Electricity Prices in the US: How the Grid Operators Compare

Electricity prices in the United States differ widely by region: in August 2026 the average residential price ranged from 14.47 cents per kilowatt-hour in the East South Central states to 28.31 cents in New England, according to the U.S. Energy Information Administration. The seven grid operators that run wholesale markets explain part of that gap, but fuel mix, weather, network costs and state regulation matter at least as much.

This guide explains who runs the U.S. grid, why prices differ between regions and how to read EIA’s regional numbers. It is not trading or purchasing advice.

Seven market operators, and the regions without one

Much of the country’s high-voltage grid is run by one of seven regional transmission organizations or independent system operators (RTOs/ISOs), the seven FERC staff track in their annual State of the Markets report. Each runs a wholesale market and the transmission network across many utilities:

Operator	Area served (broadly)	A feature that shapes its prices
ISO New England (ISO-NE)	New England	Natural gas supplied 55% of regional generation in 2025 (ISO-NE)
New York ISO (NYISO)	New York State	Tightening reliability margins, especially in New York City (FERC)
PJM Interconnection	All or parts of 13 states and the District of Columbia (PJM)	Capacity auction short of its reliability requirement (PJM)
Midcontinent ISO (MISO)	The Midwest and parts of the South	Wind often sets the price in its northern zone (FERC)
Southwest Power Pool (SPP)	All or part of 17 states (SPP)	Wind produced 36.7% of its energy in 2025 (SPP)
ERCOT	Most of Texas	No centralized capacity market (EIA)
California ISO (CAISO)	Most of California	Runs the Western Energy Imbalance Market, launched in 2014 (FERC)

The rest of the country, notably much of the Southeast and the West outside California, works differently. There, vertically integrated utilities own generation, transmission and distribution, plan their own systems and trade with neighbours through bilateral contracts. FERC’s 2025 State of the Markets report notes that the Western Interconnection outside CAISO historically “operated through bilateral arrangements”, and that both CAISO and SPP are now building day-ahead markets for the West. There is no single regional wholesale price there, and state commissions set retail rates from each utility’s costs.

ERCOT is a special case. According to EIA, at ERCOT “the balancing authority, interconnection, and regional transmission organization are all the same entity”, and ERCOT does not have a centralized capacity market.

What drives regional price differences

EIA lists five broad factors behind electricity prices: fuels, power plant costs, the transmission and distribution system, weather conditions, and regulation.

Fuel and the marginal plant

In an RTO market the price in each interval is set by the last, most expensive unit needed to meet demand. FERC staff found that natural gas-fired plants were the most frequently marginal resource in MISO, SPP, PJM and ISO-NE, except where wind is abundant, as in SPP and MISO’s northern zone, where wind is marginal more often. That makes wholesale power prices in much of the country follow natural gas prices.

FERC’s report shows how far apart regions moved in 2025. FERC attributes the regions where prices rose most to higher fuel costs, rising demand and tighter supply. We do not republish hub prices; the operators and their market monitors publish them.

Wind and solar

Plants with no fuel cost push prices down when they run. SPP, with its large wind share, and CAISO and ERCOT, with fast-growing solar, see low or even negative prices on windy nights or sunny middays. Our guide to negative electricity prices explains the mechanism.

Capacity markets and reliability costs

Four RTOs, PJM, MISO, NYISO and ISO-NE, run centralized capacity markets that pay plants to be available, according to FERC. Those payments reach retail bills. In PJM, the 2027/2028 Base Residual Auction secured 134,479 MW and PJM said committed supply was short of its reliability requirement by 6,623 MW, with a reserve margin of 14.8% against a 20% standard.

Networks, weather and regulation

Network costs vary with geography, storm hardening and the age of the grid. Extreme heat and cold raise demand, and droughts or calm spells cut cheap hydro and wind output. EIA notes that in some states public utility commissions fully regulate prices, while others combine unregulated generation prices with regulated transmission and distribution prices.

