History of outages
From the 1965 blackout to Hurricane Helene, the failures that darkened the grid and the lessons each one left behind. A story in 14 stops on the Wattlas map of the North American grid.
Act I · 1965–1977
The Northeast goes dark (1965)
At 5:27 pm on Tuesday, November 9, 1965, at the height of the evening rush, the lights of New York City began to go out. The trouble had started eleven minutes earlier and some 300 miles away, where a backup relay at the Sir Adam Beck station on the Niagara River opened one of the lines carrying power north toward Toronto. Its power swung south and east through a web of utilities that had tied themselves together so that one could help another in trouble, and that night the ties carried the collapse from system to system. In Queens stood the largest steam generating unit anywhere, Con Edison's Big Allis, rated at nearly 981 MW and in service for only four months. When the grid around it failed, the pumps that fed oil to its bearings lost their power, because they ran on the grid, and 14 of its 15 bearings were ruined. The biggest machine in the city had depended on the network it was built to feed. In the fourth basement of the New Yorker Hotel, meanwhile, the hotel's own direct current generators kept turning. Some 30 million people in the Northeast and Ontario lost power, some for up to 13 hours. The industry's answer was cooperation. On January 19, 1966 utilities in New York, New England and Ontario signed the agreement that created the Northeast Power Coordinating Council, and in 1968 the industry formed the national council that grew into NERC. In 1972, with Congress ready to tax utilities to pay for a federal research agency, they founded the Electric Power Research Institute instead. Every one of these bodies ran on the goodwill of its members, and none of them could make a utility do anything.
On the map: The dot marks Big Allis, the great Ravenswood generator in Queens, a historic site dated 1965, and EIA lists the Ravenswood plant beside it at 1,947 MW of gas. About 4 km to the west, across the East River in Midtown, the map marks the New Yorker Hotel's power plant, dated 1929. The lights are New York at night today.
Sources: Wikipedia: Northeast blackout of 1965, Wikipedia: Ravenswood Generating Station, IEEE Milestone: Largest Private (dc) Generating Plant in the U.S.A., 1929, NPCC, History, Wikipedia: Electric Power Research Institute
New York alone (1977)
Twelve years later New York learned what it meant to stand alone. On the hot evening of July 13, 1977 the city was drawing much of its power down the Hudson from the north, past the Indian Point nuclear plant at Buchanan. At 8:34 pm lightning struck the Buchanan South substation there, and a loose locking nut kept one of its breakers from closing again. A second strike took out two 345 kV lines and Indian Point's power with them. Con Edison tried to start a fast-start generating station by remote control, but nobody was there to run it, and at 8:55 a third strike at Sprain Brook in Yonkers took out two more lines. Con Edison's operator asked the New York Power Pool to relieve his overloaded lines while the pool urged him to shed load, and the two talked past each other. Just after 9:28 Big Allis shut itself down, a minute later the last tie to New Jersey tripped, and by 9:37 pm the whole Con Edison system was dark, almost exactly an hour after the first strike. Nine million people lost power, some for up to 26 hours, and in the poorest neighborhoods arson and looting went on through the night. The lightning had found a system with too few spare paths and an operation with too few hands. New York's operating entities went over every step of that hour and made changes to guard against another collapse that are in force today, and the detailed restoration procedures written afterward became part of how operators are trained to bring a dark system back. Indian Point, where the first strike fell, closed its last reactor in 2021.
On the map: The shaded area is the map's approximate extent, Con Edison's service territory as HIFLD publishes it today, which reaches north into Westchester. The ring marks the 1977 blackout's historic site at Buchanan, beside BUCHANAN, a 345 kV substation in the index. SPRAIN BROOK, also 345 kV, is 35 km to the south. The map lists no plant named Indian Point.
