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European Union: 6 energy policy briefs

The energy policies moving European Union’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Regulation (EU) 2026/667 · 2040 climate target (90 percent) amendment to the European Climate Law and the delay of ETS2 to 2028

European Union · European Parliament and Council · regulation · 2026

Where it stands: Regulation (EU) 2026/667 adopted 11 March 2026, published 18 March 2026 and in force since 7 April 2026; post-2030 sectoral revisions under way

Regulation (EU) 2026/667, in force since 7 April 2026, writes a 90 percent net emissions cut by 2040 into the Climate Law, allowing up to 5 percent of 1990 net emissions to come from international credits from 2036 (85 percent domestic), and as part of the deal delayed the launch of the second emissions trading system for buildings and road-transport fuels from 2027 to 2028, keeping the power-sector ETS on its steep post-2030 decline path.

The problem

The Climate Law required a 2040 target to bridge the 55 percent 2030 goal and net zero by 2050. The Commission proposed 90 percent in July 2025 with flexibilities after member states balked at the cost, while several governments (Poland, Czechia, Italy) sought to delay ETS2 because of fears of a fuel-price shock for households in 2027.

What it does

The Commission's proposal of 2 July 2025 amends Regulation (EU) 2021/1119 to set a 90 percent net reduction by 2040 relative to 1990. The Council reached a general approach on 5 November 2025 and the Parliament adopted its first-reading position on 13 November 2025; a provisional trilogue agreement was reached on 9 December 2025, the Parliament approved the agreed text on 10 February 2026 and the Council adopted it on 5 March 2026. The act was signed on 11 March 2026 as Regulation (EU) 2026/667, published in the Official Journal on 18 March 2026 and entered into force on 7 April 2026. The regulation allows up to 5 percent of 1990 net emissions to be met with high-quality international carbon credits under Article 6 of the Paris Agreement from 2036 (a domestic reduction of 85 percent, with a possible pilot phase in 2031 to 2035), permits domestic permanent removals to count within the ETS, provides for a review clause tied to competitiveness, and, in Article 2 of the same regulation, postpones the start of ETS2 by one year to 2028 with strengthened price-stability provisions. The 2040 target also frames the EU's 2035 NDC under the Paris Agreement, submitted in the range of 66.25 to 72.5 percent. Sectoral legislation is now being revised to align with the new target: the Commission tabled its ETS review proposal (COM(2026) 616) on 17 July 2026, with a linear reduction factor of 3.7 percent for 2031 to 2035 and 1.7 percent for 2036 to 2040, and further proposals on ETS2, effort sharing, LULUCF and CO2 standards are to follow.

Market effect

The 90 percent target implies a near-zero power sector by 2040 and locks in the ETS linear reduction factor that pushes the allowance cap toward zero around 2039, which supports long-dated EUA prices and therefore the carbon cost embedded in gas-fired marginal power prices through the 2030s; the international-credit flexibility and removals clauses slightly soften that path and were read by the market as bearish at the margin. Delaying ETS2 to 2028 postpones the carbon price on heating and transport fuels, which slows electrification demand growth (heat pumps, EVs) by a year and reduces the political pressure for redistribution through the Social Climate Fund; it does not touch the existing ETS. The sectoral revisions, starting with the July 2026 ETS review proposal, are where power-market-relevant parameters (ETS cap trajectory, Market Stability Reserve, free allocation) will be reset, so the target is a signal now and a set of hard constraints later.

Key numbers

2040 target
90 percent net reduction versus 1990 (Regulation (EU) 2026/667)
International credits
Up to 5 percent of 1990 net emissions from 2036 (domestic reduction of 85 percent)
ETS2 start
Delayed from 2027 to 2028 (Article 2 of the regulation)
2035 NDC range
66.25 to 72.5 percent (NDC submitted to the UNFCCC, November 2025)
Entry into force
7 April 2026 (Official Journal 18 March 2026)

Who gains and who pays

  • Power generators and ETS-covered industry (obligation): Steeper long-run allowance decline; carbon cost embedded in marginal prices.
  • Fuel suppliers for buildings and road transport (gains): ETS2 obligations delayed to 2028.
  • Carbon-removal and international-credit suppliers (gains): Recognition of removals and Article 6 credits from 2036.
  • Households (mixed): Later fuel-price impact; Social Climate Fund timing.
  • Renewable, nuclear and storage investors (gains): Long-run policy certainty toward a near-zero power sector.

