Compensation on Los Esteros-Nortech 115 kV Line” Project (pleases see also Table, 8.2-1, page 377), the detailed description on page 105 references a 2-ohms reactor on the Los Esteros-Nortech 115 kV line.  Please clarify that this reference does not preclude the use of a "series compensation" device that can produce an equivalent inductive impedance of 2-ohms for project recommended for approval. 

4. Comment on chapter 3 Policy-Driven Need Assessment:

-

5. Comment on chapter 4 Economic Planning Study:

In Section 4.9.3, pages 295 – 301, the CAISO recommends approval for the project, “Installing 10 ohms series reactors on the PG&E’s Moss Landing – Las Aguilas 230 kV line” (please see also Table 8.2-3, page 378).  While the studies are meticulous and thorough, the project name and discussions would seem to limit the technology option to only series reactors.  Similarly, the discussions in the studies for the 20-ohms “series reactors” on each of the two the Panoche – Gates 230 kV lines also leave the same impression. 

Smart Wires would like to recommend the CAISO to use the term “series compensation” instead of “series reactor” in the name and discussion of these projects.  While this may seem like a small change or even trivial change, Smart Wires believes it is an important datum to help convey that such proposed projects would allow the applications of other newer technology options to provide the same or better results. 

In addition, it may be beneficial to further refine the proposed solution for a 10-ohms series reactor on the Moss Landing – Las Aguilas.  Table 4.9-18 shows the BCR of 3.19 for switching in the 10-ohm series reactor for the entire year, and Table 4.9-19 shows the BCR of 4.84 for switching in the same-sized series reactor for the summer months only. So, it would seem that a more flexible device that can support more fine-tuned operating patterns may further improve the benefits.  Smart Wires requests that the CAISO allow such fine-tuning in the next steps of the development of this project. Economic studies can show that fixed reactance changes, such as with a series reactor, can result in lower production cost during some times and higher during others. The ability to dispatch the reactance change to match system conditions is required to maximize economic benefit. Smart Wires suggests that the CAISO and PG&E review and confirm that the operations of the series reactor would not result in adverse reliability impacts and identify if a variable change in impedance can result in a higher BCR.  

6. Comment on chapter 5 Interregional Transmission Coordination:

-

7. Comment on chapter 6 Other Studies and Results:

-

8. Comment on chapter 7 Special Reliability Studies and Results:

-

9. Comment on chapter 8 Transmission Project List:

Smart Wires suggests changing the project name from “Installing 10 ohms series reactors on the PG&E’s Moss Landing – Las Aguilas 230 kV line” (Table 8.2-3) to “Install series compensation on PG&E’s Moss Landing – Las Aguilas 230 kV line”.  This change would allow for use of different or newer technologies that can provide the same or better results as installing a 10-ohm series reactor.

Southern California Edison
Submitted 02/22/2022, 03:05 pm

Contact

Fernando Cornejo (fernando.cornejo@sce.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

SCE would like to reiterate and support comments made by SDG&E during the stakeholder presentation regarding the complexity and abundance of remedial action schemes today. Stand-alone and centralized RAS are an important tool in ensuring system reliability and avoiding generation curtailment, but SCE shares the concern that RAS/CRAS have already become quite complicated. The CPUC midterm procurement and future resource outlooks, including the SCE Pathway 2045 white paper, indicate that the need for generation will only continue to accelerate. Limitations on RAS/CRAS monitoring, tripping, and other complexities mean that this new generation cannot be integrated through RAS/CRAS alone. Transmission upgrades will likely be needed to avoid overreliance on RAS and CRAS, and SCE supports the CAISO continuing this discussion with stakeholders.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No comment.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

No comment.

4. Comment on chapter 3 Policy-Driven Need Assessment:

No comment.

5. Comment on chapter 4 Economic Planning Study:

No comment.

6. Comment on chapter 5 Interregional Transmission Coordination:

No comment.

7. Comment on chapter 6 Other Studies and Results:

No comment.

