The net zero target (reducing UK carbon emissions to zero by 2050 as enshrined in the amended Climate Change Act 2008) is ambitious but, according to the Committee on Climate Change and National Grid, just about feasible.

Our electricity system will need to be completely low-carbon, if not carbon negative, and industry will need to reduce its emissions drastically.  

Renewable power generation cannot provide a full solution: power is still needed when there is no wind or sun; and hydro cannot meet all demand.  According to the outgoing business and energy secretary Greg Clark, government analysis shows that between 30GW and 40GW of dispatchable low-carbon generation is needed by 2050 to meet net zero.  There will need to be some non-renewable, yet low carbon, baseload power and this is where nuclear, and gas with carbon capture and storage, comes in.


Great Britain currently has eight operational nuclear power stations, but seven of these are due to come offline by 2030 as they reach the end of their operational lives.  To meet net zero by 2050, we need to build more, but it has proven difficult up to now for the private sector to finance this.  Nuclear power stations are expensive and risky to finance, with much of the money needed up-front, long before they can start to generate revenue by selling power.  The only nuclear power station currently being built, Hinkley Point C, has been supported by the Government via a Contract for Difference (CfD), but this only guarantees a certain level of revenue once the plant has begun generating electricity; the investors still have the construction and operating risk.

There are large volumes of private sector capital (mainly pension funds and insurers) who are looking to invest in infrastructure projects, but only if their exposure to risks are within limits.  The Government has been looking for some time at alternative funding models.  It announced in 2018 that it was considering a Regulated Asset Base (RAB) model for future nuclear power plant projects as an alternative to CfDs.  The intention is that the RAB model would work alongside CfDs, so developers have a choice of which is most appropriate for their project.  The Government has now published a consultation on a proposed nuclear RAB model, which closes on 14 October.

The RAB model

The RAB model is a type of economic regulation typically used for monopoly infrastructure assets such as water, gas and electricity networks. Under the RAB model a company receives a licence from an economic regulator, granting it the right to charge a regulated price to users (which would be electricity suppliers) in exchange for the provision of the infrastructure in question. Suppliers would pass on the charge to consumers via their electricity bills.  

The charge is set by an independent regulator and can be adjusted throughout the lifecycle of the licence to ensure that the company's costs are recovered and a permitted profit margin is maintained. The independent regulator holds the company to account to ensure that any expenditure is in the interests of customers. 

The issue with using a RAB model for a nuclear power station is that the electricity market is open to competition.  No generator has a monopoly; no generator can force customers to buy their power.  They have to compete in the market to sell their power at the best possible price.  The RAB model gets round this by treating the power station as system infrastructure and the charge as a use of system charge which all suppliers have to pay.  Thus even if the nuclear plant does not sell power, it is treated as a system asset (like a power line), a necessary piece of infrastructure which is charged for.  Dieter Helm advocated this approach in his June 2018 paper, The Nuclear RAB Model.

As of 2018, the total value of RAB projects across the UK electricity, gas, water and airport sectors stood at £160bn and the poster child of the RAB model is the £4.2 billion Thames Tideway Tunnel (TTT) project.  This is similar to a nuclear project as it involves construction of a complex single asset with significant upfront capital expenditure, a long construction period and a long asset life.  The Government have used TTT as a starting point in developing the nuclear RAB model.

The proposed nuclear RAB model has four key elements:

  • Government Support Package (GSP) – Government protection for investors and consumers against specific, remote, low probability but high impact risk events. The GSP would guard against the risk of cost overruns above a remote threshold, disruption to debt markets, certain risks for which insurance is not available and political risks.
  • Economic Regulatory Regime (ERR) – to establish a fair sharing of costs and risks between consumers and investors. The nuclear project company would have a licence, which would enable it to charge RAB payments (Allowed Revenue) in exchange for the performance of its functions (the construction and operation of a nuclear plant). 
  • Revenue Stream – A route for funds to be raised from energy suppliers to support new nuclear projects, with the amounts set through the ERR for both the construction and revenue phases.
  • Regulator – A new regulator to operate the ERR, working alongside the Environment Agency and the ONR.

To give some more detail on the first three:


This level of Government support, taking on specified low probability but high impact risks that the private sector would not be able to bear, is what sets this model apart from others.  We saw this to an extent on the TTT but this goes further.  The investors do not get out of all risk though: there is a threshold for costs overruns which will be set at a level where there is only a remote chance of construction costs reaching it.  So investors would have to be comfortable that their costs were not going to overrun too much; they would have to cover overruns that did not reach the threshold.  Even overruns above the threshold are not guaranteed to be covered by Government: the Regulator will decide whether to raise the charges to enable the investors to recover the extra cost from consumers.

