Wind Electric Power Generation in the United States

NAICS 2022 — 221115 · An investor primer for public-market and private investors

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1. Overview

Wind Electric Power Generation is the business of owning and running wind farms — turbines that convert wind into electricity and deliver it into the grid. It is one of the largest, fastest-grown pieces of the U.S. power system: wind supplied about 10% of all U.S. electricity in 2024 and roughly 11% in 2025 [5][6]. Yet as a business classification it is small and asset-heavy — a lot of steel and capital, very few employees. The U.S. Census Bureau counts only about 109 firms and $14.2 billion of receipts under this exact code [1].

Investors should care because wind is now mainstream infrastructure — cheap to run, capital-intensive to build, and unusually driven by two things outside the wind itself: federal tax credits and interest rates. Both public and private investors can own it. Public-market investors buy shares of the utilities and independent power producers that own wind fleets, or a wind-themed fund. Private investors buy the wind farms directly (through infrastructure funds or project vehicles), lend to them, or finance them by purchasing their tax credits. This primer covers both routes, leads with our authoritative federal statistics, and flags where each number comes from.

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2. What it is and how it's structured

North American Industry Classification System (NAICS) code 221115 covers establishments primarily engaged in operating wind-powered generating facilities whose electricity flows into transmission or distribution systems [1][4]. It sits inside the Utilities sector (22) → Electric Power Generation (22111), where each fuel has its own code.

The code is narrower than "the wind industry." It captures only the operation of the wind farm. It excludes the rest of the value chain that investors often lump in:

Small turbines serving a single farm or campus ("distributed wind") also fall outside the code when the power is not sent to the grid [4]. This is why "wind" employment estimates vary so wildly: the U.S. Department of Energy (DOE) counts about 125,580 jobs across the whole wind value chain (2023), versus roughly 9,000–9,500 employees in the generation code itself [7][2].

Ownership mix — mostly private, mostly for-profit. Unlike hydroelectric dams (largely federal), wind grew up in competitive markets financed by private capital and tax credits. Of U.S. wind capacity in 2024, independent power producers (IPPs — merchant or contracted generators, not traditional utilities) owned about 82%, regulated electric utilities about 18%, and commercial/industrial owners a fraction of a percent [5]. A more detailed 2021 breakdown put private/non-utility owners at 80.5%, investor-owned utilities (IOUs — shareholder-owned regulated utilities) at 18.6%, municipal "public power" at 0.6%, cooperatives at 0.3%, and federal owners below 0.1% [9]. In short, roughly 99% of wind capacity is privately owned; government and cooperative bodies mostly buy wind under contract rather than own turbines.

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3. How big it is

Our authoritative federal figures (U.S. Census Bureau):

Two things stand out. First, the industry is enormous in assets but tiny in headcount — 611 sites and about 9,000 workers run roughly a tenth of the nation's electricity. That is the defining financial feature: near-zero fuel cost, minimal labor, almost all cost sunk up front in capital. Second, only 109 firms own the whole fleet, and many operate dozens of single-farm limited-liability companies (LLCs) — hence 611 establishments under 109 firms.

A caution on the revenue figure. The Census generally excludes government-owned establishments, so municipal, cooperative and federal wind is under-counted. And much wind revenue flows through project LLCs and tax-credit sales that a single census line does not fully capture. So treat $14.24 billion (2022) as the authoritative federal receipts figure, while noting the physical footprint is far larger than that number alone implies.

Physical scale (from the U.S. Energy Information Administration, EIA — the utility-side data, broader than the Census business code): The U.S. had about 153 GW (gigawatts) of nameplate wind capacity in 2024, rising toward 160 GW by early 2026 [5][8]. The fleet generated about 452 TWh (terawatt-hours) in 2024 and ~464 TWh in 2025 [5][6]. The U.S. Geological Survey's turbine database logs about 77,379 turbines across 45 states [10]. The fleet's average capacity factor — actual output divided by theoretical maximum — was about 33% in 2024 [5]. New additions have been lumpy: roughly 5.1 GW added in 2024 (a decade low), with EIA projecting a rebound to ~11.8 GW in 2026 as developers race a tax-credit deadline (see §5) [8].