8. Comment on chapter 7 Special Reliability Studies and Results:

No comment.

9. Comment on chapter 8 Transmission Project List:

No comment.

SWPG / Pattern Energy
Submitted 02/22/2022, 03:28 pm

Submitted on behalf of
Southwestern Power Group (SWPG) and Pattern Energy

Contact

Ravi Sankaran (RSankaran@mmrgrp.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Southwestern Power Group (SWPG) and Pattern Energy appreciate ISO’s recognition of the need for an accelerated pace of transmission buildout as compared to previous cycles as exhibited in the Draft 2021-22 Transmission Plan. The Draft Plan accounts for the aggressive expected growth in non-emitting resources while also planning for much needed resource diversity.

SWPG/Pattern’s comments are limited to chapter 4 (question #5) and specifically the Out-of-State Wind Study, and chapter 8 (question #9).

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No comments.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

No comments.

4. Comment on chapter 3 Policy-Driven Need Assessment:

No comments.

5. Comment on chapter 4 Economic Planning Study:

Section 4.10 Out of State Wind Study

SWPG/Pattern are developing the SunZia Transmission Project of which Line 1 will deliver 3 GW of New Mexico wind to California and the western power markets by 2025, with the majority of deliveries to the Palo Verde CAISO hub. In the Out-of-State Wind Study, New Mexico wind delivered via SunZia served as the reference case to which other out-of-state (OOS) wind scenarios from Wyoming and Idaho were compared.

SWPG/Pattern appreciate the breadth and rigor of these studies, which are superior in our view to similar studies conducted in the past because they use data from the actual transmission projects in development despite their different structural elements. We do observe a few areas for refinement, which do not necessarily invalidate the results but can be taken into account for future updates:

  • Capital costs of both generation and transmission projects are currently subject to rapidly changing economic conditions, and therefore project cost estimates undergo frequent revisions. The study uses cost estimates of $2.6B and $2.8B for SunZia and TransWest Express (TWE), respectively, which to us indicates an inconsistent vintage between the estimates given the approximate line lengths of 560 miles for SunZia and 692 miles for TWE. Since the two projects contain similar elements, one remedy is to use a standard cost-per-mile factor for sake of the study, while accounting for the fact that TWE is a blend of HVDC and HVAC whereas SunZia Line 1 is entirely HVAC. Another option is to obtain high-low cost estimates for each project.
  • In the Benefit-to-Cost Ratio (BCR) calculations, the study assumes the WY/ID alternatives avoid 50% of the cost of SunZia. Given that the Base Portfolio study assumes 1,062 MW wind from each location, the 50% avoided cost seems excessive even for a “bookend” scenario. We suggest 35% as a more appropriate measure of the SunZia avoided cost based on 1,062 MW avoided out of 3,000 MW.

Section 4.11 Summary and Recommendations

At the end of this section, CAISO communicates its plans to test for market interest in accessing Idaho wind through an open season in order to evaluate the SWIP North project’s economic study request and to compare it to TWE and SunZia which are proposed on a subscriber basis without regulated cost-of-service recovery. CAISO said on the stakeholder call that such a process is not necessary for TWE and SunZia since those projects have already conducted their open season processes.

SWPG/Pattern simply point out that the open solicitations conducted by SunZia and TWE resulted in generator interest in utilizing capacity on the respective transmission projects as opposed to load-serving entity (LSE) interest in procurement of delivered energy, and therefore in our view a comparable open season process for SWIP North would also be for interest from generators or other entities in utilizing line capacity as opposed to energy procurement interest.

6. Comment on chapter 5 Interregional Transmission Coordination:

No comments.

7. Comment on chapter 6 Other Studies and Results:

No comments.

8. Comment on chapter 7 Special Reliability Studies and Results:

No comments.

