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ERCOT Files Revenue Adequacy Study With Texas PUC

November 23, 2021

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Copyright 2010-21 EnergyChoiceMatters.com
Reporting by Paul Ring • ring@energychoicematters.com

The following story is brought free of charge to readers by EC Infosystems, the exclusive EDI provider of EnergyChoiceMatters.com

ERCOT has filed with the Texas PUC ERCOT's 2021 Revenue Adequacy Study prepared by a third party consultant and ERCOT staff.

The report states, "The energy margins for natural gas resources were calculated for all weather years and unit outage draws. The energy margins reported reflect real-time energy and reserves revenue minus unit production costs which include fuel, variable O&M, and startup costs. The slope of the CC energy margin curve, provided in Figure 12, is modest, demonstrating that scarcity is expected to be infrequent if the system achieves the reserve margin projected for 2022. Combined cycle plants are expected to achieve energy margins between $35 and $65/kw-yr when natural gas prices are near the base-case forecast of $3.10/MMBtu. The energy margins lower than CONE reflect the higher than market equilibrium reserve margin that results from the projected significant addition of online renewable capacity prior to the summer of 2022. Since renewable energy has low variable operating cost, it tends to suppress energy prices."

The report states, "The energy margins for higher heat rate gas turbines and internal combustion engines are also projected to be lower than required to cover net cost of new entry. The energy margins for GTs, shown in Figure 13, reflect more variability in percentage terms because of infrequent scarcity periods driven by wind and solar forecast error. If the wind or solar production is forecast to be higher than what actually materializes, online reserves may not achieve targeted levels resulting in ORDC price adders to real time market prices. GTs capture the revenue from a larger percentage of these events than CCs because a portion of the CC fleet is offline and unable to rapidly respond to the higher than expected net load."

Implied net revenues were calculated from energy and gas price futures. A comparison to the report's Strategic Energy and Risk Valuation Model (SERVM) weighted average net revenues is provided was provided in the report (shown below)

The report states, "Possible explanations for the significant premium in the energy price futures include the potential market assumption that ORDC will be shifted by Texas regulators, lingering concern over reliability based on experience during February 2021, skepticism about the actual renewable capacity that will come online by summer 2022, and concern that 2022 weather could be extreme, relative to what has been seen on average over the 40-year period that was considered."

The report states, "The capacity factors for higher heat rate GTs and ICs are projected to be less than 5%. As shown in Figure 15, the daily spikes in net load are mostly covered by increasing the dispatch of online CCs through a combination of operating in ‘duct burner’ mode or by carrying higher than required reserves in offpeak periods. This commitment and dispatch strategy is more cost effective than operating GTs more days per year and limits the potential revenues for GTs and ICs."

The report states, "To illustrate the market participation of GTs and CCs, the energy margins by commitment event were analyzed in Figure 17 and Figure 18 for representative generators. Nearly 80% of all commitment events produced energy margins of $10-100/MW. With an average operating period of 6-8 hours, this translates to margins over production cost of $2-12/MWh. With a capacity factor below 5%, this only covers a small portion of the cost of new entry. A few events driven by net load forecast error demonstrate scarcity pricing with energy prices above $1,000/MWh. The returns in these events that occur 1-2 times per year account for most of the projected energy margins of GTs. This is also why a few of the GTs indicate little to no energy margin for the year in Figure 16. They were likely either on planned or forced outage during those infrequent price spikes. CCs also achieve a majority of their returns in a subset of the commitment events. However, the commitment periods of the CCs are typically much longer in duration. With capacity factors of 40% or more, many CCs run for several hundred hours consecutively during the summer, and cycle daily during off-peak seasons."

See the full report here

Project 51878

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