History of gas power
From flares on the Texas Panhandle to the largest source of American electricity, thirteen places that made gas the grid's fuel. A story in 13 stops on the Wattlas map of the North American grid.
Act I · 1918–1951
Flared on the Panhandle (1918–1935)
On December 9, 1918 the Amarillo Oil Company's Masterson No. 1, drilled into a dome in Potter County, Texas, struck gas at about ten million cubic feet a day, and almost nobody wanted it. American cities lit their streets and cooked their suppers with gas made from coal in their own gasworks, and no pipe yet reached from the High Plains to anyone who could burn so much. Oil turned up nearby, and in March 1926 a promoter named Ace Borger laid out a town on the Canadian River that drew more than 45,000 people within ninety days. Gas came up with the oil whether anyone wanted it or not. Plants across the field stripped the gasoline out of it and let the rest go, and carbon black makers burned it in long rows of smoky flames to gather the soot. By 1937 the Panhandle's carbon black plants were making 82 percent of the nation's supply, and at the worst of the waste the field was flaring more than a billion cubic feet of gas a day. Texas repealed the law that had allowed the stripping in 1935, and pipelines laid from 1925 on began carrying Panhandle gas to faraway cities. The carbon black works at Borger outlasted the boom, and this is where the story of American gas power begins, on a plain where the fuel that now makes more of the country's electricity than any other was once burned for nothing.
On the map: The ring is the Borger Plant, 20 MW of gas run by Sid Richardson Carbon, and Engineered Carbons Borger Cogen, 19 MW, stands beside it. Both lie inside the map's Anadarko Basin outline, and five gas processing plants on the map are within 40 km.
Sources: Texas State Historical Association, Panhandle Field, Texas State Historical Association, Borger, Texas State Historical Association, Carbon Black Industry
The Big Inch (1942–1951)
The pipelines that finally brought Southwestern gas to the East were built to carry oil. Between January and April 1942 German submarines sank 46 tankers off the American coast, and the Northeast, which got most of its oil by sea from Texas, faced running dry. The answer was to move the oil overland, in the longest, biggest and heaviest project of its kind yet undertaken. Work on the Big Inch, 24 inches across, began in the summer of 1942 in the East Texas oil field at Longview, and on August 14, 1943 crude oil reached Phoenixville, Pennsylvania, 1,254 miles away, with branches running on to Linden, New Jersey and to Philadelphia. The Little Big Inch followed from the refineries of the upper Texas coast to Linden with gasoline and other fuels, and before the war in Europe ended the two lines had carried more than 350 million barrels east. Peace left the government holding two giant pipes and no war to feed. In November 1947 Texas Eastern Transmission, a new company backed by the Houston builders George and Herman Brown, bought both for $143,127,000 and turned them over to natural gas. The Northeast began trading the coal gas of its old gasworks for the real thing. Transco's line from Texas reached New York City in 1951, and Con Edison and Brooklyn Union Gas sent crews door to door to convert millions of stoves and heaters to burn it. Gas from the Gulf Coast had become a national fuel.
On the map: The dashed lines are the map's gas pipelines, about 360,000 km of them. Texas Eastern, which bought the Big Inch and the Little Big Inch in 1947, has 8,626 km in 16 states from Texas to New Jersey. The ring is Linden Generating Station, 1,636 MW of gas at Linden, New Jersey, where the Little Big Inch ended.
Sources: Texas State Historical Association, Big Inch and Little Big Inch, Wikipedia: Big Inch, Urban Omnibus, Buried Grudges
Act II · 1954–1990
The barges of Gowanus (1965–1972)
At 5:16 pm on November 9, 1965 the Northeast went dark, and New York City's big steam plants, which needed power from the grid to start again, sat cold until the system could be rebuilt around them. Big Allis, the million-kilowatt giant Con Edison had just started at Ravenswood, lost the pumps that oiled its bearings and was badly damaged. Regulators and utilities took the lesson that a city needed generators able to start on their own within minutes, and the gas turbine, a cousin of the jet engine, could do it. GE had put its first gas turbine to work for a utility in 1949 at Oklahoma Gas and Electric's Belle Isle station, and after the blackout it sold smaller fast-start machines for restoring a dead grid and for the few hot afternoons a year when demand ran highest. New York put its peakers on the water. In 1971 and 1972 barges full of gas turbines were moored in Gowanus Bay and off the Narrows in Brooklyn, burning gas or oil and waiting for the peaks. For half a century their exhaust drifted over Sunset Park. By the PEAK Coalition's count about 750,000 New Yorkers live within a mile of a peaker, most of them people of color or with low incomes, and ratepayers paid the city's peakers some $4.5 billion over a decade to stand ready. New York set tighter limits on their pollution from 2023, and in July 2025 notices went in to retire Gowanus 2 and 3 and Narrows 1 and 2 in July 2026, a month after the Champlain Hudson Power Express began delivering Québec hydropower to Queens.
