Over the last several months, and in particular in August, ERCOT power prices spiked to record setting levels on a combination of new record electric loads and generation shortages. Today’s energy market commentary will be part one of a multi-part series on the outlook for ERCOT power markets. Specifically, in part I we will review the current power dynamics in ERCOT driving power prices higher and in part II review the new generation under development in ERCOT and its ability to meet future load in ERCOT.
In August of 2019, day ahead and real time pricing for power across ERCOT surged to new record highs with pricing hitting the cap of $9,000 per MWh at multiple points over the extended August heat wave. The chart below shows monthly average ERCOT prices for both the day ahead and real time markets.
The new record price events were caused by system-wide strains on the ERCOT system with prices in all regions spiking and load across the system hitting new peaks as well. ERCOT load and generation has been on a steady long upward climb since 2012 as highlighted in the chart below. In 2011, average monthly generation spiked to 1,100 GWh but since 2016 every summer has seen peaks above the 1,100 GWh mark. Industrial expansion in Texas, population growth, and record setting temperatures each year have all contributed to steady growth in both baseload demand, as highlighted in the chart, and new peak levels of generation.
The peaks in generation on those high demand days have strained the ability of the system to meet peak day demand. The extreme temperatures in Texas resulted in 16 out of the top 20 generation days over the last 4 years. On the most extreme day, August 13, 2019 generation exceeded the previous year peak set on July 19, 2018 by 2.7% a healthy increase in year over year load. Pricing dynamics though were not only driven by the gains in load but by the variability in generation day to day. On the most extreme day, wind only provided 12.7% of total generation compared to August 26, which set the 3rd highest record where wind accounted for nearly 21% of generation. The chart below illustrates the top 20 generation days since 2017 and the contributions by power source.
The wide swings in generation day to day helped drive significant volatility in pricing and resulted in natural gas generators running near capacity in ERCOT for several hours of the day. Natural gas and coal generation ramped throughout the day as wind generation stagnated in the heat of the day and from 7 AM in the morning until after midnight, generators were running in excess of 50% utilization statewide with several hours above 87% utilization of summer design capacity. Typically, nameplate capacity is derated in the summer due to higher temperatures resulting in less generation output potential. Summer design capacity is derated nearly 11% for natural gas generation facilities compared to nameplate capacity. On those extreme days, plants were likely running at or near operable capacity across the system resulting in the extreme prices experienced in ERCOT. Any outages or other limitations would have driven utilization higher than shown below.
If load continues to grow in ERCOT then the frequency of price blowouts may only continue to increase without new generation additions to the system. In Part II of this blog, BTU Analytics will review new generation under construction and under development in ERCOT and the potential implications of new generation sources on power pricing in ERCOT. For more on BTU Analytics’ power market analysis and services, please reach out to the BTU Analytics team.