ERCOT Power Prices to Continue Spiking? Part 2

October 29th, 2019 |

As ERCOT has become more dependent on wind and solar and load has hit new records, pricing volatility has been on the rise. In a previous blog, we discussed the strain on pricing and natural gas generation resources that the market witnessed this past summer, however there are more than 76 GW of new wind and solar resource announced that will continue to alter the ERCOT landscape. Will these ERCOT wide price spikes continue given the new generation set to come online? Let’s take a look at how the situation would change next summer if we were to have a replay of the ERCOT’s record setting day from this summer.

As a refresher from our previous post, let’s look at August 13, 2019 in ERCOT. On that day as Texas experienced higher than normal temperatures, ERCOT hit their record load and the amount of capacity kept in reserve shrunk causing ERCOT to issue an emergency alert. As shown in the graphic below, prices spiked in the afternoon to almost $9,000/MW. Concurrently, natural gas fired plant utilizations rose to 80%.

So how would a similar situation next August play out with the new capacity that is set to come online between now and then? The generation interconnect queues are a good place to start. For any new resource to be tied in to the grid, a series of studies and applications must be completed before a project can enter service. However, while it’s a good start, an ISO’s queue can drastically overstate the amount of capacity coming online if taken at face value. Therefore, as a first pass we can look at each project’s timing and progress in the queue to determine if a project making its way to market is becoming riskier.

The graphic below shows historic timing of solar projects reaching their Full Interconnection Study (FIS) as the dark blue line corresponding to the left-hand axis. About half of the wind projects that have made their way through the queue in the last five years have received their FIS at about a year and a half or prior. The blue columns represent wind projects that are active in the queue with in-service dates prior to next August and how long they have been seeking their FIS, along with their capacity, corresponding to the right-hand axis. The farther to the right projects are the more at risk they are. In this case we marked projects that are still seeking their FIS after two years of being in the queue as “At Risk”.

This same analysis can be done for other milestones projects hit during their time in the queue, as well for wind projects. This gives us a high-level view of what capacity is at risk versus projects that are on track. Other state and federal agencies can then be used to corroborate and refine this risking. In the end, of the 11.7 GW of wind and solar in the ERCOT queue that expects an in-service before next summer, about 30% of that capacity is at risk bringing incremental wind and solar capacity for next summer down to 8.5 GW.

Now what would a record setting day look like next August? Let’s layer in that new risked wind and solar to see what natural gas generation would look like.

Ignoring further transmission congestion that would be potentially caused by the new wind and solar resources, in the evening when load peaks, ERCOT-wide natural gas generation utilizations would fall by about 7%, from 90% to 83%. There are no meaningful gas or coal retirements through next summer, however about 2 GW of incremental gas-fired capacity would bring that utilization down even further to 80%. Still a formidable use of natural gas likely to drive pricing strength, however closer to this past August’s average evening utilization of 77%. For more on BTU Analytics’ power market analysis and services, please reach out to the BTU Analytics team.

Author: Matthew Hoza

Matthew is a Manager of Energy Analysis for BTU Analytics. He oversees product development and the publication of BTU Analytics’ product offerings which cover the oil, gas, and NGL markets for the US and Canada. He also leads research on the downstream markets for natural gas, natural gas midstream, and natural gas pricing dynamics across the US. He holds a M.S. in Finance from the Simon Graduate School of Business at the University of Rochester and B.S. in Physics from Florida State University.