ERR and Allowed Revenue

The Regulator would grant the project company a licence and be responsible for setting the payments the project company can charge electricity suppliers (who then pass it on to consumers).  This is the Allowed Revenue, which would be calculated by taking into account a variety of factors in order to ensure that the project company was able to recover its costs whilst also generating a return on its investment.  The Allowed Revenue will be charged during the construction period, as well as once the plant is operational. This will make it more attractive to investors but will also mean that consumers end up paying for the cost even before the plant is built – and even if it never becomes operational.

To deal with construction cost risk, the Government has recommended using an 'ex ante' cost settlement model, in which the target total construction cost for the project would be set at the point at which the RAB licence was granted, with the project company and suppliers (and in turn, customers) sharing the risk of additional costs and the benefits of any costs savings. This cost settlement approach was used for the TTT and would allow the Government to estimate the maximum potential exposure for suppliers and their customers in advance, whilst also assisting investors to price their investment appropriately.

Revenue Stream

This is the route for funding to flow from suppliers to the project company.  Under the proposals, a separate intermediary body would collect payments from suppliers and pass these on to the project company. During the construction phase (when the project company is not yet selling power into the wholesale market), suppliers would be charged according to their share of the energy market, which could be calculated in a similar way to the Targeted Charging Review (see our article).  During the operational phase (when the project company is selling power to suppliers), suppliers would be charged their share of the project company's Allowed Revenue minus the revenue the project company would expect to receive if the power generated was sold in the wholesale market at a specified reference price. Suppliers would then pass these costs on to their customers, or reimburse customers where the Allowed Revenue is lower that the project company's revenue from power sales and the project company therefore has to make a payment to suppliers.

Due diligence and value for money

The Regulator and Government will need to carry out robust due diligence on any new nuclear project before deciding whether to grant it a new nuclear RAB licence and GSP.  There are likely to be a number of 'decision gates' to pass through.  A project will not be granted a licence or GSP unless it can show that it offers value for money to consumers and taxpayers.  Other factors which would also be taken into account would include: the project's contribution to the 2050 net zero emissions target; security of supply; effect on total electricity costs for consumers; and wider benefits specific to the project (e.g. contributions to local economies).

Comment on Nuclear RAB model

Immediately following the announcement of the consultation, several groups indicated that they intended to oppose the new RAB model on the basis that it would increase the risk of large, unquantifiable costs being passed on to consumers given the track record of significant cost overruns and construction delays across large infrastructure projects in recent years.  The nuclear industry, on the other hand, welcomes the model as a way of getting projects off the ground when other methods of investment in nuclear have failed.

Carbon capture, usage and storage

Another key part of reaching net zero emissions by 2050 is the commercialisation of carbon capture, usage and storage (CCUS) to capture emissions from plants and processes that cannot easily be decarbonised.  The Government has recognised this, setting out an ambition in the 2017 Clean Growth Strategy to have the option to deploy CCUS at scale during the 2030s, subject to the costs coming down sufficiently; and establishing the CCUS Action Plan to enable the UK's first CCUS facility to be commissioned from the mid-2020s.

But so far, other than funding for various innovation projects, we have not seen any firm commitment from the Government to helping get viable, commercial CCUS projects financed.  This could be about to change with the publication of a consultation on CCUS business models, along with a consultation on re-use of oil and gas assets for CCUS projects.  Both consultations close on 16 September.

The consultation on CCUS business models is part of the ongoing Review of CCUS Delivery and Investment Frameworks (which is mentioned in the BEIS CCUS Action Plan) and BEIS will use the consultation responses to help them progress and complete the Review.

The consultation recognises that there are different aspects to CCUS and so breaks down the CCUS chain into four areas: transport and storage; power; industry; and (looking to the future) hydrogen.

Overarching parameters

Even though different areas of the CCUS chain may have different business models that are most suitable, there are some overarching parameters that BEIS are using to guide their development, based on Greg Clark's four principles for the power sector set out in his speech of November 2018:

  • The models should be market based and incentivise CCUS to provide value to the economy.
  • The design of the models should instil confidence among investors and should attract innovation and new investors to the market.
  • The models should be cost efficient.
  • There should be appropriate and fair cost sharing between the Government and CCUS developers.
  • There should be an appropriate allocation of risk between the Government and CCUS developers that evolves as the CCUS industry matures.
  • The models should have the potential to become subsidy free.

