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For California, keeping the lights on goes beyond addressing climate change

As the state of California witnesses tens of thousands of residents fleeing raging wildfires and widespread power safety shutoffs to stem future blazes, utility regulators have another lingering concern that promises to have important long-term consequences: resource adequacy.

The California Public Utilities Commission established resource adequacy, or RA, requirements for jurisdictional load-serving entities, or LSEs — namely electric distribution utilities — following the California Electricity Crisis of 2000-2001. The primary goal of the RA program was to ensure enough resources with contractual obligations are available to provide safe and reliable operation of the grid and that the California ISO Balancing Authority has the resources to avoid blackouts and brownouts in times of peak demand. The RA program also incentivizes the siting and construction of new resources needed for future grid reliability.

Under state and federal rules, the CPUC is empowered to set the RA requirements for its jurisdictional LSEs, which include investor-owned utilities, community choice aggregators and energy service providers. Collectively, these jurisdictional entities represent 90% of the load within the CAISO service territory.

Ensuring California has enough power capacity to meet energy needs is especially important as the state moves toward carbon neutrality and faces heightened risks from climate change and a growing reliance on intermittent renewable resources. The RA program has come under heightened scrutiny recently as California and the rest of the Western United States faced an extreme heat storm from Aug. 14 through Aug. 19. During this period, California experienced four out of the five hottest August days since 1985. The third-hottest August day was Aug. 14, and Aug. 15 was the hottest.

Coupled with the extreme heat, several power plant outages and the inability to secure sufficient power imports from out of state prompted CAISO to cut off power supply to about 500,000 customers of Pacific Gas and Electric Co., or PG&E; Southern California Edison Co. and San Diego Gas & Electric Co. during the peak evening demand periods on Aug. 14 and Aug. 15. Power was out for two-and-a-half hours for some customers. It was the first set of rolling blackouts in the state since the last recorded rolling blackout of the energy crisis on May 8, 2001, and came as utilities had already been instituting localized power safety shutoffs to avoid sparking additional wildfires.

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The August heat storm

On Oct. 6, CAISO, CPUC and the California Energy Commission released a preliminary root cause analysis of the August power outages. The analysis showed that a host of factors contributed to the need for CAISO to implement rolling blackouts and that power demand exceeded the limits that California's RA programs anticipated. On Aug. 14, the net demand peak of 42,237 MW at 6:51 p.m. PT was 4,565 MW lower than the peak demand at 4:56 p.m. PT, but wind and solar generation had decreased by 5,431 MW over the same time period. The Stage 3 Emergency was declared at 6:38 p.m. PT, right before the net demand peak at 6:51 p.m. PT. Similarly, on Aug. 15 the Stage 3 Emergency was called at 6:28 p.m. PT, just after the net demand peak at 6:26 p.m. PT.

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Many resources that were required to provide energy to CAISO did not, or were not able to, deliver that energy during the hours of peak and net demand peak.

The natural gas fleet collectively experienced 1,400 MW to 2,000 MW of forced outages, referred to as "derating," or lowering the resource's available capacity. This was largely attributed to the extreme heat and day-of outages. In terms of electricity supply, conventional thermal generation such as natural gas operates less efficiently in extreme heat. Additionally, almost 400 MW of planned outages had not been substituted. In addition to the forced outages known to the CAISO at the beginning of the day, on Aug. 14, AltaGas Power Holdings (U.S.) Inc.'s gas-fired 525-MW Blythe Energy Project I in Riverside County, Calif., recorded a forced outage due to plant trouble. At the time it went out of service, it was generating 475 MW. The following day, the 412-MW operating capacity, gas-fired Panoche Energy Center unexpectedly ramped down generation to about 146 MW from about 394 MW. This was not an outage, and the CAISO now understands it to be due to an erroneous dispatch from the scheduling coordinator to the plant.

Electricity imports proved scarce because the rest of the Western U.S. was also experiencing extreme heat. Total import bids received in the day-ahead market were between 2,600 MW and 3,400 MW, or 40%-50% higher than the August RA requirements for imports. Despite this robust level of import bids, transmission constraints ultimately limited the amount of physical transfer capability into the CAISO footprint. Through the month of August, a major transmission line in the Pacific Northwest upstream from the CAISO system was forced on outage due to weather and thus derated the California Oregon Intertie.

For solar generation, high clouds reduced large-scale grid-connected solar and behind-the-meter solar generation on some days, leading to increased variability. Moreover, California hydro conditions for summer 2020 were below normal. The statewide snow water content for the California mountain regions peaked at only 63% of the April average.

