Transmission lines move bulk electricity over longer distances at high voltage; distribution lines carry it through local networks to homes and businesses. Substations and transformers connect the two stages by changing voltage. Voltage, appearance, and oversight can help distinguish them, but none is a universal test—and voltage alone does not tell you a line’s power capacity.
How electricity moves from a generator to a customer
A simplified route is generator → step-up substation → high-voltage transmission network → substations and transformers → distribution feeders → customer service. A power grid links generators and consumers using power lines, substations, and transformers; it is not usually a dedicated wire running from one power plant to one home. The U.S. Energy Information Administration (EIA) explains the delivery stages.
- Generation: A power plant or another generator produces electricity.
- Step-up transformation: A transformer raises the voltage before long-distance transmission.
- Transmission: High-voltage lines move bulk power between generators, substations, and demand areas, often across long distances or between regions.
- Substation transformation: Substations and transformers lower voltage for downstream networks.
- Distribution: Local feeders and related equipment carry electricity through neighborhoods and business areas to customer service connections.
The stages are connected rather than isolated. Power flows across the interconnected network according to available paths and network conditions, not necessarily along a prespecified route between a particular generator and customer. The Department of Energy’s transmission primer compares the network to interconnected pipes: if one path is full, power can use another available path, subject to system conditions.
Transmission vs. distribution at a glance
| Feature | Transmission | Distribution |
|---|---|---|
| Main job | Moves bulk electricity over longer distances and between generation, substations, and demand areas. | Delivers electricity locally to end users such as homes and businesses. |
| Network scale | Connects generators, substations, and demand centers across a broad, interconnected network. | Branches through local service areas, typically via feeders and customer connections. |
| Voltage | Typically high voltage. DOE examples include 115, 138, 230, 345, 500, and 765 kV; these are examples, not a national requirement. | Typically lower voltage than transmission. One FERC explainer describes distribution as usually 35 kV or less, but this is a contextual description rather than a universal boundary. |
| Common physical form | Often tall structures carrying high-voltage conductors. | Often neighborhood utility poles or underground lines. |
| Voltage conversion | Voltage is stepped up before long-distance transmission and lowered at substations for downstream delivery. | Receives power from higher-voltage systems and delivers it locally at voltages suitable for downstream service. |
| Typical U.S. oversight | FERC generally oversees rates, terms, and conditions for interstate transmission, subject to jurisdictional qualifications. | Generally overseen by state or local authorities. |
These are common roles and patterns, not a field identification checklist. A line’s function, network position, utility designation, geography, ownership, and legal classification can matter as much as its appearance or voltage.
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What voltage tells you—and what it does not
Higher voltage makes long-distance transmission more efficient and less expensive, according to the EIA’s delivery-to-consumers explanation. The generator’s output is stepped up for transmission, then voltage is reduced before electricity moves through local distribution systems.
There is no single voltage cutoff that classifies every line everywhere. A Federal Energy Regulatory Commission (FERC) explainer on its transmission rulemaking says the North American Electric Reliability Corporation generally uses 100 kV as the minimum threshold for transmission lines. A separate FERC explanation of its jurisdiction describes transmission facilities as operating at 69 kV and above and distribution as typically operating at 35 kV or less. Those statements reflect different contexts; neither should be treated as a universal boundary that overrides how a utility or regulator classifies a particular facility.
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The DOE’s 2023 Electricity Transmission backgrounder lists 115, 138, 230, 345, 500, and 765 kV as examples of typical U.S. transmission voltages. It also gives 34, 46, and 69 kV as examples of sub-transmission voltages. These examples illustrate the range of systems; they are not exhaustive or prescriptive standards.
Why line height and appearance are only clues
Transmission infrastructure commonly uses tall structures and high-voltage conductors. Distribution is often easier to spot in a neighborhood, on utility poles or underground. But visual form is not proof: transmission and distribution networks vary, and some systems may be underground or use structures that do not match the familiar image. DOE also notes that utilities may designate system voltages differently. Use the line’s role and utility or regulatory classification rather than height alone when the distinction matters.
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Capacity is not the same as voltage
A line’s voltage rating is not its power-transfer capacity. Voltage describes the electrical pressure level; capacity concerns the maximum steady-state current or power the line can carry under specified conditions. Depending on the context, it may be expressed in amps, megawatts (MW), or megavolt-amperes (MVA). The DOE backgrounder distinguishes voltage rating from power capacity.
Do not estimate a line’s MW capacity from its voltage alone. A meaningful capacity figure depends on the line’s rating and operating conditions; the voltage number by itself does not provide that information.
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What happens when transmission or distribution fails?
A transmission problem can affect service across a wider area because transmission connects regions, generators, and demand centers. A local distribution fault can interrupt service in a more limited area—for example, when a tree limb strikes a line or a vehicle hits a utility pole. The FERC overview of its role distinguishes local distribution outages from interstate transmission oversight and describes how transmission-level events can affect customers.
Interconnection and redundant paths support reliability. The EIA notes that interconnected grids provide backup paths and can reduce the extra generating capacity each utility must keep for peak demand. A failed line or generator therefore does not automatically cause a widespread blackout; the effect depends on the failure and the network’s remaining ability to carry power.
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How much electricity is lost in the lines?
EIA estimated that U.S. transmission and distribution losses averaged about 5% of electricity transmitted and distributed during 2018–2022. This is a combined transmission-and-distribution estimate, not a figure for transmission alone. The EIA FAQ reporting it was last updated November 7, 2023: How much electricity is lost in transmission and distribution in the United States?
Who oversees transmission and distribution in the United States?
FERC generally oversees rates, terms, and conditions for interstate transmission, while state or local authorities generally oversee local distribution. This is a broad summary, not a rule based solely on voltage. FERC identifies exceptions to interstate jurisdiction, including Alaska, Hawaii, and much of Texas; geography, ownership, function, and legal classification all matter. See FERC’s explanation of what it does for its jurisdictional context.
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