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4. The investable universe

There are very few "pure-play" listed wind companies. Most public exposure comes bundled inside larger utilities or renewable platforms, so the wind is one line in a bigger business. Private ownership — infrastructure funds, pensions and private developers — controls a large share of the fleet.

Public-market names (valuations as of mid-2026 where dated):

Market caps other than NextEra are not separately sourced here; the ~$184–190 bn NEE figure is the one company-documented value [11]. Foreign owners of large U.S. fleets — Iberdrola (Spain, parent of Avangrid), Ørsted and EDP (Europe), RWE (Germany), Enel (Italy) — trade on home exchanges or as depositary receipts.

Funds: For diversified exposure, the First Trust Global Wind Energy ETF (FAN) is the wind-focused exchange-traded fund (ETF) — but only ~15% of its holdings are U.S., and it mixes owners with turbine makers [15]. Broad clean-energy funds (e.g., ICLN) and utility funds (e.g., XLU, which holds NEE and AES) are the alternatives.

Major private / other owners: Invenergy (private, Chicago — reports 34+ GW developed across 200-plus projects; backed by Blackstone and Canada Pension Plan capital) [16]; Pattern Energy (private, ~12 GW installed; owner of the ~3,650-MW SunZia project) [17]; Clearway Energy Group (private sponsor, ~4.5 GW of wind) [18]; plus infrastructure investors such as Brookfield, Global Infrastructure Partners (within BlackRock), Copenhagen Infrastructure Partners, KKR and Macquarie. Municipal utilities (e.g., Los Angeles Department of Water and Power) and cooperatives (e.g., Basin Electric) own scattered projects but are mostly offtakers who buy wind under contract [9].

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5. How the money works

Wind is a fixed-cost, near-zero-marginal-cost business — the fuel is free, so once built, almost all revenue drops toward the bottom line. There are two very different economic models depending on who owns the farm.

(a) Rate-regulated (utility-owned) wind. When a regulated utility builds and owns a wind farm, the plant enters the utility's rate base (the pool of capital regulators let it earn on). The utility recovers its operating costs and depreciation from customers, plus an authorized return on equity (ROE) — the profit margin regulators allow on the equity portion of the asset. Allowed ROEs typically run ~9.5%–11%; NextEra's Florida Power & Light, for example, proposed a 10.95% ROE in its 2026 framework [18]. The economic engine is simple: more approved capital invested → bigger rate base → more earnings. Returns are bond-like and predictable, but hinge on the state public utility commission (PUC).

(b) Competitive / merchant + contracted wind (most of the fleet). IPPs sell power under long-term power purchase agreements (PPAs — fixed-price contracts with a utility or corporation) or into wholesale markets. Their revenue is a stack of:

• Energy sales — via PPA or at market prices. Recent PPA offers ran roughly $35/MWh in the wind-rich central U.S. to ~$65/MWh in California in late 2023, and North American wind PPA prices rose ~14% in 2024 as grid-connection backlogs gave developers pricing power [18][20].
• Renewable energy certificates (RECs) — a tradable proof that 1 MWh of clean power was produced.
• Capacity payments — in markets that have them, wind is paid for a derated (reduced) share of its nameplate, because it can't be counted on at peak.
• Federal tax credits — often the single biggest value driver (below).

A key merchant risk is "capture price" erosion: wind blows hardest at the same time across a region, flooding the local market and pushing prices — sometimes negative — exactly when a wind farm is producing. In 2023 the average value wind actually captured ran as low as ~$13/MWh in the Southwest Power Pool and ~$17/MWh in the Midcontinent market, versus ~$36/MWh in New England and ~$60/MWh in California [18]. High-wind regions also curtail (switch off) surplus wind; curtailment averaged ~4.6% across organized markets in 2023 [18]. (These regions — SPP, MISO, ERCOT in Texas, PJM in the mid-Atlantic, ISO-NE, NYISO, CAISO — are the independent grid operators that run wholesale power markets.)