On the map: The ring is Gowanus, 580 MW of gas turbines on barges in Gowanus Bay, dated 1971, and Narrows, 309 MW from 1972, lies 2 km to the southwest. EIA-860M August 2026 lists both as operating. The historic site 12 km to the north-northeast is Big Allis at Ravenswood.
Sources: POWER, A Brief History of GE Gas Turbines, New York Lawyers for the Public Interest, July 16, 2025, NYSERDA, June 16, 2026
Cove Point and the shortage (1976–1980)
By the winter of 1976 to 1977 the gas that had flowed so freely after the war was running short. The trouble went back to June 7, 1954, when the Supreme Court ruled five to four in Phillips Petroleum Co. v. Wisconsin that the Federal Power Commission must regulate the price producers charged for gas sold across state lines. The commission held that price low, while gas sold inside Texas and Louisiana could fetch whatever buyers would pay, so producers kept their gas at home and the interstate pipelines to the North and East came up short. That winter was one of the coldest anyone could remember, and on February 2, 1977 President Carter signed emergency legislation to move gas to where it was needed most, saying that thousands of factories had closed and about 500,000 workers had lost their jobs. Utilities looked overseas for supply. On the Chesapeake Bay in Maryland, Cove Point began taking in liquefied gas from Algeria in 1978, until Algeria demanded a higher price and the deliveries dwindled and stopped. Congress answered the shortage in 1978 with the Natural Gas Policy Act, which began lifting price controls, and with the Powerplant and Industrial Fuel Use Act, which barred new power plants from burning gas or oil as their main fuel, on the reasoning that gas was too scarce to spend on electricity. For the next decade utilities built coal and nuclear plants instead, and the gas plants that survive from the 1980s add up to less than a third of those from the 1970s.
On the map: The LNG dot at Cove Point on the Chesapeake stands for two rows on the map, an import terminal and an export terminal, both dated 1978, and Calvert Cliffs nuclear plant is 6 km to the north-northwest. Across the map, gas plants listed as operating whose first unit came in the 1970s hold about 70 GW, and those from the 1980s about 22 GW.
Sources: Wikipedia: Phillips Petroleum Co. v. Wisconsin, The American Presidency Project, February 2, 1977, Wikipedia: Cove Point LNG, EIA, Natural Gas Policy Act of 1978, EIA, Repeal of the Powerplant and Industrial Fuel Use Act
Midland (1984–1990)
At Midland, in the middle of Michigan, the nuclear boom had left Consumers Power with a half-built plant sinking into poorly compacted ground, and it was gas that rescued it. Consumers and Dow Chemical had announced the project in December 1967 as the world's first dual-purpose industrial nuclear plant, with two reactors meant to send power to the grid and steam to Dow's chemical works next door. The buildings settled and cracked, the rules tightened after Three Mile Island, and in 1984, with the plant 85 percent complete after seventeen years and $4.3 billion, Consumers gave up, a loss that nearly bankrupted it. The Fuel Use Act should have kept gas out of any replacement, but the law allowed an exemption for cogeneration, a plant that makes electricity and useful heat from the same fuel, and PURPA obliged utilities to buy such a plant's power when it cost less than their own. Conversion began in 1986 with gas turbines whose hot exhaust would raise the steam, and in 1990 the Midland Cogeneration Venture began sending power to the grid and steam to Dow. When it went into full service in 1991 it was the largest gas-fired steam recovery plant in the world, making about a tenth of the power used in Michigan's Lower Peninsula. By then the ban was gone, for falling gas prices had led Congress in 1987 to repeal the Fuel Use Act's limits on burning gas in power plants, and over the next fifteen years the gas burned for electricity in the United States more than doubled.
On the map: The dot marks the Midland Cogeneration Venture in Midland, Michigan, dated 1990. The map lists the plant beside it at 1,865 MW of gas, with 1989 as its year, the largest gas plant it lists in Michigan.
