Share of utility-scale installed capacity, by source
This interactive map and sortable table show every utility-scale coal power plant in the United States, all 565 plants of 1 MW or larger whose primary energy source is coal, color-coded by coal rank: bituminous (318), subbituminous (196), waste coal (19), lignite (17), refined coal (14) and coal synthesis gas (1). Plants are shown across all statuses: active (205), standby (6), in development (3) and decommissioned (351). The 205 active coal plants mapped here have a combined capacity of about 180,400 MW; adding the six standby plants brings the installed coal fleet to 181,648 MW (~182 GW). The capacity mix above uses the active figure. The fleet still has more retired plants than operating ones, but the picture has changed: after more than a decade in which nothing was built, three projects are now in development, two of them greenfield plants in Alaska and West Virginia backed by the Department of Energy, and the third a Maryland plant that shut in 2024 and is being recommissioned. None has broken ground.
Capacity is what is installed; generation is what actually ran. Coal holds 13.59% of US utility-scale generating capacity and produced 16.62% of the electricity in 2025, an implied capacity factor of 46.6% on a nameplate basis. Nuclear is the extreme case in one direction, at 7.30% of capacity for 17.70% of generation; solar is the extreme in the other, at 12.73% for 6.67%.
Sources, basis and how the totals reconcile
Sources. Generation is EIA Electric Power Monthly, Table 1.1, Net Generation by Energy Source: Total (All Sectors), annual 2025 row. EIA marks 2025 and 2026 values as preliminary; 2024 and earlier are final, so these shares may be revised.
Basis. Both charts cover utility-scale plants of 1 MW or larger, generating sources only. Battery storage is excluded from the capacity chart because it shifts power rather than producing it, and estimated small-scale rooftop solar (93,148 GWh in 2025) is excluded from the generation chart so the two stay comparable.
Totals. The generation slices sum to 4,434,820 GWh. EIA’s published net total is 4,429,502 GWh, being that figure less 5,320 GWh of net pumped-storage hydro, which EIA reports as a negative because pumping consumes more electricity than generation returns, and a further 2 GWh that EIA attributes to independent rounding. Pumped storage is left out of the pie because a negative value cannot be drawn as a slice. Percentages use largest-remainder rounding at two decimal places so each chart adds to 100.00%.
Category notes. EIA reports wind, biomass and geothermal as one 526,246 GWh category; the split here carries a one-unit adjustment on wind so the three reconcile to that published total. Biomass covers wood and wood waste, black liquor, landfill gas, sludge waste, agricultural byproducts and biogenic municipal solid waste. Other fossil gas is blast furnace gas, gaseous propane and other manufactured waste gases; Other is hydrogen, non-biogenic municipal solid waste, batteries, purchased steam, sulfur and tire-derived fuel. One definitional seam is worth knowing: EIA-860 files gaseous propane under petroleum products, while Table 1.1 files it under other fossil gas, so the same fuel sits in the Petroleum slice on the capacity chart and the Other fossil gas slice on the generation chart. Only one 2.3 MW plant is affected.
Share of utility-scale electricity generated, by source
EIA preliminary data
Coal plants were built as baseload but now follow demand. Units ramp through the morning, hold through the afternoon peak and back down overnight, though the swing is gentler than gas because large steam units are slow and costly to cycle.
Method: this is a modeled profile, not metered data. The 24-hour mean of 46.6% is the implied annual capacity factor, calculated as 2025 generation from EIA Electric Power Monthly Table 1.1 divided by the nameplate capacity of the active fleet on this page multiplied by 8,760 hours. EIA’s own published capacity factors use net summer capacity as the denominator and therefore run higher. The hourly shape applies the documented operating behaviour of this technology to that mean and is indicative rather than measured; metered hourly output would come from the EIA Hourly Electric Grid Monitor, which is not yet wired into this page.
| # | Plant | Type | State | Nearest city | Operator | Status | Capacity | Online |
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Plants are grouped by the primary energy source of their coal-fired generators, following the fuel codes in Form EIA-860 Table 28. Active plant counts and capacity below are for plants operating today; each colour matches the map and the table.
The workhorse of the eastern fleet, mined in Appalachia and the Illinois Basin. Hard, high-carbon and high-energy, it fuels more plants than any other rank, though many are now retired: 71 of the 318 remain active, supplying about 75,300 MW.
Lower in sulfur and energy than bituminous, and mostly shipped by unit train from Wyoming’s Powder River Basin. Its low sulfur content made it the compliance fuel of choice after the Clean Air Act amendments, and it now carries the largest active capacity of any rank: 110 active plants and about 96,100 MW.
The softest and lowest-energy rank, with high moisture content that makes it uneconomic to transport far. Lignite plants sit beside their mines in Texas, North Dakota and Mississippi, often sharing a single owner and a dedicated conveyor. 9 remain active, at about 5,950 MW.
Culm and gob, the discarded fines and rock left by a century of earlier mining, burned in circulating fluidized bed boilers that tolerate low-grade fuel. Most sit on Pennsylvania anthracite waste piles, and burning them removes a legacy pollution source. Units are small: 13 active plants total only about 1,550 MW.
Coal chemically treated before combustion to cut mercury and nitrogen oxide emissions. The category exists largely because of a federal tax credit that expired at the end of 2021, and it has been shrinking since: just 1 plant remains active, at about 1,210 MW.
Coal gasified into a synthetic gas that is cleaned and burned in a combined cycle rather than a steam boiler. Only one plant uses it, Duke’s Edwardsport in Indiana at about 331 MW. Note that EIA counts other synthesis gas, code SGP, as petroleum rather than coal.