Implementation

Regulation (EU) 2026/667 applies directly in all member states since 7 April 2026. The Commission tabled its post-2030 ETS review (COM(2026) 616) on 17 July 2026; proposals on ETS2, effort sharing and other instruments for 2031 to 2040 follow, and the first biennial assessment of progress toward the 2040 target under the amended Article 4 is due by March 2027. Check EUR-Lex for the consolidated Climate Law and the Legislative Observatory for the ETS review file.

Concerns

  • Integrity and price impact of international credits
  • ETS2 delay setting a precedent for further postponements
  • Competitiveness pressures reopening the target
  • Alignment of national plans with a 90 percent path
  • Political durability across the 2029 European elections

Dates to watch

  • 2026-H2: Parliament and Council positions on the ETS review proposal COM(2026) 616
  • 2027-Q1: Commission's first biennial assessment of progress toward the 2040 target
  • 2028: ETS2 start

Sources

Checked against sources on .

European Grids Package (Commission proposals of 10 December 2025, in trilogue)

European Union · European Commission · regulation · 2025

Where it stands: Council general approaches (26 June 2026) and Parliament mandates adopted; trilogues under way on both acts

The Commission's December 2025 package to overhaul EU grid rules: a revised TEN-E regulation and a permitting directive amending three directives, plus guidance on grid connections and two-way CfDs, aimed at speeding cross-border and internal grid build, sharing interconnector costs and steering tariffs toward anticipatory investment; the Commission puts electricity grid needs at 1.2 trillion euros by 2040. Council general approaches followed on 26 June 2026 and trilogues have run since July 2026.

The problem

EU grids are the bottleneck for the energy transition: connection queues, congestion (redispatch costs above 4 billion euros a year in Germany alone), interconnector projects delayed by cost-allocation disputes, and tariff rules that reward reactive rather than anticipatory investment. The 2023 Grid Action Plan identified fixes needing legislation, and the 2025 Draghi report and Affordable Energy Action Plan made grids a competitiveness priority.

What it does

Published on 10 December 2025, the package comprises a Communication (COM(2025) 1005), a proposed regulation revising the TEN-E guidelines (COM(2025) 1006, procedure 2025/0399(COD)) and a proposed directive accelerating permit-granting across three directives (COM(2025) 1007, procedure 2025/0400(COD)), with Commission guidance on grid connection agreements and on two-way contracts for difference. It proposes: amendments to the TEN-E Regulation to expand the scope of projects of common and mutual interest, tighten permitting deadlines and give overriding public interest status to grid projects; amendments to the Electricity Regulation and Directive on anticipatory investment, cross-border cost allocation with a default sharing key, tariff principles that allow forward-looking investment and reward flexibility, and a mandate for ACER and ENTSO-E to develop a European planning approach with offshore grids; a European Grid Forum and supply-chain measures for transformers and cables; and guidance on state aid and financing through the Connecting Europe Facility and EIB. It also addresses connection rules for large loads such as data centres and flexible connection agreements. The Council adopted general approaches on both acts on 26 June 2026; the Parliament's ITRE committee adopted its report on the permitting directive on 2 July 2026 (plenary mandate 8 July) and trilogues began on 14 July 2026, while ITRE adopted its TEN-E report on 10 September 2026 with the negotiating mandate announced in plenary on 14 September 2026.