Sources: Wikipedia: Midland Cogeneration Venture, University of Michigan, Michigan in the World, Consumers Power Company, Midland, 42 U.S.C. 8322, Fuel Use Act exemptions (Cornell LII), Wikipedia: Public Utility Regulatory Policies Act, EIA, Repeal of the Powerplant and Industrial Fuel Use Act
Act III · 1990–2016
Chesterfield and the F-class (1990)
On June 6, 1990, beside the James River some fifteen miles south of Richmond, Virginia Power started the first of a new breed of gas turbine. GE called it the 7F. It made 147 MW and fired its gas at 2,300 degrees Fahrenheit, with air channeled through its blades to keep them from melting, a trick learned from jet engines. Two years later Chesterfield 7 became a combined cycle, its exhaust raising steam for a second turbine, and the pair reached 214 MW at 45.2 percent efficiency, beyond the reach of the best steam plants of the day. The idea itself was old, for GE's first utility gas turbine, at Belle Isle in Oklahoma City in 1949, had already sent its exhaust to warm a steam plant's feedwater, but the F-class changed the economics. A combined cycle could be built in a couple of years from factory-made parts, set down near a pipeline and the load it served, and ramped up and down within the hour, and it arrived just as the repeal of the Fuel Use Act and the opening of the pipelines to all comers were making gas cheap and easy to buy. By 2020 more than 950 7F turbines had been built, some 700 of them for the United States and Canada, and the combined cycle had become the workhorse of the American grid.
On the map: Two rows on the map named Chesterfield share one point on the James River below Richmond, a 386 MW gas plant dated 1990 and 936 MW of gas turbines planned for 2029. Across the map, 510 gas plants listed as operating have part of a combined cycle as their largest generator, more than half of all gas capacity.
Sources: POWER, GE 7F turns 30, POWER, A Brief History of GE Gas Turbines
Enron and the dash to gas (1992–2003)
Kenneth Lay merged his Houston Natural Gas with InterNorth of Omaha in 1985, and the company that took the name Enron owned some 37,000 miles of pipeline, the second largest gas system in the country. Its timing was good, for that year FERC's Order 436 began turning interstate pipelines into carriers of other people's gas, and on April 8, 1992 Order 636 made them separate the gas they sold from the gas they carried, so that a buyer could purchase gas from any producer and ship it on any line. Gas became a commodity to be traded like any other, and Enron set out to be its market. Jeffrey Skilling, then a McKinsey consultant, dreamed up its Gas Bank in 1989 to let producers and buyers fix their prices and hedge their risk, and in November 1999 EnronOnline began trading energy over the internet, at its peak more than $6 billion a day. Enron and the independent power producers it championed pushed to open the electricity markets too, and cheap gas and the new turbines made plants easy to finance. Merchant developers raced to put combined cycles and peakers wherever there was a grid to sell into, and the rush crested in the first years of the new century. Enron did not see it through, filing for bankruptcy on December 2, 2001, and as power prices sagged many of the merchant builders ran into trouble of their own, leaving the country with more gas plants than it needed for years. That surplus would carry the grid into the shale boom to come.
On the map: The dot marks Enron's tower in downtown Houston, dated 2001. Channel Energy Center, 760 MW from 2001, and Deer Park Energy Center, 1,192 MW from 2003, lie 14 and 23 km to the east. Across the map, 365 gas plants listed as operating have a first unit from 2000 to 2003, about 151 GW.
Sources: Wikipedia: Enron, EIA, FERC Order 436, EIA, FERC Order 636
Mitchell's Barnett (1997–2013)
For the better part of two decades George Mitchell lost money on a rock the rest of the industry had written off. In 1981 his company drilled the C. W. Slay No. 1 near Newark, in Wise County northwest of Fort Worth, into the Barnett Shale, which held enormous amounts of gas locked in rock so tight it would barely flow. Mitchell kept drilling. By 1995 Mitchell Energy had completed seventy wells there while all its competitors together had tried three, and by 1997 it had spent some $250 million without earning it back. That year a young engineer named Nick Steinsberger suggested fracturing the shale with a thin mix of water and sand, the slickwater fracs other companies were using in East Texas sandstone, in place of the costly gels. It cut the cost of each well by $75,000 to $100,000 and freed far more gas, and in 1998 a well called S. H. Griffin No. 3 outproduced in its first ninety days every well the company had drilled before. Devon Energy bought Mitchell Energy in 2002 and paired the new fracs with horizontal drilling, which Mitchell had tried without success, and in 2008 operators in the Barnett completed 2,901 horizontal wells. The shale ran beneath Fort Worth itself, and rigs rose among its neighborhoods. At its peak in January 2013 the field made 4.56 billion cubic feet a day, 6.8 percent of the country's gas, and the methods worked out in North Texas were carried to shale basins across the continent.
