"T&D is one line on the bill." It is two layers, two regulators, two cost drivers.
The most common framing error in US energy reporting is collapsing transmission and distribution into "the wires" as a single category. They are two entirely separate engineering layers with two different regulators, two different cost-recovery mechanisms, and two completely different drivers of why your bill is going up.
Transmission is the high-voltage long-haul: 115 kV to 765 kV lines that move bulk power across hundreds of miles. FERC regulates everything that moves in interstate commerce (almost all of it). The cost is socialised across an ISO/RTO footprint through wholesale tariffs that show up on your bill as part of the supply charge. Build-out is driven by FERC Order 1000 regional planning, generator interconnection queues (now reformed under Order 2023), and the climate-policy build cycle.
Distribution is the local street: lower-voltage lines (under 35 kV) that bring power from substations to your meter. The state PUC regulates everything about it. The cost is recovered through a general rate case, typically every 3 to 5 years per utility, where the incumbent justifies its capital investment, its operating expense, and its authorised return on equity. Build-out is driven by storm hardening, AMI deployment, EV-charger interconnection, distribution-level battery siting, wildfire mitigation in CA and undergrounding in FL.
The two layers are climbing residential bills in parallel but for different reasons. FERC-approved transmission projects ($16 billion of MISO Tranche 1 alone) recover through interstate cost-allocation; state PUC-approved distribution upgrades recover through local rate cases. Treating them as one line means missing which lever actually moves your bill in your state.
Transmission and distribution, side by side.
Two engineering layers, two regulators, two cost drivers. The boundary is roughly at the substation that steps voltage from 115 to 230 kV down to under 35 kV. Everything above is transmission, everything below is distribution.
Transmission
- Voltage: 115 to 765 kV (highest in the US), plus HVDC at 500 kV+ for very long-haul ties.
- US mileage: roughly 700,000 miles of high-voltage line, plus an additional ~250,000 miles of sub-transmission (34.5 to 115 kV).
- Regulator: FERC, except inside ERCOT (PUCT-only).
- Cost recovery: ISO/RTO wholesale tariff socialised across the footprint; shows up as part of the supply / energy charge on your bill.
- Build driver: FERC Order 1000 regional planning, public-policy projects (state renewable targets), generator interconnection queue (Order 2023).
- Reliability: NERC mandatory reliability standards (planning reserves, frequency response, vegetation management, cyber).
Distribution
- Voltage: under 35 kV on primary feeders (typically 4.16, 13.2, 13.8, 25 kV); 120/240 V single-phase at the home.
- US mileage: roughly 5.5 million miles of distribution line, the vast majority overhead but ~20% underground (much higher in urban centres and FL).
- Regulator: state PUC / PSC, in every state, with no federal jurisdiction.
- Cost recovery: general rate case (typically every 3 to 5 years per utility), special-purpose riders (storm, AMI, EV, undergrounding).
- Build driver: storm hardening, AMI 2.0, EV-charger interconnection, distribution-level battery siting, wildfire mitigation, data-center load.
- Reliability: state PUC service-quality rules (SAIDI, SAIFI, CAIDI thresholds per utility per year).
The non-obvious truth. T&D combined are 30 to 40% of a residential bill, and rising in every region. You cannot shop either: in retail-choice states the competitive supplier sells you only the supply portion; everything else flows to your incumbent through tariffs set by FERC (transmission) or by your state PUC (distribution). The lever that actually moves your delivery line is not the supplier market; it is the state PUC rate case docket.
Voltage, regulator, payer, share of bill, owner.
The five-column breakdown that should sit at the top of every T&D explainer. Numbers are typical US averages; your incumbent's share of bill varies with rate design and state.
