How has the pandemic impacted power demand and pricing in Texas?

This summer, Texas is experiencing high temperatures and a dramatic surge of Covid-19. What can we expect from the power market for the next few months? In a recent webinar, our team of market analysts and meteorologists exclusively shared their outlook for the coming months in terms of power demand, pricing and more. Fill in the form to access a replay of this Summer 2020 outlook. Or read on for the top four frequently asked questions.

What are the Covid-19 impacts on ERCOT load peaks?

Direct Covid-19 impacts are starting to disappear in the ERCOT power region. However, economic factors related to the pandemic will still influence load peaks through at least 2024. The current load peak expectations are experiencing a roughly 2% drop from what we originally expected pre-Covid.

Regional normalized load data from late spring shows a stark contrast over the ERCOT territories. In the Far West region, data shows significantly reduced demand levels from potential contributors such as the major decrease in oil production, oil field employee layoffs and other general economic factors. In the North Central region, our data shows a recovery from those impacts, which may be linked to a relaxed initial reaction to the pandemic coupled with the aggressive reopening approach by the governor of Texas.

Load growth forecasts between 2020 and 2024 have been nearly cut in half in the North Central and South Central regions, based on ERCOT forecasts produced using economic analytics. Along the coast, specifically Houston, load growth is expected to have a quicker recovery rate and convergence with pre-Covid forecasts over the next few years. The Far West region’s initial growth expectations have taken an opposingly drastic hit, given the unprecedented decrease in oil and gas markets.

What are the implications for ERCOT congestion this summer?

ERCOT Far West congestion is likely to see mild impacts from the pandemic throughout the summer months. Transmission projects, like the Solstice-Bakersfield line, have experienced construction delays due to limitations in utilities and workforce. This particular line is part of the larger 345 loop project, which is intended to mitigate and handle larger scenario cases of demand growth. Delays have pushed the final line’s energization start into the fall months at the earliest.

Far West power demand this summer is now much weaker than pre-coronavirus projections. As a result, the Hamilton-Maverick constraint (flowing west to south) is expected to have a significant flow increase due to strong temperatures, lack of wind generation and Eagle Pass DC tie imports no longer offering relief for congestion.

Another trend we’re seeing this summer with generic (or non-thermal) transmission constraints, put in place to decrease inertia and frequency concerns and increase grid stability, is a greater variation in published limits for these constraints. The ISO will often lower limits, without the impact of transmission outages. This tells us that there is a pressing need to mitigate congestion issues on the grid, which could be a sign of the future for West Texas.

The most systemic generic transmission constraint we’re seeing is the Panhandle Interface, which is 500 MW below the previous year in carrying capacity due to transmission work during summer months. This is concerning as generation capacity in the Panhandle is typically higher (up to 1.7 GW) which could cause reliability issues during high load levels.

How are power price contracts and overall pricing being impacted?

On-peak power contract trading has been extremely volatile since early signs of the Covid-19 outbreak. One of the first signs of demand turndown in the ERCOT region was the bearish WTI crude oil signals that took place in February 2020. Since then, the forward curves took a steep fall as the pandemic started to take larger precedence.

In early May, pricing took a sharp upturn due to what we perceive as the market’s response to a healthy summer peak load forecast released by ERCOT, even despite economic and direct virus impacts. By early June, prices were back up to US$167 which, although not up to pre-pandemic standards, was still rather robust given the circumstances.

As temperatures warm and wind averages continue to fall, reserve scarcity and the Operating Reserve Demand Curve (ORDC) play a large role in overall pricing. We analyze the most likely wind and load curves on any given day and run these numbers through our dispatch models. A tremendous range of pricing is likely to occur on the strongest days throughout the hotter summer months, resulting in prices trending into the hundreds, if not thousands. On weaker days, prices will sit in the high teens to low twenties. August will show the widest range of pricing depending on the exponential shapes of both the supply stack and the ORDC curve.

What can we expect as we move into August?

Warmer than average temperatures and low wind generation will help the ERCOT region achieve demand level numbers we would normally expect. Our demand peak estimate for August is at 74.8 GW, only a small percentage less than our pre-pandemic expectation.

Access our full summer 2020 outlook

Want to hear more about what our team is expecting in ERCOT this summer? Fill in the form at the top of this page for complimentary access to our summer 2020 outlook replay.

Meet the team: 

• Greg Jeffrey, Research Manager, ERCOT
• Jefferson Rhoads, Senior Meteorologist
• Jessica Zolott, Market Analyst, ERCOT
• Flannan Hehir, Market Analyst, ERCOT
• Riti Goel, Market Associate, ERCOT
• Brianne Newell, Market Associate, ERCOT

Wood Mackenzie's Genscape team delivers real-time and historical data, forecasts, analytical insight, tools, and software solutions leveraging a combination of unique data collection techniques, data science, and a team of experienced energy market analysts.