9. Comment on chapter 8 Transmission Project List:

Section 8.2 Transmission Projects found to be needed in the 2021-22 Planning Cycle

SWPG/Pattern’s primary comment on the Transmission Project Lists is that the CAISO also consider upgrades triggered by the draft 20-Year Outlook that are not being proposed in the Draft 2021-22 Transmission Plan. While it is understood that upgrades triggered by the 20-Year Outlook are not intended for formal approval in this TPP cycle, CAISO may want to consider those that require long lead-times where some type of high-level feasibility study or comparison of alternatives could be helpful or even necessary to stay on track to meet the 20-year objectives. 

SWPG/Pattern also observe that the projects shown to be needed in this TPP cycle are overwhelmingly located in PG&E territory, specifically 13 of the 16 Reliability projects, 5 of the 7 Policy-driven projects and the only Economic-driven project. It is questionable why the projects are so lopsided towards PG&E territory. Also pursuant to the previous paragraph, the draft 20-Year Outlook contains a more proportional ratio of projects in PG&E, SCE, and SDG&E territories, so CAISO should consider which if any projects in SCE and SDG&E territories may need to be initiated in this TPP cycle.

TransCanyon
Submitted 02/22/2022, 09:58 am

Contact

Richard Stuhan (richard.stuhan@transcanyon.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:
  1. TRANSCANYON

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

  1. TRANSCANYON’S CROSS-TIE TRANSMISSION PROJECT

The Cross-Tie Transmission Line (Cross-Tie) is a proposed 213-mile, 1500 MW, single-circuit 500kV HVAC transmission project that will be constructed between central Utah and east-central Nevada to strengthen the electrical interconnection between the PacifiCorp and the NV Energy transmission systems while supporting interregional power transfers by linking the Rocky Mountain area to the Great Basin area. The project also facilitates CAISO meeting California’s RPS and GHG requirements by increasing transmission capability for CAISO to access Wyoming wind and Utah solar, and for CAISO to export excess solar energy to Utah and Wyoming. Cross-Tie will connect PacifiCorp’s proposed Clover 500kV substation in central Utah with NV Energy’s Robinson Summit 500kV substation in east-central Nevada, which will effectively link the Gateway South Project (PacifiCorp) with the Desert Southwest by utilizing the existing One Nevada Line (NV Energy/Great Basin Transmission, LLC), the planned Greenlink Projects (NV Energy) and the Harry Allen - Eldorado 500kV line (CAISO). The Cross-Tie Project has an estimated cost of $667mm (before the benefits of investment tax credits that would be passed to customers) and a construction period from 2023 through proposed in-service in the fourth quarter of 2026.

  1. TRANSCANYON’S COMMENTS ON THE DRAFT 2021-2022 TRANSMISSION PLAN

TransCanyon appreciates the CAISO’s detailed analysis of its transmission system for the next ten years recognizing significant load growth, climate change impacts, extreme events and changing resource mixes required to achieve the aggressive policy goals that California is marching toward. The recognition that significant improvements are necessary to meet the reliability, policy and economic goals of the state is very timely. TransCanyon supports the CAISO performing more detailed analysis of the benefits of accessing out of state wind. We do encourage the CAISO to continue to improve its assumptions in the benefit to cost analysis of the out of state wind which should include all elements of the CAISO TEAM analysis including assessing the benefit of avoided cost of solar and storage resources within California being replaced by out of state wind. We also recommend that all permutations of wind and transmission projects be assessed from the base portfolio rather than the comparison of Idaho and Wyoming wind to New Mexico wind that was performed during the CAISO 2021-2022 Transmission Planning Process. TransCanyon stands ready to assist the CAISO in any way it can as we move forward with the 2022-2023 Transmission Planning Process.

TransCanyon also encourages the CAISO to broaden the proposed market test for interest in Idaho wind to also include Wyoming wind to ensure that the most cost-effective solution is identified. TransCanyon is not opposed to potential TAC recovery of the capital cost of Cross-Tie if that combined with access across other lines would be of benefit to CAISO load-serving entities. TransCanyon already has a FERC approved formula rate developed when TransCanyon submitted its proposal to develop the Delany to Colorado River project for the CAISO.

