Electric Bulk Power Transmission and Control (U.S.)

NAICS 2022 code 221121 — an investor primer

North American Industry Classification System (NAICS) code 221121. Figures are U.S., most recent available. Where we have an ingested federal statistic, we use it and label the year; where a number comes from a report's outside source, it is cited to that source.

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1. Overview

Electric transmission is the high-voltage backbone that carries electricity from power plants to the local distribution wires that reach homes and businesses. It is the "interstate highway" of the grid. For investors, the appeal is simple: most transmission is a regulated toll road, not a commodity bet. Owners recover their costs plus an approved return on the capital they invest, set by the Federal Energy Regulatory Commission (FERC). They earn more by building more approved plant — not by selling more power — so cash flows are long-lived, inflation-linked, and largely disconnected from weather or fuel prices. The catch: there is no large U.S. pure-play publicly traded transmission company. Public-market investors get exposure through transmission-heavy regulated utilities (and the contractors that build the lines); private investors — infrastructure funds, sovereign and pension capital, direct developers — increasingly buy stakes in stand-alone transmission companies or build new lines themselves. Both are riding the same tailwind: after two flat decades, U.S. electricity demand is rising again, and the grid needs a historic wave of new capital.

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2. What it is and how it's structured

Scope. NAICS 221121 covers establishments whose primary business is operating high-voltage transmission systems and/or controlling the transmission of electricity — the lines and substations that move bulk power from the generating source to distribution centers or other utilities, plus the "control" role of coordinating and balancing power flows across the grid.[1] FERC generally treats facilities at 69 kilovolts (kV) and above as transmission, though the transmission/distribution line varies by system and state.[2]

What it excludes (and the adjacent NAICS codes):

Three roles that are easy to confuse. In transmission, ownership, operation, and regulation are separate jobs:

• Owners hold the towers, conductors, substations, and rights-of-way.
• Operators — the seven Regional Transmission Organizations / Independent System Operators (RTOs/ISOs) (PJM, MISO, SPP, ISO New England, NYISO, CAISO, and Texas's ERCOT) — dispatch the regional system and run wholesale markets but generally do not own the wires. RTOs/ISOs coordinate roughly two-thirds of U.S. electricity demand; the rest (much of the Southeast, Northwest, and Intermountain West) is run by individual utilities.[3]
• Regulators — chiefly FERC — set the rates and returns.

Ownership mix. Transmission is owned by a patchwork of private and public entities. The most complete federal breakdown is historical — the U.S. Department of Energy's (DOE) 2015 Quadrennial Energy Review estimated asset shares of roughly investor-owned utilities (IOUs) 66%, independent transmission companies 14%, federal entities 7%, other public power 6%, cooperatives 4%, and 3% unclassified.[4] Consolidation has shifted individual positions since, but the shape holds: private, shareholder-owned companies dominate, with a meaningful government, municipal, and cooperative minority. Federal owners include the Tennessee Valley Authority (TVA) and four Power Marketing Administrations (Bonneville, Western Area, Southwestern, Southeastern), which move federally generated hydropower.

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3. How big it is

As a stand-alone Census industry, 221121 looks small — because most transmission assets sit inside vertically integrated utilities that the Census classifies under distribution or generation, and because government-owned systems (TVA, the federal PMAs, municipal utilities, and cooperatives) are largely excluded from the business statistics. The narrow industry therefore captures mainly the stand-alone transmission companies and grid operators.

Our ingested federal statistics for NAICS 221121:

(The 2022 Economic Census counted 319 transmission-primary establishments and $17.63 billion of revenue; CBP's 360 establishments and 20,606 employees are a later, differently defined program. Treat both as the industry's narrow footprint, not the whole transmission system.)

The number investors should actually anchor on is capital deployment, not Census revenue. The physical network is roughly 600,000 miles of transmission line (about 240,000 miles of it high-voltage at 230 kV or more), and more than 70% of those lines are over 25 years old against a ~50-year design life.[8] More than 5,000 circuit-miles of new transmission entered service in 2024 alone.[9] Investor-owned utilities spent about $32.6 billion on transmission in 2024 (the Edison Electric Institute, EEI, tally; the Energy Information Administration's narrower "major IOU" measure was $27.7 billion in 2023) and are projected to invest roughly $178 billion over 2025–2028, with total IOU capital spending (generation + transmission + distribution) near $208 billion in 2025 and about $1.1 trillion across 2025–2029.[10][11][12] That is the real "size" of the opportunity: a multi-hundred-billion-dollar, growing capital sink.