Costs. Wind's all-in installed cost has held near $1,700 per kilowatt since 2018, and unsubsidized levelized cost of energy (LCOE — lifetime cost per unit of output) is about $49–50/MWh, up from ~$38 in 2021 on higher rates and equipment costs — still among the cheapest new generation in windy regions [18][19].

The tax-credit linchpin. Federal credits often make or break a project:

• Production Tax Credit (PTC, now the "clean electricity" Section 45Y credit): for 2025, $30/MWh for the first 10 years of output if a project meets prevailing-wage and apprenticeship (PWA) labor rules — only $6/MWh without them [21]. On a typical merchant project the PTC can rival the value of the physical power sold.
• Investment Tax Credit (ITC, Section 48E): an upfront credit worth 6% of project cost as a base, 30% with PWA, plus possible +10% bonuses for domestic content or building in an "energy community." Developers pick PTC (favors high-output projects) or ITC (favors high-cost projects, e.g., offshore) — not both [21].
• The 2025 cliff. The One Big Beautiful Bill Act (OBBBA, signed July 4, 2025) sharply shortened the runway: to keep the 45Y/48E credits, a wind project generally must begin construction on or before July 4, 2026 (or be in service by end-2027) [22]. Internal Revenue Service (IRS) Notice 2025-42 makes a "physical work" test the main way to lock in that start date; the old 5%-spending shortcut is largely unavailable for wind. New "prohibited foreign entity" rules (from 2026) add supply-chain diligence to preserve credits [22][23]. This is the single most important forward variable — it is driving a 2025–26 construction rush and a likely slowdown after 2027.

Financing. Because a developer often can't use all its own credits, it monetizes them. In traditional tax equity, an investor funds a big share of the project and takes ~99% of the tax benefits plus some cash; banks are ~80% of that market. Since 2023, credits can also simply be sold for cash ("transferability") — a market estimated around $25 billion in 2024 [25]. Tax-exempt owners (municipal utilities, cooperatives) can instead take the credit as a direct cash payment ("elective/direct pay") [24].

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6. What drives demand

1. Electricity demand is rising again. After two flat decades (~0.1%/yr, 2005–2019), U.S. power demand grew ~1.7%/yr from 2020–2025, and EIA projects ~1.9% in 2026 and ~2.5% in 2027 — driven by data centers/artificial intelligence, electrification of cars and heating, and reshored manufacturing [30]. Wind is a cheap way to add supply.
2. Corporate clean-power buying. Hyperscalers (Amazon, Microsoft, Google, Meta) and other corporations sign large wind PPAs; corporate and retail buyers took ~48% of newly installed wind in 2023 [18].
3. State mandates. As of December 2025, 28 states plus D.C. had mandatory renewable portfolio standards (RPS) requiring rising clean-energy shares — baseline demand independent of federal policy [29].
4. Cost competitiveness — onshore wind's LCOE remains low in windy regions [19].
5. Tax incentives (while they last) pull demand forward (§5).

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7. Regulation

Wind sits at the intersection of federal energy rules, federal tax rules and state utility rules.

• Federal Energy Regulatory Commission (FERC): regulates wholesale power sales, transmission and grid interconnection. Two rules matter most: Order No. 1920 (2024) requires 20-year regional transmission planning — critical because the best wind is far from cities and stuck in queues; and Order No. 2023 reforms the interconnection queue. The backlog is severe: about 366 GW of wind (including 120 GW offshore) was waiting to connect at end-2023, and only 14% of projects that entered queues from 2000–2018 ever reached operation [26][27][28].
• State Public Utility Commissions (PUCs): approve utility-owned wind, set the allowed ROE, and rule on whether costs enter rate base — they largely decide who builds and how it's recovered [18].
• U.S. Environmental Protection Agency (EPA): light touch for wind itself (no combustion emissions) — mainly construction stormwater and Clean Water Act wetland permits. EPA's pressure on fossil-fuel generators indirectly helps wind's relative economics.
• U.S. Treasury / IRS: arguably the most important regulator of wind economics, since it administers the PTC/ITC and the 2025 construction-start rules (§5).
• Bureau of Ocean Energy Management (BOEM) / Interior Department: lease and permit offshore wind — the focus of intense 2025 policy risk (§9).
• U.S. Fish and Wildlife Service: issues eagle "incidental take" permits; siting, wildlife and local zoning are recurring permitting hurdles.
• Nuclear Regulatory Commission (NRC): not applicable to wind — it governs nuclear generation (NAICS 221113). Noted only to mark the boundary.

