Electric Power Generation in the United States

NAICS 2022 code 22111 — a rollup investor primer for public-market and private investors

This is the "make the electricity" layer of the U.S. power sector — the eight fuel-and-technology industries that together produce the nation's power, before it is moved (transmission, 221121) or delivered (distribution, 221122). Core business statistics (revenue, firms, establishments, employment, concentration) are our authoritative ingested U.S. Census figures for NAICS 22111; physical capacity and generation come from the U.S. Energy Information Administration (EIA) as cited. NAICS = North American Industry Classification System; a "5-digit industry" like 22111 groups the eight related 6-digit industries beneath it.

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1. Overview

Everything else in the power system depends on this layer: eight industries that convert a primary energy source — falling water, burning gas or coal, splitting atoms, sunlight, wind, underground heat, or organic fuel — into electricity fed to the grid [1]. Together they book about $146.3 billion of counted (private-sector) revenue across roughly 1,228 firms and 4,192 plant sites, employing about 134,570 people [2][3]. That headcount is strikingly small for an industry that runs the entire U.S. electricity supply — the signature of a capital-heavy, asset-intensive business where a handful of technicians can run a plant worth hundreds of millions.

The reason to look at this level rather than the whole utility sector is contrast. These eight children are not variations on one business — they are opposites bundled under one code. One is 59% of the nation's power and cash-rich (fossil); one is a fifth of it and newly strategic (nuclear); two are growing fast and driven by tax policy (solar, wind); two are large but effectively closed to private buyers because governments own them (hydro, and a slice of nuclear); two are tiny niches, one slowly dying (biomass) and one a rounding error (geothermal); and the last is a statistical placeholder standing in for the fastest-growing thing in energy — grid storage. They differ on size, growth direction, who owns them, how concentrated they are, and whether the money comes from a regulator or a market. A top-down "utilities" summary averages all of that away. This primer leads with the differences, then covers the group.

Two ways in, common to every child. Public-market investors buy the utilities, merchant generators, and renewable platforms that own the plants — but there is no pure-play public stock for any single fuel (the closest is Ormat in geothermal); every listed owner is a mixed fleet. Private investors — infrastructure funds, private equity, direct developers, and public-power/municipal bodies — buy the plants, portfolios, tax credits, or project debt directly. Which route fits depends almost entirely on which child you are buying.

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2. What's inside — the eight children, and how they differ

The whole point of this level is the spread across the eight. Here they are, ranked by counted (Census) revenue, with the contrasts that matter.

*Share of the group's counted Census revenue [2]; per-child figures are each industry's 2022 Economic Census receipts. Generation share is the more reliable gauge of real-world size and is shown alongside because Census revenue undercounts the government-heavy children (see §3).

Five contrasts stand out:

• Size is lopsided. Fossil and nuclear together are 82% of counted revenue and ~77% of the electricity. The four renewables plus storage — the whole "energy transition" — are under 20% of revenue today, though they are where nearly all the growth is.
• Direction of travel points in opposite directions. Solar, wind, and storage are expanding fast; natural gas is re-rating up on data-center demand; coal, biomass, and (in capacity terms) hydro are flat-to-declining; nuclear is flat in megawatts but rising in strategic value. A single "sector" call would be wrong on half the group.
• Ownership flips the investability. Renewables, gas, and geothermal are overwhelmingly private / independent-power — the plants trade. Hydro and a fifth of nuclear are government and public-power — most of the fleet is not for sale at any price, which is why the Census revenue for those two badly understates them (§3). Biomass is unusual again: nearly half sits inside pulp/paper mills as behind-the-meter cogeneration.
• Concentration ranges from oligopoly to fragmentation. Geothermal is highly concentrated (top 4 firms = 83.6% of revenue; Herfindahl-Hirschman Index, a 0–10,000 concentration score, ~2,055) and nuclear nearly so (top 4 = 61.9%), while fossil is highly fragmented (top 4 = 16.2%; HHI ~181). At the rollup level the group is unconcentrated — top 4 firms just 24.2% of revenue, HHI 274.4 [2] — a number that hides both extremes.
• The economic engine differs. Regulated children earn a set return on invested capital set by a state commission; merchant children earn volatile market revenue. Most children contain both models (see §5), but the mix varies — hydro and nuclear lean regulated-plus-federal, solar/wind/geothermal/storage lean contracted-merchant.