Sources: Wikipedia: New York City blackout of 1977, U.S.-Canada task force report (2004), Wikipedia: Indian Point Energy Center
Act II · 1989–1998
A storm from the Sun (1989)
Lightning had brought down New York. In March 1989 the trouble came from the Sun. Hydro-Québec had built one of the boldest grids on the continent, carrying the power of the La Grande rivers hundreds of kilometers south to the cities along the St. Lawrence on lines at 735 kV. On March 10 and 12 the Sun threw two great clouds of charged gas into space, and early on March 13 they struck the Earth's magnetic field so hard that auroras glowed as far south as Texas. Beneath Québec lies the old, hard rock of the Canadian Shield, which resists electric current, so the currents the storm drove through the ground found an easier path along the long power lines. Protective equipment tripped across the system, the James Bay network went offline in less than 90 seconds, and the whole province was dark for nine hours. Far to the south, on an island in Delaware Bay, the same storm damaged transformers at the Salem nuclear plant in New Jersey. Hydro-Québec raised the levels at which its protection would trip and added series compensation to its longest lines. The rest of the continent took longer to act. In 2013 FERC directed NERC to write standards for geomagnetic disturbances, and the first, approved in June 2014, required operators to keep plans ready for a solar storm. A second, approved in September 2016, made utilities study how their systems and their big transformers would fare in the worst storm they could reasonably expect.
On the map: The shaded area is all of Québec, the map's stand-in for Hydro-Québec's grid. The ring marks the storm's historic site at Robert-Bourassa, 5,616 MW on the map, which with the four La Grande plants comes to about 14 GW. The map draws 338 lines at 735 kV, all in Québec and Labrador.
Sources: Wikipedia: March 1989 geomagnetic storm, NRC, Salem and Hope Creek susceptibility to geomagnetic storms, Wikipedia: Salem Nuclear Power Plant, FERC Order No. 797 (2014), FERC Order No. 830 (2016)
The West breaks apart (1996)
The West was brought down by something much closer to the ground, and in 1996 it happened twice in one summer. The Western Interconnection stretches from British Columbia to Baja California, and that year its long lines were carrying Northwest hydropower hundreds of miles south to meet California's summer demand. On July 2 a 345 kV line in Idaho sagged close to a tree and faulted, relays misoperated, and the interconnection broke into five islands, cutting off more than two million customers. On August 10, with most of the West near 100 degrees, it happened again on a far larger scale. Through the afternoon Bonneville's heavily loaded 500 kV lines in Oregon flashed to trees one after another, the fourth of them near Keeler at 3:42 pm. McNary Dam's generators strained to hold up the voltage until faulty relays tripped every one of them. The grid began to swing, gently and then violently, and at 3:48 pm the California-Oregon Intertie tore open. About 7.5 million customers lost power. When engineers set the real swings beside their studies, they found that the models of the day had shown a system that should have held. The West set about making its models match reality. Its council began requiring baseline tests of western power plants, and Bonneville began watching generators with phasor measurement units, instruments that sample the grid many times a second, so that it could check each model against how the plant really behaved. The utilities signed up for something new as well. Under the Western Systems Coordinating Council's Reliability Management System, agreed by contract in 1999, a member that broke the council's reliability criteria could now face sanctions.
On the map: The shaded area is the map's approximate extent of the August 10, 1996 blackout, seven states and provinces drawn whole plus El Paso County, all overstated. The ring marks the historic site at KEELER, a 500 kV substation west of Portland. Four 500 kV lines on the map cross from Oregon into California, and McNary, on the Columbia, is 967 MW of hydro.
Sources: NERC, 1996 System Disturbances (Internet Archive copy), NASPI, Model Validation Using Phasor Measurement Unit Data (2015), U.S. Department of Justice, business review letter to WSCC (1999), NERC, FAC-501-WECC-4
The ice storm (1998)
Freezing rain began falling on eastern Ontario, southern Québec and northern New England on January 5, 1998, and a slow procession of storms kept it coming for more than 80 hours. This time the weight fell on the towers themselves. Hydro-Québec's lines, like those of nearly every utility, had been built to carry about 45 mm of ice. In places more than 100 mm built up. Steel towers buckled under the weight and pulled their neighbors down with them in chains, until more than 1,000 transmission towers and some 35,000 wooden poles lay on the ground. On January 9 the bridges to Montréal's South Shore closed under falling ice and downtown Montréal went dark. The country between Saint-Hyacinthe, Granby and Saint-Jean-sur-Richelieu was hit so hard it came to be called the triangle of darkness, and some of its people waited weeks for power in the middle of winter. More than 4 million people lost electricity, and at the height of the crisis 15,784 members of the Canadian Forces were deployed to help. Hydro-Québec crews rebuilt the network tower by tower and brought back the last customer on February 6. Then the utility rewrote the rules it built by. New lines went up to stricter engineering standards, and every tenth tower on a line became a heavy anti-cascading tower, so that the fall of one could no longer drag down the rest. Around Montréal the loop of lines and substations was reworked so that power could reach the city by many different routes if any one of them failed.
