France's subsidised wind and solar can now sell balancing services

A decree that took effect in France on 29 October removed the rule that kept subsidised wind and solar farms out of the balancing mechanism. In the same seven days to 3 November, Britain confirmed that demand projects the government picks can be moved up the connection queue, Norway published figures showing data centres now hold about half of all reserved grid capacity in the country, and Finland and Sweden reset the price of being balanced and the size of the zonal hedge on offer. The thread running through them is permission: which assets may sell a service, and which projects may hold a connection.

France let supported wind and solar into the balancing mechanism

Decree 2026-997 of 26 October was published in the French official journal on 28 October and took effect on 29 October. Its most consequential article, a new R. 314-17-1 in the energy code, says that a feed-in tariff contract no longer stops an installation taking part in transmission and distribution system services or in the balancing mechanism. A producer can offer downward adjustment, and upward adjustment in the narrower case where the buyer had asked it to stop or limit output. The plant keeps its contractual payment, and that payment is calculated on the volume it would have produced without that participation.

Two conditions decide whether this is worth anything. Volume corrections only count when the adjustment offer was priced inside a range that the tariff orders will set, and those orders have not been published. The same decree raises the cost of walking away: a producer who ends a support contract early now faces a floor of EUR 10,000 per MW installed, or per MWp for solar, on top of two alternative methods for calculating the full indemnity. The French energy regulator had recommended a floor of EUR 30,000 per MW in its November 2025 opinion, and the final text kept the lower figure. A third change creates a common framework for negative-price periods, under which the tariff orders define when output stops being paid and what compensation follows; that compensation does not depend on how much the plant actually produced, is paid only after a minimum duration, and can be capped.

If you own or aggregate PV, wind or C&I load in France, the work starts with measurement. Payment under the contract now rests on a counterfactual: what the plant would have produced had it not been dispatched for the system. That number has to be produced, defended and transmitted, and the decree moves the deadline for regularised data to 15 April each year, or 15 September for some gas cogeneration. Check which tariff order governs your contract before assuming the plant qualifies, because the decree opens a door and the operating rules still sit downstream. Then price the balancing offer against the range those orders will set.

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Britain, Norway and the Netherlands moved on who holds grid capacity

On 28 October the Department for Energy Security and Net Zero published its response to the consultation on accelerating network connections for strategic demand, drawing on 156 replies. It will proceed with two measures. NESO will be able to prioritise demand projects the government identifies as strategic, by reallocating capacity released when other projects leave the queue, by reserving future capacity for projects that are not yet ready to join it, and by giving ready strategic projects a higher position when the next batch forms. Separately, data centre connections after 2030 will be aligned to regional infrastructure targets that limit how much can connect in each region, judged against grid capacity, expected data centre demand, water and land availability, and the needs of other kinds of demand.

These measures sit on the demand side. Generation and storage were handled by the earlier reform, which the government says deprioritised up to 300 GW of excess battery and solar projects. What changes now is the competition for demand capacity and the cost of holding it. Ofgem is consulting on a data centre commitment fee of GBP 237,500 to GBP 712,500 per MW of contracted capacity, which the response puts at 2.5% to 7.5% of average project capital expenditure, expected to apply above 40 MW where a project connects to or affects the transmission system, with a decision due in the first quarter of 2027. The response also sets out three flexibility routes in development: alternative connection agreements covering non-firm terms, phased ramps and hybrid firm plus interruptible capacity; voluntary flexibility services for large users; and a last-resort power for the system operator to direct large loads to curtail.

Norway supplied the arithmetic for why demand has become the scarce claim on a grid. On 29 October NVE published its 2026 power market scenarios. Data centres use about 3 TWh a year in Norway today, and about half of all reserved grid capacity in the country is now reserved for them. The projects that already hold allocated capacity could by themselves take data centre consumption to around 25 TWh by 2035, more than eight times today. In a scenario where consumption grows that fast and no new onshore or offshore wind is built, a normal-year surplus of roughly 15 TWh becomes a deficit of 4 TWh in 2035, with single years needing up to 30 TWh of imports and average prices 35% to 55% above NVE's earlier estimates. NVE is explicit that these are scenarios rather than a forecast.

The Dutch answer is to take capacity back. On 29 October the regulator ACM published a code change proposal from Netbeheer Nederland that widens the use-it-or-lose-it rule for transport capacity. Today it reaches only connected customers. The proposal would let TenneT apply it to parties that hold contracted transport capacity but no connection yet, where there is a reasonable suspicion the capacity will stay unused. The holder gets a conversation first and has to show the capacity will still be used, for instance by moving it to another project that already has its permits. The same proposal narrows the exemption for vital and essential services.