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8. Competitive dynamics and consolidation

The federal data show a concentrated industry: the top 4 firms earn 62.4% of industry revenue, the top 8 80%, and the top 50 99.6% — out of just 109 firms [1]. (A precise Herfindahl-Hirschman concentration index is suppressed in the federal data [1].) Project ownership is fragmented across hundreds of single-farm LLCs, but the capabilities that win — development pipelines, tax appetite, turbine-supply leverage, cheap capital — are concentrated in a few large sponsors led by NextEra.

• Scale advantages are real: bigger portfolios get better turbine and maintenance pricing, pooled spare parts, geographic diversification, and better access to tax-equity and debt markets. Projects above 200 MW show measurably lower per-unit cost [18].
• Turbine supply is concentrated: in 2023, GE Vernova supplied ~58% of U.S. installations, Vestas ~30%, Nordex ~9%, Siemens Gamesa ~4% [18]. That concentration creates warranty, parts and single-design-defect risk across a fleet.
• Consolidation is active. Iberdrola completed a full buyout of Avangrid in 2024, taking it private under its Spanish parent. A busy secondary market moves operating farms from developers to yieldcos, pensions and infrastructure funds. (One of the two research reports also cites an announced 2026 NextEra–Dominion combination described as creating the world's largest electric utility; this is single-source and should be verified before relying on it.)

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9. Risks

1. Tax-credit cliff (policy risk #1): the OBBBA construction-start deadline (July 4, 2026) and 2027 in-service cutoff threaten post-2027 new-build economics; losing credit eligibility removes value comparable to a project's power revenue [22].
2. Federal permitting / political risk — concentrated offshore: in January 2025 the administration withdrew all Outer Continental Shelf areas from new offshore-wind leasing; in December 2025 it paused five East Coast projects (Vineyard Wind, Revolution Wind, Coastal Virginia, Sunrise, Empire) on national-security grounds and moved to terminate several undeveloped leases [31]. A federal court vacated the January "Wind Order" as arbitrary in December 2025, but appeals and uncertainty persist [32].
3. Interest-rate sensitivity: wind is extremely capital-intensive, so higher rates directly raise its cost and squeeze equity returns — a key cause of recent PPA-price increases and offshore cancellations [19].
4. Interconnection and transmission bottlenecks: multi-year queues strand projects; reform is slow [27][28].
5. Capture-price / curtailment risk: more wind in a region depresses the prices wind itself earns, and can force shut-offs [18].
6. Resource variability and degradation: low-wind years cut revenue; a median project's output in year 20 is about 70% of its year-2 output [18].
7. Offshore execution risk: U.S. offshore is far costlier — New York's 2024 Empire Wind 1 / Sunrise awards priced around $150/MWh, several times land-based wind — with vessel, port, cable and construction risk on top [33].
8. Counterparty and merchant-tail risk: long PPAs turn commodity risk into credit risk, and valuations that lean on optimistic post-contract "merchant tail" assumptions can disappoint.

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10. How to invest, and the outlook

Two ways in.

