ERCOT’s Summer Peak Demand Forecast: New Investment, Generator Profits, No Blackouts
Wholesale electricity markets are in the news, as oversupplied markets drive prices down and force early coal and nuclear retirements. Companies like FirstEnergy have petitioned the federal government for regulatory changes and new market rules to drive up prices and profit margins — but the picture is different in Texas.
The Electric Reliability Council of Texas’ “energy-only” market (EOM) model exposes the value of flexible resources without capacity markets, testing market design in a high-renewables future.
Texas’ market model is working: Market forces are accelerating the transition from dirty, expensive plants to cleaner, cheaper resources including renewables, demand response and batteries. Avoiding capacity markets has saved ERCOT customers billions and kept the system reliable.
But coal retirements and increased load forecasts will put ERCOT’s EOM model to the test. ERCOT’s reserve margin is expected to be significantly below its target this summer, prompting electricity service disruption fears. Market observers are watching closely, as ERCOT does not use capacity markets, the most common alternative for ensuring reliability in markets. These capacity subsidies slow the transition away from uneconomic coal and nuclear while suppressing price signals for flexible units that complement cheaper, cleaner energy resources.
To an unschooled observer, the EOM structure’s test will be whether ERCOT can avoid shortfalls (i.e., a loss-of-load event). But no level of investment or reserve margin can entirely eliminate all risk or protect the grid.
The true test of ERCOT’s market design is whether higher prices spur investment to drive the system back from acceptable risk to a more desirable level of risk. Fortunately, ERCOT looks capable of passing this test, and it should continue avoiding expensive capacity markets.
Will a disruption happen? Putting ERCOT’s planning reserve margin in context
A December 2017 planning report prompted concerns that ERCOT’s EOM might not ensure adequate reliability, pegging its summer 2018 expected planning reserve margin (PRM) at 9.3 percent. ERCOT’s PRM has since increased to 11 percent, meaning expected generation fleet capacity exceeds expected summer peak load, minus emergency load management tools (e.g. demand response) by 11 percent.
This is below ERCOT’s 13.75 percent minimum target reserve margin, which reflects ERCOT’s desired risk threshold in line with a resource adequacy standard of “one loss-of-load event in 10 years,” where a loss-of-load event (LOLE) is defined as a system deficit triggering rotating outages. However, this summer’s dip below the target PRM doesn’t mean Texas is taking unacceptable systemwide service disruption risks.
Because plenty of uncertainty exists about exactly what level of reserve margin corresponds to a given system risk level, the target PRM is not a magic number, shown by a 2014 Brattle and Astrapé study. The Public Utility Commission of Texas asked them to estimate ERCOT’s economically optimal PRM to inform their ongoing review of market design for resource adequacy, to determine whether ERCOT’s EOM design could deliver desired reliability. Brattle’s top-line results showed widely varying values for possible target reserve margins.
The report includes a wide range of results (12.6 percent to 16.1 percent) for a reliability standard of one event in 10 years (0.1 LOLE), ERCOT’s level of desired reliability risk, in sensitivity cases. This reflects how sensitive an estimate of the desirable PRM is to model assumptions, especially assumptions about the frequency of extreme events. The PRM cannot be a precise measure of reliability risk beyond an accuracy of a couple percentage points.
The PRM resulting from market forces under current rules is called the market equilibrium reserve margin. According to Brattle’s report, ERCOT’s MERM is around 11.5 percent (9.3 percent to 12.9 percent in sensitivities), well short of its 13.75 percent target and resulting in one event in three years (0.33 LOLE) in the models. At this summer’s 11 percent PRM, the study estimates 0.44 LOLE.
The probabilities from this study are quite sensitive to small changes in PRMs and thus can’t be counted on to tell us exactly what ERCOT’s reliability level is for this summer.
Is the risk of system reliability as bad as it seems?
If ERCOT breaches undesirable levels of reliability this summer, how close to the sun will Texas’ grid fly? In other words, is an 11 percent PRM equal to an acceptable level of system risk if new investment will push it back up in coming years?
One fact should help policymakers conclude that Texas is still facing acceptable system risk this summer: Compared to metrics from other jurisdictions, 11 percent seems like an adequate PRM. For example, the one in 10 years resource adequacy standard is a historical construct adopted by the electric power industry that grid operators can interpret differently: “one event in 10 years” could be one day or 24 hours in 10 years (i.e., 2.4 loss-of-load-hours per year). According to Brattle, ERCOT only needs a 9.1 percent PRM to achieve this loss-of-load-hours standard.
Furthermore, reliability from these metrics is more stringent than what customers experience due to distribution-related outages. Suppose this summer ERCOT has an unusually high peak load and reserves dip too low. After a progressive series of steps to add generation from other grids and enlisting large customers who voluntarily are paid to be curtailed during emergencies, ERCOT and the Public Utility Commission of Texas will ask the public to conserve electricity. Once all avenues are played out, ERCOT can institute rotating outages to preserve the entire grid’s integrity — no systemwide blackout would occur.
Rotating outages have only happened three times in ERCOT history, yet even then customers experienced relatively little disruption compared to typical distribution grid problems.
Brattle’s 2014 report explains that even at the lower 2.4 loss-of-load-hours reliability standard, the possibility of rotating outages means customers can expect in a given year to be without power for “only 3 minutes per customer; this compares to an average of a few hundred minutes per customer per year from distribution outages.” The slight possibility of more system-deficit issues is a blip compared to much more common distribution outages.