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4. The investable universe

There is no large, U.S.-listed pure-play transmission company. The biggest independent, ITC Holdings, was taken private in 2016. Public investors buy diversified utilities with heavy transmission exposure; private investors buy the pure-play assets directly.

Public-market names (all are diversified regulated utilities, not pure transmission):

Dividend yields and price/earnings for names beyond AEP and FirstEnergy are not in our source set; regulated utilities of this type have historically yielded in the low-single-digit-percent range. Verify live market data before use.

Funds (diversified, not pure transmission): the Utilities Select Sector SPDR (XLU) for broad regulated-utility exposure, and the First Trust NASDAQ Clean Edge Smart Grid Infrastructure ETF (GRID) (~$11.55 billion assets, 0.56% expense ratio, ~0.76% trailing yield), which holds grid equipment and utility names.[16] No U.S. fund is a clean basket of transmission owners.

Major private and other owners:

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5. How the money works

The core engine: rate base × allowed return. A regulated transmission owner earns a revenue requirement roughly equal to:

(Rate base × allowed return) + operating costs + depreciation + taxes.

Rate base is the net value of plant in service (sometimes plus construction in progress). The allowed return is split between the cost of debt and an allowed return on equity (ROE) applied to the equity-funded portion of the assets. Because the owner earns a return on the asset base, the model is: build more approved plant → grow rate base → grow earnings. Owners are paid for prudent capital spending, not for throughput.

Allowed ROE is the single most important number. In an October 2024 order, FERC affirmed a base-ROE method that blends a discounted-cash-flow model with the Capital Asset Pricing Model.[23] Recent base ROEs cluster near 9.5%–10% — MISO transmission owners at ~9.98%, New England at ~9.57% (owners have asked FERC to raise it to 11.39%) — and rise with incentive adders.[24][25] For example, ITC Great Plains was authorized an 11.41% ROE: a 10.66% base plus a 0.25% independent-transco adder and a 0.50% RTO-participation adder.[17] Companies filing today are pushing higher (New York Transco requested 10.90%; San Diego Gas & Electric 11.75%).[23]

Incentives sweeten the economics. Under FERC's Order No. 679, qualifying projects can recover a return on construction work in progress (CWIP) before a line enters service (easing the cash drag of multi-year builds), recover 100% of prudently incurred costs if a project is abandoned for reasons outside the owner's control, and earn ROE adders for RTO membership or forming a stand-alone transco.[26] Most transcos also use formula rates that automatically true up rates to actual costs each year, reducing regulatory lag.[17]

The smaller, riskier segment: merchant transmission. A minority of lines — typically high-voltage direct-current (HVDC) interconnectors between regions with different power prices — are built on a merchant basis. Instead of a guaranteed cost-of-service return, the developer takes market risk and earns through negotiated rates, long-term capacity reservations, or take-or-pay contracts (similar in spirit to a power purchase agreement, PPA) with generators or load.[27] Higher upside, but real demand and financing risk. Grain Belt Express, Champlain Hudson, and SunZia are examples.

Tax credits are a demand subsidy, not a direct benefit. The federal investment tax credit (ITC) and production tax credit (PTC) flow to generation (wind, solar, storage), not to the transmission network itself.[28] They help transmission indirectly, by making the remote renewables that need new lines financeable. Transmission projects instead tap tools like DOE's $2.5 billion Transmission Facilitation Program, which can lend, form public-private partnerships, or buy a slice of a line's capacity to make it bankable.[29]

Why private capital pays up. FERC-regulated transmission offers utility-grade, inflation-linked, long-duration cash flows with low correlation to commodity cycles — prized "super-core" infrastructure. Brookfield's stake in FirstEnergy Transmission was struck at roughly 36 times trailing earnings, a premium that reflects how scarce these cash flows are.[15]

