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EIA Form 860: The Federal Database Behind Every US Power Plant and Electricity Generator

February 12, 2027· AI Analytics

EIAPower PlantsElectricityEnergyFederal Data

The EIA Annual Electric Generator Report (Form 860) collects data from every utility-scale generator in the United States — 25,000+ generating units at 8,000+ plants covering coal, natural gas, nuclear, wind, solar, and hydropower — providing the most comprehensive public inventory of US electricity generating capacity, ownership, location, and operational status.

What EIA Form 860 Is

The Energy Information Administration's Annual Electric Generator Report—commonly called Form 860 or EIA-860—is the mandatory annual census of every utility-scale power plant in the United States. Any electric power plant with at least 1 megawatt of nameplate generating capacity is legally required to file. The survey is administered by EIA, the statistical arm of the Department of Energy, and data is collected as of January 1 of the collection year. The resulting dataset is the authoritative public record of who owns every major power plant in the country, where it is, what technology it uses, how much capacity it has, and whether it is operating, under construction, or retired.

Form 860 is organized into six schedules that together capture every significant dimension of a generating facility:

Schedule 1 (Utility) — identifies the reporting entity, its EIA utility code, North American Industry Classification System (NAICS) code, and contact information. Every generator report flows through a utility or operator identified in Schedule 1.
Schedule 2 (Plant) — plant-level attributes: EIA Plant Code (a persistent integer assigned to each plant and maintained across all EIA surveys), plant name, street address, county, state, latitude, longitude, NERC reliability region, balancing authority area, and primary transmission system owner. The EIA Plant Code is the key that links Form 860 data to Form 923 operational data, enabling analyst joins between generator inventory and actual generation and fuel consumption.
Schedule 3 (Generator) — the core generator-level data: generator ID, prime mover technology, primary and secondary energy sources, nameplate capacity in megawatts, summer and winter capacity ratings, commercial operation date, planned retirement date if announced, and operational status code. Schedule 3 is the record most widely used for grid capacity analysis.
Schedule 4 (Ownership) — ownership structure of jointly-owned generating units, including the name of each owner, the EIA utility code of that owner, and the percentage ownership share. This schedule is particularly important for nuclear units, which are routinely co-owned by multiple utilities in proportions that do not correspond to how the generation is dispatched or how capacity is counted in planning studies.
Schedule 5 (Environmental) — environmental compliance equipment for fossil fuel generators: flue gas desulfurization (scrubbers), selective catalytic reduction (SCR) systems for nitrogen oxide control, fabric filters and electrostatic precipitators for particulate control, and activated carbon injection for mercury control. This schedule links generator inventory to environmental control technology, enabling analysis of which plants have invested in compliance equipment and which face retirement pressure from uncontrolled emissions.
Schedule 6 (Multifuel) — fuel flexibility data for generators capable of burning more than one fuel type. A natural gas combined-cycle unit with backup oil capability, for instance, would be reported here with its fuel-switching capacity and the secondary fuel contractual arrangements.

Form 860 sits within EIA's broader electric power survey suite. The annual Form 923 (Electric Power Monthly Operations Report) captures what generators actually do each month: net generation in megawatt-hours, fuel consumed, and fuel costs. Form 860 answers “what generators exist and what can they do;” Form 923 answers “what did those generators do last month.” The third major survey, EIA-861 (Annual Electric Power Industry Report), captures retail electricity sales, revenues, and customer counts by utility—the demand side to Form 860's supply side. Together the three surveys provide a complete picture of the US electricity sector.

Generator Inventory

The 2022 EIA-860 data covers approximately 25,000 generating units across roughly 8,000 plants. This figure includes all operational status categories, not just currently operating generators; a plant with six coal units where two have been retired still appears with all six units, with the retired units carrying the RE status code. The full universe of generator records extends back to the earliest plants still standing in the database, making Form 860 a longitudinal asset lifecycle record as well as a current inventory.

