Top Energy Trends in the Texas ERCOT Market: Reserve Margin

By March 9, 2020 News

As buyers of power continue to adjust their strategies to avoid risk and maximize opportunity in the market, Energy Edge recaps the trending topics of 2019 and a look ahead to leading indicators for 2020 and beyond.

Executive Summary

  • Ahead of the 2019 summer season, ERCOT forecasted a historical low reserve margin of 7.4%. This is nearly half of the preferred target at 13.75%
  • Expectations for 2020 are similar to 2019 with record use and potential constrained grid conditions
  • Reserve margins will continue to be the leading influence of forward prices as Texas’ generation mix transitions with less fossil-fuel and more renewables like wind and solar
  • As renewable energy growth continues, new fossil fuel generation is less likely to be developed

The ERCOT Reserve Margin

The primary theme for the ERCOT region in 2019 was the electric system’s Reserve Margin. ERCOT’s target reserve margin, the difference between available capacity and peak demand, is 13.75%. In December 2018, ERCOT forecasted the 2019 summer reserve margin at a record low 8.1%. The reserve margin for summer 2018 was recorded at 11%. By March 2019, ERCOT reported its then planning reserve margin was a historically low 7.4%. In its final Seasonal Assessment of Resource Adequacy (SARA) report for the 2019 summer season, ERCOT reported it had increased the forecasted planning reserve margin to 8.6%. Entering 2020, ERCOT is foreseeing a slight uptick in reserve margin to 10.6%, still below preferred targets and slightly above previous year’s lows. The grid operator reported in its recent SARA release it expects 2020’s summer to perform much like 2019: setting record demand levels and potential for emergency conditions.

What is leading to this reduction in reserve margin?  Two major factors are contributing to the reducing reserve margin in ERCOT.  First, growth in the area continues to surge leading to increased demand on the grid. Second, there have been four major coal plant retirements since 2017 totaling around 4,800 MW. Additionally, more generation is expected to be retired ahead of expected end-of-life due to the economics of running the plant versus the economics of market-priced electricity rates in Texas.

The demand growth in Texas has led to 16 new peak demand records in ERCOT between 2016 and March 2019 as well as new all-time system-wide peak demand records in 2016 and 2018.  Peak demand records are expected to continue to be surpassed in 2020.

Meanwhile, generation capacity growth is struggling to match demand.  New fossil generation is slow to develop for several reasons, mostly economical. It is expected that this imbalance of supply and demand will increase volatility on the grid. Increased volatility will lead to higher prices, in turn, will spurn generation development, leaving the future bright for adequate resources and a healthy reserve margin.  The project queue in ERCOT demonstrates how renewable projects continue to gain momentum and there exists planned expansion in generation capacity. ERCOT is expecting 7,633 MW of capacity additions to be added before summer 2020. In the near term, however, the system will continue to be tested against weather conditions, growing demand, and the intermittency of new renewable resources.

Expectations for 2020

It will continue to be a waiting game as we approach the months of July and August, where most of the cost premium exists for spot power. In 2019, settlement prices in July trended near the average for the year with a small uptick while forward prices for 2020, 2021, and 2022 started to drop slightly. It wasn’t until the second week of August when Texas experienced a brief heatwave combined with some generation going offline, did prices react to emergency events and speculation return to forward pricing.

That’s all it will take to increase volatility and near-term risk in this market:  a good old-fashioned long-running Texas Summer.  The last three years the summer has been relatively mild as far as Texas’ summers go.  Memories shouldn’t be that short to 2011 when the leading news headlines were how many 100-degree days in a row the state was experiencing.

The Takeaway for Power Buyers

  • “Waiting to buy closer to contract expiration date” is not a strategy. Near-term (12-month or less) power buys are at a premium.  Evaluate business operations policies and consider purchasing 2-3 years or more ahead to take advantage of lower future power curves.
  • Forward contract pricing from renewable assets is becoming more in-line with traditional sources and a strategic solar purchase can help an organization mitigate the risk of high prices during summer on-peak hours.
  • The drawbacks of renewable assets should still be considered. Solar and wind generation cannot serve as a “be-all-end-all” solution to bridge ERCOT’s reserve margin deficit.  Renewable sources can be intermittent, and production is not guaranteed.  Thus, emergency events could still occur in ERCOT until the reserve margin is improved.  If your business requires some level of operational resiliency then onsite generation assets should be considered to ensure continuous operations and can also act as a potential revenue stream during ERCOT emergency events.

How Energy Edge Can Help

  • Energy Edge has over ten years’ experience as a company, developing energy strategies for commercial and industrial customers.
  • We can assess current contracts against market conditions to plot a path forward based on the customer organization’s risk appetite and needs for budget certainty.
  • Energy Edge can also help the organization develop a long-term strategy that incorporates aspects of purchasing, resiliency, renewables, and sustainability.


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