How Renewable Energy Really Performed During the February Crisis in Texas

Prior to this February, the most extreme power market event in Texas was August 2019, when high temperatures and low reserve margins drove prices to $9,000/MWh for the first time in the market’s history. This February, power prices were at or near $9,000/MWh for nearly 100 hours, leading to a cumulative price that was over 10x higher than that of the prior “explosive” market event.

This article was co-written with REsurety’s VP of Power Markets Research, David Luke Oates.

Renewable energy often gets blamed for problems not of its making. It happened most recently in mid-February 2021, when ERCOT became a household name across the country, as the grid nearly collapsed during a week of crippling cold weather. 

Tragically, millions of Texans were without power and water for days. The power market, meanwhile, saw prices that smashed all previous records for high-priced events.

It is hard to overestimate the magnitude of this event from a power market perspective. Prior to this February, the most extreme event the Texas market had experienced was August 2019, when high temperatures and low reserve margins drove prices to $9,000/MWh for the first time in the market’s history. August 2019 paled in comparison to February 2021. The graph below shows the cumulative hourly price of electricity over the critical months of February 2021 and August 2019; February 2020 is shown for reference. 

Figure 1: Observed cumulative power prices at ERCOT North Hub reveal the extremeness of the February 2021 event from a power market perspective. February 2021 (shown in red) exceeded the same month in 2020 by 84 times (green line) and exceeded the previous record-setting month, August 2019, by 10.5 times (blue line).

In August 2019, prices reached the vicinity of $9,000 for 4 hours. In 2021, by contrast, the price of electricity was at or near $9,000/MWh for around 100 hours, leading to a cumulative price that was over 10x higher than that of the prior “explosive” market event.

The ultimate cause of February’s events was record-breaking low temperatures across the state, driving very high demand for electricity over several days. Outages of generation capacity dramatically increased the supply-demand imbalance and amplified power market impacts.

Interruptions in natural gas supply and frozen equipment at generator sites led to the outage of up to 26 GW of gas-fired generation capacity. Similar fuel supply and on-site systems failures led to the outage of 7 GW of coal and nuclear capacity.

While wind and solar outages also occurred, reports of up to 18 GW of outages greatly overstate the contribution of renewables to the supply-demand shortfall. Such values conflate two drivers of wind and solar output: 

1. The quantity of wind and sun “fuel” (which is commonly accounted for by planners), and, 
2. The availability of the plant to convert that fuel into electricity (which is not commonly planned for). 

Recognizing that solar output is seasonally low in the winter and that wind speeds tend to drop during cold snaps, ERCOT was depending on only 300 MW of solar and 7 GW of wind in its baseline winter 2021 peak demand scenario. In contrast, ERCOT anticipated 74 GW of thermal and hydro output, of which 33 GW ended up on outage.

At REsurety, we developed what we believe are more relevant measures of renewable outages: First, we compared the actual output of renewables to ERCOT’s planning expectations. This difference measures renewables’ contribution to the supply-demand shortfall. 

Second, we compared the actual output of ERCOT renewables to our modeled output (similar to the modeled generation available in REmap), using site-specific weather conditions. The difference between those two values is a measure of actual availability-driven outages at renewable energy projects.

The figure below shows both comparisons for ERCOT’s wind fleet. Focusing on the period of extremely cold weather, from Feb. 14 through 18, we found that average wind output was about 2.7 GW above ERCOT’s “Extreme Low Wind” scenario and about 2.5 GW below the 7 GW reflected in ERCOT’s baseline seasonal plan. Hourly wind output was above the Extreme Low Wind level during all but a couple of hours on the night of February 15th. 

Figure 2: ERCOT’s existing wind generation fleet – modeled generation based on actual wind resource available, actual generation, and expected generation per ERCOT’s planning guidelines.

Since ERCOT expects to be able to avoid widespread load shedding in both the Baseline and Extreme Low Wind Scenarios, our research suggests that the performance of wind facilities in February was consistent with reliable operation of the power system under ERCOT’s plans.

We estimate that factors such as icing and equipment failure reduced wind output by about 6 GW during the cold snap — well below the 18 GW value that has been widely reported. Nevertheless, these availability-driven outages clearly had an impact. But for this 6 GW of outages, wind output would have been well above ERCOT’s baseline expectation throughout the deep freeze event.  

Turning to solar, we found that output consistently exceeded the values expected under ERCOT’s baseline plan, except overnight. While production was relatively low due to both seasonal factors and high cloud cover due to the storm, there was little evidence of availability-driven outages. The fleet’s output was at about our modeled estimate for the duration of extreme cold.

Finger-pointing follows any major disruption like this, and that’s to be expected. However, the best way to find the problem that needs fixing is to look at the power that was projected versus the power that was delivered. And there, renewables did far better than they’re being given credit for.

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