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3. Size — the rollup figures, and a reconciliation worth understanding

Our authoritative Census figures for NAICS 22111 (the counted, private-sector industry):

A useful check on these numbers: the rollup reconciles almost exactly against the eight children. Employment (134,570), establishments (4,192), and payroll ($18.18B) are the sums of the children's County Business Patterns figures, and revenue ($146.3B) is the sum of their Economic Census receipts — dominated by fossil (58%) and nuclear (24%) [2][3]. The one figure that does not simply add up is the firm count: 1,228 at the rollup versus ~1,331 summed across the children — because a company that owns, say, gas and nuclear and solar plants is counted once here but in three child industries. That gap is a direct measure of how diversified the big owners are, and it is why the listed "pure play" almost never exists.

The undercount caveat — concentrated in two children. The Census business surveys generally exclude government-owned establishments [4]. That barely matters for solar, wind, or geothermal (government owns under 1% of those). It matters enormously for hydroelectric (~73% federal and public power) and materially for nuclear (~a fifth public, led by the federal Tennessee Valley Authority, TVA) [7][9]. So the $146.3B counts the private industry well but understates the true economic footprint of the water and atom fleets specifically. There is no official consolidated total that adds government generation back in; treat that combined figure as not available rather than estimating it. The physical-generation shares in the §2 table are the honest cross-check — hydro is only ~3% of counted revenue but ~6% of the electricity, precisely because most of it is public and off the Census books.

Physical scale (EIA, 2024), the more reliable gauge of the real industry: the U.S. fleet is about 1,230 GW of capacity producing roughly 4,300 TWh a year [5] (GW = gigawatt = 1,000 megawatts; TWh = terawatt-hour = 1 billion kilowatt-hours). Fossil supplies ~59% of that generation, nuclear ~18–19%, wind ~10%, hydro ~6%, solar ~5%, biomass ~1.1%, geothermal ~0.4% [5].

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4. The investable universe — where the value concentrates

Two facts govern the whole group. First, there is no pure-play public stock for any fuel except geothermal (Ormat). Every listed generator is a mixed fleet — which is exactly what the firm-count reconciliation in §3 predicts. Second, a large share of the physical fleet is not listed at all — it sits with federal agencies, public-power authorities, cooperatives, and private infrastructure funds.

Where public-market value concentrates. A small set of names recurs across the children, and they cluster into three profiles:

• Merchant / independent power producers (IPPs) — the torque names, valued on cash flow and capacity prices, low or no dividend. Constellation (CEG) (largest U.S. nuclear operator, ~55 GW after buying Calpine), Vistra (VST), NRG (NRG), Talen (TLN) — these appear in the fossil, nuclear, and storage chapters at once [child primers]. They re-rated sharply upward in 2024–2026 on rising demand and record capacity prices.
• Renewable platforms and yieldcos — contracted cash flow, higher dividend. NextEra (NEE) (the world's largest wind and solar owner and the largest U.S. battery owner, wrapped around regulated Florida Power & Light), Brookfield Renewable (BEP/BEPC) (the most direct listed hydro exposure, plus wind/solar/storage), Clearway (CWEN), Xcel (XEL), AES (AES).
• Regulated utilities — bond-proxy income, ~3–4% yields, earnings that grow with invested capital. Southern (SO), Duke (DUK), Dominion (D), IDACORP (IDA) (the most hydro-levered), AEP, Ameren. Nuclear, hydro, gas, and coal all sit inside these rate bases.

There is no pure-play exchange-traded fund (ETF) for any of these fuels; the broad utility funds (XLU, VPU) hold the mix but scope you into transmission and distribution too [child primers].

Where private, government, and public-power value concentrates (not buyable on an exchange):

• Federal and public power — the largest owners of the water and atom fleets. The U.S. Army Corps of Engineers and Bureau of Reclamation (hydro), the federal TVA (nuclear, gas, and hydro), the Power Marketing Administrations (e.g., Bonneville), New York Power Authority, and large municipal utilities and public utility districts. Investors reach these only through municipal and revenue bonds, not equity [7][9].
• Private infrastructure and private equity — the natural owners of the merchant and contracted fleets: LS Power, ArcLight, Energy Capital Partners, Brookfield, Global Infrastructure Partners (now BlackRock), KKR, EQT, Macquarie, Invenergy (largest private renewables developer), Pattern Energy, Arevon, and many more. Private capital has been the buyer in the sector's biggest recent deals — Constellation/Calpine (~$26.6B), NRG's ~13 GW gas purchase from LS Power (~$12B), EQT's Covanta/Reworld (~$5.3B) [child primers].
• Cooperatives and industrial self-generators — rural cooperatives (Basin Electric) and, in biomass, the pulp-and-paper mills that generate ~45% of biomass power behind the meter.