Market effect

If adopted, faster interconnector and internal grid build lowers price divergence between bidding zones (the Iberia-France, Germany-Nordics and Central-Eastern seams), reduces redispatch costs recovered through grid tariffs, and cuts renewable curtailment, all of which compress long-dated regional spreads. Anticipatory investment rules raise near-term network tariffs but avoid larger costs later. Cross-border cost-allocation defaults reduce the negotiation risk that has delayed projects like Celtic Interconnector successors and Baltic links. Data-centre connection rules would standardise how large loads get grid access across member states, relevant to the location of AI compute. Until adoption the market effect is expectational; the substance is being settled in trilogues in the second half of 2026 and would apply toward the end of the decade.

Key numbers

Proposal date
10 December 2025 (COM(2025) 1005, 1006 and 1007)
Grid investment need
About 1.2 trillion euros by 2040 for electricity grids, of which 730 billion for distribution (package Communication); 584 billion euros by 2030 was the 2023 Grid Action Plan figure
Legislative track
Ordinary legislative procedure; Council general approaches 26 June 2026; trilogues since 14 July 2026
Parliament mandates
8 July 2026 (permitting directive), 14 September 2026 (TEN-E regulation)

Who gains and who pays

  • Transmission and distribution system operators (gains): Anticipatory investment allowances and streamlined permitting.
  • Interconnector developers (gains): Default cost-allocation keys and PCI/PMI status.
  • Network users and consumers (mixed): Higher near-term tariffs; lower congestion costs later.
  • Grid equipment manufacturers (gains): Supply-chain measures and demand visibility.
  • Member state regulators (obligation): Apply new tariff and cost-allocation principles.

Implementation

Both files are in trilogue: the Council general approaches of 26 June 2026 and the Parliament mandates of 8 July (permitting directive) and 14 September 2026 (TEN-E regulation) frame the negotiations, which the European Council asked to conclude in 2026; formal adoption and Official Journal publication would then follow in 2027. Until then the existing TEN-E and market rules apply. Watch the trilogue outcome on cost allocation, congestion income and tariff provisions.

Concerns

  • Cost allocation disputes between member states
  • Tariff increases from anticipatory investment
  • Permitting acceleration versus environmental review
  • Supply-chain constraints for transformers and cables
  • Risk of the package being weakened or delayed in negotiation

Dates to watch

  • 2026-H2: Provisional trilogue agreements on the TEN-E regulation and the permitting directive
  • 2027: Formal adoption and Official Journal publication

Sources

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Electricity market design reform · Regulation (EU) 2024/1747 and Directive (EU) 2024/1711

European Union · European Parliament and Council · regulation · 2024

Where it stands: Regulation applying; directive transposed by most member states; national schemes being redesigned

The post-crisis reform keeps marginal pricing but changes what surrounds it: two-way CfDs become the required form of public support for new renewables and nuclear, capacity mechanisms become a structural tool, member states must assess flexibility needs and may support non-fossil flexibility, suppliers must hedge, and the Council can declare a price crisis that unlocks retail price interventions.

The problem

The 2022 gas shock pushed EU wholesale power prices above 500 euros per MWh because gas set the marginal price, and member states responded with uncoordinated windfall taxes and price caps. The Commission proposed in March 2023 to keep the marginal-pricing model, which delivers efficient dispatch, but to shield consumers and investors from short-term volatility through long-term contracts and to create a legal path for crisis interventions that does not fragment the internal market.

What it does

Adopted in May 2024, published in the Official Journal on 26 June 2024 and in force from 16 July 2024, the package amends the Electricity Regulation and Directive. Direct price support for new investment in wind, solar, geothermal, hydro without reservoir and nuclear must take the form of two-way contracts for difference (or equivalent schemes) with revenue above the strike returned and redistributed to final customers; existing contracts are grandfathered. Member states must promote power purchase agreements, including through state-backed guarantees, and must assess flexibility needs and may set up support schemes for non-fossil flexibility (storage, demand response). Capacity mechanisms are recognised as a structural element with a simplified approval path. The Council may declare a regional or Union-wide electricity price crisis (triggered by very high wholesale prices expected to last six months) allowing temporary regulated retail prices below cost. Suppliers must offer fixed-price contracts and hedge appropriately; consumers gain rights to energy sharing and to multiple contracts. ACER is tasked with developing virtual trading hubs to deepen forward markets, and peak-shaving products and non-fossil flexibility support are enabled. The directive's transposition deadline was 17 January 2025.