• Public-market investors get exposure mainly through diversified owners: NextEra (NEE) for scaled, premium-priced utility growth; Xcel (XEL) for regulated wind in rate base; and yieldcos like Clearway (CWEN) and Brookfield Renewable (BEP/BEPC) for bond-like contracted income (yields ~4.4%–5.4%) that is sensitive to interest rates [11][12][13][19]. A wind ETF (FAN) or clean-energy/utility funds give diversified but more volatile exposure [15]. For yieldcos, judge the distribution coverage and project debt, not just the headline yield.
• Private / infrastructure investors buy operating wind farms or platforms directly (the core strategy of Brookfield, KKR, Copenhagen Infrastructure Partners and pensions), lend to projects, or invest purely financially by funding tax equity or buying transferable tax credits at a discount — a multibillion-dollar market with defined, relatively low-risk returns and no turbines to operate [25]. Municipal and cooperative buyers increasingly participate via long-term PPAs and, now, direct-pay credits [24].

Valuation character. Regulated wind (inside NEE, XEL) is valued on rate-base growth and price-to-earnings (P/E ~22–23× for NEE and XEL) [11][12]. Contracted wind (CWEN, BEP) is valued on cash yield and long-term PPA cash flows (~4.4%–5.4%) [13][19]. No reliable public "market yield" exists for direct private wind assets — those trades are confidential, so treat any single quoted return skeptically.

Outlook — a build-out sprint, then a question mark. Near term (2025–2027) is a policy-driven rush: developers are racing to start construction before the July 2026 deadline, and EIA expects onshore additions to more than double to ~11.8 GW in 2026 [8][22]. After 2027, if credits lapse, expect a slower, more geographically selective onshore market — though projects that lock in credits keep earning them for their full 10-year window. Offshore is the wildcard: strong resources near coastal demand, but federal policy has stalled the pipeline, so offshore should be underwritten as a high-risk, policy-dependent megaproject business, not a scaled extension of Texas wind [31][32][33].

The synthesis: wind is a mature, cash-generative, capital-heavy infrastructure business with genuinely improving demand fundamentals (data centers, electrification) — but it is carrying elevated policy and rate risk at exactly the moment demand is strengthening. The best-positioned owners are those with the lowest cost of capital, the deepest tax-credit-monetization capability, and PPAs and construction starts locked in before the 2026–2027 deadlines.