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6. What drives demand

1. Data-center and AI load growth — the new supercharger. After two decades of flat demand, the North American Electric Reliability Corporation (NERC) now forecasts summer peak demand rising 224 GW (~24%) over ten years, with about 90 GW tied to data centers.[30] DOE estimates data centers used ~176 terawatt-hours (4.4% of U.S. electricity) in 2023, potentially rising to 325–580 TWh (6.7%–12%) by 2028.[31]
2. Connecting renewables. More than 2,060 GW of proposed generation and storage sat in interconnection queues at the end of 2025 (across ~8,200 projects), much of it far from load centers.[32] Most never gets built — historically only ~13% reach operation — but even a fraction requires major new lines.
3. Aging-asset replacement. With 70%+ of lines over 25 years old, reliability rebuilds are a baseline that continues even if load growth disappoints.[8]
4. Interregional resilience. After extreme-weather blackouts, DOE's 2023 National Transmission Needs Study concluded the U.S. must roughly double within-region capacity and expand interregional transfer capacity more than fivefold by 2035.[33]
5. Electrification of transport and buildings — a slower, longer-dated driver.

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7. Regulation

Regulation is the business model here. The key players:

• FERC — the primary economic regulator. It sets transmission rates, allowed ROE, and incentives, and oversees the RTOs/ISOs. Order No. 1000 (2011) opened regional projects to competition (removing the federal right of first refusal for certain planned lines). Order No. 1920 (May 2024), its biggest transmission action in over a decade, requires each region to do long-term (20-year) forward planning and set cost-allocation rules up front; Orders 1920-A/-B (2024–2025) strengthened the role of states.[34] Order No. 2023 (2023) reformed the generator-interconnection queue toward "first-ready, first-served" cluster studies.[35] A FERC move to trim base ROE or adders compresses earnings across the whole sector — the key regulatory risk lever.
• State public utility commissions (PUCs) — control siting and permitting: routing, rights-of-way, eminent domain, and the certificate of public convenience and necessity (CPCN). This is the biggest timeline risk. A line can have an attractive FERC tariff and still die because one state won't approve the route or the cost split.
• DOE — designates National Interest Electric Transmission Corridors, holds limited federal "backstop" siting authority, and runs the National Transmission Needs Study.[33]
• EPA (U.S. Environmental Protection Agency) — not the industry's economic regulator, but its reviews under the National Environmental Policy Act (NEPA), plus wetlands, endangered-species, and equipment-fluid rules, drive schedule and cost.
• NRC (Nuclear Regulatory Commission) — peripheral; relevant only where a transmission change affects a nuclear plant's off-site power. Nuclear generation itself is NAICS 221113.
• NERC — writes and enforces mandatory reliability and cybersecurity (Critical Infrastructure Protection) standards, a recurring cost of doing business.

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8. Competitive dynamics and consolidation

A natural monopoly. It rarely makes sense to build a second high-voltage line along the same route, so an operating line faces no direct competitor. Competition happens before construction — in RTO competitive solicitations and in mergers-and-acquisitions for existing assets. Incumbents keep big advantages (existing corridors, substations, regulator and landowner relationships) for local and replacement work; independent developers win mainly on multi-state, HVDC, or competitively bid projects.

Our concentration data tells a nuanced story. Among the 74 transmission-primary firms in the 2022 Economic Census, the four largest held 39.3% of revenue, the top eight 61.5%, the top 20 85.4%, and the top 50 essentially all of it (99.9%). The Herfindahl-Hirschman Index (HHI) was just 602 — below the 1,500 the U.S. antitrust agencies treat as "unconcentrated."[6] In other words, the narrow industry is a long tail of regional owners, not a tight oligopoly — even though any single line is a local monopoly.

Consolidation is flowing toward strategic and financial capital. The defining trend is scarcity-driven buying of regulated transmission:

• Fortis acquired ITC in 2016 (GIC holds a 19.9% minority);[17]
• Brookfield built up 49.9% of FirstEnergy Transmission — $2.4 billion for 19.9% (2022) plus $3.5 billion for a further 30% (2024) — while FirstEnergy kept 50.1% and operating control;[15]
• NextEra bought GridLiance (~$660 million, ~700 miles) in 2021.