  1. NOTICE AND COMMUNICATION

Service of notices, orders, and other communications and correspondences in this proceeding should be directed to TransCanyon at the address set forth below:

Jason R. Smith

President

TransCanyon
400 East Van Buren Street, Suite 350

Phoenix, AZ 85004
Tel: 602 250 2668

Email:Jason.Smith@TransCanyon.com

  1. CONCLUSION

TransCanyon appreciates the opportunity to participate in the CAISO 2021-2022 Transmission Planning Process and applauds the CAISO efforts to ensure transmission development in the CAISO footprint supports the future reliable and efficient system to enable California to meet its future reliability, policy and economic goals. TransCanyon looks forward to working with the CAISO to further refine the Out of State Wind Analysis to determine how the Cross-Tie Project fits in future CAISO plans.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

See response to question #1 or the attached comment letter.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

See response to question #1 or the attached comment letter.

4. Comment on chapter 3 Policy-Driven Need Assessment:

See response to question #1 or the attached comment letter.

5. Comment on chapter 4 Economic Planning Study:

See response to question #1 or the attached comment letter.

6. Comment on chapter 5 Interregional Transmission Coordination:

See response to question #1 or the attached comment letter.

7. Comment on chapter 6 Other Studies and Results:

See response to question #1 or the attached comment letter.

8. Comment on chapter 7 Special Reliability Studies and Results:

See response to question #1 or the attached comment letter.

9. Comment on chapter 8 Transmission Project List:

See response to question #1 or the attached comment letter.

TransWest Express LLC
Submitted 02/22/2022, 03:55 pm

Contact

David Smith (david.smith@tac-denver.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

TransWest Express LLC (“TransWest”) congratulates the CAISO on the preparation of the draft 2021-2022 Transmission Plan (“Draft Plan”) and the draft inaugural 20-year Transmission Outlook (“Draft Outlook”). The Draft Plan and Draft Outlook detail the extensive proactive transmission planning efforts to which the CAISO has committed to help lead California and the Western region toward a 21st century electric grid.  The size and scope of transmission infrastructure investments envisioned as necessary to provide reliable electrical service while transitioning to a lower greenhouse gas (“GHG”) emitting resources is staggering, although not surprising. Because of the advanced stage of development of its TWE Project, TransWest is ready to contribute to this important transition.

TransWest appreciates the opportunity to provide comments in support of the CAISO’s efforts and feedback on the Draft Plan and Draft Outlook.  TransWest’s comments include a status update on the TransWest Express Transmission (“TWE”) Project; we request that the CAISO reflect this update in the final documents to ensure accuracy regarding the TWE Project.  TransWest’s other comments focus on the on the “out-of-state” wind resource elements, with a focus on the Wyoming wind portion. 

TransWest Express Project Status Update

The TWE Project is in an advanced stage of development, focused on finalizing pre-construction matters including tower design and testing, interconnections, EPC contracting, and financing. 

TransWest plans to build and operate the TWE Project using a merchant transmission model.  In February 2021, FERC granted TransWest negotiated rate authority and approved the Open Solicitation process proposed by TransWest.[1]  The Open Solicitation process was conducted between June and November 2021 and was open to all market participants seeking access to Wyoming resources and to Wyoming resources seeking access to California markets.[2]  The capacity offered through the TWE Project Open Solicitation included long-term, firm point-to-point transmission service packaged as two south-bound products, including a 1,500 MW Wyoming to Utah product and a 1,500 MW Wyoming to Nevada product. TransWest ultimately negotiated Customer Agreements that allocated 100% of the TWE Project capacity offered in the Open Solicitation to the Power Company of Wyoming LLC (“PCW”).