Adding together all of these elements, the operational need for Aug. 14 was 1.3% higher than CAISO's 15% planned reserve margin, or PRM, intended to protect against outliers over power demand forecasts. Adding in the planned outages would increase the operational need to 2.5% higher than the PRM. On the other hand, the operational need for Aug. 15 was below the 15% PRM by 1.7% including only forced outages and 0.7% with planned outages.

The root cause analysis report found the outages resulted from a "climate change-induced extreme heat storm" across the U.S. West, along with poor planning for higher levels of variable renewable energy and actions by participants in the California ISO's day-ahead energy market that "exacerbated the supply challenges."

"There was no single root cause of the outages, but rather, a series of factors that all contributed to the emergency," said Elliot Mainzer, president and CEO of CAISO, in a letter accompanying the report to California Gov. Gavin Newsom.

An overreliance on natural gas?

It will be critical for California's resource adequacy program to function properly over the next three summers if the state is to succeed in its pivot to a cleaner energy future.

In 2019, a majority of electricity on the CAISO grid was generated by natural gas-fired power plants, and during the Stage 3 Emergencies that were declared Aug. 14 and 15, more than half of CAISO's generation was coming from gas-fired plants.

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With peaking generation in short supply, it is important for these natural gas generators to remain in service until they are no longer needed for reliability. California's State Water Resources Control Board recently granted a temporary exemption to regulations that would have required 3,700 MW of natural gas-fired steam turbine units to retire or installation of alternate cooling systems that do not harm marine life. This was done to allow time for 3,300 MW of new resources to be procured between 2021 and 2023. In contrast to those units, which were all built more than 40 years ago, the rest of California's natural gas plant fleet mostly comprises combined cycles and gas turbines commissioned after the year 2000.

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Natural gas combined-cycle and gas turbine plants typically have useful lives of 25 and 20 years, respectively. If the owners of these assets choose to retire them early, it could make ensuring reliability more difficult as new resources like battery storage or hybrid solar-and-battery storage are brought online. Based on projections from S&P Global Market Intelligence's Power Forecast, the revenue that these plants require in addition to their operating margins is more than double the weighted-average capacity price for system resource adequacy most recently reported by the CPUC. Assuming these plants are still making payments on the term loans they were originally financed with, it may be difficult for them to cover their costs with the revenue currently available to them from CAISO's energy market and bilateral capacity contracts for system resource adequacy. Original RA contracts that were structured to provide debt and equity investors in these assets with full return may have expired or become insufficient because of the impact operational changes induced by renewable energy expansion have on their energy revenue.

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New assets such as hybrid solar-and-battery storage combinations are more likely to secure contracts that provide their investors with a full return, because they are the marginal resources for system resource adequacy requirements. The 3.3 GW of capacity procurement recently ordered by CPUC is widely expected to be fulfilled mostly by solar-plus-storage plants, and a Market Intelligence Insight analysis of the CAISO Generator Interconnection Queue Report revealed that as of Oct. 21, over half of the capacity expected to come online after 2020 was composed of co-located solar photovoltaic and battery storage. In 2021, generic CAISO hybrid solar-plus-storage plants in the Market Intelligence Power Forecast are projected to benefit from higher power market prices driven by tight reserve margins. Despite the step-down of the investment tax credit during this period, the solar-plus-storage net cost of new entry is projected to be near parity with the revenue requirements of existing gas turbine plants that are not fully depreciated in 2022 and 2023.

Given this challenge of ensuring that a sufficient supply of dispatchable generation will be available during peak and net peak demand hours over the next three summers and the possibility that extreme weather events will continue to drive demand higher, the CPUC is now reevaluating the structure and processes of its RA program.

What's needed now

Most critical are immediate actions to prevent similar circumstances from threatening reliability in the near term, which include updating the resource and reliability planning targets to better account for extreme weather events and a transitioning electricity resource mix to meet clean-energy goals.

Energy regulators are also expediting the regulatory and procurement processes to develop additional resources that can be online by 2021, with a focus on demand response and flexibility. This can complement the resources that are already under construction and includes large battery storage projects that could help plug the twilight gaps as solar generation recedes. More than 4,600 MW of storage is under active development in the state, much of it at existing and new solar farms, according to Market Intelligence data.

