ERCOT presents 'roadmap' to greater reliability, February storm analysis

Reports released July 12-13 detail the causes of the Electric Reliability Council of Texas reliability failure during the deadly mid-February winter storm and a 60-item "roadmap" to enhancing reliability, affecting all market participants regarding communications, operations, regulatory and market issues.

In an open letter to Texas Governor Greg Abbott, Texas legislators and the Public Utility Commission of Texas, Brad Jones, ERCOT's interim president and CEO, said his staff "gathered ideas from many Texans including customers, city leaders, state leaders, current and former regulators, environmental advocates and market participants to help us identify important improvements."

The "Roadmap to Improving Grid Reliability" identifies 20 steps items as already complete, including:

• Revising market rules so firm load shedding is considered in scarcity pricing
• Limiting ancillary services prices to the system-wide offer cap
• Doing more than 30 on-site power plant weatherization spot checks

The other 40 items are labeled as "on track" for implementation.

Giuliano Bordignon, a power market analyst at S&P Global Platts Analytics, said July 13 that the on-track item requiring assessment of the benefits and costs of increased transmission internal and external to ERCOT "seems to be an acknowledgment that increasing interties should be part of the conversation."

Also, the roadmap's on-track proposal to eliminate barriers to distributed generation, energy storage, and demand response "confirms the role that demand can play in enhancing power grid adequacy," Bordignon said.

These items were developed in order to address issues arising from the mid-February winter storm, in which massive generation outages led to about 4 million customers losing access to electricity, some for days.

Multiple causes

At the request of the PUC, the University of Texas Energy Institute developed a report, "The Timeline and events of the February 2021 Texas Electric Grid Blackouts," released July 12 and discussed by researchers in a July 13 media call.

"The failure of the electricity and natural gas systems serving Texas before and during Winter Storm Uri in February 2021 had no single cause," the report states. "While the 2021 storm did not set records for the lowest recorded temperatures in many parts of the state, it caused generation outages and a loss of electricity service to Texas customers several times more severe than winter events leading to electric service disruptions in December 1989 and February 2011.

The 2021 event exceeded prior events in the following aspects:

• The number and capacity of generation unit outages
• The maximum load reduction through rotating outages
• The number of customers affected
• The lowest grid frequency
• The natural gas generation with fuel shortages
• The duration of the emergency with blackouts

Failures of all types of generation contributed to the emergency, the report states.

"From noon on February 14 to noon on February 15, the amount of offline wind capacity increased from 14,600 MW to 18,300 MW (+3,700 MW)," the report states. "Offline natural gas capacity increased from 12,000 MW to 25,000 MW (+13,000 MW). Offline coal capacity increased from 1,500 MW to 4,500 MW (+3,000 MW). Offline nuclear capacity increased from 0 MW to 1,300 MW, and offline solar capacity increased from 500 MW to 1100 MW (+600 MW), for a total loss of 24,600 MW in a single 24-hour period."

Power plants cited "weather-related" reasons for 30 GW of outages at 167 units, equipment issues for 5.6 GW at 146 units, fuel limitations for 6.7 GW at 131 units, transmission and substation outages for 1.6 GW at 18 units, and frequency issues for 1.8 GW at eight units, the report states.

Gas facility curtailments

Problems with the natural gas system's production, storage, and distribution facilities included the freezing of equipment, failure to inform electric utilities of critical electrically-driven components, and enrollment of 67 critical gas infrastructure facilities in ERCOT's Emergency Response Service, through which power customers are paid to agree to curtail load.

"We're not able to say who owned those facilities and how much they were paid," said Joshua Rhodes, one of the UT Energy Institute research committee co-chairs in a July 13 media call.

Another research committee co-chairman, Carey King, UT Energy Institute assistant director, said the team was also unable to quantify how much of an impact those facilities might have made on power plants downstream.

Other factors contributing to the emergency included:

• Underestimated load forecasts during severe winter storms
• Inaccurate weather forecasts before the storm
• Excessive planned maintenance outages
• Inadequate weatherization at some generators

"We didn't look at power plants that didn't fail," King said. "Maybe they were better prepared, and maybe they weren't."

The PUC has come under fire for requiring that wholesale power prices be set at the estimated value of the lost load, $9,000/MWh, for the duration of the emergency from Feb. 15 through Feb. 19, but the alternative might have brought even higher prices, the report said.

The value of the lost load is also the "high systemwide offer cap," which is the usual cap until the cumulative hypothetical net profit for a gas turbine reached a threshold of three times the $315,000 estimated cost of new entry, which was reached Feb. 16.

At that point, market rules call for the system-wide offer cap to change to either $2,000/MWh or 50 times the fuel index price, whichever is higher. As the fuel index price was the natural gas price at the Katy Hub, the "50-times-FIP" price would have been $15,359/MWh Feb. 18, the report states.