Interactive
Gas & Power Map
How each market prices gas and power, the hubs and venues that set those prices, and the basis between them. Europe and the Americas are mapped; Asia and Australia are in progress.
Europe prices gas off the Dutch TTF and the UK NBP, and power zone by zone. The spreads between those points — not any single price — drive cargo economics, plant dispatch and hedge design.
Data reviewed 28 Jul 2026 · Market structure and 2025 full-year data; price series to June 2026.
TTF gas — period averages €/MWh
Published period averages, not a continuous series. The path runs from post-crisis normalisation through 2024–25 into a tighter 2026, as colder weather, faster storage withdrawals and Middle East supply disruption re-tightened the balance. For scale, TTF hit an all-time record near €342/MWh in August 2022 — roughly 15× the pre-crisis norm of about €20.
Country mapping
Country marks below are indicative levels used for illustration (book date 14 Jul 2026), not live prices. Live benchmarks are on the Tools page.
Netherlands Europe's gas pricing anchor
The TTF is the continent's benchmark — a virtual hub deep enough that European and Asian LNG cargoes are priced against it. Dutch power is tightly coupled to German power through interconnection.
United Kingdom Separate gas hub, coupled power
The NBP trades at a basis to TTF that widens with LNG arrivals and interconnector flows. Post-Brexit the GB power market sits outside EU day-ahead coupling, so IFA/BritNed flows set the UK–NL spread.
Germany Largest power market
Europe's biggest and most liquid power curve, and the reference for Central-European hedging. High wind and solar share makes it the market where shape and negative-price risk bite hardest.
France Nuclear-led, weather-exposed
A large nuclear fleet usually keeps French power below German, so the German–French spread is a core Continental position — but it inverts on nuclear availability and cold snaps.
Basis & location spreads
| Spread | Type | Level | Daily vol | Why it moves |
|---|---|---|---|---|
| TTF – NBP | Gas location | €2/MWh | 3.0% | Widens with LNG arrivals and interconnector direction. |
| German – French power | Power location | €15/MWh | 4.5% | Driven by French nuclear availability; the largest basis exposure here. |
| German – Dutch power | Power location | −€3/MWh | 4.0% | Tight coupling — small spread, but sizeable position. |
| UK – NL power | Interconnector | €5/MWh | 5.0% | Set by IFA / BritNed flows and GB scarcity pricing. |
Correlation — what not to assume
Indicative daily-return correlations. The pairs that look "safe" to cross-hedge are exactly the ones to check — TTF/NBP at 0.85 still leaves material basis risk on a large book.
Sources
- Key developments in EU electricity and gas markets — 2026 Monitoring Report (2025 data) — ACER
- Market Monitoring Report 2024 — key developments in gas (2023 data) — ACER
- Quarterly reports on European gas and electricity markets — European Commission
- European Electricity Review — Ember
- Electricity 2026 — prices — IEA
North America prices gas off a single physical benchmark — Henry Hub — and then everything interesting happens in the basis. Power trades nodally in six of the seven US ISOs, so there is no single "US power price" either. In both markets the tradable object is a differential, not a level.
Data reviewed 30 Jul 2026 · Market structure and H1 2026 outturn; auction and policy positions verified to 30 July 2026.
RGGI allowance auction clearing price $/short ton
The most striking price move in North American environmental markets in the last year. Auction 71 in March 2026 exhausted the entire 2026 Cost Containment Reserve — 7.85 million allowances released against a $18.22 trigger — and the market still cleared $35.00 three months later, a 57% rise in nine months. The Third Program Review tightens the cap through 2037 from 2027 and fixes the CCR at roughly 11.7 million allowances per tier. Note the unit: RGGI allowances are metric tonnes, while EPA reports emitted mass in short tons.
Country mapping
Gas marks are H1 2026 outturn levels, sourced and dated below, shown for scale rather than as live prices. Power marks are deliberately absent: a US power price is specific to a node, hub or zone, and publishing a single number for an ISO would repeat exactly the error this mapping exists to prevent. Hub-level marks arrive with the market packs, each carrying its own verification code.
US Gulf Coast The global gas benchmark
Henry Hub is a physical delivery point in Louisiana, not a virtual hub like TTF, and that difference is the whole story: it sits inside the pipeline network that now feeds the largest LNG export complex in the world. Export pull increasingly sets the marginal call on US gas, which is why a European or Asian cargo decision now transmits back to a Louisiana wellhead within the same trading day.
Permian Basin Where basis goes negative
Waha averaged minus $2.19/MMBtu across H1 2026 and hit a record minus $7.95 at the end of April, staying negative for 25 consecutive days. Permian gas is associated production — it comes up whether or not anyone wants it — so when takeaway capacity binds, producers pay to have it removed. The GCX expansion and the start of Hugh Brinson pushed Waha back above zero in June 2026 for the first sustained stretch in months. This is the cleanest teaching case in the programme for why basis, not benchmark, is the traded object.