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Sources

1. U.S. Census Bureau, 2022 Economic Census — NAICS 221115 Wind Electric Power Generation (receipts $14.240 bn; 109 firms; concentration ratios CR4 62.4% / CR8 80% / CR20 96.1% / CR50 99.6%; HHI suppressed), 2024. https://data.census.gov/table/ECNBASIC2022.EC2200BASIC
2. U.S. Census Bureau, County Business Patterns 2023 — NAICS 221115 (611 establishments; 9,251 employees; $1.454 bn annual payroll), 2025. https://www.census.gov/programs-surveys/cbp.html
3. U.S. Small Business Administration, Table of Small Business Size Standards (NAICS 221115 = 1,150 employees), effective March 17, 2023. https://www.sba.gov/federal-contracting/contracting-guide/size-standards
4. U.S. Census Bureau, 2022 NAICS Manual — Sector 22 / 221115 definition and adjacent codes; U.S. DOE, Distributed Wind Market Report: 2024 Edition. https://www.census.gov/naics/reference_files_tools/2022_NAICS_Manual.pdf
5. U.S. Energy Information Administration (EIA), Electric Power Annual 2024 — ~153.5 GW nameplate / 152.1 GW net-summer wind; 451.9 TWh generation; ~33.4% capacity factor; producer-type ownership (IPP 81.8% / utilities 18.1% / commercial-industrial 0.1%), 2025. https://www.eia.gov/electricity/annual/
6. EIA, Wind and solar generated a record share of U.S. electricity in 2025 — wind ~464 TWh (~11%), 2026. https://www.eia.gov/todayinenergy/detail.php?id=67367
7. U.S. Department of Energy, Wind Market Reports: 2024 Edition — ~125,580 wind-sector jobs (2023, whole value chain). https://www.energy.gov/cmei/systems/wind-market-reports-2024-edition
8. EIA, capacity-additions coverage — ~5.1 GW wind added 2024; ~11.8 GW planned 2026 (of ~86 GW total additions), 2024–2026. https://www.eia.gov/todayinenergy/detail.php?id=67205
9. American Public Power Association, 2023 Public Power Statistical Report (EIA-860 data, 2021: non-utility 80.5% / IOU 18.6% / public power 0.6% / cooperative 0.3% / federal <0.1%; municipal & cooperative owners), 2023. https://www.publicpower.org/system/files/documents/2023-Public-Power-Statistical-Report.pdf
10. U.S. Geological Survey, U.S. Wind Turbine Database — 77,379 turbines across 45 states, 2026 release. https://www.usgs.gov/faqs/how-many-turbines-are-contained-us-wind-turbine-database
11. NextEra Energy, 2024 Form 10-K (NEER ~20,977 MW net wind / 26,335 MW gross; world's largest renewables generator; 2024 revenue $24.8 bn) and market data (market cap ~$184–190 bn; ~22.7× earnings; ~2.8% yield, July 2026). https://www.sec.gov/Archives/edgar/data/753308/000075330825000011/nee-20241231.htm; https://stockanalysis.com/stocks/nee/
12. Xcel Energy, 2025 Form 10-K (~11,000 MW wind: 4,496 MW owned + 6,504 MW contracted; ~$60 bn 2026–30 capital plan) and market data (~22.8× earnings; ~3.0% yield). https://www.sec.gov/Archives/edgar/data/72903/000007290326000009/xel-20251231.htm; https://stockanalysis.com/stocks/xel/
13. Clearway Energy, 2025 Form 10-K (~10.1 GW wind/solar/storage; ~12-yr avg contract life) and market data (~5.4% yield, July 2026). https://www.sec.gov/Archives/edgar/data/1567683/000162828026010952/cwen-20251231.htm; https://stockanalysis.com/stocks/cwen/statistics/
14. Berkshire Hathaway Energy, 2024 Form 10-K — ~12,659 MW net-owned wind, 2025. https://www.sec.gov/Archives/edgar/data/1936737/000108131625000004/bhe-20241231.htm
15. First Trust Portfolios, First Trust Global Wind Energy ETF (FAN) — 47 holdings, 0.60% expense ratio, ~15% U.S., data through July 2026. https://www.ftportfolios.com/etf/FAN
16. Invenergy, Projects Overview — 34+ GW developed across 200-plus projects (private; Blackstone / CPP Investments capital), accessed 2026. https://invenergy.com/projects/overview
17. Pattern Energy, About — ~12 GW installed across ~46 facilities; SunZia ~3,650 MW / 916 turbines, accessed 2026. https://patternenergy.com/about/
18. U.S. DOE / Lawrence Berkeley National Laboratory, Land-Based Wind Market Report: 2024 Edition (installed cost ~$1,700/kW; unsubsidized LCOE ~$49/MWh; 2023 PPA offers ~$35/MWh central U.S. to ~$65/MWh California; capture prices; curtailment ~4.6%; year-20 output ~70% of year-2; OEM shares GE 58% / Vestas 30%; corporate procurement ~48% of 2023 additions); FPL 10.95% proposed ROE, 2024–2026. https://eta-publications.lbl.gov/sites/default/files/2024-09/land-based_wind_market_report_2024_edition.pdf
