United States
Seven markets, not one, sitting on three electrically separate grids. The gas benchmark underneath them all now prices cargoes in Europe and Asia.
Overview
The United States is not one power market. It is seven organised wholesale markets, a large remainder of vertically integrated utilities, and three electrically separate grids. Over the top of all of it runs a gas market liquid enough that its benchmark sets the marginal cost of electricity across most of the country.
Roughly two thirds of national electricity load sits inside a Regional Transmission Organisation or Independent System Operator, according to FERC: PJM, MISO, ERCOT, CAISO, SPP, NYISO and ISO-NE. The other third, mostly the Southeast and much of the non-California West, is still served by vertically integrated utilities. Their prices come out of state cost-of-service rate cases, not an auction. Nobody has a position in "US power". You have a position in one region, on one grid, under one regulator.
Gas ties it together. Natural gas supplied about 41% of US utility-scale generation in 2025, per the US EIA, and a gas unit is on the margin for most hours in most regions. Henry Hub in Louisiana anchors the lot, averaging $3.52/MMBtu in 2025.
The gas trade has reversed inside a decade. A country that built import terminals in the 2000s exported 15.1 Bcf/d of LNG in 2025 — 26% of global supply, the largest exporter in the world. Domestic gas stopped being an isolated continental market some time ago. It is now the swing supply for Europe and Asia.
Henry Hub plus liquefaction and freight sets the floor under European and Asian spot gas. A cold snap in Texas lifts domestic gas, and within days the delivered cost of a cargo in Rotterdam and Tokyo follows it up. Trading this market from outside America is no longer optional for a European gas book.
Market structure
Seven auction markets. Dozens of regulated utilities, three asynchronous grids, two layers of regulator. Get the structure wrong and everything downstream of it is wrong too.
The seven organised markets
| Market | Footprint | Distinctive feature |
|---|---|---|
| PJM | Mid-Atlantic and Ohio Valley | Largest by load; forward capacity auction (RPM) |
| MISO | Midwest and a Gulf sub-region | Seasonal capacity auction; long north–south footprint |
| ERCOT | Most of Texas | Energy-only; no capacity market; its own interconnection |
| CAISO | California, plus a wider imbalance market | Heavy solar; state resource adequacy rather than a central capacity auction |
| SPP | Central plains | Wind-dominated; expanding into the West |
| NYISO | New York State | Locational capacity market; strong upstate/downstate split |
| ISO-NE | Six New England states | Forward capacity market; winter gas-delivery constraints |
What sits outside
The Southeast and much of the West have no central market at all. Utilities own generation, transmission and distribution, plan their own supply and recover costs through regulated tariffs. Trade there is bilateral and index-based, not exchange-cleared, and your counterpart's regulator is a state commission.
Three grids, not one
Physically there are three asynchronous interconnections: Eastern, Western and ERCOT. Each runs its own AC frequency. Power crosses between them only through back-to-back HVDC converter stations of modest capacity. ERCOT's near-isolation is deliberate: by avoiding significant synchronous interstate connection it stays largely outside FERC's jurisdiction over interstate transmission, as described by FERC.
There is no national US power price, and no arbitrage worth the name between the three grids. Hedges are regional. A PJM West hub position and an ERCOT North hub position are two different markets that happen to settle in the same currency.
Infrastructure — power and gas
Transmission is split three ways across the continent. The gas pipeline network is not split at all, which is why gas rather than electricity is the physically national market.
Power
Eastern Interconnection
The largest of the three, spanning PJM, MISO, SPP's eastern footprint, NYISO, ISO-NE and the regulated Southeast. Deeply meshed, and congestion between zones is the main source of basis risk.
Western Interconnection
CAISO plus a mostly non-market West. Long distances, hydro seasonality, and a growing set of voluntary imbalance and day-ahead market arrangements stitched across utility boundaries.
ERCOT
Roughly 90% of Texas load and 27 million customers, on more than 55,000 miles of transmission, joined to its neighbours only by small DC ties.
Gas
The pipeline grid works the other way round: one integrated continental network moving supply out of the Appalachian, Permian and Haynesville basins to demand centres and, more and more, to Gulf Coast liquefaction. Interstate pipelines are open-access and FERC-regulated, so capacity can be bought and resold. That is why US gas basis is a traded product where US power basis frequently is not.
Schematic — system topology, not a geographic map. The seven RTO/ISO markets and the non-market regions, grouped by interconnection. Boxes are markets and regions, not locations. Markets listed per FERC.
Demand and supply
After two flat decades demand is growing again. Gas still sets the margin, and with the gas market now export-led, domestic power buyers are competing with cargo buyers abroad.
