A version of this Spotlight from S&P Global Platts Analytics was first published July 22.
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ERCOT load in June set a new peak for the month, 70.2 GW, on the back of a heat wave that swept across a large share of the continental US. But temperatures over the past few weeks have remained below those recorded in mid-June, with demand topping 68.2 GW month to date and on-peak prices at the North Hub averaging $37.90/MWh.
As discussed in the North America Power Mid-Summer Update webinar, key price risks for the balance of summer remain wind output and forced outages, with both playing a central role in the price spikes -- up to around $1,500/MWh -- of mid-June.
As shown in the chart above, forced outages trended up from the middle to the end of June and, after softening in early July, increased again last week. By July 15 thermal outages were particularly large given that operational thermal resources in ERCOT over the summer total 63.5 GW. Wind and solar outages were also notable, although their typical capacity factors are much lower than those of thermal plants when it comes to output.
An important difference between the past week and the previous ones is the steep decline in overall outages, particularly for gas. While on July 15 capacity on outage was 5 GW, by July 21 it dropped to 1.5 GW. Coal and wind outages have also shrunk, to 1.3 GW and 1.0 GW, respectively. In aggregate, outages are now less than half of where they were during the mid-June heat wave. And this has important implications for the week-ahead and August contracts.
In fact, the latest NOAA forecast shows higher-than-normal temperatures across Texas during the week starting July 26, with ERCOT forecasting a decline in wind output from current levels and net load (defined as load net of renewable output) peaking at levels seen during the June heat wave.
But lower generator outages, if remaining at current levels or continuing to decline as ERCOT anticipates, should prevent the system from getting as tight as last month, in turn lowering the risk of price spikes.
An additional contribution to lowering such risk is the ERCOT decision to increase to 6.5 GW its minimum upward ancillary services requirements. This measure has been introduced since July 12 to mitigate the impact from generator outages and will apply at least through August. For comparison, the minimum in 2019 was about 3.5 GW.
These two elements, lower outages and higher reserve margins, should continue to reduce the risks of system tightness also in August, although important drivers remain wind output and especially temperatures.
As discussed in our webinar, wind capacity factors ranged between 20% and 40% when summer loads approached 75 GW in the past three years (loads never reached similar levels in earlier years), suggesting that wind output, given the installed capacity of about 32 GW, is likely to match the base case -- 6.7 GW -- assumed by ERCOT in its final summer Seasonal Assessment of Resource Adequacy (SARA). Furthermore, the latest seasonal forecast released by NOAA on July 15 anticipates normal temperature for most of Texas in August, with lower-than-normal ones across the Eastern region -- around the demand centers of Dallas, Houston and Austin.
Overall, when the $2,000/MWh cap on system prices is factored in, the implied heat rate of about 30,000 Btu/kWh for the August North-Hub forward contract appears excessive, as it would be the highest of any August since 2012 if we exclude 2019, impacted by a major heat wave. Our forecast, where the implied heat rate is 18,500 Btu/kWh, is very close to last year's, still the second highest for August since 2012 -- after 2019. Downside risks are therefore material, and next week should offer an early indication of what to really expect during periods of high temperatures in August.