Additional Power Needed in Southern California
By William A. Monsen and David N. Howarth
The shutdown of the 2,246-megawatt San Onofre nuclear generating station — called SONGS — and the expected shutdown during the period 2017 through 2020 of 5,068 megawatts of coastal power plants that use seawater for cooling in southern California will create opportunities for developers of both supply- and demand-side resources.
The exact magnitude of the opportunities will play out over the next several months in California Public Utilities Commission proceedings.
The region will need approximately 4,600 megawatts of new resources to maintain reliability, according to the California grid operator, CAISO. The amount of additional capacity needed will be higher if new resources are sited at less effective locations than the plants being shut down or are less effective at meeting peak demand than the gas-turbines assumed in CAISO’s modeling.
The need for additional resources would be reduced by new transmission projects, but CAISO has not yet considered those in its modeling.
Southern California Edison and San Diego Gas & Electric estimate need to be about 1,800 to 4,300 megawatts, depending on whether they are able to site new high-voltage transmission lines in the densely-populated southern California area. As with the CAISO analysis, these estimates assume resources are located at the most effective locations.
In any event, replacement of SONGS and the coastal power plants represents a significant opportunity for developers to solve difficult local supply problems in the western Los Angeles basin and San Diego. The region’s needs can be met with new or repowered gas-fired units, grid-connected and customer-located renewable resources, combined heat and power, demand response, energy efficiency, storage and new transmission.
Senior staff from the California Energy Commission, California Public Utilities Commission and CAISO presented a preliminary plan to address the situation. The plan recommends meeting about 50% of the resource need with energy efficiency, demand response, renewable energy, combined heat and power and storage. These are “preferred resources.” The remaining need would be met by transmission upgrades to reduce capacity requirements and conventional generation to the extent that preferred resources and transmission development are insufficient.
This 50-50 split would require the addition of about 3,250 megawatts of preferred resources and 3,000 megawatts of conventional generation. These estimates take into account that not all of the resources will necessarily be located at the most effective locations. A large portion of this capacity has already been authorized or is being counted on under existing programs, meaning that the state would need to authorize about 2,000 megawatts of additional preferred resources and about 1,500 megawatts of gas-fired generation to meet the targets in the staff plan.
The utilities have their own procurement proposals as well. Southern California Edison wants to procure a wide variety of resources, including a minimum of 1,000 megawatts of gas-fired generation, 400 to 600 megawatts of storage and other preferred resources, and about 500 to 700 megawatts of capacity from any resource type. SDG&E proposes to procure between 500 to 550 megawatts of new capacity from all sources. Both Edison and SDG&E premise their procurement plans on the construction of major high-voltage transmission projects that would deliver power to the western LA basin and San Diego region.
This “all-of-the above” strategy is intended to maintain reliability while keeping environmental impacts, including greenhouse gas emissions, to a minimum. While such a strategy appears to provide something for everyone, resource planning and procurement in California are subject to overlapping regulatory processes, making the outcome for any particular resource type uncertain.
Unit 3 of the San Onofre nuclear generating station experienced a radioactive leak on January 31, 2012 caused by unexpected wear in steam generator tubes that had been installed in 2010 and 2011 as part of a steam generator replacement project at the plant. When the leak was discovered in Unit 3, the plant (including Unit 2, which was already out of service for refueling) was shut down to investigate the cause and determine whether the reactors could be operated safely. Facing mounting replacement power costs and an uncertain timeline for bringing the plant back in service, Southern California Edison decided on June 7, 2013 to shut down the plant permanently and to begin decommissioning.
The SONGS plant was a key part of the electrical infrastructure serving southern California, accounting for 16% of the local supply and serving an average of 1.4 million homes in the service territories of three utilities: Southern California Edison, San Diego Gas & Electric and the municipal utility in Riverside. More importantly, the transmission system in the local area and the connection between the Edison and SDG&E systems was designed assuming the SONGS plant would be there to provide voltage support and reactive power. The loss of SONGS reduces the ability to import power into southern Orange County and San Diego and represents a serious threat to grid reliability.
Compounding the loss of SONGS is the impending closure of up to 5,068 megawatts of gas-fired plants in the local area that rely on once-through cooling using seawater. These plants must comply with water regulations that practically eliminate the use of seawater for cooling by 2017 to 2020.
The utilities, state regulators and the California grid operator have been implementing short-term contingency plans that include the conversion of retired generators at Huntington Beach to synchronous condensers to provide voltage support. However, there is a need in the longer term to replace lost generating capacity, provide voltage support and reconfigure the transmission system.
The need for new capacity presents a significant opportunity for suppliers able to develop or repower renewable and gas-fired generation projects, combined heat and power projects, energy efficiency and demand-response programs and storage projects located in the western LA basin and San Diego. There may also be an opportunity to develop transmission lines. The types and quantities of these resources that are ultimately deployed will depend on the outcome of ongoing regulatory processes that concern resource planning and procurement in California.