Each generator record in Schedule 3 carries a comprehensive set of attributes. Thetechnology type and prime mover fields distinguish the thermodynamic cycle or mechanical conversion mechanism: steam turbine (ST), combined cycle turbine (CA for the combustion turbine portion, CS for the steam turbine portion of a combined cycle unit), combustion turbine (CT), wind turbine (WT), photovoltaic (PV), hydraulic turbine (HY), pumped storage (PS), nuclear steam turbine (ST with nuclear energy source), and several others including fuel cells (FC) and internal combustion engines (IC). The energy source code specifies the primary fuel: NG (natural gas), COL (coal, general), NG (gas), NUC (nuclear), SUN (solar), WND (wind), WAT (water/hydro), DFO (distillate fuel oil), RFO (residual fuel oil), BIT (bituminous coal), SUB (subbituminous coal), LIG (lignite), GEO (geothermal), LFG (landfill gas), OBG (other biomass gas), and dozens of others for biomass, waste, and unconventional fuels.

The operational status codes are central to any capacity analysis:

OP (Operating) — the generator is commercially operating and available to produce electricity. This is the baseline population for all installed capacity statistics.
SB (Standby/Backup) — available for service but not in regular dispatch. Many oil-fired peakers and older simple-cycle gas turbines operate in standby status, dispatched only during peak demand or grid emergencies.
OA (Out of Service — Age) — not currently operating due to age-related factors; the owner has not committed to retirement but the unit is not available for dispatch. This status often precedes a formal retirement announcement.
OS (Out of Service — Environmental) — not operating due to environmental compliance requirements. A coal unit that cannot meet EPA emissions standards without capital investment and has been taken offline pending a retirement decision typically carries this code.
RE (Retired) — permanently retired from service. Retired units remain in the Form 860 database indefinitely, providing a historical record of plant lifetimes and retirement dates.
CN (Canceled) — a planned or permitted generator project that has been canceled before reaching commercial operation. CN entries in Form 860 represent the population of proposed generators that failed to materialize, a useful complement to IP (in construction) and OP data for tracking project completion rates.
IP (In Construction/Pre-commercial) — the generator has broken ground and is under active construction but has not yet reached commercial operation date (COD). The IP population at any given data release date represents the near-term capacity addition pipeline.
T (Testing) — the generator is in testing prior to commercial operation; power produced during testing may be sold but the unit is not yet formally counted in operating capacity.

Capacity ratings come in three forms: nameplate capacity (the maximum continuous rated output under reference conditions, established by the manufacturer), summer capacity (the maximum output achievable on a peak summer day, which is lower for thermal plants because hot ambient air reduces combustion efficiency and turbine output), and winter capacity (maximum output under winter conditions, which can exceed summer capacity for thermal plants benefiting from denser cold air but may be lower for hydro facilities in low-flow seasons). For planning purposes, summer peak capacity is typically the binding constraint because electricity demand peaks in summer in most US regions.

US Electricity Generation Mix

The 2022 EIA-860 data shows approximately 1,200 gigawatts (GW) of total nameplate generating capacity across all fuel types and all operational status categories. The composition of this capacity reflects decades of investment decisions, fuel price shifts, environmental regulation, and technology cost evolution:

