What's Driving the Price Right Now?

The current electricity price is not an isolated power market story. For industrial procurement in the US, three factors are converging: elevated gas prices, geopolitical risk premiums on energy flows, and a market where gas-fired generation still sets the marginal price in peak hours. In early March 2026, the loss of Qatari LNG volumes and the blockade of the Strait of Hormuz triggered an energy shock that is transmitting directly from the gas market into power forwards.

Gas Remains the Key Driver of Power Prices

The EIA confirms that higher natural gas prices in early 2026 have pushed wholesale electricity prices higher across major US markets. PJM day-ahead prices have tracked the Henry Hub rally closely, as gas-fired plants continue to set the marginal price during peak demand hours. This is particularly relevant because despite the rapid growth of renewables, gas generation still accounts for roughly 40% of US electricity output. For procurement teams, this means: anyone buying power or negotiating price escalation clauses with power-intensive suppliers needs to be watching the gas market.

The Iran Conflict Reaches the Power Market Through Gas and LNG

On March 2, QatarEnergy shut down LNG production at both main facilities following drone strikes from Iran. Qatar supplies roughly 20% of global LNG trade. The Strait of Hormuz has since been largely closed to shipping. Bruegel notes that Hormuz handles roughly 20 million barrels of oil per day plus LNG exports from Qatar and the UAE totaling about 20% of global LNG trade. For electricity, this matters because a gas supply shock translates immediately into US wholesale power prices during hours when gas plants are on the margin. The effects are already visible: industrial facilities in the Gulf Coast region have reported curtailing operations due to rising energy costs.

US Power Markets Remain Regionally Diverse but Broadly Exposed

The EIA notes that wholesale electricity prices vary significantly across US regional markets — ERCOT, PJM, MISO, CAISO, and others each have different generation mixes and price dynamics. However, because gas-fired generation plays a significant role in all major markets, the current Henry Hub price increase is transmitting broadly. Markets with higher gas dependency in their generation stack — such as ERCOT and ISO-NE — are seeing the largest price impacts.

Negative Price Hours Don't Automatically Help Industrial Buyers

The EIA also shows that negative electricity prices have become more frequent in certain US markets, particularly CAISO and ERCOT during periods of high renewable output. For industrial procurement, this is relevant but often misunderstood: more negative hours benefit flexible consumers and behind-the-meter models, but they don't automatically reduce costs for standard baseload or fixed-shape supply contracts. For most procurement teams, the forward market remains the more relevant benchmark.

What Does This Mean for US Procurement?

Make electricity costs more visible across your supplier portfolio.

If you're sourcing categories with high energy content, electricity should be explicitly visible in the cost breakdown — not just mentioned as a general cost driver. For power-intensive suppliers, this is a front-and-center issue right now.

Don't confuse spot prices with contract prices.

A supplier may point to high day-ahead or forward market prices. What matters for the negotiation is whether they're buying spot, structured, or long-term. This is especially relevant right now: the spot market swings daily between $22 and $78/MWh, while forward contracts sit around $48/MWh. The supplier's actual procurement logic makes a major difference.

Look closely at power-intensive processes.

Most relevant are suppliers with high shares of machining, heat treatment, cooling, compressed air, or continuous production. These are the cases where higher wholesale prices are most likely to flow into near-term price discussions.

What's Currently Plausible in Negotiations and What to Verify Separately

Currently plausible are references to an elevated wholesale price level and higher hedging costs, especially when suppliers procure a significant portion of their power on short-term or rolling contracts. The connection between the LNG supply shock, the Henry Hub price increase of over 38%, and wholesale power prices is real and well-documented.

What you should verify separately are blanket 'energy surcharges' that bundle wholesale costs, capacity charges, transmission, profile risk, renewable energy credits, margin, and contingency into a single line item. The key negotiation point is not whether electricity is expensive, but which portion of the increase actually comes from the power market and which comes from the supplier's contract structure or margin.