The California ISO, in its “Draft 2018-2019 Transmission Plan” released on Feb. 4, noted that it has identified 12 transmission projects with an estimated cost of about $608m as needed to maintain transmission system reliability.
Several of those projects entail a combination of preferred resource procurement and transmission upgrades working together to meet those needs, the filing noted. All of the 12 projects are located in the PG&E service territory and are comprised of 10 smaller projects each less than $50m, totaling $168m, as well as two dynamic voltage support projects totaling $440m.
The filing also said that the 12 new reliability projects found to be needed include the:
- Gates 500-kV Dynamic Voltage Support project, which has an expected in-service date of 2024, and a project cost of $210m to $250m
- Round Mountain 500-kV Dynamic Voltage Support project, which has an expected in-service date of 2024, and a project cost of $160m to $190m
- Tesla 230-kV Bus Series Reactor project, which has an expected in-service date of 2023, and a project cost of $24m to $29m
- Moraga-Sobrante 115-kV Line Reconductor project, which has an expected in-service date of 2023, and a project cost of $12m to $18m
- Lakeville 115-kV Bus Upgrade project, which has an expected in-service date of 2022, and a project cost of $10m to $15m
The filing also noted that one economic-driven transmission project with an estimated capital cost of less than $5m is recommended for approval, providing energy cost savings by alleviating local congestion. The new economic-driven transmission project found to be needed is the Giffen Line Reconductoring Project in the PG&E service area with a project cost of $5m; the expected in-service date is noted in the filing as “TBD.”
The filing noted that in reviewing previously approved projects in the PG&E service territory that were identified in the last planning cycle as needing more review, six projects are recommended to be canceled, paring between $440m and $550m from the ISO transmission capital program estimated costs; one other project will continue to be on hold pending reassessment in future cycles.
For instance, the ISO recommends to cancel the Jefferson-Stanford #2 60-kV Line project in the Greater Bay Area, which was put on hold due to load uncertainty in the area. To address the “P6 contingency,” the ISO is recommending an operating solution to open Bair-Cooley Landing 60-kV lines following the first contingency for P6 overloads, the filing added. To address the “P7 contingency,” the ISO is recommending the Jefferson 230-kV Bus Upgrade project to keep the Jefferson-Martin 230-kV cable in service following the P7 contingency of the Monta Vista-Jefferson 230-kV lines. The filing added that the estimated cost of the alternative is $6m to $11m with an in-service date of 2022.
The filing noted that a previously approved project – the Gates-Gregg 230-kV Line Project – was put on hold in the last cycle but is also recommended for cancellation in this planning cycle. That project was approved in the 2012-2013 transmission planning process as a reliability driven project with renewable integration benefits. The reliability driven need for the line was to increase the pumping opportunities at the Helms pumped storage/generation facility to ensure that there would be adequate water available when the generation was called upon to support local area loads, the filing added. The 2012-2013 transmission planning process identified that the availability of pumping would begin to decrease in the 2023 timeframe with inadequate pumping opportunities to provide sufficient water for generation to meet reliability needs in the Fresno local area by the 2029 timeframe. The filing added that the original cost estimate for the project was $115m to $145m.
The reliability need for the project has been reassessed in the 2018-2019 transmission planning process, indicating similar to the reviews in the previous cycles that the reliability need has been deferred by more than 10 years, the filing said.
Of the previously approved Midway-Andrew Project, the filing noted that the ISO assessed potential alternatives for the project, which can be split into two sections:
- North of Mesa, where the ISO is considering repurposing one of the 500-kV lines from Midway to Diablo after the retirement of the Diablo Canyon power plant in 2025
- South of Mesa, where the ISO is considering reinforcing the 115-kV system and adding a capacitor for voltage support
The North of Mesa Upgrade Alternatives are:
- Alternative 1 – Increase the winter emergency rating of the San Luis Obispo (SLO) – Santa Maria 115-kV line to 170 MVA, increase the winter emergency rating of the SLO – Mesa 115-kV line to 130 MVA, and install 50 Mvar capacitor bank at Mesa or SLO, and install special protection systems (SPS) to shed load if P6 occurs under peak load
- Alternative 2 – Build the Andrew 230-kV/115-kV substation, energize the Diablo-Midway 500-kV line at 230 kV and connect to the Andrew substation, and loop in the SLO – Santa Maria 115-kV line to the Andrew and Mesa substations
Due to uncertainty of potential generation development and transmission alternatives in the area, further assessment of the conversion of one of the 500-kV lines from Midway-Diablo will be required in the 2019-2020 transmission planning process, the filing added. The North of Mesa Upgrade is the portion of the project that is dependent on the potential conversion of one of the 500-kV lines from Midway-Diablo, the filing said, adding that the ISO is recommending to rescope the Midway-Andrew project to Alternative 2 of the North of Mesa Upgrade, and rename the project to North of Mesa Upgrade.
The estimated cost of the North of Mesa Upgrade is $170m, with an in-service date of 2026, after Diablo generation has retired and one of the 500-kV lines can be converted to 230 kV, the filing said. The rescoping of the Midway-Andrew 230-kV project to the North of Mesa Upgrade project is recommended to remain on hold, the filing noted.
The ISO is recommending the approval of Alternative 1 of the South of Mesa Upgrade, with that alternative having an estimated cost of $45m and an in-service date of 2023. Alternative 1 involves increasing the winter emergency rating of the Sisquoc – Santa Ynez 115-kV line to 120 MVA, installing 20 Mvar capacitor bank at Cabrillo, and installing SPS to shed load if P6 occurs under peak load, the filing added.
Other key findings include that given past studies of transmission system capabilities to achieve renewable portfolio standard (RPS) levels beyond 33%, no policy driven transmission was considered for approval in this planning cycle to achieve a 50% RPS – efforts focused on sensitivity studies for higher levels of RPS based on the California Public Utilities Commission’s (CPUC) integrated resource planning (IRP) reference plan 42 million metric tons (MMT) portfolio, and those studies did not identify the need for additional policy driven transmission to meet that portfolio, the filing said.
A statewide electric sector GHG reduction target of 42 MMT by 2030 was selected as the basis for a “42 MMT Scenario” reference plan for the load serving entities to consider in developing their individual plans as part of the 2018 process.
The filing added that another key finding showed the ISO’s analysis indicated in this planning cycle that the authorized resources, forecast load, and previously approved transmission projects working together continue to meet the forecast reliability needs in the LA Basin and San Diego areas. However, due to the inherent uncertainty in the significant volume of preferred resources and the timing of other conventional mitigations, the situation is being continually monitored in case additional measures are needed, the filing said.
The filing also noted that the ISO tariff sets out a competitive solicitation process for eligible reliability driven, policy driven, and economic-driven regional transmission facilities found to be needed in the plan. The filing added that the ISO has identified these regional transmission solutions recommended for approval in the 2018-2019 Transmission Plan as including transmission facilities that are eligible for competitive solicitation: the Gates 500-kV Dynamic Reactive Support Project and the Round Mountain 500-kV Dynamic Reactive Support Project.
Among other things, the filing noted that the ISO is continuing to support the implementation of solutions for transmission needs consisting of combinations of transmission reinforcements and procurement of preferred resources in the LA Basin, in Oakland, and the Moorpark sub-area.
A number of storage proposals have also been identified in this year’s transmission planning process, although none were found to be needed given the limited transmission system reinforcement requirements in this year’s cycle, as well as the conservative approaches taken in this planning cycle in assessing the value of resources that would be focused on replacing existing gas-fired generation, the filing said.