Share of utility-scale installed capacity, by source
This interactive map and sortable table show every utility-scale hydroelectric power plant in the United States, all 1,608 plants of 1 MW or larger whose energy source is water, color-coded by type: conventional hydro (1,566) and pumped storage (42). Hydropower is America’s oldest utility-scale renewable and, at roughly 102 GW here, still its largest source of renewable generation and grid storage. Plants are shown across all statuses: active (1,394), standby (85), in development (40) and decommissioned (89). Dams are long-lived, so retirements are rare; most new capacity today is pumped storage and turbine uprates. Together, the 1,373 active hydroelectric plants reported to EIA have a combined capacity of about 101,576 MW (~102 GW), and 21 smaller FERC-licensed plants added from Oak Ridge National Laboratory bring the 1,394 active plants mapped here to about 101,627 MW, of which pumped storage accounts for roughly 22 GW. Start year is the earliest unit ever sited at the dam, so a plant rebuilt with modern turbines still carries its original date.
Capacity is what is installed; generation is what actually ran. Hydroelectric holds 7.66% of US utility-scale generating capacity and produced 5.57% of the electricity in 2025, an implied capacity factor of 27.7% 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
Hydroelectricity is dispatchable, so operators hold water back and release it when demand and prices are highest. The profile follows the daily load curve, subject to river flow, reservoir levels and downstream water-management obligations that often matter more than price.
Method: this is a modeled profile, not metered data. The 24-hour mean of 27.8% 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 | FERC # | Type | State | Nearest city | Operator | Status | Capacity | Online |
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Run-of-river and reservoir dams convert the energy of falling or flowing water into electricity through a hydraulic turbine. Conventional hydro is America’s oldest large-scale renewable and still its largest by generation, anchored by giants like Grand Coulee.
Reversible turbines pump water uphill to an upper reservoir when power is cheap, then release it to generate at peak demand. Pumped storage is by far the largest form of grid energy storage in the US (~22 GW), led by plants like Bath County and Ludington.
Most US hydro dams were built in the mid-20th century and run for generations, so retirements are rare. Little new conventional capacity is added today, but new pumped-storage projects and turbine uprates are in development.
Any utility-scale plant (1 MW or larger) whose energy source is water (code WAT). That yields 1,608 plants, of which 1,565 come from EIA-860M and 43 were added from FERC licensing notices and Oak Ridge National Laboratory's Existing Hydropower Assets database. The 21 added from Oak Ridge are small FERC-licensed plants, mostly industrial and municipal, that clear this map's 1 MW threshold but are not reported in EIA-860M; together they add about 50 MW, which is included in the active capacity and in the capacity mix shown above. All 21 hold FERC licences or exemptions, and FERC jurisdiction over a non-federal project generally rests on its connection to an interstate grid. Oak Ridge records a balancing authority and a named transmission provider for five of them, including the mill plant at Flambeau River Papers, which connects through Northern States Power, and is silent rather than negative for the rest. None is a captive plant serving only its host, which is why they appear here: this map covers generation that supplies the grid. A note on unit replacement: 43 plants here have had turbines retired in place and replaced or uprated, and EIA records that by carrying both retired and operating units under one plant code. Each record shows only the capacity currently operating, so a further 1,425 MW of retired turbines sits inside plants that are still running and appears nowhere in these figures. Wanapum in Washington alone has 1,038 MW retired against 1,220 MW operating. Total retired US hydro capacity is therefore nearer 2,082 MW than the 657 MW carried by the decommissioned records, and this is a fleet that renews itself in place rather than shutting down. 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. On this page the last group is the largest: 47 of the 85 standby plants, about 340 MW, are not expected to return, so standby here is often closer to retirement than to reserve. The FERC # column gives the Federal Energy Regulatory Commission project number where one exists, drawn from Oak Ridge National Laboratory's Existing Hydropower Assets database and, for projects not yet built, from FERC licensing notices. Three values are possible. A docket such as P-2426, or CD-prefixed for a conduit exemption, means the plant is FERC-licensed. Federal means the plant is owned and operated by a federal agency, chiefly the Bureau of Reclamation, the Army Corps of Engineers or the Tennessee Valley Authority, and is therefore not licensed by FERC at all: 164 plants and about 42 GW fall into this category, including Grand Coulee, Hoover Dam and the Columbia and Snake River dams. Unknown covers the remainder. FERC's own jurisdiction test explains most of them: a non-federal plant needs a licence only if it sits on navigable waters, occupies federal land, uses water or waterpower from a federal dam, or was built after 26 August 1935 on a Commerce Clause waterway and affects interstate commerce, and unless it holds a valid pre-1920 federal permit. That last exception covers Keokuk, authorised by an Act of Congress in 1905, and San Francisco's three Hetch Hetchy powerhouses, authorised by the Raker Act of 1913, which between them account for 541 MW of the Unknown total. Separately, the Hydropower Regulatory Efficiency Act of 2013 placed qualifying conduit facilities, those using only the hydroelectric potential of a non-federally owned canal or pipeline, outside FERC jurisdiction altogether. The rest of the Unknown set is made up of projects still at preliminary-permit stage and retired plants whose dockets closed long ago. Type is set by the generator’s prime mover: a conventional hydraulic turbine (HY) or a reversible pumped-storage turbine (PS).
