13APR

JPMorgan warns on chemicals margin squeeze

3 min read

22:33UTC

Yara needs an 11% European price increase just to break even; BASF is exposed on spot gas until its Cheniere contract starts.

← Back to Europe's thinnest gas cushion since 2018 Jump to analysis ↓

PoliticsDeveloping

Key takeaway

Yara needs an 11% price rise to offset gas costs eating 20-22% of EBITDA in 2026-27.

JPMorgan warned this week that European chemicals margins face renewed compression with TTF above EUR 47/MWh. The most quantified exposure belongs to Yara International: higher gas costs are equivalent to 20% of 2026 EBITDA and 22% of 2027 EBITDA, requiring an 11% European price increase in both years to break even. Ammonia production uses natural gas as primary feedstock, so Yara has no substitution option at current technology.

BASF is exposed via spot gas purchasing at elevated prices. Its long-term Cheniere LNG supply contract begins mid-2026 but does not cover the current gap. Until that contract kicks in, BASF buys at whatever TTF offers. Bruegel confirms that industrial gas demand across the EU has remained depressed throughout 2026 with no recovery signs, even during periodic price dips. Demand destruction is the market's own price ceiling, but it operates with a lag, and it comes at the cost of European industrial output.

Deep Analysis

In plain English

Fertiliser and chemicals are among the most gas-intensive industries, because natural gas is both a fuel and a raw material. Companies like Yara (which makes fertiliser) and BASF (chemicals) consume enormous amounts of gas in their factories. With European gas prices near EUR 47/MWh, these companies' gas bills are consuming a large share of their profits. Yara says it needs to raise prices by 11% just to break even. If it cannot, it may close European factories entirely, which would reduce food production and chemical supply across the continent.

Deep Analysis

Root Causes

Ammonia production is fundamentally constrained by chemistry: the Haber-Bosch process requires natural gas both as a hydrogen feedstock and as fuel, consuming approximately 33 GJ of gas per tonne of ammonia produced. There is no viable substitute for natural gas in ammonia production at current green hydrogen costs (approximately EUR 6-8/kg, versus the EUR 0.8/kg natural gas hydrogen equivalent at EUR 25/MWh TTF).

BASF's spot gas exposure specifically reflects a procurement strategy error: the company hedged its 2022-23 gas demand through long-term contracts but allowed those contracts to roll off in 2024-25, expecting lower spot prices. Its Cheniere LNG contract beginning mid-2026 was designed to restore long-term supply certainty but the timing means it provides no protection during the current crisis.

What could happen next?

Risk
If TTF remains above EUR 45/MWh through Q3 2026, Yara is likely to announce additional European ammonia plant curtailments by June, reducing domestic fertiliser supply by an estimated 1-2 million tonnes.
Consequence
BASF's Ludwigshafen gas cost exposure at EUR 47/MWh TTF makes further German chemical capacity rationalisation economically rational regardless of any short-term supply normalisation.

Source Landscape

This story draws on neutral-leaning sources

Primary parallel: In 2021-22, TTF rising from EUR 25/MWh to EUR 200/MWh led to Yara closing its Montoir (France) and Porsgrunn (Norway) ammonia plants within nine months, removing 2.4 million tonnes per annum of European ammonia capacity permanently. BASF suspended Ludwigshafen ammonia production in late 2022. Current TTF at EUR 47/MWh approaches the levels that triggered those closures, though the 2022 spike was faster and more severe.

Counter-parallel: During the 2005-08 gas price run-up, European ammonia producers survived through temporary curtailments rather than permanent closures, because prices returned to sub-EUR 25/MWh by 2009. The 2026 situation differs: QatarEnergy's force majeure timeline is measured in years, not months, making temporary curtailment a commercially viable strategy only if producers have confidence in a normalisation date.

Yara's 20% EBITDA exposure at current TTF translates to approximately EUR 800-900 million in additional annual gas costs versus pre-crisis 2024 levels, based on Yara's 2025 EBITDA of approximately EUR 4 billion. The required 11% European fertiliser price increase conflicts with EU farmers' purchasing power after two years of elevated input costs.

