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Two power markets, two summer peaks

image credit: Adobe Stock

In today’s power markets, when electricity demand surges, natural gas usually picks up to meet the gap.  Data and analysis compiled by ABB’s Velocity Suite research team sheds light on how two of the largest power markets in America met last summer’s peak demand. The two regional transmission organizations (RTOs) in question are the Electric Reliability Council of Texas (ERCOT) and the PJM Interconnection (PJM).

ERCOT manages the flow of electricity to more than 26 million customers – representing about 90% of the state of Texas’s electric load.  The PJM Interconnection coordinates the wholesale electricity market across 13 eastern and midwestern states including the District of Columbia, and it is responsible to meet the electricity demands of an estimated 65 million Americans.

ISO/RTO footprint map


ERCOT 2019 summer peak  


August 2019 proved to be the 2nd hottest month on record for Texas, this coming after what was a cool start to the summer season where June and July represented the coolest period since 2007.  Last summer’s (2019) peak demand in ERCOT occurred on August 12 between 4:00 PM and 5:00 PM, reaching 74.7 gigawatts (GW).  Temperatures across all major Texas metropolitan areas on that day ranged from 90 to 100 degrees Fahrenheit (F).  During the peak hour, natural gas provided 63.6% (47.1 GW) of total power generation.  Coal and nuclear accounted for 16.9% (12.5 GW) and 6.7% (5.0 GW) respectively.  Fossil fuel and nuclear together accounted for 87.2% (64.5 GW) of total load, with fossil fuel alone representing 80.5% (59.6 GW) of all power generation.

ERCOT hourly electricity production by fuel, and system load on August 12, 2019 (MW)


Wind’s contribution during the peak was considerably higher than predicted in the region’s final Seasonal Assessment of Resource Adequacy (SARA) report.  The summer 2019 SARA report projected wind to provide just 4.90 GW at the time of summer peak demand, but when the peak arrived, wind provided 7.45 GW – 52% (2.55 GW) higher than anticipated.  This elevated wind availability made a significant difference to the portfolio of available capacity since the actual capacity available for operating reserves during the peak was only 1.5 GW.  Also helping the supply side at the time of peak, though relatively small, generation outages were 3.97 GW compared to the final SARA forecast of 4.23 GW.  Gas-powered combined-cycle and combustion turbines provided most of the firepower during the ERCOT peak.  From hourly unit level electricity production data compiled by the ABB team, the following list highlights the top natural gas power plants’ contribution in megawatts (MW) during the peak hour:


  • Cedar Bayou (1,839 MW), NRG Energy Inc., Chambers County, TX
  • Wolf Hollow (1,785), TexGen Power LLC, Hood County, TX
  • Forney Energy Center (1,756), Vistra Energy, Kaufman County, TX
  • Colorado Bend Energy Center (1,604), TexGen Power LLC and Exelon Corp, Wharton County, TX
  • Midlothian Energy Facility (1,415), Vistra Energy, Ellis County, TX
  • Jack Energy Facility (1,212), Brazos Electric Power Cooperative, Jack County, TX
  • Deer Park Energy Center (1,170), Energy Capital Partners, Harris County, TX
  • Kiamichi Energy Center (1,154), Tenaska Inc., Pittsburg County, OK
  • Handley (1,133), TexGen Power LLC, Tarrant County, TX
  • Channelview Cogeneration Plant (1,062), Energy Investors Funds Group, Harris County, TX
  • Remaining 71 natural gas power plants (32,347 MW)

During the peak hour, 194 gas units representing 81 power plants were generating electricity.  Sixty-one plants with 250 MW or greater capacity, accounted for 94% of the available natural gas capacity at the time.     

PJM 2019 summer peak

For the most part, the summer of 2019 was relatively uneventful in the PJM region.  Peak demand occurred on Friday, July 19, during the hour ending at 6:00 PM at 151.6 GW, substantially behind the all-time PJM peak of 165.6 GW set during the summer of 2006.  According to data compiled by the U.S. Energy Information Administration’s (EIA) Electric System Operating Database, during the 6:00 PM ET hour on July 15, total load exceeded 704 GW nationwide, the highest load level since July 20, 2017, when demand topped 718 GW nationwide.  The high demand pushed the daily output to over 14 TWh – also the highest level in two years. 

