It has been a turbulent few weeks for UK energy policy. In April 2026, the Treasury decided to scrap the Carbon Price Support and the Government signalled measures to break the link between gas and electricity prices. This caused the market to speculate about potential large-scale reform of the energy market. With the long, drawn-out Review of Energy Market Arrangement (“REMA”) only just concluded, this was obviously unsettling. However, in reality, the changes announced by HM Treasury and the Department for Energy Security and Net Zero (DESNZ) are more measured. Rather than a fundamental reset, they represent incremental adjustments to an already evolving system.

Today, the cost of carbon emissions in UK power generation is comprised of two elements:

1. The Carbon Price Support (CPS), a top‑up tax on fossil fuels used in power generation, which has been fixed at £18/ tCO₂ emitted since 2018. It was introduced in 2013 to encourage electricity generators to decarbonise.
2. The UK Emission Trading Scheme (UK ETS), a cap‑and‑trade system where large emitters buy and sell carbon allowances (c.£40–£62/tCO₂ in Q1 2026, with the average normalised price at £53.15)¹. A floor price for carbon credits is set through an auction process to ensure the cost of carbon emissions is at a level that incentivises green investment.

Together, the carbon cost (UK ETS +CPS) accounts for c.30% of the wholesale electricity price.

Gas burned in power stations pays both CPS and UK ETS. Gas burned directly in homes does not². That has helped drive decarbonisation of electricity, but it also pushes up wholesale power prices and creates distortions between sectors.

The decision to remove CPS simplifies the system and aligns the UK more closely with Europe. However, the impact on power prices is likely to be modest.

Why? Because the UK ETS will do more of the heavy lifting:

• Lower power prices could increase demand for gas generation.
• This raises demand for carbon permits.
• At the same time, the emissions cap is tightening.

The result is upward pressure on UK ETS prices, offsetting much of the benefit from removing CPS.

In short, the overall cost of carbon is unlikely to fall materially, as it still needs to support the UK’s net zero ambitions.

Removing CPS also supports closer alignment with the EU, particularly ahead of the Carbon Border Adjustment Mechanism (CBAM) in 2027.

CBAM will apply carbon pricing to imported goods in sectors such as steel, cement and aluminium, helping prevent “carbon leakage” and ensuring UK producers remain competitive³.

There is also clear momentum toward linking the UK ETS and EU ETS, with the pricing gap already narrowing.

The UK ETS has historically been lower than the EU ETS but increased nearly 50% to ~£65/t over 2025 and the difference to EU prices has narrowed to ~£9/t.

The impact on generators depends on the company’s exposure to baseload power, flexible gas peakers and renewables, and how they earn their money:

• Subsidised renewables with accreditation under the Renewables Obligation scheme plus merchant power are more exposed to wholesale price moves.
• Contract-for-Difference (CfD) and Feed‑in-Tariff (FiT) projects have largely fixed, inflation‑linked revenues and are less affected by short‑term price changes.

Importantly, renewable generators benefit indirectly from carbon pricing, as gas-fired power (typically the marginal price setter) embeds these costs into electricity prices.

So far, valuation impacts across listed renewable infrastructure have been limited. This reflects:

• Long-term contracted cashflows.
• Diversified revenue streams.
• Market assumptions that already factored in CPS removal over time.

Companies use power price forecasts from several independent consultants. These forecasters largely assumed the removal of CPS over time, tapering off at varying rates. As a result, the effect was already partially reflected in current valuations. It is expected electricity prices captured by UK generating assets, where there are no hedges in place, will reduce by up to £5/MWh from April 2028 to the early 2030’s and £2-3/MWh thereafter reflecting an increase in the UK ETS price over time.

In April, the Department for Energy Security and Net Zero (DESNZ) set out measures intended to reduce gas influence on electricity prices:

• Electricity Generator Levy (EGL)
  • Tax rate on excess generator profits to rise from 45% to 55% from 1 July 2026⁴.
• Wholesale Contracts for Difference (WCfDs)
  • A new, voluntary CfD‑style mechanism aimed at legacy low‑carbon generators accredited under the Renewables Obligation (c.20–25GW of capacity).
  • Generators would swap wholesale market exposure for a fixed, inflation‑linked price, while keeping ROC support⁵.

In practice, the EGL change may have limited impact. Wholesale prices would need to average above £75/MWh over a full year before the levy bites, and forward prices have mostly traded below that level outside crisis periods.

WCfDs could be more significant over time, offering operators a way to trade variable cashflows for long‑term certainty. However, key details are still to be defined:

• How technology‑specific strike prices will be set.
• Whether offshore wind and nuclear will have viable reference prices.
• How auctions will be structured and timed.

ROC accredited assets represent about 30% (35GW) of the UK’s electricity generation capacity. Assets are beginning to lose RO support from 2027 with 9.8GW expected to leave RO support by 2031⁶. CfD’s may support the life extension of the assets as well as full repowering. These assets are an important part of the energy mix to meet clean power 2030 and energy security in future years. Assuming nuclear is included in WCfDs, there will be interest as generators have been lobbying to extend the life of these assets⁷. EDF announced in January 2026 that it can support a 20-year life extension on Sizewell B, which is due to retire in 2035, if it can find an appropriate commercial model. The Government is set to open an industry consultation in the coming weeks or months.

Until this detail is published and consultation completed, investor nervousness is understandable, particularly with the next CfD auction round (AR8) brought forward to July 2026.