| Layer | Voltage | Who regulates | Typical bill share | Who owns |
|---|---|---|---|---|
| HVDC ties | 500 kV+ DC | FERC | Small uplift on supply | Merchant transmission developers (Clean Path NY, Champlain Hudson, SunZia) |
| Bulk transmission | 230 to 765 kV AC | FERC + RTO | 5 to 10% of bill | IOU transmission affiliates, RTO-organised cost recovery |
| High-voltage transmission | 115 to 230 kV AC | FERC | Bundled into transmission charge | Local IOU transmission company |
| Sub-transmission | 34.5 to 115 kV AC | FERC (mostly), some state PUC | Bundled | Local IOU |
| Primary distribution | 4.16 to 34.5 kV AC | State PUC | 15 to 25% of bill | Incumbent utility (IOU, muni or co-op) |
| Secondary distribution | 120/240 V single-phase | State PUC | Bundled into distribution | Incumbent utility |
| Service drop + meter | 120/240 V to your panel | State PUC | Customer charge ($8 to $25/mo) | Incumbent utility (everything up to the meter) |
! The 3,000:1 voltage drop in roughly 200 miles
A 765 kV transmission line near a Midwestern wind farm ends at a substation that steps to 230 kV. A regional sub-transmission carries the power at 115 kV to your city. A distribution substation steps to 13.2 kV; primary feeders carry it down your street. A pole-top or pad-mounted transformer (10 to 50 kVA, oil-filled) steps it to 240 V single-phase, with a centre-tap neutral that gives you 120 V for outlets and 240 V for big appliances. The full ratio is about 3,000:1 in voltage and happens across roughly five transformer stages. Each stage costs energy (transformer losses), regulated capital and FERC/state PUC oversight.
The four kinds of substation and the boundary at your meter.
A substation is a fenced yard full of transformers, breakers, switches and protective relays. Four kinds, each at a different point on the voltage staircase. The smart meter is the boundary between utility and customer.
A Step-up (generator) substation
At the power plant. Steps generator output (~15 to 25 kV) up to transmission voltage (~115 to 765 kV). Owned by the generator owner; interconnected to the transmission grid via FERC-approved Generator Interconnection Agreement (GIA).
B ISO transmission substation
Where the high-voltage lines from multiple generators meet and are switched. Operated from the ISO/RTO control centre that dispatches generators every five minutes. PJM, MISO, NYISO, ISO-NE, CAISO, SPP each operate hundreds of these.
C Step-down (distribution) substation
At the edge of a city or town. Steps from 115 or 230 kV to primary distribution voltage (4 to 35 kV). Owned and operated by the incumbent distribution utility; regulated by the state PUC. Typically every 5 to 15 miles in dense areas.
D Pole-top or pad-mounted transformer
The last transformer before your house. Oil-filled, 10 to 50 kVA, steps from primary distribution voltage to 120/240 V single-phase. Serves between 1 and ~12 homes typically. Owned by the incumbent utility, sized in the utility's distribution planning study.
The smart meter: the formal boundary
From the pole-top transformer, a service drop (overhead or underground) carries 120/240 V to a meter base on your house. Everything from the utility side of the meter base belongs to the incumbent utility (and is regulated by the state PUC). Everything from the customer side (main panel, branch circuits, every outlet) is yours and is governed by the National Electrical Code. The smart meter (AMI) reports 15-minute or 5-minute interval consumption to the utility over an RF mesh or cellular link; required for time-of-use rates, supplier billing in retail-choice states, and most DER programs.
The four reasons T&D is climbing on every US residential bill.
T&D charges are now the fastest-growing line on most US residential bills. Four structural drivers explain why, and why none of them reverse in the next decade.
Authorised ROE on rate base
Every dollar of approved capex earns this rate of return for the IOU. The bigger the rate base, the bigger the dollar return.
MISO Tranche 1 transmission
Single approved package of new MISO transmission. Cost-allocated across the MISO footprint, recoverable in retail rates.
AMI deployment by 2024
~75% of US customers had a smart meter by 2024; AMI 2.0 replacement cycle now adding to distribution rate base.
New load drivers
EV chargers and data-center interconnections are pushing distribution and sub-transmission upgrades in TX, VA, GA, OH, AZ, NV.
Three implications for the residential bill
- A Rate cases are coming faster. Utilities used to file a general rate case every 5 to 7 years. Many are now filing every 2 to 3 years to recover the accelerated capex cycle. NY (NYSEG, Con Ed), MA (Eversource, National Grid), CA (PG&E, SCE) are all in active multi-year rate-plan cycles.
- B Riders are bypassing rate cases. Storm-cost recovery, AMI deployment, EV-charger infrastructure, undergrounding all show up as special-purpose tariff riders that the utility can collect on faster than a full rate case allows. Read your bill's line items.
- C The supply line is shrinking as a share. Supply costs have risen, but T&D has risen faster. The shoppable supply portion is now closer to 40 to 50% of the bill, down from ~60% a generation ago. Shopping a competitive supplier still matters, but it has less leverage than it used to.