PJM The reference nodal market
Thirteen states, 67 million people, and the design every other US market is described against. Capacity is procured forward through RPM, which has now cleared at its cap three auctions running — the 2028/29 auction was collared at $325/MW-day by agreement between FERC and the governors of all thirteen states, against an uncapped estimate of $554.72 that would have taken the bill from $16.4bn to nearly $30bn. Note the trap: Western Hub is what trades, while PJM-RTO is a load-weighted average that is quoted constantly and traded almost never.
Texas Energy-only, at scale
ERCOT has no capacity market. Scarcity is priced instead through the Operating Reserve Demand Curve, under a system-wide offer cap of $5,000/MWh — lowered from $9,000 with effect from January 2022 — with a low cap set daily at the greater of $2,000/MWh or fifty times the gas index. The design freedom comes from a jurisdictional fact: ERCOT is intrastate and therefore outside FERC's wholesale jurisdiction, answering to the PUCT instead. It is also where the load-growth story is most extreme.
California Nodal plus a carbon price
The only US ISO with an economy-wide carbon price layered on top of energy. Resource adequacy is procured bilaterally under a CPUC mandate rather than cleared in an auction, which makes it look unlike PJM or ISO-NE despite sharing the nodal design. A caution for anyone reading federal data: EIA's generation series are utility-scale only, so California's behind-the-meter solar — reported separately under EIA-861 — is simply absent unless you add it explicitly.
Northeast US Winter is the whole risk
New England and New York sit at the end of the pipeline and compete with heating load for the same molecules, so winter basis blows out in a way that has no European equivalent. Both operate under RGGI. ISO-NE procures capacity through a forward auction; NYISO runs ICAP spot and strip auctions with a separate in-city requirement for Zone J that reflects transmission constraints into New York City.
Canada Supply, egress and two very different power markets
Alberta is the cleanest teaching case for scarcity pricing anywhere in the programme: one energy-only pool price for the entire province, with no nodes and therefore nothing locational to trade. Ontario is the opposite — nuclear-heavy, centrally dispatched, mid-transition to a renewed market design. AECO gas carries both egress risk and an FX leg, which is why the Canada packs treat currency as an explicit risk factor rather than a silent conversion.
Latin America Hydrology as the price driver
Brazil is not a bid-based market at all. ONS dispatches centrally on declared costs and a hydrological optimisation, and CCEE settles at PLD by submarket, so reservoir levels do the job that fuel prices do everywhere else — the closest analogue in this mapping is the Nordics. Mexico runs nodal PML pricing but with policy, not physics, as the dominant variable.
Basis & location spreads
| Spread | Type | Level | Daily vol | Why it moves |
|---|---|---|---|---|
| Waha – Henry Hub | Physical location, gas | −$2.19 avg H1 2026 | % | Takeaway-constrained associated gas. Record low −$7.95/MMBtu in late April 2026, negative for 25 straight days, back above zero from June as GCX expansion and Hugh Brinson came into service. The remaining basis pairs — AECO, Algonquin Citygate, Transco Z6 NY, SoCal Border — are published under licence and are not sourced here; they arrive with the gas market packs as manual, dated entries. |
Sources
- PJM Capacity Auction Procures 138,318 MW of Generation Resources — PJM Interconnection
- Review of the ERCOT Scarcity Pricing Mechanism (Project 52631) — Public Utility Commission of Texas
- CO2 Allowances Sold for $35.00 in 72nd RGGI Auction — RGGI, Inc.
- Washington, California and Québec sign agreement to link carbon markets — International Carbon Action Partnership
- The 9th U.S. LNG export terminal, Golden Pass, ships first cargo — US Energy Information Administration
- Permian Pipeline Constraints Push Waha Gas Prices Negative for 25th Straight Day — Pipeline & Gas Journal
- ERCOT's large load queue has nearly quadrupled in a single year — Latitude Media
- The One Big Beautiful Bill: Impact on the IRA's Clean Energy Tax Credits — Steptoe
JKM-linked LNG into Japan, Korea, China and India, alongside power markets that range from fully liberalised to state-set tariffs. Mapping in progress.
Mapping in progress
- Japan & Korea — JKM cargo pricing, JEPX power
- China — LNG term vs spot, provincial power reform
- India — imported LNG parity, IEX day-ahead power
- Singapore — LNG trading hub, USEP power pool
A major LNG exporter with an unusually volatile domestic power market — the NEM's five-minute settlement and extreme price caps make it a risk market of its own. Mapping in progress.
Mapping in progress
- NEM regions — QLD, NSW, VIC, SA, TAS spot and cap contracts
- East-coast gas — Wallumbilla hub, domestic reservation
- LNG exports — Gladstone trains and netback pricing
- WA — separate WEM market and domestic gas policy