On the map: The dot marks the 1998 ice storm's historic site, placed in what Hydro-Québec calls the triangle of darkness. The view holds eight of the 39 substations the map lists at 735 kV in Québec, around Montréal and across the Montérégie.
Sources: Hydro-Québec, In the heart of the triangle of darkness, Hydro-Québec, After 1998, a more robust grid, Wikipedia: January 1998 North American ice storm
Act III · 2003–2012
Trees in Ohio, and rules with teeth (2003–2008)
Five summers later the trees had their turn again, this time in Ohio, and they found two control rooms that could not see. Thursday, August 14, 2003 was hot, and the 345 kV lines of FirstEnergy's system around Cleveland and Akron were heavily loaded. At 12:15 pm bad data had knocked out the state estimator at the Midwest ISO, the model its reliability coordinators used to follow the grid, and at 2:14 pm the alarm system in FirstEnergy's own control room stopped working without anyone noticing. At 3:05 pm the Chamberlin-Harding line sagged into a tree that had been allowed to grow too close, and tripped. At 3:32 Hanna-Juniper did the same, and at 3:41 Star-South Canton gave way as its load climbed past what it could carry. FirstEnergy's operators, their alarms silent, did not know. At 4:05:57 the Sammis-Star line tripped when its relay read the low voltage and heavy current as a fault, and within five minutes the cascade was racing through Michigan, Ontario and New York. The U.S.-Canada task force that investigated made 46 recommendations, and the first was that reliability standards become mandatory and enforceable. Congress wrote that into the Energy Policy Act of 2005. On July 20, 2006 FERC named NERC the Electric Reliability Organization, and in March 2007 it approved NERC's first 83 standards, enforceable from June 18. Among them was FAC-003, which made owners keep the trees in their rights of way under control. An early test came in February 2008, when an engineer checking a switch at Florida Power & Light's Flagami substation outside Miami disabled both layers of its protection. A fault that should have cleared in a fraction of a second lingered, the disturbance tripped lines and power plants across southern Florida, and FPL later agreed to pay a $25 million civil penalty.
On the map: The ring is STAR, a 345 kV substation in the index. The view holds both ends of the four FirstEnergy 345 kV lines lost that afternoon, Harding and Chamberlin, Hanna and Juniper, Star and South Canton, Sammis and Star, among 33 substations at 345 kV. The lines and substations shown are the map's 300 to 399 kV class.
Sources: U.S.-Canada task force report (2004), Wikipedia: Northeast blackout of 2003, Troutman Pepper, the brief history of mandatory reliability standards, Federal Register, Order No. 693 (govinfo), FERC, Florida Blackout settlement, 129 FERC ¶ 61,016 (2009)
Katrina (2005)
Katrina came ashore three weeks after the Energy Policy Act became law, bringing a failure no reliability standard could have prevented. On August 29, 2005 it reached land first near Buras in southeast Louisiana and then at the Mississippi border, driving a surge that broke the levees of New Orleans in more than 50 places and left about 80 percent of the city under water. It killed 1,392 people. Along the Mississippi coast every one of Mississippi Power's 195,000 customers lost electricity. At Plant Watson in Gulfport more than 16 million gallons of brackish water filled the lower levels to a depth of nearly 20 feet, and about 80 employees rode out the storm on the upper floors of the powerhouse. The company's headquarters across from the port flooded to its elevator shafts, and about 100 of its employees lost their homes. Across the Gulf South an estimated three million people lost power. Mississippi Power grew from 1,200 employees to a force of 12,000, with crews from across the country and Canada, and in 12 days it restored power to every customer who could take it. Plant Watson's two big coal units were running again before the year was out. Afterward the company moved its storm operations to a new center on higher ground.
On the map: The shaded area is the map's approximate extent of Katrina's outages, Louisiana, Mississippi and Alabama drawn whole, which overstates all three. The ring is Jack Watson, Mississippi Power's plant at Gulfport, 754 MW of gas on the map with 1968 as its year.