PCW plans to use the 1,500 MW of Wyoming to Nevada capacity that includes offtake to the CAISO Controlled Grid and the NV Energy System in Nevada to offer a firm Wyoming wind product to be delivered into the CAISO-controlled market.  TransWest’s primary interest is to ensure that this 1,500 MW of Wyoming wind can be reliably and efficiently integrated within the CAISO Controlled Grid starting in 2026.  Integrating this Wyoming wind will assist in meeting the market’s needs for diverse renewable resources that can be delivered on a firm basis as Category 1 RPS products while also meeting resource adequacy requirements.  More specifically, TransWest is pursuing the following objectives:

  1. Lower CAISO customer costs by providing LSEs with access to 1,500 MW of Wyoming wind resources over new transmission infrastructure to meet both mid-term reliability and integrated resource planning identified resource needs;
  2. Not require the CAISO to approve a transmission rate increase to access 1,500 MW of Wyoming resources (i.e., the costs of the TWE Project line would not be recovered through the CAISO’s Transmission Access Charge);
  3. Allow the CAISO and California LSEs to access up to 30% (1,500 MW of the 5,000 MW) of the Wyoming/Idaho resources and 15% (1,500 of the 10,000 MW) of out-of-state wind requiring interregional transmission infrastructure investment that is envisioned in the Draft Outlook; and
  4. Simultaneously provide California municipal and other regional utilities in the Desert Southwest an additional 1,500 MW of delivered Wyoming wind resources to meet their respective medium- and long-term needs, which will help better integrate the Western markets.

TransWest supports the proposed extension of the 2020-2021 Transmission Planning Process (“TPP”) to continue engagement with the industry to gauge interest in Idaho resources.[3]  The potential to add 1,100 MW of Idaho resources to the committed 1,500 MW of Wyoming resources would still only represent 25% of the out-of-state resources requiring new interregional transmission infrastructure investment in the Draft Outlook.  The 2,600 MW of Full Capacity Deliverability Status (“FCDS”) wind resources being considered within the 2021-2022 TPP extension exceeds the 1,062 MW FCDS in the base portfolio.  However, the sensitivity portfolio, which was based on a 38 MMT GHG target, similar to this year’s base portfolio, included 3,000 MW of FCDS out-of-state wind resources.

TransWest notes that the TWE Project and SWIP-N are the only two advanced developed transmission projects that the CAISO can act on as part of the Draft Plan through integration and/or direct investment actions to access out-of-state wind resources.  The other transmission alternatives either do not connect to the CAISO-controlled grid and/or are being developed solely to meet Northern Grid member regional needs.  TransWest will continue to participate in the CAISO TPP as well as the regional planning processes conducted by Northern Grid and WestConnect.

Results of Policy Driven CAISO Footprint Assessment for Out-of-State Wind on New Transmission

TransWest agrees with the following key findings with respect to the 1,500 MW of FCDS capacity available at Eldorado for Wyoming wind resources and the 1,500 MW at Palo Verde for New Mexico resources. 

As requested by the CPUC, the CAISO studied the potential transmission implications and requirements inside the CAISO footprint of 1062 MW of out-of-state wind generation being injected at each of Eldorado (representing potential new capacity from Wyoming or Idaho), or Palo Verde (representing potential new capacity from New Mexico). The CAISO found that injections from these sources, as part of the base case portfolios provided the planning cycle, triggered no additional transmission requirements. However, the CAISO notes that the resources seeking to interconnect to the CAISO queue far exceed the current portfolio amounts – and current needs. Those volumes in the interconnection queue, that have already been allocated deliverability for purposes of providing resource adequacy capacity subject to meeting their obligations to advance through to commissioning, would fully utilize existing and planned transmission capacity, if they proceed. The sensitivities conducted with 1500 MW being delivered to both injection points led to the same conclusion.[4]

To ensure future planning activities, including those driven by the CAISO interconnection queue activities, the CAISO should assume up to 1,500 MW of regional wind resources will be imported at the Eldorado and Palo Verde locations.  This planning assumption would ensure the CAISO queue management system does not oversubscribe this capacity until an equitable resource adequacy capacity allocation mechanism is developed. TransWest notes the CAISO interconnection queue process does not provide a mechanism for diverse regional resources to be allocated deliverability for purposes of providing resource adequacy capacity.  This should be addressed outside of the TPP. 