Conventional hydro turns the natural flow or fall of water into electricity at a dam or run-of-river site. Pumped storage is a battery: it pumps water to an upper reservoir when electricity is cheap and releases it through reversible turbines to generate at peak demand.
About 102 GW of active and standby capacity, roughly 81 GW of conventional hydro and 22 GW of pumped storage. Hydropower is the largest source of US renewable generation historically and pumped storage is the largest form of US grid energy storage.
Hydro dams are extremely long-lived, and many have run for 70–100 years, so retirements are rare compared with thermal plants. Most are relicensed and upgraded rather than retired.
Little new conventional hydro is added in the US, but several projects are in development, chiefly new pumped-storage facilities, powering existing non-powered dams, and turbine uprates. EIA-860 lists those proposed units here under “In development.”
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 FERC licensing records for pumped storage projects EIA does not yet carry, and by Oak Ridge National Laboratory’s Existing Hydropower Assets database for FERC project numbers, licence dates and 21 small plants absent from EIA. EIA notes that preliminary monthly capacities are estimates and may be revised, and that a small number of plants may be withheld pending validation. Plants below 1 MW are not part of EIA-860.
Hydropower is the original American renewable, and the map still reflects the great dam-building eras of the 20th century. Capacity concentrates dramatically in the Pacific Northwest, where the Columbia and its tributaries host Grand Coulee, the largest power plant in the United States by capacity, alongside dozens of other federal dams. Secondary clusters follow the Tennessee, Colorado and the rivers of California, New York and the Southeast.
At roughly 102 GW of active capacity, hydro is a quiet heavyweight, and it plays two distinct roles. Conventional dams provide low-cost, flexible, carbon-free generation that operators can ramp on demand. Pumped-storage plants pump water uphill when power is cheap and release it through turbines when it is dear. In effect, they are the largest grid batteries ever built, and their value is rising as solar and wind grow. Few new large dams will be built, so hydro’s future lies in upgrading existing plants and expanding pumped storage. See how that complements solar and gas in our analysis of the changing grid.
Almost nothing gets built. No pumped storage plant of any scale has been completed in the United States since Rocky Mountain came online in Georgia in 1995. In January 2026 FERC licensed the 1,200 MW Goldendale project in Washington, the first original licence for a plant of that magnitude in twelve years, and even that took five and a half years to review, allows up to two more to finalise plans and four or five to build. Three other licensed projects on this map have never broken ground: Eagle Mountain in California has held a licence since 2014 and has had its construction deadline extended twice, most recently to June 2028, Gordon Butte in Montana faces a deadline in December 2026, and Swan Lake North in Oregon has until 2029. Against that, more than $130 billion of pumped storage investment is proposed nationally, and pumped storage remains about 96% of all US utility-scale energy storage capacity.
The pipeline also rests on very few shoulders. Of the 40 projects shown in development here, 19, holding 2,069 MW, belong to Rye Development or its subsidiaries: Goldendale, Swan Lake North, Lewis Ridge in Kentucky, four Army Corps lakes in Mississippi and eleven lock-and-dam retrofits in Pennsylvania and West Virginia. Three more are preliminary-permit filings by a single company, Premium Energy Holdings, and two others are Eagle Mountain and Gordon Butte, licensed for a decade and still unbuilt. Copenhagen Infrastructure Partners owns Goldendale and Swan Lake North outright and holds equity in Gordon Butte, which is three of the four licensed projects on this map. The fourth, Eagle Mountain, belongs to NextEra Energy. So every licensed pumped storage project in the country sits with one Danish fund manager or one Florida utility holding company. So the question of whether US pumped storage gets built is, to a surprising degree, a question about a handful of companies.
The regulatory fact that shapes this fleet is relicensing, not construction. A FERC licence runs for a fixed term, and when it expires the operator must win a new one. Around 13.5 GW of the active capacity mapped here, roughly 13% of the fleet, is running on a licence that has already expired, including Castaic at 1,682 MW since 2022 and Northfield Mountain at 1,168 MW since 2018. Brownlee and Hells Canyon share a licence that expired in July 2005 and have been in relicensing for twenty-one years. This does not mean those plants are operating unlawfully or are at risk: FERC issues annual licences that let a plant run while relicensing proceeds, and the process routinely takes decades. A further 76 plants totalling almost 7.8 GW see their licences expire within five years. Where this map knows a plant's FERC project number and licence expiry, both are given in its profile.
One licence often covers several plants, which is why the same project number repeats down the table. Of the 1,187 plants here with a docket, 386, about a third, share a licence with at least one other plant, under just 124 project numbers. Duke Energy's Catawba-Wateree project P-2232 covers twelve powerhouses across the Carolinas; Alabama Power's Coosa River project P-2146 covers seven; the Hells Canyon Complex P-1971 covers Brownlee, Oxbow and Hells Canyon together. Relicensing therefore happens at the scale of a river system rather than a single dam, which is part of why it takes so long. It also means the expired-licence figures above are concentrated in fewer proceedings than the plant count suggests: 203 plants are covered by 129 expired licences, and the single largest, California's State Water Project licence P-2426, carries Castaic, Devil Canyon and Warne, just over 2 GW between them.