The Merit Order: Why Gas Prices Set the Cost of Wind Power

In mid-September 2026, the Dutch TTF gas benchmark, the reference price for natural gas across Europe, settled at €82.00/MWh. At that level, the fuel cost alone for a standard gas-fired power plant running at typical efficiency exceeded €160/MWh of electricity produced, before adding a single euro of carbon or other costs.

Here is the part that should stop you. On the same day, the wholesale price of electricity from a wind turbine, which burns no fuel at all, tracked almost exactly that gas-linked figure. A fuel price set in Rotterdam was, in effect, pricing power from a machine that consumes nothing.

This is not a market failure or a political decision. It is the direct output of a pricing rule called the merit order mechanism, which governs liberalised electricity markets across Europe, Australia, and parts of the United States. Understanding it is the prerequisite for making sense of your energy bill, utility company earnings, and the economic logic behind the entire renewable buildout.

After this, you will be able to trace how a gas price in Rotterdam flows into a household bill in Berlin, and why every solar panel and battery installed weakens that chain link by link.

The auction that happens every hour: how electricity markets actually clear

Picture yourself watching an electricity market clear in real time. Generators across the grid submit bids, each stating how much power it can supply and the minimum price per megawatt-hour it will accept. Nothing about that setup hints at the strange result waiting at the end.

The system operator sorts every bid from cheapest to most expensive marginal cost, then calls on generators in sequence, starting at the bottom of the stack. It keeps working up the ladder, adding one plant at a time, until total supply matches total demand for that interval.

That ladder has a predictable order:

1. Nuclear and run-of-river hydro, near-zero marginal cost
2. Wind and solar, also near-zero because there is no fuel to buy
3. Coal and lignite
4. Combined-cycle gas turbines (CCGTs)
5. Open-cycle peaker gas plants
6. Oil and diesel units, called only in emergencies

For thermal generators, marginal cost is dominated by fuel. That single fact ties their bid prices directly to whatever the fuel market is doing that day, which is why gas plants tend to sit high in the stack when gas is expensive.

Now for the rule that makes the whole thing surprising. The market does not pay each generator its own bid. It pays every dispatched generator the price of the last unit needed to meet demand, the most expensive plant in the stack that hour.

The core rule: The last unit needed to satisfy demand sets the price for all. If a gas plant is that last unit, the wind farm, the nuclear station, and the hydro plant all earn the gas plant’s price.

This is the structural fact everything else rests on. When gas sets the marginal price, every generator running that hour, including the one that spent nothing on fuel, collects a gas-linked price. And you, the consumer, pay it. Internalise this, and the rest of the chain becomes readable.

How a gas price in Rotterdam becomes a bill in Berlin

The transmission from gas market to power bill runs through a handful of links, and each one is worth slowing down for. It starts with TTF, the benchmark that feeds directly into the fuel cost of every European gas-fired station.

LNG market integration means that a supply shock originating in the US Gulf Coast, through cargo rerouting or export terminal disruptions, now feeds into TTF within days, tightening the link between American production decisions and the European gas price that ultimately sets your electricity clearing price.

A CCGT converts gas to electricity at roughly 50% efficiency, which means it takes about two units of gas energy to make one unit of electricity. The arithmetic from there is simple: divide the gas price by the efficiency, and you have the fuel cost per megawatt-hour of power.

Run it with the September numbers. At TTF of €82.00/MWh and 50% efficiency, the fuel cost alone lands at roughly €160/MWh, about 16 cents per kilowatt-hour, before carbon or other variable costs enter the picture.

Implied CCGT fuel cost: approximately €160/MWh at TTF €82/MWh and 50% efficiency.

You can rebuild that calculation yourself at any gas price. The table below shows the implied fuel cost across three TTF levels and two efficiency assumptions, so the whole conversion is replicable.

Now compare that implied cost to what electricity actually sold for. On 15 September 2026, the Germany/Luxembourg day-ahead price was €180.07/MWh, per the E&C Index, with several other markets clustered nearby.

