PJM Power Prices Triple CAISO's as U.S. Gas Demand Splits Along Regional Lines
A $44 per megawatt-hour gap between PJM and California spot power prices on Tuesday exposes a deepening fracture in where U.S. gas-fired generation growth is actually landing.
PJM Western Hub spot power traded at $72.38 per megawatt-hour on Tuesday (2026-07-14) while California's CAISO NP15 cleared at $28.50 — a gap of more than $43 that captures the regional divergence now reshaping U.S. natural gas demand. ERCOT and PJM, where renewable capacity lags behind load growth, are absorbing most of the country's incremental gas-for-power burn. California is not.
The EIA's May Short-Term Energy Outlook put U.S. electric-sector gas consumption at 43.7 billion cubic feet per day for summer 2026 (June through September), flat with summer 2025 and 4% above the five-year average. The agency expects overall electricity demand to rise 2% this summer — yet forecasts no increase in gas generation, because renewables are absorbing the increment in markets like CAISO where solar resources are most abundant.6
NYMEX Henry Hub front-month was trading at $2.89 per million British thermal units on Tuesday (2026-07-14). The June contract staged a 7.4% weekly rally by its Friday (2026-05-15) settlement at $2.96, driven by expectations of summer heat, stronger gas-for-power demand, and sustained LNG export volumes — conditions most likely to persist in ERCOT and PJM rather than in CAISO.1,2
The Edison Electric Institute reported U.S. electricity generation up 2.2% year-over-year in its most recent weekly reading, with total generation over the prior year up 1.8%. Both figures are running ahead of what the May STEO implied for the full summer, suggesting demand is firmer than seasonal norms. That firmness plays more directly into gas demand across eastern and Texas grids than in the west.3
LNG exports are providing a second floor under gas prices. Weekly vessel departures reached 141 billion cubic feet in the week of 2026-05-11, up 26 Bcf week-on-week despite maintenance activity at several export facilities. Qatar's Ras Laffan complex is still running at reduced capacity after earlier damage took out roughly 20% of global LNG supply, tightening Atlantic Basin availability and supporting U.S. feedgas demand.1,2,3
Not all eastern markets are straightforwardly bullish for gas. In MISO, coal remained competitive through the first four months of 2026, with dark spreads — the gap between coal fuel costs and wholesale power prices — still favorable across the Midcontinent. Where the grid is coal-heavy and local gas infrastructure constrained, the price signal for incremental gas burn is less clean.4
The longer arc points toward 2027. The EIA forecast in May that gas consumed by the electric power sector will set a record next summer, driven by continued data-center load growth and further industrial electrification. Data-center power consumption is projected to reach 945 terawatt-hours globally by 2030, roughly 3% of world demand, and gas-fired capacity is widely cited as the preferred balancing resource given its dispatchability relative to intermittent supply.6,5
CAISO's structural position is the outlier. California has built enough solar and wind to depress afternoon spot prices below levels that can support incremental gas dispatch — an outcome ERCOT and PJM are some years from replicating. The regional power price split on Tuesday (2026-07-14) is less a weather artifact than a preview of what gas demand geography looks like as the grid's renewable build-out spreads eastward at an uneven pace.
Whether PJM and ERCOT gas burn holds through late summer depends on how heat forecasts verify across the eastern seaboard over the next several weeks. A miss on late-July temperatures would expose the assumptions behind the May rally and bring storage trajectory back into focus.3