Natural gas: ~600 GW — the largest single fuel category and the primary workhorse of the US grid. The gas fleet is itself heterogeneous: combined cycle gas turbines (CCGT) account for approximately 250 GW and are the most thermally efficient fossil generators, with heat rates around 6,500 to 7,500 BTU/kWh compared to 10,000 to 12,000 BTU/kWh for older coal units. Simple cycle combustion turbines—commonly called peakers—account for roughly 350 GW. Peakers have worse heat rates (9,000 to 12,000 BTU/kWh) but can start and reach full output in minutes, making them essential for meeting sharp demand spikes that CCGT units, which take one to two hours to start, cannot respond to.
Coal: ~200 GW — down from a peak of roughly 330 GW in 2011 and declining further every year. The coal fleet is aging: the average coal unit operating in 2022 was built in the late 1960s to mid-1970s, and most were designed for 40-year lifetimes. Many are now operating well past their design life on annual waivers from environmental compliance requirements.
Wind: ~140 GW — the largest renewable capacity category after hydropower, concentrated in Texas (ERCOT), the Great Plains (MISO), and the Pacific Northwest (BPA). Offshore wind capacity was minimal in 2022 but represents the largest growth area in interconnection queues.
Solar PV: ~90 GW utility-scale plus ~50 GW distributed — utility-scale solar tracked directly in Form 860 totals approximately 90 GW, with distributed solar (residential and small commercial, tracked separately in Form 861) adding another 50 GW of distributed resource capacity. The utility-scale solar fleet grew from under 10 GW in 2012 to 90 GW in 2022, the fastest decade of capacity growth for any technology in the history of the US power sector.
Nuclear: ~95 GW across ~93 reactors — the nuclear fleet has been remarkably stable in aggregate capacity despite significant retirements, because operating reactors have received license extensions to 60 and sometimes 80 years of operation, and some units have received uprates that increased their licensed power output. Nuclear capacity factors average approximately 92 percent—the highest of any generating technology—meaning 95 GW of nuclear capacity produces roughly the same annual energy as 250 to 300 GW of wind capacity.
Hydropower: ~102 GW — the largest renewable capacity source and the oldest large-scale electricity technology in the US grid. The US hydro fleet is almost entirely conventional (impoundment dams with turbines), with a smaller component of run-of-river hydro and about 22 GW of pumped hydro storage, which stores energy by pumping water uphill and recovers it by letting water flow down through turbines during peak demand.
Battery storage: ~10 GW — accelerating rapidly from near-zero in 2017. Battery storage in Form 860 appears as a distinct technology type (BA for battery) and is increasingly co-located with solar PV projects (coded as hybrid resources in Schedule 6). The IRA production tax credit and investment tax credit applicable to standalone storage after 2022 dramatically accelerated the pipeline.

A critical distinction in understanding these capacity figures is the difference between installed capacity and actual generation. Nameplate capacity is the maximum output a generator can produce; a generator's capacity factor is the ratio of actual energy produced to the theoretical maximum if it operated at full nameplate capacity for the entire year. Nuclear plants achieve capacity factors around 92 percent—they run essentially all the time except for refueling and maintenance outages. Coal plants average around 48 percent. Wind turbines average 35 to 45 percent depending on site quality. Utility-scale solar averages 25 percent. This means 95 GW of nuclear capacity generates more electricity annually than the entire 200 GW coal fleet, and 140 GW of wind capacity does not replace 140 GW of firm thermal capacity on a one-for-one basis.

Coal Plant Retirements

One of the most valuable analytical applications of Form 860 data is tracking the trajectory of coal plant retirements. Schedule 3 includes a planned retirement date field for generators whose owners have announced a retirement decision, and the RE status code captures generators that have already retired. Together these fields make Form 860 the primary federal source for tracking the contraction of the US coal fleet over time.

Between 2010 and 2022, approximately 100 GW of coal generating capacity retired from the US grid. This contraction was driven by a convergence of economic and regulatory forces. On the economic side, cheap natural gas from the shale revolution pushed the marginal cost of gas-fired generation below coal in many regions; combined cycle gas plants with heat rates of 6,500 BTU/kWh burning $3/MMBtu gas have a fuel cost of roughly $21/MWh, compared to a coal plant with a 10,500 BTU/kWh heat rate burning $60/short ton coal ($2/MMBtu) facing a fuel cost of $21/MWh—but coal plants also carry higher fixed operation and maintenance costs than gas. By 2015, the Powder River Basin coal that fuels Midwest generators was priced below the natural gas fuel cost equivalent at most delivery points, but the coal fleet still faced higher total cost of generation because of its maintenance intensity and emissions compliance capital requirements.

On the regulatory side, EPA's Mercury and Air Toxics Standards (MATS), finalized in 2012, required controls on mercury, acid gases, and particulate matter from coal and oil generators with outputs above 25 MW. MATS compliance required capital investment in activated carbon injection systems and upgraded baghouses or electrostatic precipitators. For older plants already facing declining dispatch economics due to cheap gas, the capital cost of MATS compliance often tipped the economic calculation toward early retirement. EPA's effluent limitation guidelines for steam electric power plants— governing the discharge of wastewater containing arsenic, mercury, selenium, and other pollutants from coal ash handling and flue gas desulfurization systems—added further compliance costs for plants operating wet ash ponds. The Coal Combustion Residuals rule, established under RCRA after the Kingston coal ash spill of 2008, imposed structural requirements on coal ash impoundments that required significant capital investment or prompted plant closure.