CPUC jurisdictional LSEs have already begun procurement of new capacity that will be online by summer 2021 derivative of prior CPUC authorizations. This includes net qualifying capacity values of approximately 2,100 MW of storage and hybrid storage resources and approximately 300 MW solar and wind resources.

Furthermore, the CPUC is already working with its jurisdictional LSEs to track the projects with 2021 online dates to reduce the risk of delays. When possible delays are identified, the CPUC, the California Energy Commission and CAISO will work with the developers, other relevant state agencies and local governments to ensure projects stay on track.

Current RA planning targets, including the 1-in-2 load forecast plus a 15% reserve margin above the monthly peak load forecast, are being updated to better account for heat storms like the ones encountered in August and September. The CPUC already has an open proceeding to consider changes in how the planning targets are set for the purposes of RA rules, and this discussion should start before summer 2021.

The CPUC opened a phase in its RA proceeding to consider changing the framework for determining reliability rules to consider adjustments for the fact that community choice aggregators dominate the retail electricity market. The CPUC is also working to ensure that increasingly prevalent distributed resources can be efficiently activated to support the grid even if they do not qualify to provide reliability services.

In the near term, state regulators in coordination with the governor's office are developing a contingency plan that will lay out a process to sequence emergency measures in rank order to minimize environmental, equity and safety impacts in the event of another energy shortfall. The measures will include load flexibility and conservation from large users, moving demand to microgrids and back-up generation, including emergency use of diesel generation that the three large electric investor-owned utilities own or have under contract for use in major emergencies such as wildfire prevention and wildfire or earthquake response, and temporarily increasing capacity of existing generation resources.

Previous actions to address RA weakness

Prior to the August blackouts, the CPUC had taken a number of actions to address shortcomings in the RA program. On June 25, it adopted revisions to the RA import rules, determining resource-specific imports should only include pseudo-tied resources or resources that are dynamically scheduled into the CAISO markets. Additionally, the commission defined qualifying capacity import contracts as those that cannot be curtailed for economic reasons.

The changes were meant to address CAISO concerns that RA import provisions could allow some RA import resources to be shown to meet RA obligations while also representing speculative supply. Some import resources bid into the CAISO energy markets but are not secured by long-term contracts, posing a risk if import resources become unavailable when there are West-wide energy shortages. In 2019, 10%-20% of CAISO system RA requirements were met with imports, according to the CPUC. The new requirement-tightening standards for RA imports will take effect in 2021.

Also in June, the CPUC approved local RA capacity requirements for various regions throughout California. Most interestingly, the requirements forecast by CAISO included an unexpected increase in the capacity requirement in the Greater San Francisco Bay Area of 1,850 MW, which represented a 40% increase over CAISO's previous study. The commission found the projected increase concerning and ultimately accepted CAISO's local capacity requirements for the Greater Bay Area for 2021, but rejected the requirements for the area in 2022 and 2023.

Separately, the CPUC approved the central procurement of multiyear local RA procurement to begin for the 2023 compliance year in the PG&E and SCE distribution service areas, including identifying PG&E and SCE as the central procurement entities for their respective distribution service areas. Under the adopted hybrid procurement model, a central procurement entity procures the entire amount of required local RA on behalf of all LSEs but gives LSEs an additional opportunity to procure their own local resources. A local RA requirement framework has been in place in California since 2004, giving LSEs responsibility to ensure customer reliability. But the commission found that having numerous entities buying small strips of local resource adequacy was not cost-effective and created market power concerns.

A proposed administrative law judge decision issued Oct. 23 in the central procurement proceeding would provide financial incentives to LSEs for existing preferred or energy storage local resources. Any new preferred resource or energy storage resource with a contract executed on or after June 17 shall be eligible for the local capacity requirement reduction compensation mechanism. The decision would also approve the proposed competitive neutrality rules for PG&E and SCE for how potentially market-sensitive information relates to confidential competitive information from LSEs, generators and third-party marketers. The full commission could take up the proposed decision at the earliest at its Dec. 3 business meeting.

The CPUC has workshops scheduled through November to address issues including resource adequacy structural changes, multiyear system and flex resource adequacy requirements, resource adequacy import rules, availability of limited resource procurement and local capacity requirement criteria among other things.

The commission's proceeding to oversee the resource adequacy program, consider program refinements and establish forward resource adequacy procurement obligations is Rulemaking 19-11-009.

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The following analysis incorporates our Q3-2020 Power Forecast findings. Learn more how our Power Forecast solution can help you understand the outlook of U.S. power markets and conduct power plant valuations effectively.

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