Market effect

Two-way CfDs as the default support instrument standardise the revenue model for new EU renewables and nuclear: strike-price competition in national auctions sets the cost of new supply, and the redistribution of excess revenues to consumers turns high-price years into rebates. Because CfD generators are insulated from the market price, their bidding is price-insensitive, which increases negative-price hours and reduces the natural hedge that merchant revenue provided; the reform tries to offset this with design rules that keep dispatch incentives. Structural capacity mechanisms let member states pay for firm capacity without the previous state-aid contortions, supporting gas and storage in the 2030s. Flexibility assessments and support schemes create a new subsidy channel for batteries and demand response across member states. Supplier hedging obligations deepen forward markets, while the price-crisis mechanism gives investors a defined rule for when governments can intervene, reducing regulatory risk relative to 2022. National transposition and implementation, not the EU text, determine how much of this appears in each market.

Key numbers

In force
16 July 2024
Directive transposition deadline
17 January 2025
Price-crisis trigger
Very high wholesale prices expected to persist about six months
Legal acts
Regulation (EU) 2024/1747; Directive (EU) 2024/1711

Who gains and who pays

  • Renewable and nuclear developers seeking public support (obligation): Support must be two-way CfDs; upside above strike is returned.
  • Storage and demand-response providers (gains): Flexibility needs assessments and non-fossil flexibility support schemes.
  • Electricity suppliers (obligation): Hedging requirements and fixed-price contract offers.
  • Gas generators in capacity mechanisms (gains): Capacity mechanisms recognised as structural.
  • Consumers (gains): Rights to fixed-price contracts, energy sharing and crisis protections.

Implementation

Member states were to transpose the directive by January 2025; several were late and infringement letters followed. National CfD schemes (Germany's planned technology-neutral auctions, France's nuclear arrangements, Spain's and Italy's renewable auctions) are being redesigned to the two-way model. ACER is developing forward-market hub proposals and flexibility assessment methodologies. The Commission's 2025 Affordable Energy Action Plan and grids package build on the reform. Watch national auction rules and the first Council decisions under the price-crisis mechanism if prices spike.

Concerns

  • Fragmented national implementation of CfD and flexibility rules
  • Negative-price frequency as CfD-backed capacity grows
  • Capacity mechanisms locking in gas capacity
  • Whether forward markets deepen enough to support supplier hedging obligations
  • Political use of the price-crisis mechanism

Dates to watch

  • 2026: National two-way CfD auction rounds under the new framework
  • 2026-H2: ACER forward-market hub and flexibility methodology decisions

Sources

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Hydrogen and decarbonised gas market package · Directive (EU) 2024/1788 and Regulation (EU) 2024/1789

European Union · European Parliament and Council · directive · 2024

Where it stands: Published and in force; regulation applying; directive transposition due 5 August 2026

The package rewrites EU gas market law for hydrogen and low-carbon gases: it creates a regulated hydrogen network regime with unbundling by 2033, a European hydrogen network operator body (ENNOH), tariff discounts for renewable and low-carbon gas, a ban on long-term unabated fossil gas contracts running past 2049, and powers to restrict Russian gas; the directive must be transposed by 5 August 2026.

The problem

EU gas law dated from 2009 and had no framework for hydrogen pipelines, blending, low-carbon gas certification or the phase-down of fossil gas. The REPowerEU goal of 10 million tonnes of domestic renewable hydrogen by 2030 required a regulated network model, and the energy crisis showed the need for joint purchasing and the ability to limit Russian supplies.