Deals increasingly take the form of minority stakes and joint ventures rather than whole-company takeovers, which face heavier state and federal merger review. Meanwhile a handful of engineering-and-construction specialists (Quanta Services, MYR Group, MasTec) capture much of the build spend — Grain Belt Express alone awarded $1.7 billion to Quanta and Kiewit.[18]

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9. Risks

1. Siting and permitting — the dominant risk. DOE finds major projects take about 10 years on average (roughly 5–17 years across the range); SunZia took nearly 20.[36] A single contested county or state can stall an entire multi-state line. This is a timeline-and-abandonment risk more than a demand risk.
2. Cost-allocation fights. A technically beneficial line can fail if states and customer classes can't agree who pays — a live tension under Order 1920.
3. ROE compression. FERC (pushed by state consumer advocates) can cut base ROE or incentive adders. Because valuations capitalize decades of regulated earnings, even a small cut moves equity value.
4. Interest rates and financing. Transmission is capital-hungry and often free-cash-flow-negative during a build-out. Higher rates raise debt costs, force dilutive equity issuance, and pressure valuations. Judge growth per share, not just aggregate capex.
5. Supply chain. Large power transformers can carry 36-month-plus lead times, and over 80% are imported;[37] steel, aluminum, copper, and HVDC converter equipment can blow out budgets (mostly passed through on regulated lines, but not on merchant ones).
6. Load-forecast / overbuild risk. Data-center requests can be double-counted across territories; if regulators approve against inflated forecasts, customers pay for underused assets.
7. Merchant-line risk. Uncontracted capacity, offtaker credit, and price-spread compression (a new line can erode the very congestion value that justified it) make merchant projects binary.
8. Cyber, physical security, and climate. Substations and control centers are high-consequence targets, and wildfire, storms, and heat drive both damage and liability.
9. Policy reversal. Cuts to clean-energy tax credits would slow the renewable build-out that drives much incremental transmission demand.

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10. How to invest, and the outlook

Two ways in.

• Public-market investors buy transmission through diversified regulated utilities — the most concentrated liquid exposure is Fortis (via ITC), followed by transmission-heavy names like AEP, FirstEnergy, WEC Energy, Ameren, Exelon, and NextEra (§4). These trade like regulated utilities: low-single-digit dividend yields (AEP ~2.9%, FirstEnergy ~3.8% as of July 17, 2026), valuations in the high-teens-to-low-20s times earnings, and total return of dividend plus rate-base-driven earnings growth.[14][15] A leveraged, un-capped alternative is the contractors (Quanta, MYR, MasTec), which capture the build spend without the regulated-return ceiling — at the cost of project-cycle volatility. The key metric to track is transmission rate-base growth per share, not headline capex.
• Private-market investors buy the pure assets: a minority stake in an operating regulated transco (the Brookfield/FirstEnergy Transmission and GIC/ITC templates — lower risk, premium multiples of 30×+ earnings), a competitive regulated greenfield project won in an RTO solicitation (higher return for taking bidding, siting, and construction risk), a merchant HVDC line (highest upside, most binary), or public-private structures anchored by DOE capacity contracts. Fixed-income exposure is available through municipal, cooperative, and project debt.

Outlook. The base case is a decade-plus transmission capital cycle: renewed U.S. load growth (data centers above all), DOE's call to double regional and quintuple interregional capacity by 2035, an aging network needing replacement, and Order 1920's planning mandate all point to sustained, above-inflation growth in transmission rate base — from roughly $33 billion a year in IOU spending today toward and beyond $40 billion.[30][33][10] But completion will run well below headline plans, because the true scarcity is not capital or proposed projects — it is fully permitted, properly cost-allocated, financeable lines that reach service on time. Public investors should expect utility-like total returns (mid-to-high single digits) with a grid-growth kicker; private investors are paying premium prices for scarce, bond-like, inflation-protected assets. The edge, in both cases, is owning the fastest-rate-base-growing names and assets — and the contractors who capture the spend without the return cap.

