Texas utility regulators last week directed the state's power market operator to boost payments to generators during periods of high electricity demand amid growing concerns that the state could run short of capacity this summer.
The Public Utilities Commission of Texas (PUCT) directed the Electric Reliability Corporation of Texas (ERCOT) to make changes to the Operating Reserve Demand Curve (ORDC), a market mechanism that governs how power prices respond during times of grid stress. The shift in the ORDC will mean higher prices for power plants and demand-side resources that can respond during peak demand periods.
The move came after ERCOT reported its 2019 reserve margin had dropped to 7.4%, well below the state's target of 13.75%. Power generators, who floated similar changes to the ERCOT market in 2017, praised the proposed changes.
The PUCT's decision to alter its pricing mechanisms is the latest in a series of regulatory responses to the retirement of large, aging coal and nuclear generators due to low natural gas and renewable energy prices.
Last week, ERCOT announced it had approved the indefinite mothballing of the 460 MW Gibbons Creek coal plant operated by the Texas Municipal Power Agency. That lowered the state's reserve margin — the amount of capacity it has above expected peak demand — from 8.1% to 7.4%.
Texas survived the summer peak demand season in 2018 with an 11% reserve margin, but PUCT Chair DeAnn Walker called the 7.4% projection "very scary," warning at the Thursday meeting that the state could experience power outages "if we have a large unit trip this summer on the hottest day of the year."
ERCOT officials told the PUCT they predict "no indication of rotating outages," but the slimmer margin “increases likelihood they could be needed."
In response, the PUCT directed ERCOT to make two sets of changes to the ORDC, outlined in a memo Walker issued the same day.
The changes to the ORDC involve tweaking ERCOT's Loss of Load Probability, an algorithm that predicts how likely power demand is to exceed generation reserves. The two shifts — one before this summer and one in 2020 — will cause prices to rise faster during times of generation shortages.
Walker hopes the opportunity for higher payments will incentivize generators to stay online and spur the deployment of new customer-sited resources.
"[T]here should be various responses from the entire market," Walker wrote in her memo, "such as the following: increased development of demand response, distributed generation, self-generation by customers, increased investment in generation maintenance, delays in pending generator retirements, expedited return to service of certain generating units, and additional investment in newer generation technologies that are quicker to build and more operationally flexible."
The directive is similar to changes in the ERCOT market proposed in May 2017 by independent generators NRG and Calpine. That white paper expressed concern about a "noticeable decline in energy prices since 2014" due to low natural gas prices and higher penetration of subsidized wind energy.
The two generators and others praised the move from Texas regulators.
"As the Texas electric system evolves from older, less-efficient technology, proper price signals must be sent to incentivize investment in maintaining the existing generation facilities and developing new, more efficient technology to continue the reliable and competitively priced access to electricity by Texas consumers," Vistra Energy, the state's largest power generator, said in a statement.
Also at the Thursday meeting, the PUCT declined to incorporate measures of marginal line loss into market prices paid to power plants. The changes would have made power resources far away from load centers more expensive, particularly affecting wind resources in the state. Walker wrote that any benefits from incorporating marginal losses in the market are not "worth the implementation cost and market disruption."