On the map: The outline is the map's Fort Worth Basin, home of the Barnett Shale. The map lists 43 gas plants inside it as operating, about 9.2 GW, and 28 gas processing plants. The ring is Wolf Hollow II, 1,103 MW from 2017, the largest gas plant in the outline with a first unit from 2015 on.
Sources: Wikipedia: Barnett Shale, Wikipedia: George P. Mitchell
The Marcellus (2004–2016)
In October 2004 Range Resources went back to a well in Washington County, Pennsylvania, called Renz No. 1, which had shown little promise when it was drilled the year before, and pumped a Barnett-style slickwater frac into the Marcellus Shale, a black band of rock beneath much of Appalachia, and gas flowed from a formation few had thought worth the trouble. By 2006 word of it had reached the big companies of Texas and Oklahoma, and soon wells were being drilled across Pennsylvania and West Virginia, their horizontal legs reaching out beneath hills that had given the country its first oil boom and much of its coal. The gas lay close to the biggest markets in the East, and there was so much of it that prices collapsed. In 2012 gas at the Henry Hub averaged $2.77 per million Btu, the lowest since 1999. Power plants run on whatever is cheapest, and cheap gas pushed coal further down the order in which plants are called on, month after month, until by 2016 gas had passed coal as the country's leading source of electricity. The new plants rose on top of the field itself, big combined cycles set down in coal country beside the wells and the pipelines, and the largest of them, Guernsey in eastern Ohio, came online in 2023. Pennsylvania became the second largest gas producing state, behind only Texas.
On the map: The outline is the Marcellus play. The map lists 41 gas plants inside it as operating, about 15 GW, and 18 of them, about 9.1 GW, have a first unit from 2015 on. The ring is the largest, Guernsey Power Station in Ohio, 1,789 MW from 2023.
Sources: Range Resources, Marcellus Shale at 20 years, EIA, Today in Energy, 2012 prices, EIA, Today in Energy, gas passes coal
Sabine Pass (2008–2016)
At Sabine Pass, where Sabine Lake drains into the Gulf on the Louisiana line, Cheniere Energy built a terminal for a country that expected to run short of gas. Giant insulated tanks and deepwater berths were made ready for tankers bringing liquefied gas from abroad, and in 2008 the terminal opened for imports, just as the shale wells of Texas and Pennsylvania were proving that the country had gas to spare. Within two years Cheniere turned its plan around. In 2012 it became the first company in the Lower 48 to win federal approval to build liquefaction trains, the enormous refrigeration plants that chill gas to about 260 degrees below zero, and it sold the cargoes at prices tied to the Henry Hub. On February 24, 2016 the tanker Asia Vision sailed from Sabine Pass for Brazil with 3.3 billion cubic feet of liquefied gas, the first export cargo of the shale era. Cove Point, built in the shortage of the 1970s to take in Algerian gas, was rebuilt to send gas out in 2018, and by 2025 the United States was exporting 15 billion cubic feet a day, more than any other country in the world. Gas that had once been flared on the Panhandle for want of a buyer now crossed oceans to find one.
On the map: The LNG dots at Sabine Pass are Cheniere's import terminal, dated 2008 on the map, and the liquefaction plant beside it. Golden Pass, 5 km to the west across the channel in Texas, is listed as an import terminal from 2010 and an export terminal under construction.
Sources: Cheniere, History, EIA, Today in Energy, ten years of exports, Wikipedia: Cove Point LNG
Aliso Canyon (2015–2016)
On October 23, 2015 Southern California Gas found that a well called SS-25, drilled in 1953 into an old oil field in the hills above Porter Ranch, was leaking from a break about 8,750 feet down. Aliso Canyon was one of the largest gas storage fields in the country, a depleted reservoir where SoCalGas banked gas for the winter and for the summer heat, and for four months the gas poured out faster than crews could stop it. By early January 2016 some 2,800 households, more than 11,000 people, had moved out of their homes, and Governor Jerry Brown declared a state of emergency. When the well was finally sealed in February it had released about 97,100 metric tons of methane, the worst natural gas leak in the country's history. Then the grid had to reckon with what it had lost. The field fed the gas plants that carry the Los Angeles Basin through its summer peaks, and in April the state's energy agencies, its grid operator and LADWP warned that without it there could be fourteen days that summer when gas shortages ran deep enough to interrupt power to millions of customers. They set out eighteen measures to head that off, and the state hurried to add batteries that could stand in for gas plants at the peak. The field reopened in July 2017 under a lower limit, and California has been working out how to do without it ever since.
