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Doubling Down on ERCOT’s CDR Report, Summer 2018

Feb 15, 2018 5 MIN. READ
Generators could see a tremendous opportunity to earn above-new-cost returns.
Two months ago, ERCOT’s Capacity, Demand and Reserves (CDR) report projected a reserve margin of just 9.3 percent going into 2018. Even though this figure is widely acknowledged to be well below both economical equilibrium and target planning levels, the power market has reacted only modestly. However, a close look at the situation this summer shows that the $9,000 price cap for energy in the market may be sustained over the summer peak this year, producing scarcity revenues far above what market forwards are showing and creating opportunities for owners and investors.

On-peak Forward Prices Traded Over February 7th


Peak Forward ($/MWh)

Scarcity Estimate ($/kW)


















ERCOT Summer Assessment: 2017 vs. 2018 (Projected)

MW - Summer Reserve Capacity

Forecasted Case

90th Percentile Thermal Outage

90th Percentile Low Wind

Extreme (2011) Weather Load Adjustment






2018 (anticipated)





ERCOT notes that any value below 2,300 MW indicates risk of EEA1, the point at which ERCOT begins to take emergency actions such as manual all-call of resources, deployment of interruptible load (ERS), and use of emergency interties. The real-time price at this point is likely at the $9,000/MWh price cap.

In the forecasted case, the peak hour reserves dip to 1,037 MW, which means a shortfall of 1,263 MW before ERCOT could avoid emergency conditions. Using recent load shapes, we estimate that on average, nine hours over the course of the year would be within 1,263 MW of the peak demand. If each of these hours were at the price cap, it would imply scarcity of $81/kW-yr just in those hours, and additional hours would see high prices as well, further raising scarcity. For comparison, we estimate no year since 2011 has seen scarcity higher than ~$30-35/kW, with 2015-2017 being below $20/kW-yr each. Further, this is just considering normal forecasted conditions, not accounting for possible contingencies.

We expect scarcity for the remainder of the year could be as high as $100-120/kW. Further, the forwards have only moved up to these levels recently (showing ~$50/kW of scarcity), with the January 23rd price spikes as a result of a delay in the day-ahead clearing mechanism, unrelated to any fundamental summer peak condition. The August peak forward for 2018 as of December 7th was just $88.1/MWh, vs. the $107.1/MWh as it stands in early February.

What could that mean? Forward prices tend to overweight recent historical outcomes and undervalue shifts in market fundamentals going forward. If the summer of 2018 materializes with very high scarcity, the forwards may again overreact, allowing savvy market participants to lock in forward contracts. Though not without risks, this situation presents a tremendous opportunity to generators to earn above-new-cost returns at a time when capacity market pricing elsewhere have been modest.

Viborg thermal power station in Denmark
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