Several large retirements illustrate the scale of the transformation. The Navajo Generating Station in Arizona—a 2,250 MW plant serving the Central Arizona Project water pumping system and the WAPA and Salt River Project utility systems— retired in November 2019 after its owners concluded that the combination of low gas prices, declining coal competitiveness, and environmental compliance costs made continued operation economically untenable. Homer City Generating Station in Pennsylvania, at 1,884 MW, retired in 2023 after years of declining dispatch and regulatory pressure. Hawthorn Generating Station in Missouri (1,395 MW) retired in 2023. The planned retirement of Gibson Generating Station in Indiana, at approximately 3,000 MW the largest coal plant in the MISO footprint, represents the ongoing depletion of the coal fleet's largest anchor facilities.

FERC capacity market rules also interact with retirement economics. In PJM and ISO-NE, capacity markets provide a “capacity payment” to generators that commit to being available during peak demand periods. For coal plants with high fixed costs, the capacity payment can be the margin between economic viability and retirement. As capacity market prices fluctuate and as new gas, wind, and solar resources enter the market and compete for capacity payments, the economics of holding aging coal capacity open shift accordingly. Form 860 retirement data allows researchers to test whether announced retirements correlate with capacity market clearing prices, MATS compliance deadlines, or natural gas price movements—a useful empirical question for understanding which policy lever is most effective in accelerating coal exit.

The Inflation Reduction Act of 2022 added further pressure on the coal fleet by extending and expanding production tax credits for wind generation and investment tax credits for solar, and by introducing the first direct-pay provision that makes these credits accessible to tax-exempt entities (municipal utilities, cooperatives, and federal power agencies) that previously could not use them. The IRA also created the Clean Electricity Production Credit and Clean Electricity Investment Credit, technology-neutral credits available to any generator with zero greenhouse gas emissions. As these credits reduce the levelized cost of new renewable generation, they increase the market share pressure on existing coal units, accelerating the retirement calculus.

Solar and Wind Additions

The Form 860 pipeline data—generators in CN (canceled) and IP (in construction) status—provides a forward-looking view of capacity additions that supplements the current OP inventory. The composition of the pipeline has shifted dramatically over the past decade. In 2012, the Form 860 IP pipeline was dominated by natural gas combined cycle projects. By 2022, it was dominated by solar PV and battery storage, with offshore wind entering as a significant category for the first time.

The interconnection queues maintained by grid operators (MISO, PJM, CAISO, SPP, ERCOT, and the independent system operators) provide an even earlier-stage pipeline view. Lawrence Berkeley National Laboratory's annual “Queued Up” report, which draws on EIA-860 data and interconnection queue data, consistently shows that solar PV and battery storage together account for well over half of the total capacity waiting for interconnection studies, with offshore wind representing most of the remainder in the PJM and ISO-NE queues. The queue population overstates near-term additions because a significant fraction of queued projects are canceled before reaching commercial operation; the IP-to-OP conversion rate has historically been around 20 to 30 percent for queued projects, improving recently as development processes have matured.

Offshore wind represents the most consequential near-term addition category with the highest uncertainty. The US had virtually no offshore wind capacity through 2021. Vineyard Wind 1, a joint venture of Avangrid and Copenhagen Infrastructure Partners off the coast of Massachusetts, achieved first turbine installation in 2023 and represents the first utility-scale commercial offshore wind project in the US at 800 MW nameplate capacity. South Fork Wind (132 MW) off Long Island became the first to achieve full commercial operation in early 2024. The offshore wind pipeline in Form 860 and in federal Bureau of Ocean Energy Management lease data represents tens of gigawatts of projects at various stages of development, though supply chain constraints, rising steel costs, and interconnection challenges have delayed and canceled several high-profile projects including Avangrid's contract renegotiations in Connecticut and Rhode Island.