On the map: The storage dot above Porter Ranch is Aliso Canyon, which the map lists at 86.2 Bcf of working gas, the most of any storage field it lists in California. LADWP's Valley plant, 563 MW of gas from 2001, is 16 km to the east-southeast.
Sources: Wikipedia: Aliso Canyon gas leak, CPUC, Aliso Canyon, Aliso Canyon Action Plan, April 2016, Ars Technica, September 16, 2016
Act IV · 2021–present
Gas in the February freeze (2021)
The cold that settled over Texas in mid-February 2021 reached down into the gas fields. Water that comes up with the gas froze in wellheads and gathering lines, ice closed the roads that crews and trucks needed to keep wells running, and producers shut in wells to keep them from freezing. As the grid failed, the load shed reached the gas system as well, cutting power to wells and processing plants that the gas supply depended on. Production across Texas, Oklahoma and Louisiana fell by more than half, to about 20 billion cubic feet a day, and on February 17 the country's dry gas output stood 28 percent below where it had been on February 4, the largest monthly decline on record, and power plants that burned gas could not get enough of it. FERC and NERC counted 1,045 generating units that suffered outages, derates or failures to start between February 8 and 20, 604 of them fueled by gas, and found fuel supply the second largest cause after frozen equipment, nearly nine times in ten a shortage of natural gas. Each system had depended on the other, and each had pulled the other down. The inquiry called for gas and electricity to be planned for the cold together, and Texas passed a law that year requiring the gas facilities its regulators deemed critical to be able to withstand a weather emergency.
On the map: Texas has 209 of the map's 840 gas processing plants, more than any other state or province. The ring marks the 2021 Texas power crisis, placed at ERCOT's operations complex in Taylor.
Sources: FERC, NERC and Regional Entity staff, preliminary findings, September 23, 2021, FERC, NERC and Regional Entity staff, final report, The Texas Tribune, May 26, 2021
The Permian (2023–2029)
When the Texas Legislature met again after the freeze, it set out to pay for power plants that could run whatever the weather, and in practice that meant gas. It created the Texas Energy Fund in 2023, and on November 7 that year about two thirds of the state's voters approved it, $10 billion in all, most of it for low-interest loans to build dispatchable plants on the ERCOT grid. The largest loan the fund had announced by November 2025, $1.1 billion, went to Competitive Power Ventures for Basin Ranch, a 1,350 MW combined cycle in Ward County that broke ground on November 20, 2025, with turbines from GE Vernova, the power business GE spun off in 2024, whose line runs back to the 7F at Chesterfield. It is rising in the middle of the Permian Basin, where drillers chasing oil bring up gas faster than the pipelines can carry it away. The Permian produced about 27.7 billion cubic feet of gas a day in 2025, and when its pipes fill the price at the Waha hub falls below zero, as it did on 39 days that year. In the spring of 2026 it stayed negative for at least 47 days in a row, and producers accepted the losses on gas because the oil paid for them. A decade earlier many would simply have flared it, and new pipelines to the coast are being laid to catch up. Nearly a century after the Panhandle wells blew their unwanted gas into the sky, West Texas still has more gas than it can send to market, and at Basin Ranch some of it will be burned close to where it comes out of the ground. Gas that began as waste on the High Plains has become the fuel the grid reaches for first whenever it needs to grow, here and as far away as Pennsylvania, where the ground of the retired Homer City coal plant is being rebuilt as the largest gas plant in the country.
On the map: The ring is CPV Basin Ranch, 1,345 MW of gas that EIA-860M August 2026 lists as under construction for 2029. It lies inside the map's Permian Basin outline, which holds 99 gas processing plants, 11 of them within 50 km.
Sources: Utility Dive, November 2023, Competitive Power Ventures, November 20, 2025, Pipeline and Gas Journal, March 12, 2026, Pipeline and Gas Journal, April 14, 2026, POWER, April 2025