Share of utility-scale installed capacity, by source
This interactive map and sortable table show every utility-scale petroleum-fired power plant in the United States, all 1,277 plants of 1 MW or larger whose primary fuel is petroleum (diesel/distillate, residual fuel oil, kerosene, jet fuel, waste oil or petroleum coke), color-coded by the prime mover of their petroleum-fired generators: reciprocating engine (944), combustion turbine (248), steam turbine (79) and combined cycle (6). Natural gas plants are excluded (including dual-fuel gas sites), so there is no overlap with the Natural Gas page. Petroleum is a small, mostly standby slice of US power, used for backup and peaking, especially in Alaska, Hawaii and remote grids. Plants are shown across all statuses: active (568), standby (257), in development (2) and decommissioned (450). Together, the 568 active petroleum plants mapped here have a combined capacity of about 21,386 MW (~21 GW); the 257 standby plants add a further 2,333 MW, an unusually large share for any fuel and a reminder that most oil-fired plant exists to be held in reserve.
Capacity is what is installed; generation is what actually ran. Petroleum holds 1.61% of US utility-scale generating capacity and produced 0.43% of the electricity in 2025, an implied capacity factor of 10.3% 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
Petroleum units are peakers and backup. They sit idle most hours because fuel is expensive, then start for the evening peak, for winter cold snaps when gas is constrained, or when another unit trips. The result is the spikiest and lowest profile of any source on this site.
Method: this is a modeled profile, not metered data. The 24-hour mean of 10.3% 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 prime mover of their petroleum-fired generators, the machine that actually turns the generator. Active plant counts and capacity below are for plants operating today; each colour matches the map and the table.
A diesel engine driving a generator, the same machine as a truck engine at far larger scale. It starts in seconds, runs on fuel that can be trucked or barged anywhere, and needs no steam cycle, which makes it the default where a grid is small or isolated. These dominate by count but are individually tiny: 423 active plants average about 7 MW each, totalling roughly 3,040 MW.
A jet engine burning oil instead of kerosene, spinning a generator directly with no boiler. Bigger than an engine and still quick to start, it is the classic peaking machine, held for the few hours a year when demand spikes or gas supply is constrained. 124 active plants carry about 11,390 MW, the largest active capacity of any type here.
Oil burned in a boiler to raise steam, the same architecture as a coal plant. These are the giants of the page, including Wyman, Wagner and Kahe, built when oil was cheap and now kept largely for winter reliability in the Northeast and on island grids. Few remain: 15 active plants, but averaging over 400 MW each for about 6,080 MW.
A combustion turbine whose exhaust heat raises steam for a second turbine, recovering energy that would otherwise be lost. It is the most efficient arrangement here and the rarest, because the capital cost only pays back with heavy running, which petroleum plants no longer do. Just 5 active plants, about 860 MW.
Any utility-scale plant (1 MW or larger) with at least one generator whose primary energy source is a petroleum liquid or petroleum coke, namely distillate/diesel (DFO), residual fuel oil (RFO), kerosene (KER), jet fuel (JF), waste oil (WO) or petroleum coke (PC), aggregated to the EIA plant. That yields 1,277 plants, typed by prime mover. A plant burning both oil and gas appears here only if petroleum is its predominant fuel; gas plants with oil backup, of which there are more than two hundred, are carried on the Natural Gas page instead.
No. Any plant that has a natural-gas-primary generator is treated as a natural gas plant and appears only on the Natural Gas page, including dual-fuel sites that can burn both gas and oil. This page lists only plants whose primary fuel is petroleum, so the two lists do not overlap.
Petroleum units are mostly backup and peaking capacity and are expensive to run, so they sit idle most of the year and start only during emergencies, extreme demand, or fuel shortages. Hundreds are therefore classified standby rather than actively operating.
They cluster in places without easy access to gas pipelines or large grids: Alaska, Hawaii and remote communities rely on diesel engines, while the Northeast keeps large oil-fired steam units for winter reliability. Island territories such as Puerto Rico rely heavily on oil too, but this site covers the 50 states and the District of Columbia only.
About 24 GW of active and standby capacity, a small share of US generation, and shrinking as older oil units retire. Most of it is rarely run.
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). EIA notes that preliminary monthly capacities are estimates and may be revised, and that a small number of plants may be withheld pending validation.
Petroleum is the website’s clearest example of capacity that exists to be held in reserve rather than run. Standby plants nearly rival active ones, and the geography explains why. Diesel engines and oil turbines concentrate where pipelines and large grids do not reach, in Alaska, Hawaii and remote communities, and in island territories such as Puerto Rico, which this map does not cover. They are joined by a set of large oil-fired steam plants in the Northeast, kept for the coldest winter days, when gas is diverted to home heating.
The four prime movers divide the fleet unevenly, and the split is itself a map of how oil is used. Reciprocating engines account for three-quarters of the plants but barely a seventh of the capacity, averaging about seven megawatts each, because their job is to keep a village or an island running rather than to serve a grid. Combustion turbines are fewer and larger and carry the most capacity, roughly 11,390 MW, as the classic peaking machine. The 15 remaining oil-fired steam plants average over 400 MW apiece, survivors of an era when oil was cheap enough to burn as baseload. Combined cycle, the most efficient arrangement, is almost absent at five plants, because its capital cost only pays back with heavy running and these plants are built precisely not to run.
Two things have changed for that reserve fleet, and neither is visible in the record itself. The first is that part of it now runs under federal order rather than market signals. Herbert A Wagner Unit 4 in Maryland has operated under Department of Energy emergency orders since May 2026, issued under Section 202(c) of the Federal Power Act and renewed through November, and the dual-fuel Eddystone units in Pennsylvania have been kept from retirement the same way since May 2025, though those appear on the Gas page because EIA codes natural gas as their primary fuel.
The second is a reserve role this page cannot show at all. Through 2026 the Department of Energy has repeatedly authorised PJM, Duke Energy and ERCOT to call on backup generation at data centres and other large customers as a last resort during grid emergencies. The exhibits filed with those applications describe what that capacity is: diesel sets at water treatment plants, booster stations, wellfields and pumping stations, mostly between 100 and 2,250 kilowatts. Willmar Municipal Utilities in Minnesota was dispatched by MISO to run its diesels twice in a single January day, and receives an annual payment simply for keeping the capability. These are behind-the-meter units that EIA does not track as power plants, so they are correctly absent from this map, but they are a growing part of the same reserve function the plants here perform.
Oil-fired power is expensive to run, so operators avoid it whenever cheaper sources can do the job; its advantage is that fuel can be stored on-site in tanks, independent of any network. That makes it the ultimate insurance policy. It is idle most of the year, invaluable during the rare hours of crisis. As batteries take over more of that reserve role, the petroleum fleet is slowly sliding from standby toward retirement, a transition visible in the large share of decommissioned plants on the map. We explore this reserve logic in The Power Plants That Almost Never Run.