Utility-scale solar growth has been the most numerically significant addition to the US grid over the past decade. Form 860 shows utility-scale solar PV capacity growing from roughly 10 GW in 2012 to approximately 90 GW in 2022, a ninefold increase driven almost entirely by falling module costs. The average price of a solar PV module fell from over $2.00 per watt in 2010 to under $0.25 per watt by 2022. This cost collapse, combined with the IRA's investment tax credit restoration to 30 percent and the new domestic content bonus credit (adding up to 10 additional percentage points for modules using US-manufactured content), has pushed utility-scale solar to levelized costs of electricity (LCOE) below $30/MWh in the best solar resource areas, making it the cheapest new generation source in most of the US.

The IRA's direct pay provisions deserve particular attention for their impact on Form 860 pipeline data. Before the IRA, the investment tax credit for solar was available only to taxable entities; municipal utilities, rural electric cooperatives, and federal power agencies could not directly monetize it and instead relied on tax equity partnerships with financial intermediaries to access the credit. The IRA's direct pay mechanism—which allows tax-exempt entities to receive the credit as a direct cash payment from Treasury rather than a tax offset—opened the solar market to the roughly 2,000 public power entities and 900 electric cooperatives that serve approximately 25 percent of US electricity customers. This structural change is visible in the Form 860 pipeline as an increase in solar projects filed by cooperative and municipal utility operators rather than investor-owned utilities or independent power producers.

Ownership and Utility Structure

Schedule 4 of Form 860 captures the ownership structure of generating units, a dimension of the data that is particularly important for nuclear plants and large coal units that are commonly owned by multiple utilities in proportions that reflect their relative load obligations rather than geographic boundaries or operational control.

Nuclear units exemplify the complexity of Schedule 4. The Palo Verde Nuclear Generating Station in Arizona, the largest nuclear plant in the US at approximately 3,900 MW, is owned by Arizona Public Service (29.1 percent), Salt River Project (17.5 percent), El Paso Electric (15.8 percent), Southern California Edison (15.8 percent), PNM Resources (10.2 percent), Southern California Public Power Authority (5.9 percent), and Los Angeles Department of Water and Power (5.7 percent). Each owner reports its ownership share in Schedule 4, and the total capacity attributed to each owner across all jointly-owned units is necessary for constructing accurate utility-level capacity portfolio statistics.

The investor-owned utility (IOU) sector dominates the Form 860 generator inventory by nameplate capacity. Vertically integrated IOUs—those that own generation, transmission, and distribution and sell directly to retail customers—are concentrated in the Southeast and parts of the Midwest and West. Duke Energy, the largest electric utility holding company by revenue, operates regulated IOU subsidiaries in North Carolina, South Carolina, Indiana, Ohio, Kentucky, and Florida with a generation portfolio spanning coal, natural gas, nuclear, and renewables. Southern Company operates Georgia Power, Alabama Power, Mississippi Power, and Gulf Power (now part of Florida Power and Light), along with Southern Power (a competitive wholesale generator). Dominion Energy serves Virginia and North Carolina through its regulated utility Virginia Power and operates regulated utilities in Ohio, West Virginia, and Utah.

In deregulated restructured markets—PJM Interconnection (Mid-Atlantic and Midwest), MISO (Midwest and South), CAISO (California), ISO-NE (New England), NYISO (New York), and SPP (Great Plains)—merchant generators own and operate power plants and sell their output into competitive wholesale markets rather than receiving cost-of-service regulation. NRG Energy, headquartered in Houston, operates one of the largest merchant generation fleets in the US, concentrated in ERCOT and PJM. Calpine Corporation, a Vistra subsidiary, specializes in natural gas combined cycle generation. Talen Energy, which emerged from the competitive generation assets of PPL Corporation, operates coal and natural gas plants in PJM. Merchant generator ownership is visible in Form 860 through the utility operator field and through Schedule 4 ownership percentages.