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Sources

1. U.S. Census Bureau, 2022 NAICS — 221121 Electric Bulk Power Transmission and Control (definition; cross-references to 22111 generation and 221122 distribution). https://www.census.gov/naics/?input=221121&year=2022&details=221121
2. Federal Energy Regulatory Commission (FERC), "Formula Rates in Electric Transmission Proceedings: Key Concepts." https://www.ferc.gov/formula-rates-electric-transmission-proceedings-key-concepts-and-how-participate
3. FERC, "Electric Power Markets" (RTO/ISO coverage; ~two-thirds of U.S. load). https://www.ferc.gov/electric-power-markets
4. U.S. Department of Energy (DOE), Quadrennial Energy Review, Appendix C: Electricity (transmission ownership shares), 2015. https://www.energy.gov/documents/qerappendixcelectricitypdf
5. U.S. Census Bureau, County Business Patterns (CBP): 2023 — NAICS 221121 (establishments 360; employment 20,606; annual payroll $3.28B; Q1 payroll $1.07B). https://data.census.gov/table/CBP2023.CB2300CBP
6. U.S. Census Bureau, 2022 Economic Census — EC2200BASIC and concentration tables, NAICS 221121 (firms 74; revenue $17.628B; CR4 39.3%, CR8 61.5%, CR20 85.4%, CR50 99.9%; HHI 602), 2025. https://data.census.gov/table/ECNBASIC2022.EC2200BASIC
7. U.S. Small Business Administration (SBA), Table of Small Business Size Standards (NAICS 221121 = 950 employees; effective March 17, 2023). https://www.sba.gov/document/support-table-size-standards
8. Congressional Research Service, Introduction to Electricity Transmission (IF12253) — ~600,000 miles of line, ~240,000 miles high-voltage, 70%+ over 25 years old. https://www.congress.gov/crs-product/IF12253
9. FERC, 2024 State of the Markets Report (>5,000 circuit-miles entered service in 2024), 2025. https://www.ferc.gov/sites/default/files/2025-03/25_State-of-the-Market_0320_1200.pdf
10. Edison Electric Institute (EEI), 2024 Financial Review (transmission investment $30.0B 2023 / $32.6B 2024; ~$178B 2025–2028), 2025. https://www.eei.org/-/media/Project/EEI/Documents/Issues-and-Policy/Finance-And-Tax/Financial_Review/FinancialReview_2024.pdf
11. U.S. Energy Information Administration (EIA), "Major Utilities' Spending on the Electric Transmission System Continues to Rise" ($27.7B in 2023), 2024. https://www.eia.gov/todayinenergy/detail.php?id=63724
12. EEI / Utility Dive, "Investor-owned utilities could spend $1.1T between 2025 and 2029" (~$39.9B transmission 2025; ~$208B total 2025), 2025. https://www.utilitydive.com/news/investor-owned-utilities-spending-more-than-ever-eei/802315/
13. Fortis Inc., "Our Value Proposition" and "Share Information" ($28.8B 2026–2030 capital plan; ~7% rate-base growth; 4%–6% dividend growth; C$0.64 quarterly dividend). https://www.fortisinc.com/investors/our-value-proposition
14. American Electric Power, dividend release and Macrotrends P/E (~40,000 line-miles; 2,200+ mi 765-kV; $132.14, $3.80 dividend, 2.88% yield, ~22× P/E, July 17, 2026). https://www.aep.com/investors and https://www.macrotrends.net/stocks/charts/AEP/american-electric-power/pe-ratio
15. FirstEnergy Corp. / Utility Dive, Energize365 update and Brookfield transaction disclosures (~24,000 line-miles; 50.1%/49.9% split; Brookfield $2.4B + $3.5B; ~36× trailing P/E; $48.54, $1.86 dividend, 3.83% yield). https://www.utilitydive.com/news/firstenergy-brookfield-transmission-ferc-morgan-stanley/642085/
16. First Trust, NASDAQ Clean Edge Smart Grid Infrastructure ETF (GRID) (~$11.55B AUM, 0.56% expense ratio, ~0.76% yield); State Street, Utilities Select Sector SPDR (XLU). https://www.ftportfolios.com/retail/etf/etfsummary.aspx?Ticker=GRID and https://www.ssga.com/us/en/intermediary/etfs/the-utilities-select-sector-spdr-fund-xlu
17. ITC Holdings Corp., Form 10-K (~16,000 circuit-miles; Fortis 80.1% / GIC 19.9%; formula rates; ITC Great Plains ROE 11.41% = 10.66% base + 25 bps + 50 bps), SEC EDGAR CIK 1317630. https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=1317630