CO2 Transport and storage

The CCUS industry only works if there is infrastructure to transport and permanently store the CO2.  It is expensive to build these from scratch but there is potential to re-use existing oil and gas assets that are coming to the end of their commercial life: a way for oil and gas companies to contribute to carbon reduction.  See the separate consultation on this.

Any financing model for CO2 transport and storage (T&S) needs to cater for:

  • The unique risks of CCUS assets: cross-chain risks (other transport and storage assets not operating, or the capture plant not operating); stranded asset risk (e.g. a capture plant is built before the transport infrastructure is finished); and longer-term CO2 storage liability and leakage.
  • Multiple users of the assets
  • Providing sufficient certainty to investors in CO2 T&S infrastructure of revenue and transparency of the T&S fee to carbon capture projects.

The BEIS Select Committee recommended having a separate funding model for CO2 T&S infrastructure from that for carbon capture at individual facilities.  This funding model would have a T&S operator responsible for developing and managing the T&S infrastructure in a specific region, with different users of the infrastructure charged a T&S fee.

Does this sound familiar?  A monopoly over infrastructure with users charged a fee is basically how an RAB model works, and so unsurprisingly, the Government are considering an RAB type model for T&S.  The thinking here is nowhere near as advanced as the nuclear RAB model and the consultation notes that any RAB model would need to take into account factors like: the need to identify a long term, credit worthy customer base and revenue stream (T&S users could be a mix of different industrial emitters, hydrogen production facilities and power plants with different financing structures); and who would be an appropriate economic regulator.  It may even be that the T&S assets are owned and financed by the Government initially.

Power CCUS

Power CCUS is electricity generation from gas-fired power stations equipped with carbon capture and storage.  If we are to decarbonise by 2050 we will need this; renewable generation alone will not be sufficient.

The role of gas-fired power CCUS is likely to evolve over time, from initially providing firm baseload power to more dispatchable power in the medium term, turning on when renewable power generation is lower, such as at night or on still days.

The main funding model being considered for power CCUS is some sort of Contract for Difference, such as the 'Flexible CfD' recommended by the Market based frameworks for CCUS in the power sector report from Cornwall Insight and WSP.

Industrial CCUS

Industry currently accounts for a quarter of UK emissions, with more than two thirds of industrial emissions coming from a small number of energy intensive industries such as steel, cement, oil refining and chemicals.  To decarbonise these, and meet our net zero goal, CCUS is essential, but at the moment, not a viable investment.

Any investment model developed needs to be flexible, as the costs of carbon capture vary considerably between different industries, and should become subsidy-free over time, by developing a market for low-carbon products.

Potential models being considered include a CfD with a strike price per tonne of CO2 abated (which will vary between industrial sectors); or tradeable CCS certificates plus an obligation.  This would work in a similar way to Renewable Obligation Certificates: CCS certificates would be awarded per tonne of CO2 abated, and an obligation (increasing over time) on each party to ensure a certain amount of CO2 is captured and stored.  Whom the obligation is placed on will be crucial: if on industrial emitters, there may need to be an additional incentive (e.g. a CfD) to prevent carbon offshoring.

CCUS for Hydrogen 

The consultation considers hydrogen production, although the thinking on this is at an earlier stage than the other CCUS areas.  Hydrogen is likely to play a key part in the UK's transition to net zero.  In National Grid's Future Energy Scenarios (see our article), particularly the Two Degrees scenario, 312TWh of hydrogen will be needed.  Most of this would be produced by Steam Methane Reforming, which requires CCUS in order to be classed as low-carbon. 

The consultation examines the key challenges that a sustainable business model for hydrogen production will need to address and from this, the Government will seek to consult on specific business models for hydrogen in 2020, with a view to responding to the consultation by the end of 2020.

Comment on CCUS

This consultation is long-awaited and is part of the ongoing Review of CCUS Delivery and Investment Frameworks.  There is not long to digest and respond, given the summer holidays, so we encourage you to respond if you can.  The final question is, What capabilities are needed for the delivery of CCUS in the UK?  The CCUS Advisory Group, established in March 2019, recommends a specific CCUS delivery body.  What is clear is that if we are to meet net zero by 2050, we need to take action soon.  

Key Contacts

Paul Dight

Paul Dight

Partner, Energy and Utilities
United Kingdom

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Rory Connor

Rory Connor

Partner, Infrastructure Projects & Energy
London, UK

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Richard Goodfellow

Richard Goodfellow

Head of IPE and Co-head of Energy and Utilities
United Kingdom

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