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Utilities underestimated the energy they would need. Forecasts by state agencies were out of date. The heat was extreme. Natural gas and renewable resources were offline, and imports were constrained. All five of these are to blame for California’s mid-August blackouts, according to the first formal investigation into its cause.

The preliminary assessment by the California grid operator, California Public Utilities Commission and California Energy Commission acknowledges their shared responsibility and highlights “actions that should have been taken to avoid or minimize the impacts to those we serve.” Their joint analysis to the governor was released Oct. 6.

“We are committed to working with the Governor’s office, state agencies, and the broad set of stakeholders in California and across the Western US to accelerate our efforts to reliably decarbonize the electricity grid,” Elliot Mainzer, the new President and CEO of the California Independent System Operator, stated.

The root cause analysis of the Aug. 14 and 15 temporary blackouts reveals that the private utilities failed to plan for adequate capacity during peak demand over the two-day heat wave across the West. Utility and other load serving entities' shortfall in ready resources to meet actual peak demand was nearly 3.5 gigawatts both days. In the late afternoon, during net peak demand, it was 1,792 MW and 3,219 MW short for Aug. 14 and 15, respectively.

The assessment by the CAISO and two energy agencies warns that current forecast and planning criteria fail to account for climate change or for the steep demand as the sun sets on a grid supplied by surging levels of intermittent renewable resources.

It also notes the loss of 1,400 to 2,000 MW of natural gas power that went offline mid-August.

There also was a drop in solar and wind resources and imports.

Solar energy production during the net demand peak was 1,200 MW, 40% less than expected, and 1,000 MW, or 35% less on Aug. 14 and 15, respectively. In early evening, there was about 230 MW, or 20% less actual wind energy produced, on Aug. 14, but 120 MW, a 10% increase in energy on Aug. 15.

During those same critical two days, a transmission line sending power from the Pacific Northwest went offline because of the heat, reducing the flow of electrons by 330 MW. Between 2,600-3,400 MW was bid in the day ahead market.

How much demand response programs succeeded in reducing load at critical times is still being investigated. But more than 1,200 MW of energy was estimated to be dropped around the evening peak on Aug. 14 and about 1,000 MW of load reduction the following day just before 7 PM. Demand response advocates said far more demand response could have been available but they've been sidelined by the CAISO and CPUC.

The report warns that current planning resources do not ensure there is adequate power available in the evening, known as net peak. That is, as solar generation and wind drop as the sun goes down. It also notes the 15% supply reserve is not set in accordance with extreme heat but under less intense weather conditions.

It also points out this 15% resource adequacy requirement is geared towards traditional peak demand, which starts mid-afternoon. However, the most critical time on the grid has shifted, and is no longer simply when people require the most energy. As result, the “single critical period of peak demand is giving way to multiple critical periods during the day.”

Net peak demand, starting early evening when the sun is disappearing and demand remains high, gives grid operators headaches. Resource adequacy is supposed to meet load throughout the day but “the net demand peak is becoming the most challenging time period in which to meet demand.”

On Aug. 14, the net demand peak of 42,237 MW at 6:51 pm was 4,565 MW less than the peak demand two hours earlier. But wind and solar generation had decreased by 5,431 MW, according to the report.

The evaluation acknowledges some practices in the day-ahead energy market exacerbated the supply challenges under highly stressed conditions.

The trio of agencies vow to:

Update resource and reliability planning targets to better account for heat storms; Ensure generation and storage projects under construction in California are completed by their targeted online dates; Expedite procurement so that additional resources are online by 2021. This is expected to focus on demand response and flexibility; Coordinate additional procurement by non-CPUC jurisdictional entities; and, Ensure CAISO market practices reflect the actual balance of supply and demand during stressed operating conditions.

The agencies’ final report will include an analysis of how utility scheduling coordinators scheduled load in the day-ahead market and address improving communications with utilities ahead of future critical reliability events.