BASF's Ludwigshafen complex is the largest chemical site in the world by integrated output value, consuming approximately 3.5 TWh of gas per day. Each EUR 1/MWh TTF increase adds approximately EUR 1.28 billion to Ludwigshafen's annual gas cost. At EUR 47/MWh versus a 2019 baseline of EUR 15/MWh, the cumulative additional burden on Ludwigshafen alone is approximately EUR 41 billion per year, explaining BASF's accelerated capacity rationalisation programme.

Consensus view: Goldman Sachs European chemicals team assessed in its April sector note that ammonia producers face a permanent cost floor problem: North African competitors (Egypt, Morocco, Algeria) source gas domestically at EUR 5-8/MWh equivalent, giving them a structural EUR 40/MWh advantage over European producers at current TTF, sufficient to undercut European ammonia prices even after shipping costs.

Yara's 11% required price increase assumes European buyers absorb the full cost differential; demand substitution to imported ammonia is already occurring.

Counter-view: SEB Research commodity analyst Bjarne Schieldrop argued that the European fertiliser market cannot simply be replaced by imports: nitrogen fertiliser applied in April for the summer growing season requires physical storage and just-in-time distribution networks that take years to relocate. European farmers who depend on Yara's distribution network face a practical supply constraint regardless of price, limiting the demand destruction risk in the short term.

Key tension: Whether European agricultural dependence on domestic fertiliser production provides a structural demand floor for Yara and BASF that limits near-term demand destruction, or whether price pass-through triggers enough farmer substitution to accelerate European fertiliser production closures.

Sources:EU Energy Live

Mentions:JP Morgan →Iran International →BASF →Cheniere →France →Prima →QatarEnergy →Egypt →Qatar →Goldman Sachs →Norway →Morocco →Algeria →Bruegel →Dutch TTF →

First Reported In

Update #1 · Europe's thinnest gas cushion since 2018

EU Energy Live· 13 Apr 2026

Read original →

Different Perspectives

European Commission

Commissioner Jorgensen formally acknowledged the post-Russia energy security framework cannot absorb the LNG shock, cutting the mandatory storage target from 90% to 80% and explicitly warning that normalisation is not foreseeable even with immediate peace. The Commission is now dependent on coordinated member state LNG purchasing and demand flexibility to bridge the remaining gap.

Germany

Germany holds the EU's largest storage estate but entered injection season at 23.32% fill with a 4.3 TWh/day injection ceiling that physically prevents any sprint recovery; the Bundeswirtschaftsministerium has maintained its early warning stage since July 2025. An escalation to Alarmstufe, which would trigger compulsory injection obligations, remains live if storage fails to rise through April.

QatarEnergy

QatarEnergy declared force majeure on European LNG contracts citing Ras Laffan strike damage, while the Gulf Research Centre assessed the declaration may also reflect a commercial decision to reallocate volumes toward higher-priced Asian spot markets without triggering breach penalties. Independent engineering confirmation of damage extent has not been published, leaving legal and commercial uncertainty unresolved.

Equinor / Norway

Norway remains the EU's largest pipeline gas supplier and benefits from sustained elevated TTF; Norwegian pipeline capacity has partially offset the Russian supply loss but cannot close the structural gap. Norway Zone 4 power prices at EUR 2/MWh on 13 April illustrate how hydro-dominated systems are structurally decoupled from the gas price shock affecting continental Europe.

Italy

Italy cleared day-ahead power at EUR 133/MWh on 13 April, four to five times the Iberian equivalent, because gas-fired plants set the marginal price for approximately 90% of generation hours. Italy's circa 40 GW of gas-fired CCGT capacity, built when gas was cheap and nuclear was politically blocked, is now a structural liability at EUR 47/MWh TTF.

Spain

Spain cleared at EUR 29/MWh on the same day Italy paid EUR 133/MWh, the starkest single-day demonstration that its renewable energy investment is translating directly into price shock insulation for industry. Iberian interconnector constraints at the Pyrenees mean Spain cannot export this advantage to northern European markets at scale.