Demand
From the mid-2000s efficiency cancelled out growth and demand went sideways. Not any more. Data centres, electrification and new manufacturing load have put growth back, and PJM, ERCOT and the Southeast are stacking up interconnection requests far faster than anyone builds plant. Watch capacity prices, not energy prices. That is where the tightness surfaces first.
Supply
Gas dominates the margin and coal keeps retiring. Nuclear output is flat, and increasingly contracted straight to large buyers rather than sold into the pool. New build is now mostly wind and solar. Ember records wind and solar together at about 19% of 2025 generation, with solar meeting the majority of demand growth.
Gas, coal, nuclear and total renewables (24%) for 2025 from US EIA; the wind-and-solar split within renewables from Ember. Hydro and other renewables shown as the residual.
2025 exports of 15.1 Bcf/d, up 26% year on year, from US EIA; the 2024 bar is that article's implied prior-year level.
Every new liquefaction train turns domestic molecules into exportable cargo. The domestic balance tightens and the floor under Henry Hub rises. Because gas sets the marginal power price, that floor feeds straight through to wholesale electricity in most of the country, whether or not anyone in those states cares what a cargo fetches in Asia.
Price setting mechanism
A security-constrained auction prices electricity separately at every node on the network. In most of these markets a second auction then pays generators simply for being there.
Locational marginal pricing
Every RTO clears a day-ahead and a real-time market, stacking offers cheapest-first against the physical limits of the network. Out of that comes a locational marginal price (LMP) at each node: the cost of delivering one more megawatt-hour to that exact point. It breaks into a system-wide energy component, a congestion component when a transmission constraint binds, and a small loss component. PJM publishes live zonal LMPs on its markets page.
Congestion is where the money is. Two nodes fifty miles apart can differ by hundreds of dollars per MWh when a line binds, and one of them can go negative if there is enough wind trapped behind the bottleneck. Hence financial transmission rights. A hub price hedges a hub, not a plant sitting behind a constraint.
Capacity versus energy-only
PJM, ISO-NE and NYISO run separate capacity markets paying for firm availability years ahead. PJM's 2027/2028 Base Residual Auction cleared at $333.44/MW-day UCAP, at the FERC-approved cap, for a total of about $16.4 billion. An auction pinned to its cap is telling you the system is short, not going through the motions.
ERCOT does the opposite. No capacity market, so revenue has to come out of energy and ancillary services. To put scarcity into the energy price it applies the Operating Reserve Demand Curve, an adder that rises as reserves fall towards the minimum contingency level of 3,000 MW, with the value of lost load and the system-wide offer cap both set at $5,000/MWh.
In a capacity market most of the tail has been bought out years in advance and the energy price stays comparatively tame. In ERCOT the whole tail lives in the energy price. Same commodity, different distribution. An ERCOT summer position behaves like a short options book; a PJM one does not.
Regulatory regime
Two regulators, divided by the wholesale/retail line. Misplace that line and you will file your petition with the wrong body.
| Body | Remit |
|---|---|
| FERC | Interstate transmission of electricity, gas and oil; wholesale power sales; interstate pipelines and storage; LNG terminal siting; RTO tariffs and market rules |
| State public utility commissions | Retail rates, resource planning and approval of new generation and distribution within a state |
| NERC | Mandatory reliability standards for the bulk power system, enforced under FERC oversight |
| PUCT / ERCOT | Texas keeps both wholesale and retail oversight in-state, because ERCOT is not synchronously interconnected across state lines |
| NRC | Nuclear licensing and safety — explicitly outside FERC's remit |
| EIA | Independent statistics; not a regulator, but the reference dataset for the whole market |
Where the line falls
FERC states plainly that it does not regulate retail electricity and gas sales to consumers, does not approve the physical construction of generating plant, and does not regulate nuclear plants or local gas distribution. Those sit with the states and, for nuclear, the NRC. A wholesale market rule change is a FERC filing. Whether a utility may build a plant and recover the cost is a state rate case.
Why the split creates risk
Friction between the two levels throws off price-relevant surprises with some regularity. State clean energy procurement and out-of-market subsidies sit badly with federally regulated capacity auctions. State siting decisions determine whether federally cleared capacity ever gets built. Queue reform is a FERC matter while the bottleneck in the queue is usually local. Hold forward capacity or congestion and the regulatory calendar is a position, not background reading.
Gas
Interstate pipelines are open-access under FERC, with published tariffs and a secondary market in released capacity. Intrastate pipes, Texas above all, are state-regulated. That is one reason Texan gas supply behaved so differently from federally regulated systems in February 2021. Model US gas deliverability without knowing which regime each pipe sits under and the model is decorative.
Key links
Primary sources for this market. Figures on this page are drawn from these and from published market data.