Keep Pace with the Transforming Energy Market

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Since the start of the year, the Texas power market has been heating up.  In January, there were signs that this year was going to be different when energy prices in the Electric Reliability Council of Texas (ERCOT) cleared $1,000 per megawatt hour (MWh) and, for a few brief periods, were as high as the $9,000 per MWh price cap. The increasing prices are a welcome sign for many Texas power generators, which have suffered through a bear market for the past three years with the average energy price from 2015 through 2017 of just $23 per MWh.

Most of Texas operates in the ERCOT power market.  ERCOT is unique among the multiple independent power market system operators in the United States in that it operates an energy-only market with a very high hourly price cap. It operates with limited transmission ties to neighboring markets, leaving it unable to import energy during scarcity conditions.

There are a number of strong indications that electricity prices in ERCOT will continue to spike this summer and going forward.

1) The financial futures markets for electricity prices in ERCOT recently settled the August 2018 futures price for ERCOT North Hub over $200 per MWh. For comparison, ERCOT North Hub prices in August 2017 averaged around $28 per MWh.

2) Wholesale electricity prices in Texas are sensitive to temperature, with air conditioning loads driving consumer electricity demand. ERCOT is projecting a peak summer load of 72,756 MW which is 1,600 MW higher than the all-time peak demand record set in August 2016. Since the ERCOT 2018 forecast assumes normal weather, an even higher record could be set if the National Weather Service prediction for higher-than-normal temperatures this summer comes true.

3) Texas has seen strong population and economic growth driven by shale oil and natural gas plays and low business costs.  These drivers have also contributed to steady electric load growth over the past decade. ERCOT projects energy demand to continue to grow and expects peak summer demand to increase by 8 percent between 2019 and 2023.

4) 4,200 MW of coal-fired capacity retired earlier this year with another 1,260 MW planned for retirement in 2019. For years, these older coal-fired power plants have struggled to compete due to low natural gas prices and low power prices squeezing profit margins.  The coal-fired power plants have also struggled to adapt to the nearly 21,000 MW of wind resources in operation in ERCOT. At times, wind electricity generation is able to serve nearly half of ERCOT load, putting downward pressure on electricity prices and causing ERCOT to turn off inflexible power plants.

These retirements along with strong load growth projections have driven down the planning reserve margin in ERCOT, which is a measure of the amount of reliable power generation capacity available to meet peak loads.  ERCOT targets a planning reserve margin of 13.75 percent, but currently expects the reserve margin to be approximately 11 percent this summer.  It could fall toward 9 percent without new power generation capacity additions.

5) Leidos forecasts ERCOT electricity prices will increase and see higher summer peak levels over the next few years.  The real fireworks could come in four to five years when ERCOT summer peak demand is expected to reach 80,000 MW.  Without a mini construction boom of new power generation capacity, demand could drive extended price spikes with prices frequently approaching the $9,000 price cap.

While these five indicators point to increasing wholesale power prices in ERCOT and an improving profit outlook for power generators in ERCOT, there are also growing risks that power generators need to evaluate: 

  • Because of ERCOT’s energy-only market design and reliance on administrative “price adders” during peak hours when scarcity conditions occur, the relatively small increase in installed capacity from adding a few natural gas-fired peaking plants can have dramatic effects on price levels.
  • In our modeling, adding a few new power plants before 2022 could drastically lower the level that prices reach during peak hours and eliminate any “fireworks.”

In short, it is a time of great opportunity but rapidly increasing risk for developers and investors in power generation in the ERCOT market.

For more information on our power market outlook and how we evaluate risks and opportunities for generation developers and investors, please see

John Higgins has nearly three decades of experience in the energy industry, helping clients analyze complex issues involving competitive energy markets, market rule and tariff design, and the operation of energy assets. He has significant experience providing energy market advisory services focused on market assessment and price forecasting services, as well as market consultant reports, valuations, and dispatch studies in support of energy asset transactions. John also represents clients in regional ISO/RTO stakeholder processes, providing advisory services on proposed changes to market rules and anticipated impacts on client assets. He has recently supported several acquisitions, sales, and equity investments in gas and wind resources in ERCOT.