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5. How the money works — one shared logic, two engines

Under the fuel differences, every child runs on the same two economic models; the group's variety is mostly how much of each model a given fuel uses.

Engine A — the regulated (cost-of-service) model. Where a plant sits inside a state-regulated utility, it earns rate base × allowed return. The utility's prudent invested capital (net of depreciation) is its rate base; a state Public Utility Commission (PUC) sets an allowed return on equity (ROE) — clustered near 9.5–10% across recent 2024–2026 decisions in California, Idaho, and elsewhere — and customer rates recover operating costs, fuel, depreciation, taxes, plus that return [child primers]. Cash flows are bond-like. The growth lever is capital spending: build or refurbish an approved plant and earnings rise at the allowed ROE. This is how regulated hydro, nuclear, gas, coal, and utility-owned solar/wind earn. The risk is disallowance — a commission can refuse to let overruns into rate base (Plant Vogtle's nuclear cost ballooned from ~$14B to ~$35–37B, and shareholders absorbed part of it) [child primers].

Engine B — the merchant / contracted model. Uncontracted plants sell into wholesale markets run by regional grid operators (independent system operators / regional transmission organizations, ISO/RTO). Revenue is a stack: energy ($/MWh), capacity payments (getting paid to be available), ancillary services, renewable energy credits (RECs), and — increasingly the anchor — long-term power purchase agreements (PPAs), many now signed directly with data-center operators. The single biggest recent development across the merchant fleet is the capacity-price surge: PJM's (the largest market's) capacity price jumped from $28.92 to $269.92/MW-day for 2025/26 and reached the $325/MW-day cap for 2028/29 — roughly $118,600 per MW-year for simply being available, and worth the most to already-built, dispatchable capacity (gas and nuclear) [child primers].

The shared cost signature: no fuel for most, capital everywhere. Six of the eight children (all but fossil and biomass) have near-zero fuel cost — the money is spent up front to build, and the plant then runs cheaply. That makes the whole group unusually interest-rate-sensitive: higher rates raise the cost of the capital that is the business and compress every valuation.

The tax-credit lever — and the sharpest fault line in the group. The 2022 Inflation Reduction Act (IRA) created technology-neutral clean-electricity credits — the Section 45Y production credit and Section 48E investment credit (up to 1.5¢/kWh or 30% of cost with wage/apprenticeship compliance), both transferable for cash and available as direct "elective pay" to tax-exempt public owners [child primers]. But eligibility now splits the children apart:

• Excluded: unabated fossil (coal, gas, oil) never qualified — the credits' effect there is purely competitive.
• On a cliff: wind and solar must generally begin construction by July 4, 2026 (or be in service by end-2027) under the 2025 budget law (the "One Big Beautiful Bill Act") — driving a 2026–27 construction rush and a likely slowdown after.
• Preserved through ~2033: hydro, geothermal, nuclear, and storage kept full eligibility even as wind and solar were curtailed — a durable advantage for the firm, dispatchable technologies.
• Special cases: nuclear also has the Section 45U production credit (up to $15/MWh through 2032), which works as a price floor that ended premature reactor retirements; biomass often cannot claim 45Y/48E because combustion is not automatically zero-emission on a lifecycle basis.

So the credit regime is now actively reshaping the group: it subsidizes the firm-clean children and the near-term renewables build, taxes fossil by comparison, and sets a 2027 policy cliff that is the single most important forward variable for wind and solar.