What it does

Adopted in May 2024 and in force from 4 August 2024, the directive (transposition by 5 August 2026) and regulation (applying from February 2025 with some provisions from 2026) establish a hydrogen market: third-party access to hydrogen networks, regulated tariffs, ownership or independent-operator unbundling of hydrogen network operators by 2033 with transitional models, the creation of the European Network of Network Operators for Hydrogen alongside ENTSOG, ten-year hydrogen network development plans, and certification of low-carbon hydrogen and gases with a 70 percent greenhouse-gas saving threshold. Renewable and low-carbon gases get tariff discounts at cross-border and entry points; cross-border tariffs for hydrogen are abolished. Long-term contracts for unabated fossil gas may not extend beyond 31 December 2049. Member states may restrict access to their networks for gas from Russia and Belarus, and a permanent joint purchasing mechanism (AggregateEU) is established. Consumer protection and the phase-down of gas distribution networks are addressed through national planning duties.

Market effect

For power markets the package matters through gas: the 2049 contract limit and network phase-down duties signal a declining long-run gas demand path, which affects the economics of new gas plants and LNG import terminals, while the Russian-gas restriction powers (used through the 2025 REPowerEU roadmap and the 2025 regulation phasing out Russian gas imports by 2027) keep European gas prices structurally above pre-2021 levels and therefore keep the marginal power price high in gas-setting hours. The hydrogen regime provides the regulated-asset model for the European Hydrogen Backbone, which underpins hydrogen-ready gas turbines and electrolyser demand as a flexible load in power markets. Certification rules define which hydrogen counts as low-carbon, which sets the boundary for blue hydrogen from natural gas with CCS. Tariff discounts modestly favour biomethane, a small but growing dispatchable fuel. Transposition in 2026 is where national blending rules, distribution phase-down plans and hydrogen network designations will appear.

Key numbers

In force
4 August 2024
Directive transposition deadline
5 August 2026
Hydrogen network unbundling
By 2033 (transitional models allowed)
Long-term unabated fossil gas contracts
Not beyond 31 December 2049

Who gains and who pays

  • Hydrogen network developers and TSOs (Gasunie, OGE, Snam, Enagas) (gains): Regulated-asset model and network development plans.
  • Gas suppliers with long-term fossil contracts (costs): Contracts cannot run beyond 2049; Russian supply restrictions.
  • Electrolyser and low-carbon hydrogen producers (gains): Certification, tariff discounts and network access.
  • Gas distribution network operators (obligation): Must plan for decommissioning and consumer protection.
  • Gas-fired power generators (mixed): Long-run demand decline signalled; hydrogen-ready designs favoured.

Implementation

Member states are drafting transposition laws ahead of the August 2026 deadline; Germany's and the Netherlands' hydrogen core-network frameworks were adapted to the EU model. ENNOH is being set up, ACER is developing hydrogen tariff and network-code methodologies, and the Commission adopted delegated acts on low-carbon hydrogen certification in 2025. The separate 2025 regulation phasing out Russian gas imports by the end of 2027 uses powers linked to this package. Watch national transposition bills and the ENNOH ten-year plan.

Concerns

  • Slow hydrogen demand leaving regulated networks under-used and costs on consumers
  • Certification thresholds for low-carbon hydrogen and the treatment of blue hydrogen
  • Distribution network phase-down and stranded gas assets
  • Security of supply as Russian gas is excluded
  • Late or divergent transposition across member states

Dates to watch

  • 5 August 2026: Transposition deadline for Directive (EU) 2024/1788
  • 2027: End of Russian gas imports under the 2025 phase-out regulation

Sources

Checked against sources on .

Net-Zero Industry Act · Regulation (EU) 2024/1735

European Union · European Parliament and Council · regulation · 2024

Where it stands: Regulation in force; implementing acts adopted; national auctions applying criteria

In force since June 2024, the NZIA sets a benchmark that 40 percent of the EU's annual deployment needs in net-zero technologies be manufactured in Europe by 2030, imposes permitting deadlines of 12 to 18 months, requires non-price and resilience criteria in a share of renewable auctions and public procurement, and mandates 50 million tonnes a year of CO2 storage injection capacity by 2030.

The problem

Chinese overcapacity in solar modules, batteries and electrolysers and the US Inflation Reduction Act's manufacturing credits left EU manufacturers uncompetitive, while permitting for factories and storage sites took years. The Green Deal Industrial Plan of 2023 proposed the NZIA as the regulatory arm alongside relaxed state-aid rules.

