The Electric Reliability Council of Texas Inc. forecast planning reserve margin for summer 2020 was increased by 0.1 percentage point in the grid operator's latest long-term resource adequacy report, reflecting a lower forecast peak load and an increase in renewable capacity expectations.
In the Capacity, Demand, and Reserves, or CDR, report released Dec. 5, ERCOT forecast a planning reserve margin of 10.6%, up from the May CDR's summer 2020 forecast of 10.5%.
The planning reserve margin — the percentage by which total resources are expected to exceed forecast peak load — was just 8.6% going into the summer of 2019, and real-time prices during an August heat wave hit the systemwide offer cap of $9,000/MWh.
In forward trading on the Intercontinental Exchange Dec. 5, ERCOT North Hub July-August on-peak packages were essentially flat at about $147/MWh.
However, the new CDR report forecast significant planning reserve margin increases for 2021-2024, which prompted July-August packages to fall more than $2/MWh for 2021, 2022 and 2023.
The latest CDR report forecast the summer reserve margin to be 18.2% in 2021, compared with last May's forecast of 15.2%, for example, but some are skeptical of that prediction.
"It is unlikely that 2021 reserve margins would actually get to 18.2%," said Manan Ahuja, senior director of North American power at S&P Global Platts Analytics. "I would expect that number to move down significantly next year, as with the current forward curve, a lot of the projects in the queue may not get financed or built."
Lower peak load forecast
ERCOT forecast demand to peak at 76,696 MW in the summer of 2020, up from its record peak load of 74,820 MW set Aug. 12. However, for planning purposes, ERCOT assumes that demand response, energy efficiency and its Emergency Response Service would reduce the need for resources to 74,480 MW.
"The ERCOT region continues to experience above-normal growth in peak electricity demand due to strong load growth in Far West Texas and along the coast where new industrial facilities are being constructed," the latest CDR said.
ERCOT expects installed thermal capacity to total 65,001 MW, down slightly from the May CDR total of 65,207 MW, but this capacity is augmented by a percentage of installed renewable resources, specifically, wind and solar, that are expected to be available during peak times totaling 7,242 MW, up from 5,897 MW in the May CDR.
The latest report also assumes 2,648 MW of switchable capacity, net of resources that would be unavailable, compared with 2,672 MW in the May CDR. Also, the latest CDR assumes 483 MW of mothballed capacity would be available at peak, up from 118 MW in the previous report, and 3,327 MW of private use network capacity — behind-the-meter industrial capacity — down from 3,478 MW in the previous report.
The latest report also includes planned renewable capacity slated to be online by June 1 totaling 2,640 MW, down from 3,391 MW in the previous CDR, and 212 MW of planned capacity that is not wind, solar or storage, down from 301 MW in the previous CDR.
Non-synchronous DC ties to other systems are expected to provide 850 MW of capacity in the latest report, down from 938 MW in the May CDR, as the latest report assumes only 68% of that capacity would be available at peak, compared with 75% in the previous report.
In all, ERCOT's latest CDR indicates 82,403 MW of resources should be available to meet 74,480 MW of expected peak demand in the summer of 2020, compared with 82,521 MW of resources to meet 74,705 MW in the May report.
ERCOT's planning process makes certain assumptions about the likely availability of renewable resources at peak times, basically discounting nameplate capacity by expected intermittent weather conditions. The latest peak load capacity factor assumptions and their assumptions in the May CDR are as follows:
- Coastal wind: 63%, up from 58%
- Panhandle wind: 29%, up from 15%
- Other non-coastal wind: 16%, up from 15%
- Solar: 76%, up from 74%
"On the one hand, the CDR's improved margins show that the market continues to work," said Bill Peacock, vice president for research at the Texas Public Policy Foundation. "On the other hand, much of the increase in margins is due to renewables, and it is unclear if they will be available on the hot summer days when they are needed most."
The latest CDR notes that two gas-fired plants totaling 1,227 MW have been canceled and eight solar projects totaling 1,056 MW of capacity contribution have been delayed since the May CDR, and Travis Whalen, a Platts Analytics power market analyst, said the solar reductions "significantly increase the risk of high volatility this summer."
"Delays to as few as three projects could push reserve margins back into single digits," Whalen said.
However, Gavin Dillingham, clean energy policy program director at the Houston Advanced Research Center, saw no need for concern from the cancellations, as the capacity of projects submitted for generation interconnection studies continues to swell, even as cancellation numbers have fluctuated widely each month.
"The overall trend for projects being studied continues to increase and significantly outpace the cancellation activity," Dillingham said Dec. 5. "So, I would suggest no reason for concern at this point."
Mark Watson is a reporter for S&P Global Platts. S&P Global Platts and S&P Global Market Intelligence are owned by S&P Global Inc.