Look at how close those wholesale prices sit to the gas fuel cost you just calculated. That proximity tells you something specific: at these gas levels, gas is not occasionally nudging the market. Gas is the market, sitting at the margin and setting the clearing price for everyone.

Why your bill does not move in lockstep with wholesale prices

If gas doubled tomorrow, your bill would not double the next day. Three damping mechanisms sit between the wholesale price and what you actually pay.

The first is hedging. Suppliers buy much of their power in advance through futures and long-term contracts, so a short wholesale spike hits only the unhedged volume rolling off soon, not the whole book.

Electricity futures markets allow suppliers, industrials, and traders to lock in prices well ahead of delivery, which is exactly the hedging mechanism that sits between a volatile wholesale clearing price and the more stable figure on a retail bill.

The second is regulation. Many EU countries run capped or social tariffs that slow or limit how fast wholesale shocks reach households, shifting the risk onto suppliers or the state.

The third is the structure of the bill itself. Network charges, taxes, levies, and policy surcharges make up a large share of what you pay, so even a big wholesale move produces a less-than-proportional change in the final figure.

There is one exception worth knowing. If you are on a dynamic or time-of-use tariff, the merit order becomes visible directly, cheap midday windows when solar floods the stack, expensive evening peaks when gas returns. Both ACER and Ofgem have documented that the wholesale-to-retail pass-through is real but partial and lagged, not instant.

What happens to the merit order when wind and solar dominate the stack

Now run the market forward as a time-lapse and watch the stack change shape. Every new solar farm and wind turbine adds zero-marginal-cost capacity near the bottom of the ladder, pushing gas progressively further from the top.

This produces a characteristic daily price curve. As midday solar output surges, it displaces gas from the marginal position entirely, and prices sink. As the sun fades in the evening, gas re-enters the stack, retakes the margin, and prices climb back up. The shape of your daily electricity price is, quite literally, the shape of the merit order flexing hour by hour.

This is not a forecast. It is already happening, and the International Energy Agency’s data shows how fast:

• EU all-renewables share: 44% in 2023, rising to about 50% in 2024 and roughly 52% in 2025
• EU solar and wind specifically: 26% in 2023, about 30% in 2024, and around 33% in 2025
• Global renewables share: 45% in 2023, 50% in 2024, and approximately 55% by 2026

The milestone: Renewables reached roughly 50% of global electricity generation in 2024, per IEA data. Market analytics also point to around 185 negative-price hours across EU bidding zones in the 30 days to mid-September 2026, with 55 in Spain alone (a figure flagged as not independently verified at source, but directionally illustrative of the pressure).

The IEA trajectory tells you the merit order is already changing structurally, not theoretically. At a 50%-plus renewable share, gas is no longer the habitual marginal unit, and the economics of every plant in the stack shift with it. Germany’s day-ahead price of €180.07/MWh on 15 September 2026, alongside negative-price hours recorded in earlier months, captures the widening volatility band.

Renewable energy’s market transformation extends beyond electricity pricing mechanics; it is restructuring the capital allocation decisions of oil majors, sovereign wealth funds, and industrial energy users simultaneously, as the declining frequency of gas-at-the-margin hours changes the long-run investment calculus for fossil fuel infrastructure.

The cannibalisation problem and what it means for new investment

There is a catch that matters intensely if you are looking at renewable energy as an investment. It is called cannibalisation.

The more solar and wind capacity enters the market, the more often prices collapse during exactly the high-output hours when those assets are generating. Renewables erode their own spot-market revenue by driving down the very prices they earn when they produce most.

This does not stop the energy transition. It does reshape its economics, pushing new projects away from pure merchant models and toward power purchase agreements, contracts for difference, and capacity support mechanisms.