What it does

The regulation, adopted in May 2024 and in force from 29 June 2024, lists net-zero technologies (solar, wind, batteries and storage, heat pumps, electrolysers and fuel cells, sustainable biogas, CCS, grid technologies, nuclear and others) and sets an indicative Union manufacturing benchmark of 40 percent of annual deployment needs by 2030 and 15 percent of world production by 2040. Member states must designate a single point of contact and decide permits for manufacturing projects within 12 months (18 months for larger projects), with net-zero strategic projects receiving priority status. Renewable-energy auctions must apply non-price criteria (resilience, sustainability, cybersecurity, ability to deliver) to at least 30 percent of volume or 6 GW a year per member state, and public procurement of net-zero technologies must include resilience considerations where a single third country supplies more than 50 percent of EU demand. Oil and gas producers are obliged to contribute to a Union-wide CO2 storage injection capacity of 50 million tonnes a year by 2030. Net-zero acceleration valleys and regulatory sandboxes are provided for, and the Net-Zero Europe Platform coordinates.

Market effect

The auction rules are the market-facing piece: from 2025 and 2026 national renewable auctions must reserve part of their volume for bids scored on resilience and non-price criteria, which raises the cost of winning bids that use Chinese modules and inverters and gives European or diversified supply a price advantage of several percent, feeding into strike prices and PPA costs. Permitting deadlines shorten the time-to-market for battery gigafactories and electrolyser plants, though many announced European battery projects still failed on economics in 2024 and 2025, showing the act cannot offset cost gaps alone. The CO2 storage obligation creates a regulated pipeline of storage capacity that underpins CCS on gas plants and industry, relevant to the emissions trajectory of thermal generation. Public procurement resilience rules affect grid equipment (transformers, cables) where Chinese share is high, tightening the supply chain for the grid build-out.

Key numbers

In force
29 June 2024
Manufacturing benchmark
40 percent of EU deployment needs by 2030; 15 percent of world production by 2040
Auction non-price criteria
At least 30 percent of volume or 6 GW a year per member state
CO2 storage capacity
50 million tonnes a year by 2030

Who gains and who pays

  • European manufacturers of solar, wind, battery and grid equipment (gains): Auction and procurement preferences; faster permits.
  • Renewable developers (costs): Non-price criteria raise procurement costs for a share of auction volume.
  • Chinese and other third-country suppliers (costs): Resilience criteria penalise concentrated supply.
  • Oil and gas producers (obligation): Must deliver CO2 storage injection capacity.
  • Member state permitting authorities (obligation): Deadlines and single points of contact.

Implementation

The Commission adopted implementing acts on the non-price criteria and on strategic project selection in 2025; member states have designated points of contact and begun applying auction criteria (Germany and Spain among the first). The Industrial Accelerator Act proposed in 2025 and the Clean Industrial Deal extend the approach with made-in-Europe requirements. Monitor national auction terms and the Commission's list of net-zero strategic projects.

Concerns

  • Higher renewable procurement costs from non-price criteria
  • Trade friction with China and WTO compatibility
  • Manufacturing benchmarks without matching subsidy money
  • Permitting deadline compliance in member states with slow processes
  • CO2 storage obligation feasibility

Dates to watch

  • 2026: National auctions with resilience criteria; Industrial Accelerator Act trilogues
  • 2030: Manufacturing and CO2 storage benchmark year

Sources

Checked against sources on .

Carbon Border Adjustment Mechanism · definitive phase from 1 January 2026

European Union · European Parliament and Council · regulation · 2023

Where it stands: Definitive phase in effect from 2026; simplification adopted; certificate sales begin 2027

From 2026 importers of electricity, steel, aluminium, cement, fertilisers and hydrogen must buy CBAM certificates priced at the EU ETS allowance price for the embedded emissions of their imports, with a 2025 simplification exempting small importers under 50 tonnes a year; free ETS allowances for the same sectors phase out in step through 2034.

