Texas power market, a tale of two years and two months
In the summer of 2019, with a lower than optimal reserve margin forecast (8.6%), the Electric Reliability Council of Texas (ERCOT) experienced periods of high electricity demand and price spikes that ultimately reached the market cap of $9,000/MWh. In order to retain reliability and soften the elevated wholesale electricity prices, the market operator used demand response resources and called on customers to voluntarily cut loads during peak periods. The challenges were significant but could have been worse.
To highlight how the large Texas power market, representing more than 90% of Texas, has evolved, consider the market fundamentals displayed in August of 2011 compared to August of 2019. According to data compiled by ABB’s Velocity Suite research team, during both periods, high temperatures persisted, and electricity demand broke all-time records, with real-time market prices spiking to the designated market cap, which was $3,000/MWh in 2011, and $9,000/MWh in 2019.
Source: ABB Velocity Suite
Note: Average hourly LMP prices are derived from 5-minute real-time price reporting by ERCOT compiled by the ABB Velocity Suite team
According to a report published by DOE’s Energy Information Administration (EIA) in September 2011, a prolonged August heatwave enveloped Texas. The weather produced two periods of relatively high wholesale electricity prices. Before August 2011, ERCOT’s peak demand record was 65.8 GW established in the summer of 2010. During the sustained heatwave, peak load exceeded that level on 15 separate days, including new all-time peak demand records recorded on three consecutive days (August 1-3, 2011) reaching an all-time new peak of 68.4 GW on August 3, during hour 16 – exceeding the previous year’s peak by 3.8%. The grid operator would have set yet another record on August 4, 2011, if not for the shedding of 1.5 GW of interruptible load. During the month, throughout the entire state, record high temperatures were set. In Dallas, high temperatures were above 100 degrees Fahrenheit (F) on all days of the month except for two. During five days in August 2011, real-time prices reached the market cap of $3,000/MWh.
Supported by similar market drivers present in 2011, during August 2019, high temperatures across Texas drove electric demand to new records while prices reached the market cap of $9,000 on several occasions. Over a two-week period (August 6-19, 2019) daily peak demand exceeded 70 GW every day, with an all-time peak record of 74.5 GW set on August 12, 2019, between 4:00 and 5:00 pm CDT.
Market impacted more in 2011 than in 2019
Driven by extreme sustained heat and thin reserves in August 2011, real-time wholesale prices stayed elevated longer than during the same month in 2019. Average hourly real-time prices topped $1,000/MWh on 20 separate hours compared to 7 times in 2019. Prices topped $500/MWh on 34 separate hours in 2011, while reaching that milestone on only 13 occasions in 2019.
Source: ABB Velocity Suite
During 2011, coal, clearly a baseload fuel at the time, accounted for 33.7% of the electricity production, while in 2019, coal accounted for only 17.7%, with the hourly power curve looking more like a peaker fuel. Wind power has grown substantially within ERCOT over the past decade, accounting for only 5.1% of total generation in 2011 and growing to 14.5% in 2019. Natural gas was by far the largest contributor of power in ERCOT in both 2011 (51.5%) and 2019 (57.4%), with solar (1.2%) beginning to show some contribution, though small, in 2019.
Source: ABB Velocity Suite
Note: Average hourly LMP prices are derived from 5-minute real-time price reporting by ERCOT compiled by the ABB Velocity Suite team
The ERCOT system average hourly real-time (RT) Locational Marginal Price (LMP) was considerably higher in 2011 at $126/MWh compared to 2019 at $62/MWh. The higher average wholesale prices in 2011 were driven mostly by higher natural gas prices. In August of 2011, Henry Hub (HH) natural gas prices averaged $4.06/mmBtu, while in 2019, HH gas prices averaged only $2.22/mmBtu – lower by 45.3%.
What will the summer of 2020 bring?
On December 5, 2019, ERCOT released its Capacity, Demand and Reserves (CDR) Report which included planning reserve margins for the next five years. The reserve margin for summer 2020 is forecast at 10.6% – about 2% higher than last summer. Summer peak demand is expected to reach 76.7 gigawatts (GW) in 2020, and 78.3 GW in 2021. The Texas market reached an all-time system peak of 74.8 GW last summer on August 12, 2019.
According to the CDR report, the region is expected to experience above normal load growth driven by electricity demand in western Texas and along the gulf coast where new industrial facilities are being built. Citing plans by generation owners, capacity additions totaling 7.6 GW are expected to be operational before the 2020 summer peak, which is typically expected in either late July or August.
Today’s ERCOT fuel-mix is quite different from what existed a decade ago. Natural gas accounts for most of the power output during the summer peaking months. Wind power has become a significant resource but is only available when the wind blows.
The key fundamentals to keep an eye on are the timely addition of new capacity expected and the price of natural gas deliveries to the state’s gas power plants. If the past is any indicator for what could occur again, lessons learned during two hot summers nearly ten years apart sheds light on the challenges ahead as the summer heat hits Texas again.
ERCOT’s next Seasonal Assessment of Resource Adequacy will be released in March, and the mid-year CDR report will be released in May 2020.
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