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Outlook 2019: ERCOT likely to face another summer with low reserve margin


Regulators likely to implement reforms

Sources differ on tight market pricing

  • Author
  • Mark Watson
  • Editor
  • Annie Siebert
  • Commodity
  • Electric Power

Houston — Despite the Electric Reliability Council of Texas' tight supply conditions in the summer of 2018 resulting in no energy emergencies, state regulators probably will implement some market reforms in 2019, industry observers say, but they differ over how power prices might behave next year.

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"I think the most important event in 2018 was a new peak without much significant [scarcity] price formation," said Joshua Rhodes, University of Texas Energy Institute research associate.

One of the hottest summers on record resulted in a new record peak of 73.3 GW in July, but ERCOT never had to initiate an Energy Emergency Alert or request power conservation, ERCOT told the Public Utility Commission of Texas in September.

This past summer was the first since about 5,000 MW of generation retired this past winter, which dropped the planning reserve margin to about 11%, well below the 13.75% target.

"In 2018, we were lucky, and we saw wind resources that performed well," said Michele Gregg, Texas Competitive Power Advocates executive director. "Had wind not performed well, we would have had probably a different picture. Prices didn't reflect the risk we saw, in terms of the reliability of the market. ... Right now, the price signals are to retire and not invest in ERCOT."

Also in September, American Electric Power's Texas utility announced plans to shut down its coal-fired, 650-MW Oklaunion Power Station at Vernon, Texas, in mid-2020, and Gregg said Tuesday about a thousand megawatts of thermal generation capacity in the queue for construction in ERCOT have been canceled.

ERCOT's Capacity, Demand and Reserves Report, issued this month, showed an even lower planning reserve margin, 8.1%, for this coming summer.

Based on such events, Rhodes said, "I would not be surprised if some market pricing reforms happen as summer 2019 gets closer."


Gregg's group advocates a one-standard-deviation shift in the loss-of-load probability used in ERCOT's Operating Reserve Demand Curve, a mechanism for raising prices across the system as reserves diminish. Such a shift would cause the mechanism to operate more frequently for longer periods and larger amounts than in 2018.

Doing so would "better reflect the actual scarcity in the market and the risk we see in the ERCOT market with high levels of renewables," Gregg said.

ERCOT's CDR indicated that peakload will exceed existing resources by 2022, Gregg said, which she called "very concerning."

Some have criticized the proposed ORDC shift, as one proponent, Exelon, estimated it would bring about $4 billion a year more in revenue to the ERCOT over the next four years.

Nevertheless, Gregg said her group is "hopeful" that the PUC will OK such a change.

"We're waiting to see what their decision is," Gregg said. "We expect they will do what they believe is the best decision to make sure our electric market continues to be healthy in the future."


Asked how wholesale power prices might behave in 2019, UT's Rhodes said, "I think average prices will be lower (depending on natural gas prices), but peak prices will be higher."

Travis Whalen, an S&P Global Platts Analytics power market analyst, said he anticipates "a substantial year-over-year jump in prices as a result of the tighter margins."

For example, Platts Analytics expects June on-peak prices in the mid-$50s/MWh, July's in the mid $90s/MWh and August's in the mid-$130s/MWh, he said in an email Tuesday. This past summer, ERCOT North Hub average day-ahead on-peak locational marginal prices averaged $35.52/MWh, $108.85/MWh and $37.76/MWh, respectively, Platts data showed.

"The problem with forecasting ERCOT prices in general is that we're essentially attempting to predict the small number of extraordinary peaks that will determine whether average prices blow out or remain suppressed by the steady pressure of cheap wind generation," Whalen said. A statistical comparison of ERCOT North monthly average day-ahead on-peak LMPs to ERCOT average daily wind generation shows a negative correlation of 0.43, indicating that, in general, power prices fall as wind outputs rise.

"ERCOT generators are perpetually gambling on hitting just the right combination of high peak loads and low available capacity to spur drastic price increases without risking load shedding," Whalen said. "Next summer offers better odds, but that doesn't change the fact that it's a gamble."

Doug Mathes, president of Power Energy, a Spring, Texas-based energy broker, said, "The risk of prices settling higher exists due to reserve margin expectations being lower for this coming year, but we are not sold on the fact we will see overall higher prices when looking at the averages."

Asked to assess the chances of ERCOT implementing rolling blackouts to cope with excess demand this summer, Mathes said, "A lower anticipated reserve margin makes this seem more likely when compared to previous years, but the percentage chance is likely still low."

-- Mark Watson,

-- Edited by Annie Siebert,