If you operate BESS, EV chargers, HVAC systems, C&I loads or PV assets behind a connection in these markets, start with the capacity you already hold. Capacity that sits unused is turning into something you can be asked to justify, explicitly in the Netherlands and through progression milestones in Britain. Flexibility, meanwhile, is being priced as the entry ticket for large loads: Britain is building non-firm and phased connection agreements so that demand can connect earlier by accepting curtailment. A site that can prove it will move load on request is buying a connection date with that proof. If you want to scope what your own loads could offer before taking it further, our knowledge bot Fusie is the quick way in.

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Finland raised the cost of being balanced, Sweden widened the hedge

Fingrid said on 27 October that the volume fee charged to balance responsible parties for every megawatt-hour produced or consumed in Finland will be EUR 0.2/MWh in December 2026 and EUR 0.64/MWh from 1 January 2027, with other balance service fees unchanged. The fee covers the reserves that hold system frequency, and Fingrid sets it from forecasts of reserve costs and imbalance power trading. European Current records that the same fee stood at EUR 1.73/MWh at the start of 2025 and EUR 1.35/MWh at the start of 2026, and that Fingrid set it to zero for October and November because reserve costs came in below forecast. The 2027 level is therefore about half the early-2026 rate and more than three times what December will charge.

The day after, Svenska kraftnät raised the volume of EPAD contracts it auctions, from about 15% to about 20% of transfer capacity between SE2 and SE3 and between SE3 and SE4, starting in December 2026. EPADs hedge the gap between a Swedish bidding zone price and the Nordic system price, and the operator has auctioned them since 2023. The increase runs alongside a regional extension it had already announced, covering SE1 and the Lithuanian price area, and it is studying a longer auction horizon. Svenska kraftnät frames the decision as a response to demand from market participants in a period of geopolitical uncertainty, disrupted energy supply chains and continued price volatility.

These two land on opposite sides of the same profit and loss account. Finland adds a per-megawatt-hour cost to every unit a portfolio produces or consumes, which bites hardest on assets that cycle often, so a 2027 budget built on the current zero rate is already wrong. Sweden makes it cheaper to carry zonal price risk, and the extension it has announced brings a Baltic price area into the same auction. For a portfolio spanning the Nordics and the Baltics, the useful step this month is to re-run next year's numbers with the Finnish fee in them, and to check whether a deeper EPAD book changes which zone you would rather contract in.

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Britain asked its operating wind and solar whether they want a fixed price

Also on 28 October, the same department opened a consultation on a Wholesale Contract for Difference, aimed at low-carbon plants already operating in England, Scotland and Wales. It closes on 9 December. The consultation covers eligibility, allocation and auction design, commercial arrangements, the effect on the electricity market and the legislation required, and asks about a hybrid model for plants accredited under the Renewables Obligation.

European Current's read of the proposal fills in the shape. Contracts would run 5 or 10 years, awarded in a single auction rather than annual rounds, expected towards the end of 2027 with delivery from 2028. Up to 33.2 GW would be eligible, or 29.8 GW if only plants above 5 MW can bid. Standalone batteries are proposed to be excluded, and co-located storage would sit under the standard CfD. The pull comes from the other side of the ledger. The Electricity Generator Levy, which has taken 55% of revenue above GBP 82.61/MWh since 1 July 2026 and was due to end in 2028, is extended in the Budget published the same day until the longest of these contracts ends, and holders of a Wholesale CfD are exempt from it.

An owner of operating British wind or solar now has a choice with a date on it: keep merchant revenue and the levy that sits above it for another decade, or lock a strike price for up to ten years. The government warns in its own documents that the scheme may discourage long-term power purchase agreements and thin the forward market. For anyone who buys or sells British PPAs, that is the line to watch, because a thinner pool of sellers moves the price long before the first contract is signed. If you run storage, the proposal leaves you where you are: standalone batteries fall outside it, so your revenue stays merchant while some of the generation around you may not.

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Regulatory and market watch list

• France: the tariff orders that set the price range inside which an adjustment offer counts toward a supported plant's contractual volume, and the negative-price compensation parameters, are still to come (L'EnerGeek).
• Britain: the Wholesale Contract for Difference consultation closes on 9 December 2026 (DESNZ).
• Britain: Ofgem's decision on the data centre commitment fee is due in the first quarter of 2027, before the next NESO application window, and its consultation on self-build and transfer of transmission connections closes on 13 November (DESNZ).
• Netherlands: ACM has the use-it-or-lose-it code change in front of it, case ACM/26/202624, and has not yet decided (ACM).
• Finland: the balance service volume fee steps to EUR 0.64/MWh on 1 January 2027 (Fingrid).
• Sweden and Lithuania: the larger EPAD volumes start in December 2026, alongside the extension to SE1 and the Lithuanian price area (Svenska kraftnät).
• Lithuania: Litgrid and ESO have opened a consultation putting the flexible capacity the country will need by 2035 at 7.13 GW, up from 4.36 GW, and the balancing capacity reserved from state operator Energy Cells fell from 30 MW to 20 MW on 1 November (European Current).