Retail prices by region: what EIA’s data show

EIA’s Electric Power Monthly, Table 5.6.A, reports the average price paid by end users in each Census division and state. The August 2026 figures below were released on 23 October 2026 and are preliminary; 2025 values are final.

Census division (main grid operators)	Residential, Aug 2026 (¢/kWh)	All sectors, Aug 2026 (¢/kWh)	Residential, Aug 2025 (¢/kWh)
New England (ISO-NE)	28.31	24.41	29.01
Middle Atlantic (NYISO, PJM)	25.17	20.61	23.73
Pacific Contiguous (CAISO; non-RTO Northwest)	25.59	23.44	25.42
East North Central (MISO, PJM)	19.60	14.69	18.11
South Atlantic (PJM; non-RTO Southeast)	16.04	13.71	15.64
West North Central (MISO, SPP)	15.92	12.51	15.17
West South Central (ERCOT, SPP, MISO)	15.30	11.12	14.79
Mountain (mostly non-RTO)	14.86	12.42	14.57
East South Central (mostly non-RTO)	14.47	12.16	13.99
Pacific Noncontiguous (Alaska, Hawaii)	40.79	36.46	34.72
U.S. total	18.16	14.87	17.57

State figures from the same table show the spread more sharply. Residential prices in August 2026 were 30.48 cents in Massachusetts, 28.65 cents in New York and 29.75 cents in California, against 15.91 cents in Texas, 14.82 cents in Oklahoma, 15.90 cents in Georgia, 13.37 cents in Idaho and 12.87 cents in Louisiana. Hawaii, which has no connection to the mainland grid, was highest at 47.18 cents. Over the whole of 2025, EIA puts the U.S. average retail price at 13.63 cents per kWh, ranging from 35.72 cents in Hawaii to 8.20 cents in North Dakota, and notes that Hawaii’s prices are high mainly because most of its electricity comes from imported petroleum fuels.

How to read the comparison

The table does not rank grid operators:

• Census divisions are not RTO footprints. PJM spans parts of four divisions, and several divisions mix RTO and non-RTO utilities; the labels are a rough guide.
• Retail is not wholesale. A retail price bundles energy, capacity, networks, taxes and policy costs.
• August is a summer month. Compare the same month across years, as EIA’s table does.
• “All sectors” is pulled down by industry, which pays less per kWh.

Live demand on the U.S. grids

Our U.S. pages show hourly demand from EIA’s Hourly Electric Grid Monitor (EIA-930) for PJM, MISO, ERCOT, SPP and ISO New England. These pages show demand and generation, not prices. In the hours we have tracked so far, from the hour starting 21:00 EDT on Friday 23 October 2026 to the hour starting 05:00 EDT on Sunday 25 October 2026 (with no data for 15:00–19:59 EDT on Saturday 24 October), demand followed the usual weekend shape:

Operator	Highest hourly demand we hold (MW)	Local hour	Lowest hourly demand we hold (MW)	Local hour
PJM	87,293	Fri 23 Oct, 21:00 EDT	75,496	Sun 25 Oct, 02:00 EDT
MISO	75,838	Fri 23 Oct, 20:00 CDT	60,891	Sun 25 Oct, 03:00 CDT
ERCOT	58,813	Sat 24 Oct, 19:00 CDT	44,116	Sat 24 Oct, 04:00 CDT
SPP	32,934	Fri 23 Oct, 20:00 CDT	26,342	Sun 25 Oct, 04:00 CDT
ISO-NE	12,784	Fri 23 Oct, 21:00 EDT	8,472	Sat 24 Oct, 12:00 EDT

Values are EIA’s preliminary hourly figures as we queried them on 25 October 2026; EIA revises them later. Hours shown are the start of each hour. A few days of data say nothing about long-run patterns, and the highest values partly reflect where our window begins. ISO-NE’s lowest hour fell at Saturday midday, which fits a region where rooftop solar reduces the demand the grid operator sees.

The short version

Regional U.S. prices differ because regions burn different fuels, face different transmission limits, pay for capacity differently and regulate retail rates differently. For a specific bill, the utility’s or supplier’s own tariff is the figure that counts.