It was the best of grids, it was the worst of grids.
Two weeks ago, the same brutal heat dome stretched from the Gulf Coast to the Great Lakes. Temperatures topped 100°F in Houston and heat indices hit 113°F in Philadelphia. Two of America’s largest power grids faced the same test — and delivered radically different answers.
In Texas, ERCOT shattered every demand record in the book. No emergency. No conservation appeal. No drama. In PJM, the Department of Energy declared a statutory emergency and ordered data centers to fire up backup generators as a last resort to keep the lights on.
Same summer. Same sun. Two very different stories.
Act I: The Grid That Almost Died
To appreciate what happened in Texas this July, you have to remember what almost happened before.
February 2021. Winter Storm Uri descended on Texas with temperatures the state hadn’t seen in a generation. Within hours, 52,000 MW of generation — gas, coal, wind, nuclear — went offline simultaneously. The grid came within four minutes and thirty-seven seconds of a total, uncontrolled blackout that engineers warned could have taken months to restore. Instead, ERCOT ordered rolling outages that left 4.8 million homes without power, some for days. Two hundred forty-six Texans died. Damages reached an estimated $200 to $300 billion.
The criticism was searing and deserved. Texas had built an isolated, energy-only grid with no capacity market, no winterization mandates, and insufficient reserves. Uri laid bare every structural weakness.
The financial carnage for retail energy providers was staggering. The Public Utility Commission held wholesale prices at the $9,000/MWh systemwide cap for nearly four consecutive days — a price that normally appears for minutes, if at all. The ERCOT wholesale market accumulated an estimated $55 billion in charges in a single week — four years’ worth of normal market activity compressed into days. Brazos Electric Power Cooperative, Texas’s oldest and largest generation and transmission co-op, received a $2.1 billion bill from ERCOT and filed for bankruptcy. Griddy Energy, a retail provider whose customers were exposed to real-time wholesale pricing, collapsed after customers received individual bills exceeding $9,000 for a single billing period. At least three energy providers filed for Chapter 11 protection in the storm’s aftermath.
Summer 2023 offered a different flavor of the same vulnerability. That August, ERCOT set 10 new all-time peak demand records in a single summer, topping out at 85,435 MW. Eight times that month, grid operators issued conservation appeals — essentially asking Texans to turn off their lights and sweat it out — because generation couldn’t keep pace. Gas and coal plants tripped offline unexpectedly. Wind generation fell short of forecasts. Solar dwindled earlier than expected. The state narrowly avoided rotating blackouts. In the wholesale market, real-time prices spiked above $1,000/MWh 182 times between June and August, with some hours exceeding $4,000/MWh — against a median price of just $25/MWh. For REPs caught on the wrong side of their hedge books, every conservation appeal was a margin event.
The narrative was set: Texas had an unreliable grid, dependent on weather it couldn’t control and markets that didn’t build enough. And for the retailers serving those markets, every summer was a financial minefield.
Then came July 2026.
Act II: The Quiet Triumph
On July 23, 2026, ERCOT recorded 91,308 MW of peak demand — obliterating the previous record by nearly 6,000 MW. What happened next is the part worth studying.
Nothing.
No conservation appeal. No emergency declaration. No voltage reductions. Wholesale electricity prices stayed well below the systemwide cap — 95% below, at times. The grid operated under normal conditions with more than 10 GW of reserves to spare. For retail energy providers who had lived through the $9,000/MWh nightmare of Uri and the $4,000/MWh spikes of 2023, this was a different world: a record-demand day that looked, on their settlement statements, like an ordinary summer Tuesday.
The difference wasn’t luck. It was the stack — gas, batteries, solar, and wind working together in a way that would have been unimaginable five years earlier.
Natural gas remained the backbone, the largest single fuel source on the system. At 3 p.m. on the record day, ERCOT showed 113,543 MW of available generation against 90,027 MW of demand — and gas plants were carrying roughly half of that output, doing what gas does best: ramping fast, running hard, and holding the line while intermittent resources shifted around them. Demand response shaved another 2 to 3 GW off the peak, buying additional headroom.