Sources: Wikipedia: Hurricane Katrina, Mississippi Power, Disaster recovery, Hurricane Katrina, Southern Company, Plant Watson fully restored (June 13, 2006)
San Diego in eleven minutes (2011)
By 2011 the new rules were in force, and a hot September afternoon in the desert showed what they could not yet do. On September 8, 2011 Southern California was importing about 2,750 MW from Arizona, close to its limit. At Arizona Public Service's North Gila substation near Yuma a technician isolating a series capacitor bank skipped a critical step, and at 3:27 pm the Hassayampa-North Gila 500 kV line tripped. Its operators told their neighbors it would be back in about 15 minutes. None of them could see the wide phase angle the loss had opened across the system, or how the power the line had carried was swinging west onto the Imperial Irrigation District's transformers. Over the next 11 minutes more than 100 events followed, and San Diego, the Imperial Valley, Yuma and northern Baja California separated from the rest of the West and went dark together as the evening commute began. About 2.7 million customers lost power, some for up to 12 hours. FERC and NERC found operators who had not planned for losing a single line and could see too little of their neighbors' systems, and made 27 recommendations. The penalties reached all the way to the Western Electricity Coordinating Council, which agreed to a $16 million civil penalty, $3 million to the Treasury and NERC and $13 million invested in reliability work, and in 2014 its duty to watch over the whole Western grid as reliability coordinator passed to a separate company, Peak Reliability.
On the map: The shaded area is the map's approximate extent, the San Diego Gas & Electric and Imperial Irrigation District territories, Yuma County and all of Baja California, which overstates it. The ring marks the historic site at NORTH GILA, a 500 kV substation near Yuma. Two 500 kV lines on the map cross from Arizona into California.
Sources: FERC and NERC, Arizona-Southern California Outages on September 8, 2011 (2012), FERC, final settlement in the 2011 Southwest blackout case, Troutman Pepper, WECC settlement (2015)
Sandy at East 14th Street (2012)
The sea came for the grid of New York in the autumn of 2012. Sandy swung west off the Atlantic toward New Jersey late that October, a hurricane so wide that its tropical-storm-force winds reached across 1,150 miles. On the evening of October 29 its surge came up the East River. At Con Edison's East 14th Street complex the water rose nearly 14 feet, over a wall built for 12, and poured into the substation that feeds most of Manhattan below 36th Street. Arcs in the flooded substation lit the sky over the East Village, and many who saw them thought the plant had blown up. Lower Manhattan went dark, and across 24 states some 8.5 million customers lost power. Con Edison had every Manhattan network back on the evening of November 3. The storm changed what a utility on the coast had to expect of the water. In 2014 New York regulators approved a $1 billion Con Edison program to protect its system from storms. At East 14th Street the company raised equipment and walls and added floodgates, moats and pumps, and in the suburbs it installed smart switches and thousands of fuses so that a falling tree would darken a few blocks instead of a whole circuit. Across the harbor PSE&G's Energy Strong program set aside $620 million to raise, relocate or protect 29 switching stations and substations that water had damaged. The next surge would find the grid of New York and New Jersey standing higher.
On the map: The dot marks Hurricane Sandy's historic site at Con Edison's East 14th Street complex on the East River. EAST 13TH STREET, beside it, is a 345 kV substation in the index, and EIA lists the East River plant at the site at 616 MW of gas, with 1951 as its year.
Sources: Wikipedia: East River Generating Station, Wikipedia: Hurricane Sandy, T&D World, Con Edison prevents thousands of outages with Sandy improvements (2014), The Regulatory Review, Con Edison invests $1 billion (2014), PSEG, Energy Strong settlement (May 1, 2014)
Act IV · 2017–present
Maria (2017–2018)
Puerto Rico's grid was failing before Maria ever reached it. PREPA, the island's power authority, owed $9 billion and had filed for bankruptcy that summer. Its power plants had a median age of 44 years, and about 70 percent of its generation sat in the south while about 70 percent of the demand was in the north, joined by lines that crossed the mountains of the interior. Two weeks earlier Irma had passed to the north and cut power to about a million people. At 6:15 am on September 20, 2017 Maria came ashore near Yabucoa as a high-end Category 4 hurricane, and by the time it had crossed the island the grid was gone. All 3.4 million residents lost electricity. A month later only 18.5 percent of the island had it back. Hospitals ran on generators, and people who depended on oxygen or dialysis struggled to get them. Crews from mainland utilities worked beside Puerto Rico's own through mountains and rain forest, and it was August 2018 before the last customers were reconnected, one of the longest blackouts in American history. Of the storm's 3,059 deaths, 2,975 were in Puerto Rico, many of them in the long months without power. Much of the island's own answer went up on rooftops. By January 2022 some 42,000 rooftop solar systems were enrolled in net metering, more than eight times as many as before the storm. The public grid has been rebuilt far more slowly. By 2026 federal agencies had set aside $17.1 billion for it and paid out $3.6 billion, and in April 2025 the whole island went dark again for almost two days.