19. Lazard, Levelized Cost of Energy+ (June 2024) — unsubsidized onshore wind ~$50/MWh (up from ~$38 in 2021); Brookfield Renewable yield ~4.4% / 5–9% distribution-growth guidance. https://www.lazard.com/media/xemfey0k/lazards-lcoeplus-june-2024-_vf.pdf; https://stockanalysis.com/stocks/bepc/dividend/
20. LevelTen Energy, PPA Price Index — North American wind PPA prices +~14% year-over-year in 2024. https://www.leveltenenergy.com/ppa
21. Internal Revenue Service, Clean Electricity Production Credit (§45Y) and Investment Credit (§48E) — 2025 rates: PTC $30/MWh with PWA ($6/MWh base); ITC 6% base / 30% with PWA plus bonuses. https://www.irs.gov/credits-deductions/clean-electricity-production-credit; Internal Revenue Bulletin 2025-38.
22. One Big Beautiful Bill Act analyses (Sidley Austin; Winston & Strawn) and IRS Notice 2025-42 — 45Y/48E terminate for wind placed in service after 2027 unless construction begins by July 4, 2026; physical-work test is the principal begin-construction method, 2025. https://www.sidley.com/en/insights/newsupdates/2025/07/the-one-big-beautiful-bill-act-navigating-the-new-energy-landscape
23. IRS, Guidance on Material Assistance from Prohibited Foreign Entities (Notice 2026-15), 2026. https://www.irs.gov/newsroom/treasury-irs-provide-guidance-for-certain-energy-tax-credits-regarding-material-assistance-provided-by-prohibited-foreign-entities-under-the-one-big-beautiful-bill
24. IRS, Elective Pay and Transferability FAQs, accessed 2026. https://www.irs.gov/credits-deductions/elective-pay-and-transferability-frequently-asked-questions-overview
25. Crux Climate / ACORE and Reunion Infrastructure, transferable-credit and tax-equity market sizing (~$25 bn transferable in 2024; total transferable market ~$45–50 bn; banks ~80% of tax equity), 2024. https://www.cruxclimate.com/insights/tax-equity-clean-energy-credits; https://www.reunioninfra.com/insights/how-big-is-the-transferable-tax-credit-market
26. FERC, Order No. 1920 — Transmission Planning and Cost Allocation Final Rule, May 2024. https://www.ferc.gov/explainer-transmission-planning-and-cost-allocation-final-rule
27. FERC, Order No. 2023 — Interconnection Final Rule. https://www.ferc.gov/explainer-interconnection-final-rule
28. Lawrence Berkeley National Laboratory, Queued Up: 2024 Edition — ~366 GW wind (incl. 120 GW offshore) in interconnection queues end-2023; 14% completion rate for 2000–2018 entrants, 2024. https://emp.lbl.gov/publications/queued-2024-edition-characteristics
29. EIA, Renewable Portfolio Standards — 28 states + D.C. with mandatory RPS, updated December 2025. https://www.eia.gov/energyexplained/renewable-sources/portfolio-standards.php
30. EIA, U.S. electricity demand growth accelerates — ~1.7%/yr 2020–2025 vs 0.1%/yr 2005–2019; ~1.9% (2026), ~2.5% (2027), 2026. https://www.eia.gov/todayinenergy/detail.php?id=67344
31. Bureau of Ocean Energy Management / U.S. Department of the Interior — January 2025 OCS offshore-leasing withdrawal; December 2025 pause of Vineyard Wind, Revolution Wind, Coastal Virginia, Sunrise and Empire; lease terminations, 2025–2026. https://www.doi.gov/pressreleases/trump-administration-protects-us-national-security-pausing-offshore-wind-leases
32. Congressional Research Service, Offshore Wind Leasing and Permitting / court vacatur of the January 2025 "Wind Order" as arbitrary and capricious, December 8, 2025. https://www.congress.gov/crs-product/LSB11402
33. New York State Energy Research and Development Authority, Empire Wind 1 and Sunrise Wind awards — weighted-average all-in cost ~$150.15/MWh, February 2024. https://www.nyserda.ny.gov/About/Newsroom/2024-Announcements/2024_02_29-Governor-Hochul-Announces-Two-Offshore-Wind-Project_Awards

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Prepared July 2026. Core NAICS 221115 business statistics (receipts, firms, establishments, employment, payroll, concentration, SBA size standard) are Histometrics-ingested U.S. Census Bureau / SBA figures and take precedence over third-party estimates. Physical-capacity, generation, ownership-mix, price, tax and market figures are drawn from the cited federal, company and research sources with reference years noted. Forward-looking statements in §10 are analytical judgments, not guarantees.