But what turned a survivable day into a comfortable one was the rest of the stack.
Texas’s battery storage fleet has undergone one of the fastest infrastructure buildouts in American energy history. At the end of 2024, ERCOT had roughly 8.6 GW of installed battery capacity. By early 2026, that figure had climbed to 13.9 GW. By the time the July heat wave hit, it stood at approximately 16.3 GW — nearly tripling in under two years. During the peak, batteries discharged 11,980 MW into the grid — the seventh time ERCOT storage had exceeded 10 GW of discharge, with five of those milestones occurring in July 2026 alone. As the sun set and solar faded, batteries absorbed the evening ramp with surgical precision.
Solar generation hit its own record of 34,665 MW earlier in the day, shouldering an enormous share of the midday load and freeing gas capacity for the critical evening hours. Wind — often modest during hot Texas afternoons — filled a different role, ramping through the overnight and early morning hours to keep reserves healthy around the clock. Together, wind and solar generated roughly 37% of ERCOT’s electricity during the heat wave week, a figure that would have seemed fanciful during the Uri crisis.
The energy-only market that critics had written off turned out to be the market structure that rewarded this kind of diverse, flexible investment most directly. High real-time prices during scarcity hours sent a clear signal, and developers responded by building gas peakers, utility-scale solar, battery storage, and wind farms at a pace that centrally planned markets struggled to match.
Act III: The Grid Under Siege
Thirteen hundred miles northeast, a different story was unfolding.
On June 29, PJM Interconnection — the nation’s largest grid operator, serving 67 million customers across 14 states and the District of Columbia — filed a formal request with the Department of Energy warning of an “imminent electricity reliability emergency.” Peak demand was projected to reach 166,304 MW on July 2, which would have broken PJM’s all-time record set two decades earlier in 2006.
Energy Secretary Chris Wright issued an emergency 202(c) order directing all fossil fuel plants in the PJM footprint to maximize output and authorizing temporary relief from environmental permit restrictions. The order went further: it approved PJM’s request to direct transmission owners, as a last resort, to curtail data centers and other large loads with backup generation — essentially asking the very facilities driving demand growth to disconnect from the grid and run on their own diesels.
PJM survived. But survival by emergency decree is not the same as reliability by design.
The underlying structural challenges are severe. PJM’s capacity market — the mechanism designed to ensure enough generation exists to meet peak demand — has failed to clear sufficient resources for three consecutive years. The most recent Base Residual Auction revealed a 6.8 GW shortfall, triggering a backstop procurement auction scheduled for September 30. Capacity prices spiked 76% in the first quarter of 2026 alone.
The catalyst is data centers. PJM’s territory includes Loudoun County, Virginia — home to the densest concentration of data centers on the planet. Hyperscaler demand for power has reshaped the grid’s economics: data centers now account for $6.3 billion, or 38%, of PJM’s $16.4 billion in total capacity costs. When PJM reopened its reformed interconnection queue in May 2026, it received 811 project applications totaling 220 GW of new capacity requests — including a staggering 105 GW of natural gas generation that startled even veteran transmission planners.
The irony is sharp. PJM’s capacity market was built to prevent exactly this kind of crisis — to pay generators to be available when they’re needed most. Instead, it has become a mechanism that socializes the costs of data center growth across millions of residential ratepayers while failing to procure enough resources to keep the lights on without federal emergency intervention.
Act IV: The Shape of What’s Coming
Zoom out from any single heat wave and the trajectory is unmistakable.
In the first half of 2026, solar and battery storage accounted for 91% of all new electricity generation capacity added to the U.S. grid, according to the Solar Energy Industries Association. Not 91% of renewables — 91% of everything. In California, CAISO discharged a record 12.99 GW from batteries on July 9, covering 36% of the state’s electricity demand at that moment from storage alone.
