Despite uncertainties posed by the COVID-19 pandemic, the Electric Reliability Council of Texas (ERCOT) again expects to shatter its peak demand record this summer. Factoring in changes to its generation profile, extreme weather, and low wind output, the grid operator expects energy alerts are still possible.
ERCOT’s forward-looking projections for capacity, demand, and reserves are murkier, however, owing mainly to the unknown duration and impact of the pandemic on economic growth. New reserve margin projections also reflect new ERCOT rule changes that determine a planned project’s “active” status. And while new capacity on the grid will overwhelmingly be wind, solar, and small, flexible gas-fired resources, they also include the return-to-service of a 420-MW coal-fired power plant that was shuttered last year.
Another Record-Breaking Summer
ERCOT, which manages the flow of power to about 90% of Texas’s electric customers, said on May 13 that it adjusted its peak load forecast to 75,200 MW to “account for economic impacts related to COVID-19.” That figure, cited in its final Seasonal Assessment of Resource Adequacy (SARA) for the upcoming summer season (June to September), is 1,496 MW less than what ERCOT reported in the March-released preliminary summer SARA, and in good news for the region that has grappled with reliability concerns, increases the summer 2020 reserve margin to 12.6%, up from 10.6%. “However, the new forecast is still higher than ERCOT’s all-time peak demand record of 74,820 MW set on Aug. 12, 2019,” it warned.
The projections are significant when compared to other regions in the U.S. According to a May 7 report from the Energy Information Administration (EIA), business shutdowns related to pandemic mitigation efforts have caused daily weekday electricity demand in the central U.S. to fall 9% to 13% in March and April compared with expected demand, after accounting for seasonal temperature changes. That decrease is similar to declines seen in New York. Other regions like Florida, however, have not experienced significant changes, “which may partly be caused by regional differences in how much electricity each end-use sector consumes and the varying effects of COVID-19 mitigation efforts on the sectors,” the EIA said.
“There is a lot of uncertainty in today’s world, but we are confident that Texas will still be hot this summer,” said ERCOT President and CEO Bill Magness in a statement. “Texans will need electric power as they do every summer, and ERCOT is prepared to do our part to keep it flowing reliably.”
The final summer SARA identifies four risk scenarios. One is modeled on extreme weather conditions based on a long heat wave and devastating drought during the summer of 2011, an event that forced the grid operator to cut power to large industrial users to avoid rolling blackouts. But it also takes into account impacts from the COVID-19 pandemic. On May 12, Calvin Opheim, ERCOT manager for its Load Forecasting and Analysis division, observed that daily peaks are consistently 2% to 3% lower. The final SARA suggests that even with COVID-19 impacts, an extreme summer forecast could boost summer peak demand to 78,416 MW.
Meanwhile, only about 411 MW of planned resource capacity has been delayed beyond the summer— about 45% of which is wind capacity. However, as ERCOT Manager of Resource Adequacy Pete Warnken told reporters on Wednesday, that shortfall will partially be offset by 257 MW of new solar and wind projects, which will come online “sooner than expected.” Asked how the pandemic has affected output, Warnken noted that ERCOT in April asked project developers to notify the grid operator of any planned project delay, and so far, it had received notice of only a single delay of a small battery energy storage facility.
A low-wind scenario, meanwhile, could diminish the grid’s total resource output of 82,199 MW by about 1,622 MW. Perhaps more concerning to the grid operator, however, is how much thermal capacity could be forced offline. Under all four scenarios, based on a historical average for the last three summer seasons (2017 to 2019), ERCOT expects forced outages of about 4 GW.
A Healthy-ish Reserve Margin
How COVID-19 will affect ERCOT in future years is less certain, which is why ERCOT’s updated Capacity, Demand and Reserves (CDR) Report, also released on Wednesday, reflects pre-COVID load forecasts, Warnken said.
The report projects that based on a pre-COVID load forecast of 78,299 MW, the planning reserve margin for summer 2021 will be 17.3%, but if projected COVID-19 impacts on the economy are included, the margin could soar to 19.9%. Looking forward, without factoring in COVID impacts, planning reserve margins will vacillate through 2025: 19.7% in 2022, 18% in 2023, 15.1% in 2024, and 14.1% in 2025. If COVID impacts are included, reserve margin figures will be 2.8% higher on average.
Those numbers, along with the 12.6% reserve margin planned for this summer, are notable improvements compared to previous years. In 2019, ERCOT operated at a tight reserve margin of 8.6%, lower even than the precipitous plunge from 16.9% in 2017 to 9.3% in 2018, owing to a spate of plant retirements—including of major coal baseload generators—and above-normal growth in peak electricity demand due to strong load growth in Far West Texas and along the coast where new industrial facilities are being built. It is also a significant improvement from dismal reserve margin projections from only eight years ago, when ERCOT declared several emergencies to reduce electric demand, and stricken with capacity shortages, forecast a negative margin by 2022.
The 17.3% reserve margin projections for 2021 reflects retirement of an unnamed coal plant after the summer season, “as well as the removal of about 900 MW of active planned projects from the reserve margin calculation,” Warnken said.
The CDR is based on data provided to ERCOT by generators and project developers. “Therefore, the reserve margins we report are not based on any speculation regarding new generation that may be coming online. Generation developers will notify us if and when they make any changes to the status of the projects, and we account for those changes in subsequent CDRs. Particularly, cancellations happen all the time so we provide additional plan resource status information to help our stakeholders construct their own future resource scenarios,” explained Warnken. For example, it publishes monthly updates to its Generator Interconnection Status report, which provides specific project milestones.
The May 2020 CDR, however, reflects new ERCOT rules that require any planned projects designated as “inactive” from being excluded as CDR resources, he said. “If a planned project does not meet all the requirements to be included in our short-term planning models within two years after the plant’s interconnection studies have been completed, then we change it to ‘inactive’. Project developers can also change projects to ‘inactive’ for any reason, at any time.”
Return-to-Service for Retired Gibbons Creek Coal Plant
Notably, however, the new CDR also includes some plant capacity that wasn’t included in its December preliminary CDR report, noted Warnken. That includes 1,400 MW of new planned solar projects that did not qualify for the CDR, as well as the return-to-service of the retired 420-MW Gibbons Creek 1 in Grimes County before the summer of 2021.
The coal plant was operated by the Texas cities of Bryan, Garland, Denton, and Greenville under the Texas Municipal Power Agency before it was mothballed indefinitely in 2018. Despite efforts to seek a buyer for the coal plant, the member cities in June 2019 collectively decided to pursue retirement of the project.
Warnken noted the project has a new owner. ERCOT documents show the plant’s interconnecting entity is TEERP Power Station LLC, and that an interconnecting agreement was signed on April 29. Asked by POWER why the plant is being restarted, Warnken said, “obviously, the owners think that it’s an economic project, but in terms of the details around that, I’m not privy to that.”
How the coal plant built in 1984 will compete in the cutthroat market remains unclear. In 2019, about 15.9% of the region’s generation capacity was coal-fired, producing about 20% of total generation. Since the end of 2014, more than 5.6 GW of coal capacity has retired while wind generation has almost doubled.
Warnken also said that developers of a combined capacity of about 2,000 MW had delayed projects past 2021, and one wind project had been canceled, but that no developers have so far indicated these delays stem from pandemic-related impacts.