The approved projects are located within the Pacific Gas & Electric (PG&E) service territory, the ISO said, adding that 11 of the projects are reliability driven, two of which are eligible for competitive solicitation. The other two projects are economic driven, as one project will reduce congestion in a generation constrained area, while the other one will eliminate the need for local capacity requirements in another locally constrained area, the ISO said.
As noted in the March 19 revised draft of the plan, the new reliability projects found to be needed include the:
- Gates 500-kV Dynamic Voltage Support project, which has a cost of $210m-$250m, and an expected in-service date 2024
- Round Mountain 500-kV Dynamic Voltage Support project, which has a cost of $160m-$190m, and an expected in-service date of 2024
- South of Mesa Upgrade project, which has a cost of $29.6m-$59.2m, and an expected in-service date of 2023
- Tesla 230-kV Bus Series Reactor project, which has a cost of $24m-$29m, and an expected in-service date of 2023
- Moraga-Sobrante 115-kV Line Reconductor project, which has a cost of $12m-$18m, and an expected in-service date of 2023
The plan also noted that the new economic driven transmission projects found to be needed are the:
- East Marysville 115/60-kV Project, with a cost of $26m-$32m, and an expected in-service date of 2022
- Giffen Line Reconductoring Project, with a cost of $5m, and a “TBD” expected in-service date
As noted in the filing, the revised draft transmission plan reflects changes from the draft plan released in February, including:
- The Lakeville 115-kV Bus Upgrade, to add a sectionalizing breaker to section D, is not recommended for approval in this cycle; assessment of the need for that project will be continued in future planning cycles
- The scope of the South Mesa project has changed from a rerate of the Sisquoc-Santa Ynez 115-kV line to reconductoring as it was determined that the rerate of the winter rating was not feasible
- The cost estimate for the East Marysville project in the Pease LCR sub-area was refined in the comments submitted by PG&E and with that, the benefit to cost ratio for that project is 1.62; the East Marysville 115/60-kV project is recommended for approval to economically reduce the local capacity requirement in the Pease sub-area
The filing noted that key trends in this year’s transmission plan – which is developed through a stakeholder process and relies on coordination with the California Public Utilities Commission (CPUC), and the California Energy Commission – include:
- The progress made through past plans to address reliability issues overall and planning for the retirement of once-through-cooling generation, including the San Onofre Nuclear Generating Station, continue to result in relatively modest transmission reinforcement needs. Despite relatively flat load forecast growth currently projected over the planning period, new reliability challenges have emerged driving the need for system reinforcements on a case-by-case basis, however
- Sustained emphasis on minimizing environmental impacts of the electric industry and reducing greenhouse gas emissions continue to drive more integrated solutions to emerging needs that rely on combinations of preferred and conventional resources, as well as transmission, although the relatively modest requirements of the 2018-2019 transmission plan afforded few opportunities for those solutions
- Transmission needed to access renewable generation development to achieve the state’s 33% renewable portfolio standard (RPS) goal by 2020 and 50% RPS goal by 2030 have largely been identified and are moving forward; this year’s planning studies included reliability and economic studies performed meeting 50% RPS goals. New transmission requirements to achieve 50% RPS standards were greatly reduced from expectations only a few years ago due to the much higher than anticipated development of behind-the-meter solar generation. While that generation does not count directly towards RPS measures, it reduces the amount of energy served by the grid. With 2030 RPS requirements now shifting to a 60% RPS goal, direction from the CPUC’s integrated resource planning process for the 2019-2020 planning cycle is anticipated to be consistent with the higher RPS goal
- The longer term requirements for gas-fired generation for system and flexible capacity requirements continue to be examined in the CPUC integrated resource planning process, as well as in ISO studies conducted outside of the annual transmission planning process for purposes of supporting CPUC efforts. The uncertainty regarding the extent to which gas-fired generation will be needed to meet system and flexible capacity requirements necessitated taking a conservative approach in this planning cycle in assigning a value to upgrades potentially reducing local gas-fired generation capacity requirements
The ISO said in its statement that its board also approved a proposal aimed at enhancing its reliability must-run (RMR) and capacity procurement mechanism (CPM) programs, which allow the ISO to procure additional energy or keep resources online that would otherwise be retired or taken out of service.
The ISO noted that the enhancements address stakeholder concerns that current procurement provisions are outdated and unclear. The significant amounts of renewable energy added to the market has created financial stress on many conventional power plants, some of which are important for grid reliability, the ISO said. The ISO said that the enhanced reliability procurement mechanisms provide a backstop to ensure critical resources needed for the grid can remain in operation and financially viable.