Something fundamental is shifting. The old model — build a big plant, connect it to a wire, hope demand shows up — is giving way to a distributed, responsive, software-defined grid. Home batteries are aggregating into virtual power plants that respond to price signals in milliseconds. Utility-scale storage is absorbing midday solar surplus and discharging it into evening peaks with surgical precision. And natural gas — far from disappearing — is evolving into the fast-twitch muscle the grid depends on: fewer baseload hours, more high-value ramping, more strategic peaking. GE Vernova’s gas turbine backlog stands at 116 GW, with data centers accounting for 20% of buyers. Gas isn’t going away. It’s being repositioned around the resources that are growing fastest.
The ISOs that embrace this transition — that build market structures rewarding flexibility, speed, and distributed intelligence — will thrive. The ISOs that try to solve tomorrow’s problems with yesterday’s capacity constructs will spend their summers on the phone with the Department of Energy.
Both ERCOT and PJM face enormous data center demand. The difference is that ERCOT’s market structure attracted the storage investment needed to meet it. PJM’s capacity market, for all its theoretical sophistication, delivered a 6.8 GW hole and a federal emergency order.
This isn’t an argument against capacity markets or for any single market design. It’s an observation that market signals matter, that speed of deployment matters, and that the grid of the future will be built by technologies — batteries, DERs, AI-powered optimization — that reward the markets willing to let them compete.
Where ennrgy.com Fits
At ennrgy.com, we operate at the intersection of these converging forces every day.
Our Risk360 platform provides the energy trading and risk management infrastructure that energy companies need to navigate markets where a single summer afternoon can reshape the year’s P&L. Our Headroom Intel engine delivers the real-time pricing intelligence and market signals that separate informed decisions from expensive guesses. And our Asset Optimizer powers the AI-driven battery dispatch strategies that are turning storage assets from passive insurance policies into active revenue generators.
This isn’t theoretical for us. Earlier this year, Abundance Energy selected ennrgy.com for managed operations and AI-powered battery optimization across its growing residential virtual power plant portfolio in ERCOT — exactly the kind of distributed, intelligent grid resource that helped Texas set records without breaking a sweat this summer.
The tale of two ISOs is, at its core, a tale about readiness. The grid operators, market participants, and technology partners who prepared for a distributed, battery-powered, data-driven future didn’t just survive July 2026. They barely noticed it.
The ones who didn’t are already planning for the next emergency.
References
- DiGangi, Diana. “PJM anticipates new peak demand record as heat wave tests power grid.” Utility Dive, July 2, 2026.
- “US Issues Emergency Order for PJM Interconnection as Heatwave Looms.” U.S. News & World Report, June 30, 2026.
- “As Texas temperatures soar, ERCOT crushes demand and generation records without incident.” Renewable Energy World, July 2026.
- “ERCOT just set a forever peak in July 2026.” Arcobi Blog, July 2026.
- “Texas ERCOT Grid Holds Beyond 91 Gigawatts in Heat Wave.” Energy News Beat, July 2026.
- “PJM Emergency Order: Heat Wave Threatens Record Demand.” Electric Choice, July 2026.
- “PJM Hot Weather Operations Update — July 2, 2026.” PJM Inside Lines, July 2, 2026.
- “ERCOT issues multiple energy conservation appeals.” The Center Square, August 2023.
- “How ERCOT is narrowly getting through an extreme summer.” News 4 San Antonio, August 2023.
- “The 220-GW Grid Queue Is Datacentres’ New Bottleneck.” TechReaderDaily, 2026.
- “PJM accelerates backstop auction amid uncertainty over data center cost allocation.” Utility Dive, May 20, 2026.
- “‘Stretched to the limit’: Heat wave prompts US electrical grid emergency.” ABC News, July 2026.
- “Power Co-op Files Bankruptcy After $2.1 Billion ERCOT Bill.” POWER Magazine, March 2021.
- “Record-breaking Texas summer heat tests the grid, ERCOT operations.” Federal Reserve Bank of Dallas, October 2023.
- “Analyzing Record-breaking ERCOT Price Spike During Winter Weather.” Yes Energy, February 2021.
Navigate any market. Any summer.
Risk360 gives retail suppliers, cooperatives, and gas marketers real-time position management, settlement reconciliation, and AI-powered intelligence across every major ISO.