In addition, the TPP extension to further consider the SWIP-N project would need to ensure that 2,600 MW of FCDS capacity is available at the CAISO boundary to accommodate: (a) 1,500 MW of TWE Project delivered products; (b) the potential for 1,100 MW delivered over SWIP-N; and (c) other CAISO Network Upgrades and RA deliverability allocations.

TransWest suggests the key finding from the Executive Summary excerpted above should be included within the conclusion section of the policy-driven Assessment section.  TransWest expands on this recommendation below in its comments on Chapter 3.


[1] FERC Order (ER21-645-000), February 2021.

[2] A TWE Project Open Solicitation website was established and remains operational to provide the public with information about the Project and the process.  See www.transwestexpress-os.com.

[3] See Draft Plan at 7.

[4] See Draft Plan, Executive Summary, at 6.

 

2. Comment on chapter 1 Overview of the Transmission Planning Process:

No Comment.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

No Comment.

4. Comment on chapter 3 Policy-Driven Need Assessment:

Analysis of External Transmission Needs to Deliver Out-of-State Wind Resources

The California Public Utilities Commission’s (“CPUC”) requested that CAISO examine the transmission needed to deliver Wyoming wind and other out-of-state resources to the CAISO system.[1]  In addressing this request, it is not clear why CAISO used economic analysis featuring production cost modeling instead of the peak and off-peak deliverability assessment.  The Draft Plan would benefit from an explanation as to why deliverability assessments were not conducted.   (TransWest provides recommendations regarding the economic analysis performed for the out-of-state resources in its comments below on Chapter 4).

The deliverability assessment of remote CAISO generators located in Wyoming would be fairly straight forward to conduct and analyze.  Based on transmission alternatives data included in the Draft Plan and assumed costs for the Gateway South and Gateway West projects, TransWest believes that a deliverability assessment would have the following results:

  • 1,500 MW of wind resources in the Wyoming area will be constrained unless the following transmission investments are made:
    • TWE Project: 1,500 MW of 3,000 MW of HVDC segment and the 1,500 MW, 500 kV AC segment to Harry Allen, $2,223M (i.e. $1.48/MW);
    • SWIP-N: 400 MW constrained, 1,100 MW of 500 kV capacity from Idaho to Harry Allen ($826M) plus 1,100 MW of firm, long-term capacity on PacifiCorp’s new Gateway West[2] project.   >$2,125M (i.e. $1.93/MW); or
    • Cross-tie project: 500 kV from Clover to Robinson ($945M), plus 1,500 MW of firm, long-term capacity on PacifiCorp’s new Gateway South[3] project and potentially 500 kV line from Robinson to Harry Allen, >$2,600M (i.e. $1.73/MW)
  • 1,500 MW of Idaho wind resources would be constrained unless the following transmission investments were made:
    • SWIP-N: 400 MW constrained, 1,100 MW of 500 kV capacity from Idaho to Harry Allen ($826M)  (i.e. $0.75/MW)
  • 1,500 MW of resources in the New Mexico area would be constrained unless the following transmission investments were made:
    • SunZia: 1,500 MW of 3,000 MW HVDC segment ($1,690), plus 1,500 MW of firm, long-term transmission on existing Arizona system, at an uncertain cost. 

Based on the above results and consistent with the CAISO’s Draft Plan, TransWest believes that the following conclusions can be made:

  1. The TWE Project is the lowest cost transmission needed to deliver Wyoming wind resources to Harry Allen;
  2. The TWE Project has completed an Open Solicitation process and has entered into a Customer Agreement with PCW for 1,500 MW of transmission capacity from Wyoming to Nevada, allowing for the delivery of 1,500 MW of Wyoming wind resources to the CAISO system;
  3. The SWIP-N Project provides the transmission needed to deliver Idaho wind resources to Harry Allen;
  4. The CAISO transmission cost is only lower to access Idaho resources compared to Wyoming resources if you assume the cost for the TWE Project as a CAISO transmission cost.  In fact, the TWE Project cost will not be included in CAISO transmission rates, but instead recovered from TWE transmission customer PCW under its merchant transmission model.  In addition, the CPUC IRP process identified Wyoming and New Mexico as less costly than Idaho wind resources;
  5. The CAISO should test market interest in procurement of Idaho wind resources through the SWIP-N project in order to provide a benchmark for comparing current market interest in the Wyoming resources seeking access to California markets through the TWE Project[4];
  6. The TWE Project and SWIP-N Project together meet 2,600 of the 3,000 MW of out-of-state wind with full RA deliverability (pending review of 2,600 MW of FCDS at Harry Allen);

