By Jason Fordney

California’s scorching heat and soaring load pushed CAISO day-ahead energy prices to record highs in the second quarter after the ISO’s market mitigation measures unexpectedly failed.

CAISO’s Department of Market Monitoring (DMM) said it will investigate some of last quarter’s day-ahead market outcomes that may be rooted in a misalignment between software systems.

The Monitor raised concerns in its second-quarter report because energy prices increased even after undergoing mitigation. At one point in the midst of the heat wave, day-ahead prices exceeded $200/MWh during a five-hour period and pushed past $600/MWh in one hour.

“DMM expects that prices should generally not be significantly higher in the final market run than in the market power mitigation run,” the report says. “Both DMM and the ISO will continue to investigate this issue.”

On June 21, “the total bid in cost of energy in the binding pricing interval run was about $1 million higher than the as-bid cost before market power mitigation,” the Monitor said. “However, energy revenues were almost $25 million greater in the binding integrated forward market than in the market power mitigation run due to the magnified impact that higher prices have on the total market.”

One possible cause, which has been raised previously in stakeholder discussions: software differences between the market mitigation and the integrated forward market (IFM) runs, the latter of which is a fundamental CAISO market process that establishes exactly what generators will be needed to meet demand forecasts.

The two processes run independently of each other and produce separate results, or solutions, based on differing inputs, specifically because the mitigation run relies on mitigated bids that can produce a different dispatch order from the IFM.

“If it is determined that a software error resulted in erroneously high prices, DMM requests that the software error be resolved and that the ISO consider the possibility of price corrections,” the Monitor said in the report.

According to the report, CAISO has proposed two explanations for the deviation between the mitigation and IFM runs: differences in unit commitment due to the reduction in available bids (due to lower prices) in the market power mitigation run; and differences in the solution stemming from the independence of the market runs and solution error tolerance.

In the report, the Monitor recommends that the ISO study revisions to solution time and tolerances in the day-ahead market “given the substantial settlement impacts of this case.”

“DMM’s analysis indicates it is unlikely the differences are due to the impact of bid mitigation,” CAISO spokesman Steven Greenlee told RTO Insider. “DMM is asking the ISO to continue investigating the cause further in the event it is caused by a software or other issue that may have a significant impact on market results in the future.”

Greenlee also said that CAISO currently has no plans to issue price corrections until there is “conclusive” evidence of an error, noting that the ISO is “significantly beyond” the price corrections window.

As for the $25 million discrepancy, “DMM has not concluded this is an overpayment but believes the magnitude of this impact highlights the need to further investigate the cause of significantly higher prices in the market run compared to the market power mitigation run,” Greenlee said.

Hot Weather Drives Up Prices

Average day-ahead and 15-minute prices increased during every month in the second quarter, the report showed. Monthly average day-ahead prices rose from less than $23/MWh in March to about $34/MWh in June, caused by high temperatures and loads.

Aside from weather and load, congestion was high on the Path 26 transmission line, which links the Southern California Edison and Pacific Gas and Electric service areas. Price spikes — as high as $250/MWh in the five-minute market and a $750/MWh in the 15-minute market — also increased as a result of weather and the line restrictions. North-south congestion on Path 26 drove real-time congestion to its highest level since the 15-minute market became binding in 2014.

Solar output hit a new record in the second quarter, but higher system loads reduced the instances of negative pricing that accompanied solar surpluses in the first quarter. Real-time prices went negative during 15% of intervals during April, falling to under 6% in June, compared with about 22% of intervals in March.

Solar generation continued to grow on the system, reaching a record peak output of 9,914 MW on June 17. There were reduced curtailments in the second quarter despite a reduction in the power balance constraint tool for oversupply from 300 MW to 30 MW, effective April 11.

“During nearly all of the intervals in the second quarter when prices were negative, there were sufficient dispatchable market bids to resolve oversupply and the software did not have to relax the power balance constraint or curtail self-scheduled generation,” the report said.

EIM Members Fail Sufficiency Tests

In the Energy Imbalance Market (EIM) region comprising PacifiCorp East, NV Energy and Arizona Public Service, prices were often similar because of large transfer capacity and little congestion. There was some price separation in these balancing authority areas because one or more failed the flexible ramping sufficiency test, which limited transfers among them. EIM balancing areas continued to fail the upward and downward sufficiency tests “regularly” in the second quarter, the report said. “In particular, Puget Sound Energy failed the downward sufficiency test more frequently, during about 13% of hours, up from about 3% of hours in the previous quarter.”

EIM participants have discussed what they see as problems with the market’s resource sufficiency test stemming from shifting CAISO load forecasts. (See EIM Participants Seek Resource Test Tweaks.)

The ISO and PacifiCorp were exporters in the EIM during the quarter, while the other areas were mostly net importers, with the ISO’s largest exports occurring during solar-heavy hours.

The quarter also saw relatively high “bid cost recovery payments,” which ensure that resources scheduled in the market recover costs when the market does not provide sufficient revenues. Excessively high bid cost recovery payments can indicate that unit commitment or dispatch is inefficient, and the costs of the payments are allocated to market participants through uplift costs.

Those payments were estimated at about $28 million during the quarter, the highest since 2013, with much of that covering during several days in May. On May 3, the ISO declared a system emergency for the first time in nearly 10 years, and many committed units received payments higher than $50,000, the report said.