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6. Demand drivers

After roughly 15 years of flat U.S. electricity demand, load is inflecting up — the change that re-rated much of this group since 2024. The drivers are shared:

• Data centers and artificial intelligence (AI). Lawrence Berkeley National Laboratory estimates data centers used ~4.4% of U.S. electricity in 2023, rising toward 6.7–12% by 2028 (and up to ~15% by 2030) — much of it wanting 24/7 firm power, which favors gas, nuclear, geothermal, hydro, and storage over bare wind and solar [child primers].
• Broad demand growth. EIA projects ~0.9–1.6%/year through 2050 and a 50–90% increase in generating capacity to meet load and replace retirements [child primers].
• Electrification and reshoring — electric vehicles, heat pumps, and new chip/battery factories add large concentrated loads.
• Corporate 24/7 carbon-free procurement — hyperscalers signing directly with generators: Brookfield–Google (up to 3,000 MW of hydro), Constellation–Microsoft and Constellation–Meta (nuclear restarts and uprates), Meta and Google contracting geothermal, and large wind/solar PPAs.
• State clean-energy mandates — 28 states plus D.C. have renewable/clean-energy standards, creating baseline demand for the renewable children independent of federal policy.

The common counter-forces: efficiency, rooftop solar, and the real risk that forecast data-center load is delayed or double-counted — the two-sided swing factor behind every bull case in the group.

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7. Regulation

Every child answers to an overlapping set of regulators, but the binding one differs by fuel:

• State PUCs are the profit-and-loss statement for the regulated slice of every child — they set rate base, ROE, and cost recovery, and can disallow.
• The Federal Energy Regulatory Commission (FERC) governs wholesale markets, interstate transmission, the capacity auctions that now dominate merchant economics, and grid interconnection — the binding constraint on new solar, wind, and storage, where queues hold well over 1,000 GW with multi-year waits. FERC also licenses non-federal hydro (relicensing is its biggest hydro workload and the key valuation event).
• The U.S. Treasury / IRS is arguably the most consequential regulator for solar, wind, geothermal, and storage — it administers the 45Y/48E/45U credits, transferability, and the sourcing rules (§5).
• The Environmental Protection Agency (EPA) is the swing regulator for fossil (greenhouse-gas, mercury, and coal-ash rules that eased in 2025–26) and a lighter touch elsewhere.
• The Nuclear Regulatory Commission (NRC) governs only nuclear (221113) — licensing, renewals, restarts. It is the moat (new competitors are nearly impossible to permit) and the main cost center for that child, and it is not applicable to any of the other seven.
• Specialist regulators attach to individual children: the Bureau of Land Management (geothermal's dominant landlord), the Bureau of Ocean Energy Management (offshore wind), the Fish and Wildlife Service and Clean Water Act (hydro and wind siting), and the federal statutes governing the Corps, Reclamation, and TVA (which insulate the federal hydro/nuclear fleet from FERC relicensing but expose it to federal budgets).

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8. Consolidation

The group is fragmented at the rollup (HHI 274) but consolidating within its most valuable segments [2]. Three patterns run in parallel:

• Merchant scale-up. The biggest wave is in gas and nuclear: Constellation bought Calpine (~55 GW combined), NRG bought ~13 GW of gas from LS Power, Talen and CPS Energy bought gas plants — all racing to own existing, interconnected, dispatchable capacity ahead of data-center load and record capacity prices, because new turbines face multi-year backlogs [child primers].
• Infrastructure roll-ups of fragmented fleets. In hydro, biomass, and storage, infrastructure funds consolidate scattered plants to centralize compliance, standardize maintenance, and aggregate output into larger PPAs (Hydro-Québec's Great River Hydro, Ontario Power's Eagle Creek, EQT's Covanta, Macquarie's WIN Waste, LS Power's storage platform).
• A closed frontier for two children. Hydro's best sites were dammed decades ago and no new reservoirs get built; the federal ~half of that fleet is effectively un-contestable. Nuclear cannot add merchant reactors at scale (Vogtle showed why). For both, competition is a race to own and extend existing scarce assets, not to build new ones.

Antitrust and FERC-required divestitures cap how far any single-market concentration can go (Constellation had to sell ~4.4 GW to clear the Calpine deal).