18. Invenergy, "Grain Belt Express Awards $1.7B to Quanta and Kiewit to Build Largest Transmission Line in U.S. History" (~800-mile HVDC, 5,000 MW, ~$11B, ~2029). https://invenergy.com/news
19. S&P Global, "1,250-MW Champlain Hudson line into NYC reaches commercial operation" ($6B, in service May 2026); SunZia ($11B, 550-mile HVDC). https://www.spglobal.com/commodity-insights
20. Tennessee Valley Authority, "Transmission" (~16,400 line-miles; 500 substations). https://www.tva.com/energy/transmission
21. Bonneville Power Administration, "About BPA" (~15,000 circuit-miles). https://www.bpa.gov
22. Western Area Power Administration, "About WAPA" (17,000+ circuit-miles). https://www.wapa.gov/about-wapa/
23. Baker Botts LLP, "FERC Revises ROE Methodology for Transmission Owners" (Oct 2024 order; DCF+CAPM; NY Transco 10.90%, SDG&E 11.75% requests), 2024. https://www.bakerbotts.com/thought-leadership/publications/2024/october/ferc-revises-roe-methodology-for-transmission-owners
24. RTO Insider, "FERC Sets MISO TOs' ROE at 9.98%," 2024. https://www.rtoinsider.com/89798-ferc-sets-miso-tos-roe-eliminates-risk-premium-model/
25. Utility Dive, "New England transmission owners ask FERC for increased ROE" (base ~9.57%; request to 11.39%). https://www.utilitydive.com/news/new-england-transmission-ferc-eversource-roe/819055/
26. FERC, "Transmission Incentives" (Order No. 679; CWIP, abandoned-plant recovery, RTO/transco adders). https://www.ferc.gov/transmission-incentives
27. FERC, Champlain Hudson Power Express Negotiated-Rate Order (ER20-1214), 2020. https://www.ferc.gov/sites/default/files/2020-06/20200529162139-ER20-1214-000.pdf
28. Internal Revenue Service, "Clean Electricity Investment Credit" (network transmission generally ineligible; credits apply to generation/storage). https://www.irs.gov/credits-deductions/clean-electricity-investment-credit
29. DOE, "Transmission Facilitation Program" ($2.5B; loans, PPPs, anchor capacity contracts). https://www.energy.gov/gdo/transmission-facilitation-program
30. NERC, 2025 Long-Term Reliability Assessment (via Utility Dive) — peak demand +224 GW / ~24% over 10 years; ~90 GW data centers. https://www.utilitydive.com/news/nerc-10-year-peak-demand-forecast-jumps-24-on-new-data-center-loads/810955/
31. DOE, "Report Evaluating Increase in Electricity Demand from Data Centers" (176 TWh / 4.4% in 2023 → 325–580 TWh / 6.7%–12% by 2028), 2024. https://www.energy.gov/articles/doe-releases-new-report-evaluating-increase-electricity-demand-data-centers
32. Lawrence Berkeley National Laboratory, Queued Up (end-2025 data: ~2,060 GW across ~8,200 projects; ~13% historical build rate), 2026. https://emp.lbl.gov/queues
33. DOE, National Transmission Needs Study (double regional / >5× interregional capacity by 2035), 2023. https://www.energy.gov/sites/default/files/2023-12/National%20Transmission%20Needs%20Study%20-%20Final_2023.12.1.pdf
34. FERC, "Explainer on the Transmission Planning and Cost Allocation Final Rule" (Order No. 1920, May 2024; 1920-A/-B). https://www.ferc.gov/explainer-transmission-planning-and-cost-allocation-final-rule
35. FERC, "Fact Sheet: Improvements to Generator Interconnection Procedures — Order No. 2023," 2023. https://www.ferc.gov/news-events/news/fact-sheet-improvements-generator-interconnection-procedures-and-agreements
36. DOE, Transmission Impact Assessment (~10-year average development; ~5–17-year range), 2024. https://www.energy.gov/sites/default/files/2024-10/DOE_OP_2024_Report-Transmission_Impact_Assessment.pdf
37. DOE, Large Power Transformer Resilience Report (36+ month lead times; 80%+ imported), 2024. https://www.energy.gov/sites/default/files/2024-10/EXEC-2022-001242%20-%20Large%20Power%20Transformer%20Resilience%20Report%207-10-24.pdf