The SunZia project is needed and will likely have a similar transmission cost level as the TWE Project and the SWIP-N projects, although there is no direct action the CAISO can take other than being sensitive to how future potential upgrades may impact the 1,500 MW FCDS available at Palo Verde.

Section 3.11 Conclusions

TransWest suggests that the key finding excerpted above from the Executive Summary[5] also be included in the policy-driven Need Assessment Conclusion section.  In addition, it would be helpful for CAISO to  provide additional details on how the interconnection queue will be managed when pursuing the TPP policy-driven analysis for out-of-state/out-of-footprint wind resources.  The portfolios currently include out-of-state/out-of-footprint wind resources with full RA deliverability status and a process must be outlined for achieving this status. 

 


[1] See D.21-02-008.

[2] Gateway West is being developed by PacifiCorp to meet Northern Grid regional needs. The Northern Grid Transmission Plan does not include capital costs estimates. An assumed capital cost estimate of $1.275B was used.

[3] Gateway South is being developed by PacifiCorp to meet Northern Grid regional needs. The Northern Grid Transmission Plan does not include capital cost estimates. An assumed capital cost estimate of $1.275B was used.

[4] See Draft Plan at 329.

[5] See Draft Plan, Executive Summary, at 6.

 

5. Comment on chapter 4 Economic Planning Study:

Section 4.10.2 Alternative Transmission Upgrades for Out-of-State Wind

TransWest requests the CAISO update the Draft Plan to accurately describe the TWE Project.  The description used in the 2020-2021 Transmission Plan is accurate with respect to the description of the TWE Project’s three segments.  Within the Draft Plan, half of the HVDC Segment (Segment 1) capacity and cost and the 500 kV AC line from IPP to Crystal/HAE (Segment 2) capacity and cost were studied in the comparative BCR analysis.

The study conducted by the CAISO assumed the TWE capacity was “owned” by the CAISO and funded through the CAISO’s Transmission Access Charge.  These assumptions were required to make a comparative BCR analysis of a hypothetical CAISO approval of the TWE Project as a cost-of-service cost recovery as a participating transmission owner. However, because the TWE Project has completed its subscription process as a merchant transmission line, CAISO approval of an increase in CAISO transmission rates will not be required.

TransWest provides below a redline (additions underlined, deletions struck out) of the Draft Plan to accurately describe the TWE project, with our proposed changes in red.  

TransWest Express Project

Figure 4.10-3 showed the updated diagram of the TWE Project considered in this planning cycle, provided by TWE in September 2021. The project includes two linked segments:

  1. A 405-mile HVDC system between TWE_WY substation in Wyoming and central Utah, including
  • New TWE_WY 500 kV substation in Wyoming;
  • Gateway West and Gateway South 500 kV lines loop-in to the TWE_WY 500 kV bus;
  • Platte - Latham 230 kV line loop-in to the TWE_WY 230 kV bus;
  • New Bi-pole HVDC lines between the TWE_WY substation in Wyoming and the new TWE_IPP substation in Utah with 3000 MW capacity; and
  • a 345 kV connection to the LADPW’s Intermountain 345 kV bus.
  1. A 278-mile 500 kV AC upgrade between the TWE_IPP substation and the CAISO’s Harry Allen – Eldorado 500 kV line. The capacity of this segment is 1500 MW.
  • Three 500/345 kV phase shifters at the TWE_IPP substation.
  • New 500 kV line between the TWE_IPP 500 kV bus and the Crystal North 500 kV bus; and
  • New 500 kV line between the TWE_IPP 500 kV bus and a 500 kV bus on the Harry Allen – Eldorado 500 kV line.