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9. Risks

The group shares a common risk core, with fuel-specific tails:

1. Demand-forecast risk — the biggest two-sided factor. The whole re-rating rests on data-center load landing near consensus. If AI demand disappoints, is delayed, or is double-counted, the merchant valuations across gas, nuclear, and storage unwind.
2. Policy and tax-credit contingency. The 2027 wind/solar cliff, the durability of the hydro/geothermal/nuclear/storage credits through 2033, EPA's fossil-rule whiplash, and 45U's 2032 expiry are all live — and the capacity-price surge itself faces political pushback over higher bills.
3. Interest rates. Because six of eight children are near-zero-fuel and capital-is-the-business, higher rates directly compress valuations and acquisition values across the group.
4. Merchant and commodity volatility. Spark spreads (gas), capture-price erosion and curtailment (wind, solar), ancillary-revenue saturation (storage), and drought (hydro) all inject earnings swings the regulated children are shielded from.
5. Fuel-specific tails. Hydrology/drought (hydro); relicensing, fish mandates, and dam removal (hydro); Vogtle-style new-build overruns, outages, spent-fuel and catastrophic tail risk (nuclear); coal stranding and cleanup liabilities (fossil); interconnection queues (solar, wind, storage); offshore permitting freezes (wind); resource/drilling risk (geothermal); uncompetitive economics and carbon-accounting (biomass); and battery fire/safety plus Chinese-supply-chain tariffs (storage).

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10. How to invest & outlook

The group is best read as a barbell, not a bloc. One end is firm and dispatchable (fossil gas, nuclear, hydro, geothermal, storage); the other is variable and policy-driven (wind, solar). Coal and biomass are a third, declining category. The near-term winners are the firm-clean and gas assets that data centers and capacity markets are paying up for; the near-term risk is concentrated in the wind/solar tax-credit cliff and in offshore wind's policy freeze.

Which parts are attractive vs. at risk (analytical judgment, grounded in the sourced facts):

• Attractive now: owners of existing, interconnected, dispatchable capacity — merchant gas and nuclear (Constellation, Vistra, Talen, NRG) riding record capacity prices; hydro as scarce firm-clean value (Brookfield Renewable, hydro-levered utilities) with credits preserved to 2033; and storage as the structural complement to every new solar megawatt. Geothermal is a small, firm, credit-protected niche with genuine enhanced-geothermal option value (Ormat, Fervo).
• At risk / two-sided: wind and solar carry the strongest demand tailwind but the sharpest policy cliff — a 2026–27 build rush, then a selective, slower market; underwrite the construction-start date. Offshore wind is a high-risk, policy-dependent megaproject business, not a scaled extension of onshore. Coal is a managed runoff; biomass is a defensive, contracted, low-growth niche with a structural cost disadvantage and no listed pure play.

How to get in. Public-market investors choose a profile, not a fuel: merchant IPPs (CEG, VST, TLN, NRG) for torque to load growth and capacity prices; renewable platforms and yieldcos (NEE, BEP/BEPC, CWEN) for contracted-cash-flow income with transition upside; regulated utilities (SO, DUK, D, IDA) for bond-proxy income whose refurbishment and clean-energy capital is now both rate-base- and tax-credit-accretive. Private investors buy the assets the way the industry is actually owned: operating project equity (contracted, infrastructure-like), tax-equity and transferable-credit purchases (a ~$30B+ market at ~90–95 cents on the dollar), project debt, development equity, and public-power municipal bonds for the government-owned hydro and nuclear fleet.

Outlook. After a lost decade of flat demand, electric power generation as a whole has moved from managed maturity to a demand-led expansion — but the eight children are traveling at very different speeds and in different directions. The durable thesis across the group is the scarcity and rising value of firm, already-built, dispatchable capacity meeting suddenly-rising load, with tax policy actively sorting the winners. The single variable that matters most for the whole group is whether data-center demand lands near consensus; the single variable that matters most for its fastest-growing children is the 2027 tax-credit cliff.

