June 5, 2020

ERCOT Market Monitor finds pricing change increased revenue by $2 billion

by Kelso King, Grid Monitor
Source – Grid Monitor
Posted 06/05/2020

Potomac Economics, the Independent Market Monitor (IMM) for the Electric Reliability Council of Texas (ERCOT), released its 2019 State of the Market Report for the ERCOT Electricity Markets in May 2020.

The IMM concluded that overall, the ERCOT wholesale market performed competitively in 2019. The IMM’s key observations from 2019 include:

•     Warm summer temperatures increased both the peak and average loads by roughly 2% from 2018 and set a new record peak hour demand of 74,820 MW on August 12, 2019.

•     Average real-time energy prices rose by 32% in 2019, despite a 23% reduction in natural gas prices. This increase is attributable to shortage pricing in August and September, with prices close to the offer cap of $9,000 per MWh for a total of more than two hours.

•     The first stage of a change to the shortage pricing mechanism was implemented on March 1, 2019. This change had the effect of increasing the revenue due to shortage pricing by $1.9 to $2.1 billion in 2019, out of a total $3.7 to $5.1 billion. Shortage pricing is key in ERCOT’s energy-only market because it plays a pivotal role in facilitating long-term investment and retirement decisions.

•     The supply mix in ERCOT continues to change rapidly.

The report noted that the PUCT directed market improvements to help transition the wholesale market to a future with a different resource mix. Most importantly, it approved the implementation of real-time co-optimization of energy and ancillary services, which is planned to begin in 2024. This will significantly improve the real-time coordination of ERCOT’s resources, lower overall production costs, and improve shortage pricing. These improvements will be increasingly valuable as additional intermittent wind and solar resources enter the ERCOT market.

Approximately 4.9 gigawatts (GW) of new generation resources came online in 2019, the bulk of which were wind resources with total nameplate capacity of 4.7 GW. Investment in wind resources has continued to increase over the past few years in ERCOT. The amount of wind capacity installed in ERCOT approached 27 GW at the end of 2019. ERCOT continued to set new records for peak wind output in 2019. On January 21, wind resources produced a record 19,672 MW instantaneously. On November 26, wind provided nearly 58% of the total load, also a new record.

Congestion costs in ERCOT’s day-ahead and real-time markets in 2019 totaled $1.1 and $1.26 billion, respectively. These values were comparable to congestion in 2018, the largest share of which was in the West zone in both years.

For the first time since 2011, “net revenues” in all four zones exceeded the estimated cost of new entry for both natural gas combustion turbines and combined cycle resources, driven primarily by significant shortages in August and September combined with the adjustments to the ORDC in 2019.

According to the IMM, based on an examination of “pivotal suppliers,” structural market power continues to be a potential concern in ERCOT, requiring effective mitigation measures to address it. However, very low levels of potential economic withholding allowed the IMM to conclude that “the ERCOT market performed competitively in 2019.”


The IMM recommended a number of key improvements to ERCOT’s pricing and dispatch to address perceived market inefficiencies and suggest improvements and enhancements.

1.       Remove the “opt out” option for resources receiving Reliability Unit Commitment (RUC) instructions to remove an incentive to submit Commercial Operations Subcommittee (COPS) that do not reflect the actual planned resource status.

2.       Eliminate the “2% rule” and price all congestion regardless of generation impact because this rule eliminates the only market signal showing prospective resource owners where to place resources to help solve “unsolvable” congestion.

3.       Modify the allocation of transmission costs by transitioning away from the 4CP method and adopting a method that creates incentive that better reflect the true drivers for new transmission.

4.       Price Ancillary Services based on the “shadow price” of procuring each service so that the clearing prices, both current and future, are based on all the constraints used to procure those services.

5.       Modify the reliability deployment adder and operating reserve adder to improve pricing during deployments of Emergency Response Service.

6.       Implement a locational reliability deployment price adder (RDPA) to reflect local reliability actions.

7.       Improve the mitigated offers for generating resources by: (a) including commitment costs for RUC-committed intervals by amortizing these costs over the RUC commitment period; (b) including opportunity costs, major maintenance costs, and operating risks that are marginal costs; and (c) removing all fixed costs that are not marginal.

8.       Implement transmission demand curves to reflect the increasing reliability costs of higher overloads and improve the nodal prices at all locations that are affected by a violated constraint.

The IMM also recommended retiring several previous recommendations:

·         Evaluate and improve Load Distribution Factors (LDFs) used in the CRR and Day-Ahead Market (DAM) clearing activities.

·         Evaluate and improve Load Distribution Factors (LDFs) used in the CRR and Day-Ahead Market (DAM) clearing activities.

·         Modify the real-time market software to better commit load and generation resources that can be online within 30 minutes.

·         Evaluate the need for a local reserve product.

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