Any utility-scale plant (1 MW or larger) with at least one generator whose primary energy source is a coal fuel: bituminous (BIT), subbituminous (SUB), lignite (LIG), waste coal (WC), refined coal (RC) or coal-derived synthesis gas (SGC). That yields 565 plants. Standby covers three different EIA states: plants held in reserve and available when needed, plants out of service but expected back within a year, and plants out of service with no expected return. Four of the six standby coal plants here, about 1,220 MW, are out of service with no expected return. Filtering on the primary fuel excludes gas plants that merely co-fire coal.
Coal is graded by carbon and energy content. Anthracite is hardest and highest-energy (rare in power generation today); bituminous is the workhorse of the eastern US; subbituminous (mostly Wyoming Powder River Basin) is lower-sulfur and widely shipped; lignite is the softest and lowest-energy, burned close to the mine in Texas and North Dakota.
US coal capacity has dropped sharply since around 2010 as cheaper natural gas, renewables and environmental rules pushed plants into retirement. This dataset shows 350 decommissioned plants versus 205 active; the two are now roughly one-to-one.
No. Three are, the first in more than a decade: the Terra Energy Center in Alaska and the TerraSpark Energy Campus in West Virginia, both greenfield plants backed by the Department of Energy, and AES Warrior Run in Maryland, which shut in 2024 and is being recommissioned. None has broken ground, and new US generation remains overwhelmingly gas, solar, wind and storage.
They describe steam conditions and efficiency: subcritical is the older, lower-efficiency design; supercritical and ultrasupercritical run hotter, higher-pressure steam for more output per ton of coal. A few plants (e.g., W. A. Parish in Texas) add carbon-capture equipment. Where EIA reports these, they appear in the tile profiles.
It reflects EIA Form EIA-860M (Preliminary Monthly Electric Generator Inventory) through August 2026, reconciled against the EIA-860 2025 early release (Schedules 2 and 3), supplemented by Department of Energy announcements for the two new coal projects in Alaska and West Virginia. EIA notes that preliminary monthly capacities are estimates and may be revised, and that a small number of plants may be withheld pending validation. Active and standby coal capacity here totals roughly 182 GW, consistent with EIA’s published figures.
No map on the website is shrinking faster. Decommissioned coal plants now roughly equal the number still operating, and essentially none are in development. The entire trajectory points one way. The survivors concentrate in the Ohio and Tennessee valleys, the Upper Midwest and the Plains, near the mines and barge routes that historically fed them. Most are large baseload steam plants built between the 1950s and 1980s, now running fewer hours each year as cheaper gas and renewables displace them.
The technology behind them is unchanged in outline since the 1950s. Pulverized coal is burned in a boiler to raise high-pressure steam, which spins a steam turbine coupled to a generator. What separates one plant from another is the steam condition: older units run subcritical steam, while newer and more efficient ones run supercritical or ultrasupercritical, extracting more electricity from the same tonne of coal. A handful have added carbon capture. The exception on this map is the single synthesis gas plant, which gasifies coal and burns the product in a combined cycle instead.
That inheritance is now the fleet's problem. Because these are large units designed to run continuously, they are expensive to operate at the low capacity factors the market now gives them, and retrofitting a 1970s boiler is rarely worth the cost against new gas or solar. US coal capacity has fallen sharply since about 2010 as a result.
That decline has now slowed sharply, and the reason is federal intervention rather than economics. In 2025 the US retired 2.6 GW of coal capacity, the least since 2010, against 8.5 GW that operators had planned at the start of the year. Of the shortfall, 4.8 GW was delayed and the operators of two plants totalling 1.1 GW cancelled retirement outright. Since May 2025 the Department of Energy has issued more than forty emergency orders under Section 202(c) of the Federal Power Act, directing plants to keep running and stalling at least 4.4 GW of retirements. Each order lasts 90 days and can be renewed indefinitely, and several have been. The Congressional Research Service notes this is a novel use of the authority, because in the first orders the grid operators had neither requested the action nor identified reliability risks tied to those retirements, and the orders are being challenged in court. Six plants on this map are affected: J.H. Campbell, Transalta Centralia, R.M. Schahfer, F.B. Culley, Brandon Shores and Comanche.
Money has followed the orders. Under the Department of Energy's Restoring Reliability: Coal Recommissioning and Modernization programme, roughly $850 million was committed in June 2026 across 17 projects: two new plants, a recommissioning at Warrior Run in Maryland, a retrofit of a 510 MW plant in Puerto Rico, and modernisation at more than a dozen existing stations including John E. Amos and Cardinal on this map. DOE states it has now supported or preserved 45 coal plants representing more than 40 GW. Separately, EPA has granted 47 companies exemptions from the Mercury and Air Toxics Standards running from July 2027 to July 2029, removing a compliance cost that had been driving several retirement decisions. EIA's May 2025 inventory had coal capacity falling from 172 GW to 145 GW by the end of 2028; EIA now says that pace could slow.
Yet because the remaining plants are big, coal still represents about 180 GW of active capacity. That is second only to natural gas among thermal sources, and far more than nuclear. That tension, a fleet that is simultaneously enormous and in decline, defines US coal today. Each retirement removes a large block of dispatchable capacity that the grid must replace with gas, renewables plus storage, or, increasingly, by keeping other plants on standby. Explore that replacement dynamic in our look at the US power fleet in 2026.