On the map: The shaded area is PREPA's service territory, the map's stand-in for all of Puerto Rico. The ring marks the historic site at San Juan. Four of the six largest plants the map lists on the island, about 3.5 GW together, stand on the south coast, and the other two on the north coast near San Juan.
Sources: Wikipedia: Effects of Hurricane Maria in Puerto Rico, Wikipedia: Hurricane Maria, IEEE Spectrum, Rebuilding Puerto Rico's power grid (2018), Canary Media, Puerto Ricans are powering their own rooftop solar boom (2022), GAO-26-107772, Puerto Rico grid recovery (2026)
The Camp Fire (2018)
Until then the failures in this story had struck the grid. In the Sierra Nevada foothills a year after Maria, the grid itself became the danger. PG&E's Caribou-Palermo line, a 115 kV circuit carrying hydropower out of the Feather River Canyon, ran on towers many of which dated from the early 1900s. On one of them near Pulga, a hook holding a string of insulators had worn about seven-eighths of the way through. Early on the morning of November 8, 2018 it gave way, the live conductor arced against the steel, and winds of 50 mph drove the fire through the canyon toward the town of Paradise. The Camp Fire destroyed 18,804 structures across 153,336 acres and killed 85 people, the deadliest wildfire in California history. PG&E filed for bankruptcy in January 2019 and later pleaded guilty to 84 counts of involuntary manslaughter. The fire changed what an outage could be. In July 2019 California created a wildfire fund of up to $21 billion to stand behind its utilities, and on October 9, with dry winds in the forecast, PG&E began switching off power to nearly 800,000 customers on purpose. Darkness had become a way of keeping people safe, and a hard one to live with. In 2021 PG&E said it would bury 10,000 miles of power lines in the places most at risk of fire.
On the map: The dot marks the Camp Fire's historic site in the Feather River Canyon near Pulga. PG&E hydro plants line the canyon around it, Cresta, 70 MW, 3 km away, and Poe, 120 MW, 10 km to the south.
Sources: Wikipedia: Camp Fire (2018), Business Wire, PG&E begins to turn off power to nearly 800,000 customers (October 9, 2019), California Legislature, AB 1054 (2019), NPR, PG&E to bury 10,000 miles of lines (July 21, 2021)
The Texas freeze (2021)
Texas had been warned twice. In 1989 a hard freeze drove ERCOT to rolling blackouts across its whole system, and in February 2011 the cold came back and 210 of ERCOT's generating units tripped, cut their output or failed to start. The federal report on 2011 found that no state, regional or NERC standard required generators to winterize, and urged Texas and its neighbors to prepare for winter as carefully as they prepared for summer, which was as far as a federal report could go. In mid-February 2021 an arctic air mass settled over the state and held it below freezing for days. Gas wells froze, processing plants and pipelines faltered, and power plants of every fuel failed just as demand for heat climbed toward a winter record. Early on February 15 ERCOT's operators were minutes from losing the entire interconnection, and they shed firm load until the frequency recovered, 20,000 MW of it at the peak. More than 4.5 million Texans lost power, some for four days in freezing homes, and the state counted 246 deaths. This time the rules changed. On June 8, 2021 Governor Greg Abbott signed laws requiring power plants and the gas facilities that supply them to prepare for extreme weather, with penalties of up to $1 million. The Public Utility Commission adopted its first weatherization rule that October, and ERCOT began inspecting power plants in December. In August 2022 the Railroad Commission ordered gas wells, processing plants and the pipelines that serve power plants to weatherize as well.