Like in ERCOT, natural gas was the largest contributor at the hour of peak demand.  Natural gas-powered 42.1% (65.2 GW) of all power generated in the PJM during the hour.  Coal (42.9 GW) and nuclear (32.7 GW) accounted for 27.7% and 21.1% of total power generation at the time.  The combined power output from fossil and nuclear represented 93.2% (144.5 GW) of all available power.   The combined output of hydro (5.3 GW), wind (3.8 GW), solar (0.73 GW), and other renewables (0.63 GW) represented 6.8% of total output during the on the hour.

PJM Interconnection hourly electricity production by fuel, and system load on July 19, 2019 (MW)


The following list displays the capacity contribution by the top natural gas power plants during the peak hour across the PJM grid:


  • Greensville Combined Cycle Facility (1,587 MW), Dominion Energy, Greensville County, VA
  • Lackawanna Energy Center (1,382), Invenergy LLC, Lackawanna County, PA
  • Brunswick County Power Station (1,347), Dominion Energy, Brunswick County, VA
  • Warren Power Generating (1,315), Dominion Energy, Warren County, VA
  • Hanging Rock Energy Center (1,285), Vistra Energy, Lawrence County, OH
  • PSEG Linden Generating Station (1,224), PSEG, Union Country, NJ
  • Fairless Energy Center (1,207), Starwood Capital Group, Bucks County, PA
  • Bergen (1,153), PSEG, Bergen County, NJ
  • Lawrenceburg Energy Facility (1,094), ArcLight Capital Partners, Dearborn County, IN
  • Kendall County Generation (1,085), Vistra Energy, Kendall County, IL
  • Remaining 128 natural gas power plants (50,030 MW)

At the peak hour, 311 gas units representing 138 power plants were generating electricity.  Eighty-five plants with 250 MW or greater capacity accounted for 90.1% of the available natural gas capacity at the time.

Looking forward

Despite the huge buildout in wind resources across Texas in recent years, according to ERCOT’s final 2020 summer SARA report, wind is expected to provide about 6 GW of capacity at the time of peak this summer.  Today there are over 30 GW of operating wind farms in Texas.  There is far less renewable capacity available to meet peak conditions in PJM, but that could change substantially in the years to come as the proposed buildout of offshore wind along the New Jersey, Delaware, Maryland, and Virginia coastal areas, becomes operational.  

As the summer heats up, we’ll be keeping a close eye on how reliability is achieved when electricity demand peaks.  Natural gas is the peaking fuel of necessity in today’s markets, but with a combination of more renewable resources and the recent surge in planned battery storage projects, that could change in the future.

Kent Knutson's picture

Thank Kent for the Post!

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Matt Chester's picture
Matt Chester on Jun 29, 2020 9:54 pm GMT

Despite the huge buildout in wind resources across Texas in recent years, according to ERCOT’s final 2020 summer SARA report, wind is expected to provide about 6 GW of capacity at the time of peak this summer.  Today there are over 30 GW of operating wind farms in Texas.

Does this mean that there might not be as much of an appetite to continue building out that wind, since building more won't translate to it being able to meet that peak demand in any substantial amount? 

Kent Knutson's picture
Kent Knutson on Jul 2, 2020 3:38 pm GMT

Matt, thanks for your comment.  Both wind and solar will continue to be attractive investments in Texas -- particularly when projects are coupled with energy storage.  Though I don't have the data sitting in front of me, I believe that the average LMP prices across most organized markets with a high level of renewables have been going down in recent years.  The low availability number (6-GW) for wind forecast for the time of peak demand in ERCOT is just the nature of planning for intermittent resources.  The hottest days create a tight market that can get pricey, but usually only for a short period of time over the hottest or coldest weeks.  That's when gas is needed to meet the high loads.  A gas peaking unit could make most of its annual revenues in just a few hours a few times a year.  Good for everyone . . . but, with more coal and nuclear retirements, it will become interesting to see how systems perform and how high LMPs rise when power demand goes high.    

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