Renewable energy accounted for one-quarter of the electricity consumption in 2020, up from 8% in 2010. There’s more on the way, with the solar capacity expected to quadruple by the year 2024 from current levels. Renewables require backup from many other power facilities to supply electricity demand because their availability is unpredictable.
Meanwhile, Texas’s older coal, nuclear, and gas (collectively known as “thermal”) power plants require more than planned downtime for maintenance and repairs, putting the state at risk of running out of power during peak demand periods. Furthermore, Texas’s energy consumption will only rise due to population growth, transportation electrification, and increased demand from industrial suppliers like petrochemical plants and data centers.
Given the lack of investment in a new thermal generation, does Texas’s electricity market design provide adequate incentive to expand capacity for future power requirements? For Texas consumers to have reliable electricity in the future, increased usage of demand-response and battery storage programs—incentives utilities provide customers for voluntary, scheduled cutbacks in energy consumption—and new gas power generation may be required.
With daily wind and solar generation varying according to weather and time of day, balancing electricity supply and demand for Texas’ grid operator, the Electric Reliability Council of Texas (ERCOT), becomes more difficult each year. This raises the demand for “dispatchable” power or electricity that can be summoned rapidly, typically from natural gas power facilities, to bridge the gap when the renewable power supply falls short.
This problem will only get worse as utility-scale solar capacity grows from 7,800 megawatts (MW) now to more over 28,000 MW by 2024, according to ERCOT. On a sunny day in Texas, that quantity of solar power could power approximately 4.5 million households.
ERCOT anticipates its predicted power generation capacity, demand (load), and the reserve margin—the surplus generation above peak load, which occurs during the hottest and coldest hours of the season. To avoid blackouts, ERCOT aims for a reserve margin of at least 13.75 percent to meet an unforeseen demand surge or even power plant failure.
ERCOT considers weather trends for renewables as well as downtime schedules given by power plant operators when projecting available generating capacity. ERCOT expects reserve margins to exceed 30% between the year 2023 and the year 2026 based on these assumptions.
While these margins appear to be ample, they can be drastically reduced in the summer due to extensive power plant outages, high temperatures, and low renewables output. According to ERCOT’s projection, if all of these occurrences occurred during the current summer season, the system would be over 14,000 MW short in a generation, causing severe disruptions.
The February 2021 winter storm was an example of a situation in which every improbable event occurred simultaneously. Electricity demand exceeded projections, natural gas and power plants facilities were not adequately winterized, more units were unavailable for maintenance than projected, and renewable generation was exceptionally low.