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PJM Interconnection watched the temperature pass 100 °F the week of 23 June, yet one metric mattered most. At 5 p.m. on Monday, system demand in PJM reached 160,463 MW, the highest June load since 2006 and 6GW above the operator’s own summer outlook. Wholesale power across New York City cleared close to $2,400 per megawatt-hour, Long Island touched $7,000, and ISO-New England broke $1,500 as operators scrambled to preserve reserves.
On Friday the 20th, weather models locked onto a heat dome stretching from Chicago to Boston. Arcus’ AI models captured data and broadcasted a 95%+ coincident-peak (CP) alert for the coming Monday through Wednesday. That notice reached every client before the close of trading. By dawn Monday, PJM declared a Maximum Generation Emergency and suspended non-essential maintenance. The alert validated our signal: the 3-day window now carried the highest CP probability seen this decade.
At noon, solar production in PJM sat near 19 GW, wind just under 11 GW, and batteries prepared to release 4 GW. Load was still going up. Our DAM model plotted the afternoon peak at 161 GW with a margin tight enough for customers to act with confidence. When the 17:00 meter read 160,463 MW, the forecast error stood within the margin, narrower than any public projection. The next day repeated with 158,868 MW at 17:00, again within margin, locking in a second CP hour and securing two of the five values that will set 2026-27 capacity tags.
PJM’s official summer outlook, published in May, called for 154,000 MW at peak, asserting adequate. Reality proved leaner. Dew-points above 70 °F kept air-conditioning duty cycles near maximum across 16 states. Data-center expansions and a growing fleet of EV added an estimated 3.5 GW compared with last June. The shift towards renewable energy sources has inadvertently reduced the system's ability to manage unexpected demand surges. This transition has led to the decommissioning of approximately 1.2 GW of coal capacity over the past year, contributing to a nationwide trend of accelerated retirements. As a result, the energy grid's flexibility has diminished, leaving it more vulnerable to fluctuations in demand and supply.
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Midday solar output looked strong at 19 GW, yet that sunlight faded to 2 GW by the system peak. Wind eased to 4 GW as a late-day lull arrived. Batteries discharged at 4 GW for less than twenty minutes. The grid lost 21 GW of renewable support between 14:00 and 17:00, forcing a 25 GW net-load ramp. Operators leaned on gas, coal, and nuclear units already near their technical ceilings. The episode showed that solar flattens the lunch-hour curve yet sharpens the evening spike, a pattern certain to repeat until far more storage enters service.
Energy prices told the story of scarcity in real time. PJM hubs from AEP-Dayton to Illinois cleared above $3,000 during multiple intervals. Illinois Hub went upto $4,100 at 18:00 on Wednesday when solar reached zero and imports faced congestion. New York City saw $2,400, and Long Island registered $7,000 as overheated conductors restricted transfers into the peninsula. ISO-New England invoked a “Power Caution” after a forced outage removed a gas turbine, pulling reserve megawatts to keep things running.
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Last summer’s high stood at 152,666 MW on 16 July. The prior year topped at 146,843 MW. In two seasons, load grew 9% while solar grew 5GW and batteries to 2GW. The gap explains why 2025’s first heat wave delivered price levels unseen since 2021 Winter Storm Elliott. PJM’s long-term forecast now expects RTO summer demand to rise another 31,600 MW by 2030. That trajectory would push peak risk into the 170 GW range within five years, assuming weather patterns stay near the current trend and electrification of transport and heat advances at today’s pace.
The Texas grid faced similar heat three days earlier yet maintained wider reserves. ERCOT met 80 GW of load with 47 GW of utility-scale renewables and 13 GW of battery discharge. Prices remained tame, and emergency alerts stayed silent. The comparison highlights what an expanded storage fleet can deliver: a softer net-load ramp and fewer scarcity intervals even under extreme weather. PJM holds more than 200 GW of solar-plus-storage in its interconnection queue, meaning the raw potential is on the drawing board even if the steel is not yet in the ground.
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Capacity tags matter because they roll forward for two planning years. A 5 MW industrial plant that trims 10% during a CP hour typically saves more than $100,000/MW in future capacity charges at current auction prices. Arcus’ sub 1% error rate let clients curtail only when it counted. They avoided false cuts that affects production and still captured the full credit. PJM’s public day-ahead run posted a mean absolute error near 1.6 percent across the same hours, large enough to force many operators into extra, unnecessary load drops.
Some articles noted that the heat pushed multiple regional operators into “razor-thin margins,” prompting Duke Energy in the Southeast to request emergency authority to run older plants at full capacity. New York ISO warned of rotating outages, and ISO-New England imported from Hydro-Québec while pausing all maintenance. Each region shares the same vulnerability: the evening drop in renewable output now collides with a structural rise in summer demand. Until long-duration storage or flexible demand scales further, precision forecasting and agile response will carry the burden of reliability.
First, earlier peaks are no longer an outlier. The historical record favored late July or early August, yet this June delivered two CP hours. Second, the solar fleet shapes price but does not guarantee stability once the sun sets. Third, batteries make a difference yet need deeper energy reservoirs to cover multi-hour ramps. Fourth, forward-looking load estimates must incorporate data-center clusters and fleet electrification or they will fall short. Finally, customers equipped with real-time analytics can still turn volatility into opportunity even when the broader market feels the strain.
PJM’s long-term report suggests summer peaks could touch 170 GW by the end of the decade. If 1/4 of the solar-storage projects now in the queue reach commercial service, the evening ramp would likely fall by half, cutting the frequency of emergency alerts. Until that build arrives, the cheapest hedge in the Northeast stack remains a mix of precise forecasts, rapid curtailment plans, and a clear view of price incentives. Arcus continues to refine its AI engine with each event, learning from feeder-level deviations, micro-weather inputs, and real-time market inputs to deliver forecasts that keep clients one step ahead of the next heatwave.
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