Four structural reasons T&D will never be deregulated.
Retail choice opened the supply line in 18 states. Transmission and distribution remain regulated monopolies in every state, regardless of the supply structure. Four reasons explain why, and why this is unlikely to change.
Wires are a natural monopoly, by physics
It is not economically rational to run two parallel sets of distribution poles down the same street, two parallel transformers serving the same block, two parallel transmission corridors crossing the same county. Every regulator and every economist agrees. The state PUC awards an exclusive distribution franchise; FERC awards an exclusive transmission service territory through the RTO.
Reliability requires coordination, not competition
The 1965 and 2003 blackouts both started as small transmission incidents that cascaded because of poor coordination. NERC standards, FERC-approved RTO planning and state PUC service-quality rules all require the wires owner to coordinate maintenance, switching and emergency response across the entire footprint. A fragmented competitive wires market would have no mechanism for that coordination.
Capital intensity demands long-term cost recovery
A new 345 kV transmission line costs $1 to $3 million per mile to build and lasts 40 to 60 years. A distribution substation is $5 to $20 million. No private market can amortise that capex without a guaranteed cost-recovery mechanism, which is exactly what cost-of-service regulation provides. Investor-owned utilities raise debt and equity at investment-grade rates because their cost recovery is regulated.
Eminent domain is a public-use power
Building a new transmission line across many private properties requires eminent-domain authority, which only a state-regulated utility or a FERC-certified interstate developer can wield. Competitive wires entities would have no path through right-of-way acquisition. The legal framework that lets wires get built at scale is incompatible with retail-style competition.
The takeaway: T&D regulation is structural, not historical. The 1996 retail-choice wave deliberately left wires regulated because nobody serious proposes otherwise. The lever that actually shapes your delivery line is the state PUC rate case (for distribution) and the FERC + RTO planning process (for transmission). Consumer advocates, public-staff offices and intervenor groups participate in both; you can too.
Six concrete steps to manage T&D charges on your bill.
Find the T&D line on your bill
Most US bills break out "delivery" or "transmission and distribution" as separate lines from "supply" or "generation". Add them up and divide by total kWh to get your effective T&D ¢/kWh. Compare to your state's EIA average.
Read the rate-case docket
Every state PUC publishes the active rate-case docket for your incumbent. Filings list the capex package, the asked-for ROE, the riders, the proposed bill impact. Public comment is accepted; consumer advocates use it.
Lean on time-of-use rates if available
TOU tariffs shift consumption to off-peak hours and avoid the most expensive distribution-peak loading. A 5 to 15% bill reduction is typical for a household that shifts EV charging, dishwasher and dryer to overnight. Smart thermostat helps.
Engage your consumer advocate
If your bill jumps, email your state's ratepayer-advocate office. NC Public Staff, OUCC, OCA, CUB, NJ Rate Counsel, MD OPC, DC OPC, Mass AGO. They cross-examine the utility on capex and ROE in every rate case.
Track the RTO transmission plan
PJM, MISO, ISO-NE and NYISO each publish a regional transmission expansion plan annually under FERC Order 1000. New $-billion line packages get socialised across rate-payers in the footprint; reading the plan tells you what is coming.
Consider a battery to dodge peak demand charges
Some states (CA, NY, parts of MA, AZ) bill residential demand charges based on your highest 15-minute kW draw. A battery can shave the peak and cut the demand line meaningfully. Solar + battery + the IRS 30% credit accelerates payback.
Common questions about US transmission and distribution.
Transmission is the long-haul highway: high-voltage lines (typically 115 kV to 765 kV) carry bulk power from generators across hundreds of miles to substations near population centres. Roughly 700,000 miles of transmission line in the US, regulated by FERC (except inside ERCOT where the PUCT regulates). Distribution is the local street: lower-voltage lines (typically under 35 kV, often 4 to 25 kV in residential areas) carry power from those substations to homes and businesses. Roughly 5.5 million miles of distribution line in the US, regulated by the state PUC. Transmission moves the energy; distribution delivers it.
Both are paid by you, on different lines of your bill. Transmission costs are billed by your incumbent utility, which has paid the wholesale transmission charge to the ISO/RTO (PJM, MISO, NYISO, ISO-NE, CAISO, SPP) or to a neighbouring transmission owner. Distribution costs are billed directly by your incumbent, set in the state PUC's general rate case (typically every 3 to 5 years per utility). Combined, T&D charges are roughly 30 to 40% of a residential bill and rising. You cannot shop your way out of either; both flow to the wires utility regardless of who supplies your kWh.