The problem

As the EU ETS price rose above 60 to 90 euros per tonne and free allowances were to be withdrawn, energy-intensive producers faced carbon leakage to countries without a carbon price. CBAM levels the carbon cost on imports so that the ETS can tighten without exporting emissions, and gives trading partners an incentive to adopt carbon pricing that can be credited against the levy.

What it does

Regulation (EU) 2023/956 entered into force in May 2023. A transitional phase from 1 October 2023 to 31 December 2025 required quarterly reporting of embedded emissions without payment. The definitive phase began on 1 January 2026: only authorised CBAM declarants may import covered goods, they must declare annually the embedded direct (and for some goods indirect) emissions, and surrender CBAM certificates whose price tracks the weekly average ETS auction price, with a deduction for carbon prices effectively paid in the country of origin. The Omnibus simplification adopted in 2025 introduced a 50-tonne annual mass threshold that removes about 90 percent of importers (mostly small ones) while keeping about 99 percent of emissions in scope, delayed the first certificate purchases to February 2027 for 2026 imports, and streamlined authorisation and default values. Electricity is a covered good, with importers from third countries (Western Balkans, Ukraine, Moldova, the UK pending any linking) liable for the embedded emissions of imported power unless exemptions for coupled markets apply. Free allocation to covered ETS sectors phases out from 2026 to 2034 in step with CBAM. The Commission is assessing extension to downstream goods and to indirect emissions more broadly.

Market effect

For electricity, CBAM prices carbon into imports across the EU's external borders, which narrows the arbitrage that let coal-heavy Western Balkan and Ukrainian power undercut EU generators; interconnector flows from those regions fall or reprice, tightening supply in south-east Europe in scarcity periods. It also creates the incentive for Ukraine, Serbia and others to build ETS-compatible carbon pricing and pushes the UK toward linking its ETS with the EU's (negotiations opened in 2025) to avoid CBAM on UK exports. For gas and hydrogen, hydrogen imports face the levy unless produced with low emissions, which supports EU electrolysis. The wider industrial coverage raises input costs for steel and aluminium users and, through the phase-out of free allowances, lifts the effective ETS price faced by EU industry, which feeds into industrial electricity demand and demand-response behaviour. The ETS price itself, not CBAM, sets the level; CBAM sets who pays it.

Key numbers

Definitive phase start
1 January 2026
De minimis threshold
50 tonnes of covered goods a year per importer
First certificate purchases
February 2027 for 2026 imports
Free allocation phase-out
2026 to 2034

Who gains and who pays

  • Importers of steel, aluminium, cement, fertilisers, hydrogen and electricity (obligation): Authorisation, annual declaration and certificate surrender from 2026.
  • Third-country power exporters (Western Balkans, Ukraine, Moldova, UK) (costs): Embedded emissions priced at the ETS level unless a domestic carbon price is credited.
  • EU generators and industry in covered sectors (gains): Carbon-cost parity with imports; but free allocation phases out.
  • Small importers under 50 tonnes a year (gains): Exempt after the 2025 simplification.
  • Trading partners (mixed): Incentive to adopt carbon pricing; trade friction and WTO scrutiny.

Implementation

The CBAM registry and authorisation of declarants went live for 2026; the Commission adopted implementing acts on default values, verification and certificate pricing in 2025. The UK-EU ETS linking negotiation and the assessment of downstream-product extension (a legislative proposal was announced for late 2025 or 2026) are the next steps. Monitor the Commission's CBAM pages for implementing acts and the list of recognised carbon prices.

Concerns

  • Trade retaliation and WTO challenges from India, China and others
  • Administrative burden and verification quality of embedded emissions
  • Circumvention through downstream products and resource shuffling
  • Impact on electricity supply in south-east Europe
  • Export competitiveness of EU producers losing free allowances

Dates to watch

  • 2026: Commission proposal on extending CBAM to downstream goods; UK-EU ETS linking talks
  • 2027-02: First CBAM certificate purchases for 2026 imports

Sources

Checked against sources on .