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Sources

1. U.S. Census Bureau, 2022 North American Industry Classification System (NAICS) — Sector 22 (Utilities), Industry Group 22111 Electric Power Generation and its eight 6-digit industries, 2022. https://www.census.gov/naics/?details=22111&year=2022
2. U.S. Census Bureau, 2022 Economic Census — Summary Statistics and Concentration Ratios, NAICS 22111 (receipts $146,289,953 thousand; 1,228 firms; CR4 24.2% / CR8 33.7% / CR20 53.4% / CR50 78.7%; HHI 274.4). Histometrics ingested ground-truth statistics. https://data.census.gov/table/ECNBASIC2022.EC2200BASIC
3. U.S. Census Bureau, 2023 County Business Patterns, NAICS 22111 (4,192 establishments; 134,570 employees; annual payroll $18,178,682 thousand; first-quarter payroll $5,559,163 thousand). Histometrics ingested ground-truth statistics. https://www.census.gov/programs-surveys/cbp.html
4. U.S. Census Bureau, Understanding NAICS and Economic Census Coverage (government-owned establishments generally excluded from business statistics), 2022. https://www.census.gov/programs-surveys/economic-census/year/2022/guidance/understanding-naics.html
5. U.S. Energy Information Administration (EIA), Electric Power Annual 2024 (total U.S. capacity ~1,230 GW and generation ~4,300 TWh; shares by source — fossil ~59%, nuclear ~18–19%, wind ~10%, hydro ~6%, solar ~5%, biomass ~1.1%, geothermal ~0.4%), 2025. https://www.eia.gov/electricity/annual/
6. U.S. Census Bureau, 2022 Economic Census, per-industry receipts for NAICS 221111–221118 (fossil $85.5B; nuclear $34.6B; wind $14.24B; solar $5.51B; hydro $4.292B; geothermal $1.14B; biomass $0.948B; other $0.0415B). Histometrics ingested ground-truth statistics; sum reconciles to the 22111 rollup [2]. https://data.census.gov/table/ECNBASIC2022.EC2200BASIC
7. U.S. Department of Energy (DOE) and Oak Ridge National Laboratory, U.S. Hydropower Market / Fleet ownership (hydro ~49% federal, ~24% nonfederal public, ~27% private; federal >40% of capacity), 2015–2026. https://www.energy.gov/eere/water/hydropower-market-report
8. American Public Power Association, Public Power Statistical Report (EIA-860 ownership: solar ~83% non-utility/IPP, ~16% IOU; wind ~82% IPP, ~18% utility), 2023–2026. https://www.publicpower.org/
9. U.S. Energy Information Administration, U.S. Nuclear Plant Ownership (roughly four-fifths shareholder/merchant, one-fifth public/federal/cooperative; TVA the largest government owner), 2025. https://www.eia.gov/nuclear/reactors/ownership.php
10. Internal Revenue Service, Clean Electricity Production Credit (§45Y), Investment Credit (§48E), Zero-Emission Nuclear Credit (§45U), and Elective Pay/Transferability, updated 2026. https://www.irs.gov/credits-deductions/clean-electricity-production-credit
11. U.S. Congress, Public Law 119-21 (One Big Beautiful Bill Act, 2025) and legal analyses (wind/solar 45Y/48E must begin construction by July 4, 2026 or be in service by Dec 31, 2027; hydro, geothermal, nuclear, and storage eligibility preserved through ~2033). https://www.congress.gov/119/plaws/publ21/PLAW-119publ21.pdf
12. PJM Interconnection, Reliability Pricing Model / Capacity Auction Results (2024/25 $28.92 → 2025/26 $269.92 → 2028/29 $325.00/MW-day cap), 2024–2026. https://www.pjm.com/markets-and-operations/rpm
13. Lawrence Berkeley National Laboratory, United States Data Center Energy Usage Report — 2024/2025 Updates (4.4% of U.S. electricity in 2023; 6.7–12% by 2028; up to ~15% by 2030). https://emp.lbl.gov/publications/united-states-data-center-energy
14. Company disclosures and press releases underlying the child primers — Constellation/Calpine, NRG/LS Power, Talen, Vistra, NextEra, Brookfield Renewable, Ormat, Fervo, and others (SEC filings; corporate newsrooms), 2024–2026. https://www.sec.gov/
15. U.S. Small Business Administration, Table of Small Business Size Standards (per-industry employee thresholds for NAICS 221111–221118), effective March 17, 2023. https://www.sba.gov/document/support-table-size-standards

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Prepared July 2026. Core NAICS 22111 business statistics (receipts, firms, establishments, employment, payroll, concentration) are Histometrics-ingested U.S. Census figures and take precedence over third-party estimates; per-child receipts sum to the rollup total. Physical capacity, generation, ownership-mix, tax, and market figures are drawn from EIA, DOE, APPA, IRS, and company filings via the eight child primers, with reference years noted. Where government/municipal ownership dominates (hydroelectric and part of nuclear), federal business statistics undercount the true industry; this is stated rather than estimated around. Forward-looking statements in §10 are analytical judgments, not guarantees.