Energy shock in industrials: which margin adjustments buyers will accept

On a €60m industrial deal, the seller removed the March energy hit from EBITDA. We accepted a third of the adjustments. What held: signed contracts and automatic indexation. What did not: 2025 unit costs and mark-to-market gains.

Six weeks into the conflict that began on 28 February, the first Q1 2026 management accounts are reaching data rooms. Brent closed at $72.48 on 27 February and at $112.57 a month later. March was its biggest monthly rise since the contract started in 1988. Qatar halted LNG production on 2 March. By 9 March, TTF gas had moved from about €32 to €54/MWh and French day-ahead power had roughly doubled, because gas-fired plants set the marginal price. The March S&P Global PMI for French manufacturing showed the sharpest rise in input prices since late 2022.

Sellers have responded quickly. Most information memoranda we now receive show a "normalised" EBITDA that removes the energy hit, as if Q1 2026 were an accident. Some of that is fair. Some of it treats the shock as temporary when the target's contracts say otherwise. Below is how we dealt with this on a recent buy-side mandate, with figures anonymised and rounded.

The target and the seller's bridge

The target is a French metal surface treatment business. Revenue is about €50m. Gas is used in its furnaces and treatment baths, so energy represents around 9% of revenue. The seller asked for an enterprise value of €60m, about 8x a normalised LTM March 2026 EBITDA of €7.5m.

Reported LTM EBITDA was €6.4m. The seller's bridge to €7.5m had two add-backs:

1. Energy restatement, +€0.71m. Q1 2026 gas and electricity volumes were repriced at the 2025 average unit cost.
2. Pass-through catch-up, +€0.38m. This was the energy surcharge that "will be" invoiced to customers for costs incurred in Q1.

The bridge had a third item that was less visible. The reported €6.4m already included a €0.29m mark-to-market gain on gas swaps covering April to December 2026, booked in other operating income in the monthly reporting.

1. Pass-through clauses: read the contract, then the invoices

The seller's case rested on the claim that "our customers bear energy costs". We sorted the top 30 customers, about 80% of revenue, by the type of clause in their contracts:

• Automatic indexation (41% of revenue): the price is revised each quarter using a published gas index averaged over the previous quarter. Q1 costs are therefore recovered through Q2 invoices, one quarter late, and two contracts cap the revision at 8%.
• Renegotiation clause (27%): the parties "will meet" if energy costs move by more than a threshold. Nothing is automatic.
• No clause (32%): annual price lists or purchase orders. The only route is article 1195 of the Civil Code, the hardship provision, which lets a party ask for renegotiation after an unforeseeable change. It does not suspend performance, and several of these contracts waive it.

We accepted the catch-up only for the first category, recalculated on contract terms with the caps applied: €0.17m. We checked it against the surcharge lines on the first April invoices. For the other two categories, management showed letters sent to customers, but no signed amendment. A request is not a price. The remaining €0.21m stayed out of EBITDA, and we modelled it as a downside in the business plan, not in the price.

The lag deserves separate attention. With a one-quarter delay and caps, the target carries the cost on its working capital while prices rise. We included this in the normalised NWC discussion. It is not an EBITDA add-back.

2. Hedging: realised and mark-to-market do not belong together

The target had hedged 55% of its 2026 gas volumes with swaps taken out in late 2025. Two different amounts showed up in the accounts:

• Realised settlements on Q1 volumes (€0.12m). These reduce the cost of gas actually consumed in Q1. They belong in the energy line, next to the cost they offset, and that is also how French GAAP presents a qualifying hedge (PCG article 628-11, from ANC regulation 2015-05). We moved them from "other income" to energy costs. The effect on EBITDA is nil.
• Mark-to-market on future volumes (€0.29m). This is the value today of a price advantage on gas that will be consumed between April and December. It is not part of Q1 earnings. Under French GAAP, an unrealised gain on a hedge is not taken to the income statement ahead of the hedged item. In IFRS groups, a contract that falls outside own-use or hedge accounting brings these swings into profit or loss. In both cases, we remove it from EBITDA.

Here, the seller added back the gross energy over-cost and also kept the mark-to-market gain. That counts the same protection twice. The value of the swaps is real, but it belongs in one place only. Either the forecast uses the hedged price for the hedged volumes, or the bridge shows the swap as a cash-like item at its realisable value. It cannot be in both.

3. Pro forma energy cost: only with a signed contract

The €0.71m restatement assumed that 2025 unit costs are the "normal" level. Nothing in the data room supported this. 2025 is no longer a reference point for French electricity in particular: ARENH, which gave access to nuclear power at €42/MWh, ended on 31 December 2025, and its successor mechanism provides no regulated price or volume. Forward prices also tell their own story: the French 2027 baseload contract rose about 15% in the first ten days of March. The Banque de France's 25 March projections assume Brent at up to $92 in Q2 2026 and gas at €51/MWh.

We accepted one part. On 20 March the target signed a fixed-price electricity contract for April 2026 to December 2027, covering 70% of its volumes. Repricing that share of Q1 consumption at the contract price is a pro forma based on a signed document: +€0.24m. For gas and the rest of the electricity volumes, Q1 actual cost stays in normalised EBITDA. If the seller expects prices to fall back, that is a forecast. It belongs in the business plan, where the buyer can apply its own price curve.

Where we landed

At the same multiple, the gap is close to €8m. The parties did not split it down the middle. They agreed on a €56.5m headline, with €1.5m deferred and payable if the energy surcharge actually recovered in H2 2026 reaches an agreed level, measured on invoices. That moved the disagreement from the price to a fact that both sides will be able to observe.

What to do now

• Sellers: separate the Q1 energy effect into contracted recovery, requested recovery and unrecovered cost before the IM goes out. Only the first will survive the buyer's work, so lead with it.
• Buyers: ask for the top customer contracts and the first post-shock invoices, not a summary of "pass-through terms". Check caps, reference index, lag and any waiver of article 1195.
• Both: list every energy derivative with its notional, maturity, realised amount and mark-to-market. Agree up front whether its value sits in the forecast or in the equity bridge.
• CFOs: if a supply tender is in progress, try to sign before the data room opens. A signed contract is the only pro forma energy cost a buyer will accept.
• In the SPA: where the gap rests on recovery that has not happened yet, measure it with a short deferred payment based on invoiced surcharges rather than arguing over a run-rate.

This note is general information, not advice on a specific transaction.