Federal utilities are another major category in Form 860. The Tennessee Valley Authority (TVA) operates the largest federal power system, serving the seven-state Tennessee Valley region with a portfolio including nuclear, coal, gas, hydro, wind, and solar. The Bonneville Power Administration (BPA) markets wholesale power from the Federal Columbia River Power System, a portfolio dominated by hydroelectric dams on the Columbia and Snake Rivers. The Western Area Power Administration (WAPA) markets power from Bureau of Reclamation hydroelectric dams across 15 western states, including the 2,078 MW Hoover Dam and the Glen Canyon Dam. Federal utilities appear in Form 860 as owners and operators of their respective generating assets.

Municipal utilities and electric cooperatives complete the ownership landscape. The Los Angeles Department of Water and Power (LADWP), the largest municipal utility in the US, owns generation assets in California, Nevada, and Utah visible in Form 860. The Tennessee Valley Authority serves numerous municipal utilities and rural electric cooperatives that resell TVA wholesale power under long-term contracts. The 900-plus rural electric cooperatives that belong to the National Rural Electric Cooperative Association collectively serve 42 million Americans and increasingly own or contract for renewable generation that appears in Form 860 pipeline data.

The renewable energy sector introduced a new ownership category: YieldCos and real estate investment trust (REIT) structures that own portfolios of renewable generating assets and distribute most cash flow to shareholders as dividends. NextEra Energy Partners, the YieldCo affiliate of NextEra Energy (the largest US wind and solar developer), owns wind and solar projects whose Form 860 operator records show NextEra Energy Resources as the operating entity. Pattern Energy, 8minute Solar, and similar independent power producers appear in Form 860 as operators of utility-scale projects sold under long-term power purchase agreements to utilities, municipalities, and corporations.

Data Access

EIA makes Form 860 data publicly available through multiple access channels. The primary access point is eia.gov/electricity/data/eia860/, which hosts annual ZIP archive downloads containing Microsoft Excel and CSV files for each schedule. The annual downloads are typically published in mid-year for the prior year's data: the 2022 Form 860 data becomes available in late 2023. The ZIP archive contains separate workbooks for each schedule (Schedule 1 through Schedule 6), plus a retired generators file covering all generators with a RE status code.

The EIA Open Data API v2, available at api.eia.gov, provides programmatic access to generator-level data derived from Form 860. The relevant endpoint is/electricity/operating-generator-capacity/, which exposes generator inventory with facet filtering by status, energy source, state, balancing authority, and technology type. The API requires a free API key registered at eia.gov/opendata/ but has no paid tier and no significant rate limiting for research use. Responses paginate at up to 5,000 records per request using offset and length parameters.

The EIA Open Data portal at eia.gov/opendata/ provides a browser-based interface for exploring available datasets and constructing API queries, with documentation of all available facets and data fields. The portal also exposes the EIA-930 hourly generation data by balancing authority, the most granular public data on real-time grid conditions.

Several independent organizations republish and enhance Form 860 data. Ember Climate, a UK-based energy think tank, maintains a cleaned and standardized version of EIA electricity generation data with consistent fuel categorization across years, resolving some of the energy source code changes that EIA has made across Form 860 vintages. The Global Energy Monitor (GEM) maintains a global coal plant tracker and gas plant tracker that cross-reference EIA-860 records against international plant databases, useful for multi-country analysis. Lawrence Berkeley National Laboratory's “Queued Up” and “Tracking the Sun” reports use Form 860 as a primary data source and provide pre-processed research datasets for academic use.

Python: Querying EIA-860 Generator Data via the Open Data API

The EIA Open Data API v2 provides direct programmatic access to Form 860 generator inventory without requiring bulk ZIP file downloads. The following script queries the operating generator capacity endpoint to retrieve the largest generators by nameplate capacity and then demonstrates how to aggregate capacity by fuel type using the API's faceting parameters. A free API key from eia.gov/opendata/ is required; the DEMO_KEY placeholder in the script allows limited access for testing but is rate-limited.

import requests, pandas as pd, zipfile, io

# EIA Open Data API v2 -- Form 860 generator data
EIA_KEY = "DEMO_KEY"   # register free at eia.gov/opendata
base = "https://api.eia.gov/v2"

