In October 2017, Vistra Energy announced that it would be retiring over 4,000 MW of generation capacity before the summer of 2018. The retirements represented ~5% of ERCOT’s total generation capacity and have significantly reduced the projected reserve margin for the summer 2018 planning period. In the latest Capacity, Demand, and Reserves report issued by ERCOT, the grid operator projected a 9.3% reserve margin for this summer which represents a 50% decrease from the previously forecast reserve margin of 18.9%.
As a direct result of recent retirements of coal based generation units, prices for on‐peak electricity for delivery during summer months in 2018 have nearly tripled across ERCOT since October.
The impacts of the retirements continue into the future with prices for summer 2019 and 2020 electricity having increased 80% and 68% respectively over the same period.
The increases in summer 2018 have been more dramatic than 2019 or 2020 for a couple of reasons:
There are very few “solutions” in the works to address the possible shortages during summer 2018, with any possible new generation resources not expected until late 2018 or early 2019. Natural gas‐fired generation is expected to increase by 1,038 MW in late 2018 (after summer) and 1,413 MW in early 2019. This generation will be split between nearly ten new projects and additions with the largest being the 663MW Tenaska Roans Prairie project. There are a few projects that are anticipated to start service in late spring of 2019 and if they were to come under any regulatory or construction delays, the anticipated natural gas‐fired generation would not be available for the summer and electricity prices would remain elevated. Traders are also taking a “wait and see” approach to how the grid reacts during the coming summer before assessing the true risk to prices and grid reliability.
Significant Risk Remains!
There are four coal‐fired power plants in ERCOT representing an additional ~4,000 MWs or ~5% of ERCOT generation capacity that remain at risk of retirement, according to a 2016 study by the Institute for Energy Economics and Financial Analysis. They are Dynegy’s 600 MW Coleto Creek located near Fannin, TX, and three plants owned by public power utilities or power agencies. Those are the 1,600 MW Fayette Power Project located near La Grange, TX, the 470 MW Gibbons Creek plant located near Carlos, TX (currently runs only five months of the year due to a lack of profitability), and the 1,300 MW J.K. Spruce Unit 1 and Unit 2 located near San Antonio, TX. Of note, the Spruce Power plant is in the process of installing carbon reduction systems which should forestall its retirement.
Further, the City of San Antonio which owns both the J.K. Spruce and the 932 MW J.T. Deely coal‐fired power plants, has already announced that the Deely plant will be shuttered at the end of 2018. The potential retirement time of the four plants is undetermined at this point. With the recent increase in 2018 summer electricity prices, the potential retirement of these plants will probably be reassessed after we see how prices react this summer.
Actual weather this summer will play an extremely large role in how the grid and prices react. Recent summer weather outlooks have predicted the 7th hottest summer on record based on population weighted cooling degree days, a measure of how much air conditioning electricity demand will occur. The forecast specifically paints a “warmer than normal” summer for Texas:
Should that forecast prove true, summer 2018 prices could be even more volatile than current prices account for, which would result in 2019, 2020, and maybe even 2021 prices to react and increase.
Countering some of the risk presented by the weather forecasts are possibilities that load shifting and demand response actions by consumers in Texas will limit peak demand and mitigate some price volatility. Those actions are hard to predict and in many cases consumers’ willingness to participate wanes during periods of sustained heat. Even modest participation levels, which remove 2% or 3% of demand during peak periods, would have the effect of increasing implied reserve margins back above 10% and lowering prices dramatically.