Hotter weather and higher natural gas prices pushed up energy market costs in the California Independent System Operator territory in the second quarter, nearly doubling day-ahead electricity prices from the same period a year ago, the ISO's independent market monitor said.
Gas prices increased at both the SoCal CityGate and PG&E CityGate hubs, which drove up marginal energy prices across the ISO footprint, the Department of Market Monitoring said in its Second Quarter Report on Market Issues and Performance.
"Increases were due to a period of extreme heat in the West on some days in June, higher natural gas prices, and ongoing drought conditions causing low hydroelectric production," DMM said.
The day-ahead market was structurally uncompetitive for more hours than in any second quarter in the past five years, DMM said in the report. DMM uses two methods, known as the pivotal supplier test and the residual supply index, to measure market competitiveness.
"In the electric industry, measures based on two or three suppliers in combination are often used because of the potential for oligopolistic bidding behavior," DMM said. "The potential for such behavior is high in the electric industry because the demand for electricity is highly inelastic, and competition from new sources of supply is limited by long lead times and regulatory barriers to siting of new generation."
Average five-minute prices were lower than both 15-minute and day-ahead market prices in the second quarter, with day-ahead prices averaging $40/MWh, 15-minute prices averaging $36/MWh, and five-minute prices averaging $33/MWh.
The total number of generation outages in the second quarter was also the highest in the past five years, with planned outages increasing 34 percent and forced outages by 11 percent compared with the same period a year ago. An outage is considered to be planned if a market participant submits a notice more than seven days prior to the outage. Causes of outages can be plant maintenance; operational issues; outages due to ambient temperature or not due to temperature; unit testing; environmental restrictions; transmission issues; transitional limitations; or cycling, DMM said.
In the second quarter, average total generation on outage exceeded the same period last year by about 2,350 MW. Planned maintenance outages averaged 4,100 MW, while other types averaged 1,850 MW.
Renewable-energy production increased by about 3 percent over the second quarter of last year, even with a 38-percent drop in hydroelectric generation figured in.
In the Western Energy Imbalance Market, Los Angeles Department of Water & Power, Public Service Company of New Mexico and NorthWestern Energy joined in the second quarter, which brought 15 GW of generation capacity and more than 20 GW of transfer capacity into the market.
Prices in NV Energy territory were more than $100/MWh on average in the hours between 8 p.m. and 9 p.m. in both the 15-minute and five-minute markets, driven by high penalty prices associated with undersupply infeasibilities when NV Energy was separated from the rest of the system, DMM said, adding that penalty prices were raised in March from $1,000/MWh to $2,000/MWh. Undersupply infeasibilities often occur following the failure of a resource-sufficiency test, which can limit imports into a failing area. CAISO in June implemented Phase 2 of Federal Energy Regulatory Commission Order No. 831, which limited conditions in which the $2,000/MWh penalty price can be applied.
Prices in California areas in the second quarter were more than $10/MWh higher than in other regions in the EIM, on average, because of transmission congestion caused by transfer constraints and additional greenhouse gas costs that are applicable in the state.
During peak system-load hours, there was limited transfer capability out of the Northwest region, which kept prices lower in the areas of PacifiCorp West, Puget Sound Energy, Portland General Electric, Seattle City Light and Powerex.
Congestion in the day-ahead market decreased prices in the San Diego Gas & Electric and Southern California Edison areas. Total day-ahead congestion rent was $98 million, a decrease from $194 million in the previous quarter, but an increase from $90 million in the same quarter in 2020.
Congestion revenue rights auction revenues were estimated to be $17 million less than payments made to non-load-serving entities during the second quarter, compared with the $4 million below LSE payments seen in the first quarter, representing about 12 percent and 2 percent of day-ahead congestion rent, respectively. The losses as a percent of day-ahead congestion rent were well below the average of 28 percent experienced in 2016 through 2018, before changes were made to the methodology.