On the map: The map lists 274 gas plants as operating in ERCOT's region, about 61 GW, more than any other fuel there, and 16 of them are 1,000 MW or more. The dashed lines are gas pipelines. The ring marks the 2021 crisis's historic site at Taylor.
Sources: POWER, FERC and NERC on the February 2011 Southwest blackouts (August 17, 2011), FERC, NERC and Regional Entity staff, February 2021 cold weather outages, Texas Tribune, Abbott signs grid bills (June 8, 2021), Texas Tribune, PUC weatherization rule (October 21, 2021), Railroad Commission of Texas, weatherization standards (August 30, 2022)
Helene and Hot Springs (2024)
Helene reached land in Florida's Big Bend late on September 26, 2024 with 140 mph winds and kept going. Within hours it was over the southern Appalachians, hundreds of miles from the sea, where as much as 30.78 inches of rain fell on the mountains of western North Carolina. Rivers rose past any flood in living memory and tore away roads and whole neighborhoods, and the grid went with them. Substations flooded, and poles and towers came down in valleys that crews could not reach. More than a million customers in North Carolina were without power at the state's peak, and more than a week after landfall about 167,000 in the North Carolina mountains were still waiting. Helene was the deadliest hurricane to strike the mainland since Katrina. In Hot Springs, a town of just over 500 people on the French Broad River, the flood washed out the substation at Marshall that fed the town's only line. That line ran ten miles through the Pisgah National Forest and had failed often, and rather than build a second one, Duke Energy had given the town a microgrid of its own in 2023, 2 MW of solar panels and 4.4 MW of batteries. From October 2 until the main grid returned on October 8, the microgrid kept the town center lit and, except for some overnight hours, the rest of Hot Springs too. On the coast, utilities had spent a decade raising and walling in their equipment against the sea. Helene carried the test far inland, and in one mountain town part of the answer turned out to be a grid small enough to stand on its own.
On the map: The ring is Hot Springs Energy Storage & Microgrid, a 6.3 MW battery plant Duke Energy runs in the mountain town of Hot Springs, with 2022 as its year. Marshall Dam, a 4 MW Duke hydro plant, is 23 km to the southeast.
Sources: Wikipedia: Hurricane Helene, U.S. Department of Energy, Hurricane Helene situation report #4 (September 30, 2024), Duke Energy, rebuild after Helene (October 4, 2024), Duke Energy, Hot Springs microgrid in service (February 2, 2023), Southern Alliance for Clean Energy, a microgrid in a flood-damaged town (December 2024), Canary Media, Helene and solar-battery microgrids (October 18, 2024), Wikipedia: Hot Springs, North Carolina
What the grid learned (now)
Sixty years of failures lie across this map, one faint layer over another, and each of them left something behind. The blackout of 1965 gave the Northeast its first reliability council. The storm of 1989 taught Hydro-Québec to guard its long lines and, in time, pushed utilities across the continent to plan for the Sun. The trees that brought down the West in 1996 and Ohio in 2003 led to a federal standard for clearing rights of way, and the blind control rooms of 2003 turned voluntary rules into law, enforced by NERC with penalties behind them. After the ice of 1998 Hydro-Québec built anti-cascading towers into its lines. After Sandy the utilities of New York and New Jersey lifted their substations above the flood line, and after the freezes of 2011 and 2021 Texas finally required its power plants and gas fields to winterize. None of it came free, and too many of these lessons were paid for in lives. The grid that carries North America's power today is far better watched and far better protected than the one that went dark in 1965, and it is being asked to carry more than ever. In its long-term assessment published in January 2026, NERC found 13 of 23 North American assessment areas at elevated or high risk of falling short over the next five years, as data centers and electrification push demand up faster than new plants and lines can be built. More failures will come. The record written across this map says the grid will learn from each of them.
On the map: Every shaded area is one of the 25 historic outages on the map, drawn together, and where they overlap the shading deepens. Each is an approximate extent, most of them overstated. The Historic outages layer shows them one at a time.
Sources: NERC, 2025 Long-Term Reliability Assessment (January 2026), POWER, NERC warns long-term grid reliability risks mounting (January 29, 2026), NPCC, History