A report on the causes of California’s August blackouts details for the first time the role that convergence bidding played in masking tight supply and contends that constrained transmission prevented much needed imports from reaching the state.

The 107-page report to Gov. Gavin Newsom by CAISO, the California Public Utilities Commission and the state Energy Commission blames previously discussed causes, including extreme heat induced by climate change and inadequate resource planning. And it expands on the allegation, mentioned in passing at recent CAISO meetings, that load-serving entities failed to anticipate their needs when scheduling in the day-ahead market.

“We have identified several factors that, in combination, led to the need for the CAISO to direct utilities in the CAISO footprint to trigger rotating outages,” the organizations wrote. “There was no single root cause of the outages, but rather, a series of factors that all contributed to the emergency.”

The rolling blackouts were the first to sweep the state since the energy crisis of 2000-2001. Over two days, about 812,600 households — representing about 2.4 million people — lost power.

Outmoded RA Planning

In an expected finding, CAISO said the state was unprepared to meet the extreme Western heat wave of Aug. 14-19 and that resource planning now must assume there will be similar events caused by climate change.

During the mid-August “heat storm,” California experienced four out of the five hottest August days since the ISO and the CEC began tracking such data in 1985, the report said. The organizations use an average daily temperature composite to predict electricity consumption across the CAISO region.

“Current resource adequacy planning standards are based on a one-in-two peak weather demand plus a 15% [planning reserve margin] to account for changing conditions,” the report said.

But the August heat wave was a one-in-35-year event “not anticipated in the planning and resource procurement time frame, which is necessarily an iterative, multiyear process.” The state needs more supply resources, including battery storage for wind and solar, and must use new planning criteria for long-term projections, it said.

The rolling blackouts were made worse by transmission constraints and other causes, but “it is unlikely that current RA planning levels would have avoided rotating outages” under the same conditions, even without those contributing factors, it said.

Constrained Supply

Import bids in the day-ahead market were 40 to 50% (2,600 to 3,400 MW) higher during the August energy emergency than typical RA requirements from imports in August, but the output couldn’t get where it need to go, the organizations said.

“Despite this robust level of import bids, transmission constraints ultimately limited the amount of physical transfer capability into the CAISO footprint,” the report said.

A major transmission line in the Pacific Northwest upstream from CAISO was on forced outage because of weather conditions, and the California Oregon Intertie (COI) was derated, the report said.

“The derate reduced the CAISO’s transfer capability by approximately 650 MW and caused congestion on usual import transmission paths across both COI and Nevada-Oregon Border,” it said. “In other words, more imports were available than could be physically delivered, and the total import level was less than the amount the CAISO typically receives.”

Under-scheduling

CAISO said LSE scheduling coordinators “collectively under-scheduled their demand for energy by 3,386 MW and 3,434 MW below the actual peak demand for Aug. 14 and 15, respectively.”

During the net peak — the hours after solar goes offline but demand remains high on hot days — LSEs under-scheduled demand by 1,792 MW for Aug. 14 and 3,219 MW for Aug. 15, the ISO reported. The blackouts on those days occurred in the net-peak hours.

“The under-scheduling of load by scheduling coordinators had the detrimental effect of not setting up the energy market appropriately to reflect the actual need on the system and subsequently signaling that more exports were ultimately supportable from internal resources,” the report said.

CAISO said its own peak forecasts were 825 MW below actual demand for Aug. 14 and 559 MW above actual demand for Aug. 15. Its forecasts for the net demand peak times were 511 MW and 632 MW above actual demand.

But during the mid-August events, “it was difficult to pinpoint these contributing causes because processes that normally help set up the market masked the under-scheduling,” the report said.

One of the processes was convergence bidding, a financial hedge that some observers believed could have been used to game the market.

“As the name suggests, convergence bidding is intended to allow bidders to converge or moderate prices between the day-ahead and real-time markets,” the report said. “Under normal conditions, when there is sufficient supply, convergence bidding plays an important role in aligning loads and resources for the next day. However, during Aug. 14 and 15, under-scheduling of load and convergence bidding clearing net supply signaled that more exports were supportable.”

“Once this interplay was identified on Aug. 16 after observing the results for trade day Aug. 17, convergence bidding was temporarily suspended for Aug. 18 trade date through the Aug. 21 trade date,” it said.

During those days, when conditions remained much the same as Aug. 14-15, further blackouts were averted.

RUC Flaw

The report also delved into complications stemming from a flaw in CAISO’s residual unit commitment (RUC) process. The ISO runs the RUC after the day-ahead Integrated Forward Market (IFM) process to avoid real-time supply shortages in rare cases when LSEs under-schedule demand.

The report notes that inputs into the RUC process differ from the outputs of the IFM in three ways:

• Load cleared in the IFM is replaced by CAISO’s own day-ahead forecast, which does not include exports.
• Wind and solar schedules cleared in the IFM are replaced by CASO’s wind and solar forecasts.
• Virtual supply and demand that cleared in the IFM’s convergence bidding market are removed.

The RUC itself consists of two passes: a scheduling run intended to address any unresolved market constraints based on “an intricate but prescribed set of relative priorities” for relaxing the constraint or curtailing schedules; and a pricing run to produce prices that align with both the $1,000/MWh bid cap and the scheduling run.

To ensure that schedules produced by the IFM are physically feasible, the RUC process enforces a power balance constraint to ensure that forecast load can be met in real time.

In 2014, CAISO implemented the Pricing Inconsistency Market Enhancement (PIME) to address inconsistencies between schedules and prices. PIME redirected both the IFM and the RUC to use pricing run results as the source of both prices and schedules.

“Through these RUC constraints, the CAISO determines what portion of the day-ahead schedules are physically feasible and which portion that market participants should tag when the E-Tag is submitted in the day-ahead,” the report said.

After the Aug. 14 and 15 blackout events, CAISO determined that rather than reducing the volume of infeasible exports scheduled in the IFM, the RUC pricing run instead relaxed the power balance constraint, compromising the ISO’s ability to meet actual load. But the ISO found that the RUC’s scheduling run (no longer used to set final schedules) would have relaxed the IFM’s scheduled exports before relaxing the power balance constraint.

As a result, CAISO said it stopped using the PIME functionality in its RUC process beginning Sept. 5, allowing it to use scheduling run results for RUC schedules rather than pricing run results.