In late March, ERCOT published their Seasonal Assessment of Resource Adequacy (SARA) report. The SARA report discerns the output from all new, current, and planned generating resources, comparing that amount to the forecasted peak load. Reserve margin is determined by calculating the difference between the forecasted peak load and the total amount of generation available to meet that demand. The reserve margin has risen from a low of 8.6% in 2019 to 12.6% in 2020.
According to the SARA report for this summer, a peak load of 77,144 MW is forecasted, which would indicate a new all-time record for ERCOT. This would mark a 3%, or about 2,250 MW, increase in comparison to last summer’s peak of 74,376 MW and 2019’s peak of 74,897 MW. This 3% increase would be equal to nearly half of Texas’ entire nuclear generation fleet. On the bright side, ERCOT is forecasting a reserve margin of 15.5% to meet the growth in summertime demand. All of this suggests that Texas is growing despite the pandemic and new generating capacity growth is outpacing the increase in demand.
This summer’s SARA report forecasts a 86,908 MW bottom-line capacity number (the number used to calculate reserve margin), a 4,700 MW increase over 2020’s 82,199 MW bottom-line. This hefty reserve margin provides comfort for this summer, but things become even more interesting when observing longer-term projections for resource adequacy, which include a substantial amount of new renewable generating capacity, including wind and solar. Figure 1 displays the amount of new solar generating capacity that is forecasted to be available through April 2022.
ERCOT predicts Texas’ peak electricity demand to grow between 1% and 2% each year, which is considered a reasonable rate. However, the nagging question is whether the new forecasted renewable generation will become operational. Next summer’s capacity is expected to increase to 97,645 MW, a 10,737 MW increase from this year. In 2023, that figure is forecast to reach 99,249 MW. Although wind and natural gas constitute about 1,400 MW of this increase, the majority is set to come from planned solar developments.
The solar projects that have posted financial security alongside signed Interconnection Agreements (the maroon bars in Figure 1) are the most likely to be built. This results in over 7,000 MW of new solar generating capacity in ERCOT over the next year. Even if half of these projects are delayed or do not end up being built, this will still create a lot of new generation.
Figure 1: ERCOT Solar Addition by Year (as of Mar 31, 2021) from ercot.com
An important question to ask from a price risk management perspective is “what happens if only a few or none of these solar projects materialize?” Most of this new solar generation and excess generation is accounted for by forward electricity markets via its futures prices. This can be discerned because the forward market for on-peak summer prices is backwardated, indicating prices get less expensive with each subsequent summer. Because the market is aware that demand will increase, it must also anticipate that the growth rate of future generating capacity will outpace demand. If this anticipation were not present in the market, electricity futures would be elevated.
Winter Storm Uri sent shockwaves through the ERCOT power market, with reverberations that extended beyond Texas’ borders. Due to underperformance during the storm, many developers of renewable generation assets were hurt financially. Along with added costs for winterization and the potential for additional ancillary service costs, this could further strain solar project developers. While the developer bears the burden of these increased costs, ultimately it is the buyer who pays the price, through higher market prices due to a reduction in supply from cancelled generation projects or through increased offered prices for wholesale electricity to cover the developer’s increased costs.
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