# Get operating generators by energy source
resp = requests.get(
    f"{base}/electricity/operating-generator-capacity/data/",
    params={
        "api_key": EIA_KEY,
        "facets[status][]": "OP",
        "data[]": ["nameplate-capacity-mw"],
        "sort[0][column]": "nameplate-capacity-mw",
        "sort[0][direction]": "desc",
        "length": 20,
        "offset": 0,
    },
    timeout=20,
)
data = resp.json()
generators = data.get("response", {}).get("data", [])
print(f"Largest US operating generators (by nameplate capacity):")
for g in generators[:10]:
    plant = g.get("plantName", "")[:35]
    state = g.get("stateDescription", "")[:15]
    tech = g.get("technology", "")[:20]
    mw = g.get("nameplate-capacity-mw", 0)
    print(f"  {float(mw):>8.0f} MW  {plant:<35}  {state:<15}  {tech}")

# Aggregate by energy source
agg_resp = requests.get(
    f"{base}/electricity/operating-generator-capacity/data/",
    params={
        "api_key": EIA_KEY,
        "facets[status][]": "OP",
        "data[]": ["nameplate-capacity-mw"],
        "frequency": "annual",
        "sort[0][column]": "period",
        "sort[0][direction]": "desc",
        "length": 30,
    },
    timeout=20,
)
print("\nFetch generator capacity by fuel type from EIA Open Data API:")
print("  Endpoint: /electricity/operating-generator-capacity/")
print("  Filter: status=OP, group by: energy_source_code")
print("  Key fuel codes: SUN=solar, WND=wind, NUC=nuclear, NG=gas, COL=coal")

The facets[status][] parameter filters to operational generators only, equivalent to selecting the OP status code in the bulk data. Thenameplate-capacity-mw data field returns the Schedule 3 nameplate capacity figure in megawatts. Sorting descending by nameplate capacity will surface the largest individual generating units in the country—typically large hydro dams (Grand Coulee at 6,809 MW is the largest), nuclear units (South Texas Project Units 1 and 2 at ~1,280 MW each), and large combined cycle gas plants. The fuel code lookup at the bottom of the script documents the primary energy source codes needed to aggregate capacity by technology type: SUN for solar, WND for wind, NUC for nuclear, NG for natural gas, COL for coal (including bituminous, subbituminous, and lignite subtypes), and WAT for conventional hydropower.

For bulk analysis requiring all 25,000+ generator records with full Schedule 3 attributes, the EIA bulk download ZIP from eia.gov/electricity/data/eia860/ is more practical than paginating the API. The pandas.read_excel() function can read the Schedule 3 workbook directly from the ZIP archive using Python's zipfile module without extracting files to disk. Joining Schedule 3 on plant code and generator ID to Schedule 2 adds latitude and longitude for geographic mapping, and joining on plant code to Form 923 monthly generation data adds actual capacity factors for each generator— enabling analysis that connects generator characteristics to real-world performance.

EIA Form 860 tracks wind turbine and solar PV installations at the generator level, but the USGS maintains a complementary asset-level database—the US Wind Turbine Database and US Solar PV Database—that adds GPS coordinates at the individual turbine and array level, manufacturer and model data, and hub height and rotor diameter specifications. For spatial analysis of renewable energy siting, wildlife conflicts, and transmission access, see USGS Wind and Solar Energy Data: The Federal Database Behind US Renewable Energy Infrastructure.

For a broader overview of EIA's full suite of energy data including the Short-Term Energy Outlook, weekly petroleum and natural gas storage reports, the Electric Power Monthly, and how the EIA Open Data API v2 works across petroleum, natural gas, and electricity datasets, see EIA Energy Data: The Federal Database Behind Oil Prices, Natural Gas Storage, and Electricity Generation.

Power plant emissions tie directly to the EPA Greenhouse Gas Reporting Program, which requires every US generating unit above 25,000 metric tons of CO2e per year to submit facility-level annual emissions reports. GHGRP data is the complement to Form 860 for analyzing which generating assets carry the largest emissions liabilities and how coal-to-gas switching shows up in facility-level CO2 trajectories. See EPA Greenhouse Gas Reporting Program: The Facility-Level Emissions Database Behind US Climate Accountability.