Contracts for difference (CfDs) are the leading policy response. A CfD guarantees a generator a fixed strike price: the government tops up the difference when market prices fall below it and claws back the surplus when they rise above. That decouples the investor’s revenue from spot volatility while leaving the merit order intact to send short-run dispatch signals.

Battery storage as a merit order intervention

It is tempting to file battery storage under green technology. For understanding the market, that framing misses the point. Storage is a market design tool that physically changes which generator sets the marginal price, and when.

Grid-scale energy storage has moved from an optional policy ambition to a structural requirement for any market aiming to suppress gas-at-the-margin hours, because without the ability to time-shift cheap surplus power, renewable capacity additions alone cannot break the TTF-to-clearing-price transmission chain.

The mechanism runs as a sequence:

1. Solar output peaks at midday and gas exits the merit order
2. Prices fall toward midday, sometimes toward zero or below
3. The battery charges, lifting midday demand slightly
4. Solar output declines into the evening
5. Gas re-enters the merit order to cover the evening
6. The battery discharges, adding supply and suppressing the price spike

Both ends of that cycle cut volatility. Charging props up midday prices that would otherwise crater, while discharging adds evening supply that blunts gas-driven peaks. The more cheap renewable surplus you can time-shift, the less the international gas price feeds through to what buyers pay.

Connect this back to cannibalisation. Storage monetises exactly the surplus that would otherwise create negative prices and destroy merchant revenue, so it addresses the transition’s biggest commercial weakness while compressing the gas transmission chain.

The structural case: IWR, through Managing Director Dr. Norbert Allnoch, has argued for expanding wind and solar alongside privately financed battery storage as a priority for strengthening the economy, positioning storage as core grid infrastructure rather than an optional add-on.

Here is why the mechanism matters in hard numbers. Every hour a battery keeps gas off the margin is an hour where that implied €160/MWh fuel cost does not set the clearing price for the entire market. Fewer gas-at-the-margin hours means a shorter, weaker transmission chain from Rotterdam to your bill.

For anyone weighing grid-scale battery projects or utility equities, this is the framing that separates the technology story from the market economics. Storage projects live or die on the spread between peak and off-peak prices, and that spread is itself a product of the merit order.

Specific authoritative figures for installed battery storage capacity were not available in the research base. For current numbers, consult the IEA, ENTSO-E, or national regulators directly.

What the merit order transition means for the next decade of electricity markets

Pull the chain together and it reads cleanly. Gas prices set the marginal cost, the merit order transmits that cost to every generator running, renewable growth gradually displaces gas from the marginal position, and storage locks in that displacement across more hours of each day.

The reform debate is worth understanding honestly. Pay-as-bid pricing, where each generator earns its own bid rather than the clearing price, is raised often in political circles. Technical analysis from ACER and academic bodies holds that it would not lower prices, because generators would simply raise their bids toward the expected clearing price, reducing transparency without cutting cost.

The reforms with broader institutional backing sit alongside the merit order rather than replacing it. CfDs retain efficient short-run dispatch signals while shielding investors from spot volatility through guaranteed strike prices and two-way settlement. Some analysts also float a split-market design, one long-term contract layer plus a short-term balancing market, though this remains an evolving option rather than settled consensus.

Watch three structural variables to gauge how fast the merit order changes:

• The pace of renewable capacity additions, with global share heading toward roughly 55% by 2026 per IEA data
• The volume of storage deployed to time-shift cheap surplus power
• The market design reforms, principally CfDs, that decide how investment risk is shared between generators, consumers, and governments

The transition risk is specific. The road to lower average prices runs through a stretch of heightened volatility, because gas keeps its marginal role during scarcity, calm and cloudy winter evenings, even as its average frequency falls. When gas is expensive during those hours, the spikes in a renewable-heavy system can be sharper, not milder.

The core takeaway: The link between gas prices and electricity prices is structural, not incidental. Dismantling it takes storage, market design, and demand flexibility as much as raw generation capacity.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Past performance does not guarantee future results, and forward-looking projections are subject to market conditions and various risk factors.