 

The TWE Project includes a third linked segment between the Crystal/Harry Allen area and the Eldorado 500 kV substation. This segment was not considered in this planning cycle.

The estimated cost of segment 1 is $2.1 billion (2020 dollars), and the estimated cost of segment 2 is $660 million (2020 dollars), based on the 2020 ITP submission and the updated scope of the project.

TWE has allocated 1,500 MW of Wyoming to Nevada capacity through a FERC-approved Open Solicitation process to Power Company of Wyoming LLC, whose +3,000 MW Chokecherry and Sierra Madre Wind Energy Project is under construction.  It was assumed in this study for purposes of calculating benefit to cost ratios that half of the capacity and cost of segment 1 and all of the capacity and cost of segment 2, totaling 1,500 MW and $1.71 billion, is modeled as being CAISO “owned” and recovered from CAISO transmission ratepayers through the Transmission Access Charge.

 

Section 4.10.4 through Section 4.11

TransWest agrees with the CAISO’s observation in the Draft Plan that it is challenging to directly compare the production cost modeling results outlined in the Draft Plan.  TransWest does not agree with the inference that the current production modeling results can inform or support the key issues that can be summarized as follows:

  • the TWE Project is using a merchant transmission model, has completed an Open Solicitation Process, and entered into a Customer Agreement with PCW for 1,500 MW of transmission capacity from Wyoming to Nevada;
  • the SWIP-N project is a unique opportunity although the market interest to access Idaho resources by investing in SWIP-N is uncertain; and
  • the CAISO will conduct an open subscription process to gauge interest in accessing Idaho wind resources as part of an extension to the 2021-2022 TPP.

TransWest recommends the CAISO conduct additional economic analysis of the TWE Project and the SWIP-N Project during the 2021-2022 extension to help inform the market on various transmission investment opportunities. Instead of comparing the production costs of the resources assuming that one or another comparable alternative will be built, this analysis should follow the process used for the GLW 230 kV Upgrade and other projects that were also examined as policy-driven projects. 

TransWest recommends that the CAISO conduct a stand-alone BCR production cost analysis of the Wyoming wind resources with and without the TWE Project investment, and a separate analysis comparing the assumed Idaho wind resources with and without the SWIP-N Project investment.  These two production cost comparisons with and without the transmission upgrade for a given resource assumption would then be comparable with the other economic analysis for California, Nevada, Idaho and Wyoming renewable resources and their respective transmission upgrades to supply the CAISO market.

6. Comment on chapter 5 Interregional Transmission Coordination:

No Comment.

7. Comment on chapter 6 Other Studies and Results:

No comment.

8. Comment on chapter 7 Special Reliability Studies and Results:

No Comment.

9. Comment on chapter 8 Transmission Project List:

No comment.

Vistra Corp.
Submitted 02/23/2022, 03:17 pm

Contact

Cathleen Colbert (cathleen.colbert@vistracorp.com)

1. Please provide your organization’s overall comments on the Draft 2021-2022 Transmission Plan Feb 7, 2022 stakeholder call discussion:

Please see attached comments.

2. Comment on chapter 1 Overview of the Transmission Planning Process:

Please see attached comments.

3. Comment on chapter 2 Reliability Assessment – Study Assumptions, Methodology and Results:

Please see attached comments.

4. Comment on chapter 3 Policy-Driven Need Assessment:

Please see attached comments.

5. Comment on chapter 4 Economic Planning Study:

Please see attached comments.

6. Comment on chapter 5 Interregional Transmission Coordination:

Please see attached comments.

7. Comment on chapter 6 Other Studies and Results:

Please see attached comments.

8. Comment on chapter 7 Special Reliability Studies and Results:

Please see attached comments.

9. Comment on chapter 8 Transmission Project List:

Please see attached comments.