Two different regulators. Transmission is regulated by FERC for everything that moves in interstate commerce, which is almost all of it. ERCOT is the exception: its intra-state transmission is regulated by the PUCT alone. Distribution is regulated by the state Public Utility Commission or Public Service Commission, in every state, with no federal jurisdiction. NERC writes mandatory reliability standards for transmission (planning reserves, frequency response, vegetation management) under FERC delegation; distribution reliability is set by each state PUC individually.
Distribution rates are set on rate base (the depreciated capital the utility has invested in poles, wires, transformers, substations), not on kWh. Your incumbent's rate base keeps growing: storm hardening, undergrounding, AMI 2.0 smart meters, EV-charger interconnection, data-center load growth, wildfire mitigation (CA), undersea cable replacement (Long Island), distribution-level battery siting. Each capital project earns the utility's authorised return on equity (typically 9 to 10.5%). When the rate base grows faster than the kWh delivered, the rate per kWh has to rise. This is the structural reason T&D charges are now climbing on every US bill.
Transmission: 115 kV, 138 kV, 230 kV, 345 kV, 500 kV, 765 kV (highest in the US), plus high-voltage DC at 500 kV+ for very long-haul ties. Sub-transmission: 34.5 kV to 115 kV. Distribution: 4.16 kV, 13.2 kV, 13.8 kV, 25 kV, 34.5 kV on the primary feeders that reach neighbourhoods. 120/240 V in your house, single-phase, stepped down by the pole-top or pad-mounted transformer outside (~10 to 50 kVA for a typical residential cluster). The voltage drop from 765 kV transmission to 240 V at your panel is roughly 3,000:1.
It steps the voltage up or down and switches the lines that feed each other. A transmission substation (often called a "switchyard") near a power plant steps generator output (~15 to 25 kV) up to transmission voltage (~115 to 765 kV). A step-down substation at the edge of a city steps it down to sub-transmission or distribution voltage. A distribution substation at the start of a feeder steps to primary distribution voltage (4 to 35 kV) and breaks the network into feeders that radiate out to neighbourhoods. ISOs operate transmission substations from a control centre that dispatches generators every five minutes.
The smart meter (Advanced Metering Infrastructure, AMI) is the physical boundary between the distribution utility and the customer. Everything on the utility side (the service drop from the pole or pedestal, the meter itself, the connection terminals) is the incumbent's. Everything on the customer side (the main panel, branch circuits, every outlet) is yours. The smart meter reports interval consumption (15-minute or 5-minute) to the utility over a private RF mesh or cellular link. Roughly 75% of US customers had an AMI meter by 2024; the figure is higher in deregulated retail-choice states because time-of-use rates and supplier billing require it.
Roughly 5 to 6% nationally, on average, between generator output and customer meter. Transmission losses average about 2 to 3%, distribution losses another 2 to 4%. Losses go up under high load (resistive losses scale with current squared) and down in moderate weather. The lost energy is real and is paid for by all customers as an uplift on the supply rate. The number is published in each utility's annual FERC Form 1 filing.
Keep learning about US energy infrastructure
Plant to plug: the journey
How your electricity gets from a power plant to the outlet at home, step by step.
Wholesale electricity markets
The seven US ISO/RTOs and the July 2025 PJM record auction.
Who regulates US energy?
FERC, state PUCs, NERC, DOE, EPA and consumer advocates.
Incumbent electricity suppliers
The legacy utilities that own the wires and provide default supply.
Distributed energy
Rooftop solar, batteries and EVs as wholesale resources under FERC Order 2222.
Deregulated states map
State-by-state status of electricity and natural gas retail choice.
Competition in US energy markets
PURPA, EPAct 1992, FERC Orders 888, 889 and 2000 in plain English.
How liberalization affects you
What retail choice means for residential customers, state by state.
Electricity prices per kWh
EIA-verified state-by-state residential prices, May 2026.
New York: 1998 to 2026
NYISO, ConEd, NYSEG, National Grid and the role of the NY PSC.
Illinois: ComEd, Ameren and PJM
Why the PJM 2026/2027 auction lands hardest on ComEd customers.
Texas energy hub
ERCOT, the TDUs and PUCT-only intra-state regulation.