Stable government policy is key to encourage large scale infrastructure investment and retrospective changes to policies and tax undermine investor confidence as we saw last year when the Government surprised the market by bringing forward the rebasing of the indexation of the RO buy out price and feed-in-tariffs to CPI from RPI. As part of this policy and reflected in the 2025 Autumn Budget, effective from April 2026, 75% of the cost of the RO scheme will be funded through general taxation. This is feasible as the ROC scheme is a known liability considering the scheme closed to new entrants in 2017, with the capacity enrolled on the scheme known, the cost is largely predictable. Moving to a CfD introduces a less predictable liability that is market linked. This opens the policy to future governments revisiting the support.

There may also be unintended consequences transitioning from a “pay-as-clear" marginal pricing market where the wholesale price of electricity is set by the most expensive generation unit on the system (typically gas-fired plants) in which renewable generators were "price takers" to a more decoupled hybrid-market. This will put downward pressure on prices and may lead to more stable forward market but risks lower liquidity in the forward wholesale market as less generation is hedged into the future. This “thin” liquidity may lead to wider bid-ask spreads in periods of market stress and lead to more short-term volatility in prices as the system loses its ability to absorb supply and demand shocks.

We believe offering existing low-carbon generators to lock in future revenues under CfDs is a positive step, with CfDs for new projects already proving to be successful. Knee-jerk policies under pressure work against this.

Despite the rhetoric, gas and power are already less tightly linked than during the 2021–23 energy crisis.

Analysis from Ember shows that in the four weeks following the start of the US-Israel war with Iran the average daily cost of UK gas generation increased 42%, rising to £110.42/MWh from £77.75/MWh in the week prior. This compares to the 2021-23 fossil fuel crisis where the average daily cost of gas generation increased from £42.30/MWh before the crisis in 2020 to £180.10/MWh in 2022, when the annual wholesale power price reached £204.71/MWh, on average.

Several factors have helped reduce the impact:

• The UK has diversified its natural gas supply, with a greater share from the North Sea (c.40%), Norway (47%) and the US and very limited exposure to the Middle East (1%)⁸.
• UK gas demand has fallen by 20% over the past 3 years⁹, helped by improved efficiency, warmer winters and a rapid build‑out of renewables.
• More than a quarter of Britain’s wind and solar capacity has been built since the last crisis, sharply cutting gas‑fired generation in the power mix (a reduction of 39%)⁸.

Perhaps the most important point is that the system is already evolving.

Government analysis suggests gas used to set the power price around 90% of the time in the early 2020s. Today that figure is closer to 60%¹⁰ and could fall to c.15% in the future as more renewables and nuclear come online ¹¹.

Recent CfD auctions support this direction of travel:

• AR7 secured a record 14.6GW of new low‑carbon capacity, including 8.4GW of offshore wind, and extended CfD contract lengths from 15 to 20 years for many technologies.
• The UK now has 38.4GW of offshore wind either operating or contracted, versus a 2030 target of 43–50GW.
• Grid‑connection reforms by the National Energy System Operator (NESO) have cleared a substantial backlog, aligning new capacity with 2030 and 2035 system needs.

In other words, the real decoupling is happening through investment in renewables, grid upgrades and diversification of gas supply – not through ad-hoc policy decisions.

Following the conclusion of the Review of Electricity Market Arrangements (REMA), the Government has confirmed it will retain a single national wholesale power price, rather than moving to zonal or nodal pricing.

Instead, DESNZ has outlined a Reformed National Pricing (RNP) framework, supported by a Strategic Spatial Energy Plan to be updated every three years. The focus is on:

• Better locational signals via planning, network charging and connection reforms.
• Ensuring new infrastructure is built where it is most valuable to the system.

The Government has opened a consultation on the measures it is proposing and will provide feedback to the market by the end of 2026. We see this as an encouraging step.

We are encouraged by the Government’s desire to drive down electricity prices and move to a more resilient energy market. But recent policy changes should be seen in context.

• Removing CPS simplifies carbon pricing but won’t materially lower electricity prices
• Measures to “break the link” with gas are incremental and largely untested
• The real decoupling is already happening through the growth of renewables

The direction of travel is clear. We are moving towards a cleaner, more resilient energy system. But to deliver this at scale, the UK needs more than ambition. It needs consistency, clarity and investor confidence. Without that, even well-intentioned reforms risk becoming a distraction rather than a driver of progress.

For investors in listed renewables and infrastructure, the overall picture is one of incremental policy evolution, not a fundamental shift. Diversification by technology, revenue model and contract length remains the best defence against both market and policy noise.

Notes

¹ ICE - UK ETS Futures Price

²Institute of Fiscal Studies - Response to scrapping carbon price support

³HM Treasury - Carbon border adjustment mechanism November 2025

⁴ The EGL was initially established in 2023 in response to the 2021-23 fossil fuel crisis. The levy was intended to impact exceptional receipts from energy generation. The threshold has been maintained at £75/MWh (2023 real) which is indexed annually and is currently £82.0/MWh.

⁵ When RO projects generate electricity, they earn the wholesale electricity price, which is usually set by gas power. In addition, they are paid a fixed subsidy via “renewable obligation certificates” (ROCs).

⁶Energy UK Explains: The Renewables Obligation and the Wholesale Contract for Difference

⁷ EDF - Nuclear life extensions

⁸DESNZ - Iran, the Middle East and UK energy: factsheet March 2026

⁹ Energy Trends: Natural gas supply and demand March 2026

¹⁰ Ember - Clean power fortifies Britain against gas price shocks (April 2026)

¹¹ Decisive action to break influence of gas on electricity prices

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