The preliminary plan that senior staff of the California Public Utilities Commission, California Energy Commission and California grid operator presented proposes meeting about 50% of the incremental need with energy efficiency, demand response, distributed generation, renewables and storage. The remaining need would be met through transmission upgrades and, to the extent that preferred resources and transmission development are insufficient, conventional generation.
This 50-50 split would require the addition of about 3,250 megawatts of preferred resources and 3,000 megawatts of conventional generation. A large portion of this capacity has already been authorized or is being counted on to result from existing programs. The incremental capacity to reach these targets amounts to about 2,000 megawatts of preferred resources (including 1,000 megawatts of energy efficiency included in base forecasts, but not yet authorized and funded) and 1,500 megawatts of conventional generation. Figure 1 shows how the staff sees these additions playing out over time, as well as the timing of the retirements that create these resource needs.
In the case of preferred resources, the programs designed to support new development have historically been statewide and not location-specific. Given the local reliability issues that need to be addressed, regulators will need to make a concerted effort to ensure that the resources are developed in the locations where they are needed. For example, resources located outside the western LA basin or San Diego provide no assistance in meeting local capacity requirements.
The staff also made some specific recommendations to mitigate near-term risks. These include focusing preferred resource development in the SONGS area, adding reactive power support including synchronous condensers at key points in the affected transmission system, accelerating development of CAISO-approved transmission projects, delaying retirement of existing generation and accelerating development of approved new projects, and authorizing procurement to replace the 950-megawatt Encina power plant that will have to comply by 2017 with restrictions on use of seawater for cooling.
The staff also identified some longer-term mitigation options. It wants to see alternative transmission proposals, including a project identified by Edison to loop the Mesa substation into the transmission system using existing rights of way, as well as other alternatives like a submarine DC cable delivering from the north to San Diego. Another option is to consider extending the seawater cooling compliance schedule, specifically for the Encina project, which has a compliance date at the end of 2017. Another idea is the San Diego energy park proposed by SDG&E to be located at Camp Pendleton, which is across the highway from SONGS, and offered to independent generators as a site for up to 1,000 megawatts. Another option is for Edison to offer contingent site permits to developers for peaking plants to be located at high-value sites in the southern part of the western LA basin.
Every two years, the California Public Utility Commission holds a long-term procurement planning proceeding to authorize the procurement of new resources needed to maintain system reliability. The current planning cycle for 2012 and 2013 was divided into multiple tracks including a track 1 that addressed local reliability in the LA basin and a track 4 that is addressing resource needs stemming from the SONGS shutdown.
Track 1 concluded in February 2013 with a decision authorizing Southern California Edison to procure 1,400 to 1,800 megawatts of resources in the western LA basin. At a minimum, Edison must procure 1,000 megawatts from conventional gas-fired resources, 50 megawatts from energy storage and 150 megawatts from preferred resources. No more than 1,200 megawatts may be procured from conventional gas-fired resources, and up to an additional 600 megawatts may be procured from preferred resources and energy storage. Edison issued a request for offers on September 12. Bids are due on December 16.
Local needs for San Diego Gas & Electric were addressed in a separate proceeding. In that proceeding, SDG&E was authorized to procure 308 megawatts. SDG&E has applied to meet this authorized need by contracting with the Pio Pico gas-fired generator, which was selected in a previous solicitation and rejected by the California Public Utilities Commission.
Track 4 is ongoing. The procurement authorization anticipated in February 2014 will probably be for an amount less than the identified need to reflect the possibility that subsequent analyses that incorporate various transmission system improvements show a reduced need. It is unclear whether additional procurement beyond the interim authorization resulting from track 4 will be considered in a second phase of track 4 or delayed by two years if it is carried over into the next long-term procurement planning proceeding.
The California grid operator, CAISO, is currently studying transmission options for addressing local reliability issues associated with the SONGS retirement as part of its current transmission planning process and anticipates adopting a transmission plan in March 2014, at which point it plans to update its resource needs assessment.
At this point, CAISO has not recommended any specific level of procurement authorization to address the shutdown of SONGS. However, it suggested in testimony in the CPUC long-term planning proceeding that approximately 4,600 megawatts of additional capacity will be needed in the SONGS area assuming replacement gas-fired resources are sited at the most effective locations. CAISO proposes to delay firm decisions about the need for new generation until it is able to finalize its transmission planning process. Meanwhile, CAISO has indicated that it does not oppose the CPUC authorizing Edison and SDG&E to procure about 500 megawatts of local capacity each above and beyond any prior procurement authorization by the CPUC.
Edison and SDG&E both submitted testimony in the long-term procurement planning proceeding in which they offered estimates of local capacity need as well as their preferred approaches for procurement. Both utilities relied on different reliability requirements than CAISO in their assessments, which led to lower levels of identified needs. The following tables summarize the need identified by each utility and their recommended levels of procurement.
By: William A. Monsen and David N. Horwath with MRW & Associates, LLC in Oakland