UK Electricity Market Reforms

This time last year, Peter Kydd contributed an article to EFR about the significant changes that would need to take place in the UK power market as the UK transitioned to a local carbon economy The UK Power Market: An Example of Significant Change, EFR, Volume 4, Issue 2, December 2010). One year on, change is happening and as with all actions, there are also some significant re-actions. This article highlights those changes and the impacts they are having.


A quarter of the UK’s existing generation capacity will be retired within the next decade as stricter European emission standards take effect and as some generation plants reach the end of their economic life (see Box 1). However, it is not a simple case of replacing retired plants on a like for like basis, as the UK also has a legal requirement to reduce carbon emissions progressively until an 80 percent reduction in the 1990 total emissions is achieved (by 2050).

In addition, the government has to meet the EU Renewable Energy Directive which requires that the UK increases the amount of energy it generates from renewable sources from two to 15 percent by 2020. Renewable energy at 15 percent translates to around 30 percent of all electricity coming from renewables. Looking forward, a significant tranche of the transport and heat sectors will have to be electrified, rather than relying on hydrocarbons, if the UK is to achieve its 2050 carbon reduction targets. This, combined with a continued rise in the UK’s population (currently 60 million but projected to reach 75 million by 2050), translates to a doubling of electricity demand to 2050, even if a 25 percent reduction in today’s electricity demand is factored in to reflect increasing use of energy efficiency measures. Box 2 shows the pace of demand increase by comparison with historic demand growth.

There are many different pathways to achieve an 80 percent reduction in CO2 emissions by 2050, but almost all require a combination of significant energy efficiency and conservation measures (equivalent to 25 percent of our current electricity consumption) and use of electricity to displace fossil fuel use for domestic and industrial heat and transport. This is why electricity demand almost doubles to over 700TWh/year by 2050 even after reducing consumption by 25 percent).

The government’s approach in the electricity sector has three primary objectives:

  • To ensure security of supply whilst at the same time reducing carbon emissions from the generation of electricity;

  • To encourage investment in renewables and other low carbon generation such as nuclear and, in time, carbon capture and storage; and

  • To manage energy consumption through demand reduction and energy efficiency, recognising that reducing carbon emissions from new generation plant will result in increased electricity costs.

Box 3 on the following page illustrates the challenges in the UK electricity sector and the need for market reform. 

Energy efficiency policy instruments include the Green Deal, which is aimed at encouraging domestic customers to invest in energy saving measures, and the Renewable Heat Incentive (RHI), which provides long-term financial support to encourage the uptake of renewable heat. The RHI first phase will target the non-domestic sector (industry, commerce, and institutions) and provide long-term tariff support for over 20 years to reduce carbon emissions from this sector (currently accounting for 38 percent to the UK’s total carbon emissions).

Whilst energy efficiency and other measures such as planning reform comprise an important part of the government’s electricity market reforms, the principal measures relate to the market itself and how it can be refined to be more attractive to investors whilst at the same time limiting impacts on household electricity bills. In July 2011, following its initial consultation, the government published its white paper—Planning Our Electric Future: a White Paper for Secure, Affordable and Low-Carbon Electricity, UK Department of Energy and Climate Change —detailing the specific nature of the reforms to be adopted and the timescale for their implementation.

One of the challenges facing the government is the scale of the task. To meet the 2020 renewables target, the government expects 18GW to come from offshore wind, with additional contributions from the onshore wind, hydro, and biomass, coupled with 10GW or so of new gas plants, the majority of which would run on a reserve basis (i.e. would only be used when the existing low carbon generators could not provide sufficient energy to meetdemand).

ROCs and FiTs

The most significant of the reforms published in the white paper confirms that Renewable Obligation Certificates (ROCs) will be phased out and replaced by a Contract for Difference Feed in Tariff (FiT CfD). Whilst ROCs provided subsidy only to renewable forms of generation, the feed-in-tariff will apply to all low carbon forms of generation so will include nuclear power. The new approach would come into operation in 2014 but, to manage the transition and ensure existing investors continue to plan with confidence, ROCs will still be available to new investors until 2017.

A review of the current ROC regime has just taken place (different technologies attract different levels of ROC support) which has four main messages (Consultation on proposals for the levels of banded support under the Renewables Obligation for the period 2013-2017 and the Renewables Obligation Order 2012, UK Department of Energy and Climate Change, October 2011):

  • Offshore wind is regarded as the benchmark technology for new renewables;

  • Financial support for renewable technologies will reduce as they mature;

  • Biomass will have to demonstrate sustainable fuel sources; and

  • Embryonic technologies such as tidal stream and wave power will be supported to encourage their commercialisation.

The FiT CfD works on the basis that a project developer negotiates with the government’s administration body (yet to be established) to create a long-term contract with contractual terms governing revenue and length. This will give investors predictable returns on their investment and the legal enforceability of contracts should significantly reduce the cost of capital.

The tariff works by guaranteeing the generator a tariff (i.e. strike price) over the contract period. The government would set the strike price for each technology and use this figure in its contract. The government would also calculate the reference price on an ongoing basis—the average electricity price over a specific time period. The generator would then receive the difference between the strike price and the reference price. However, if the reference price is higher than the strike price, the generator is required to repay this to the government—i.e. the revenue per unit of electricity sold is the same over the contract period, irrespective of variations in the market wholesale price.

Risk items will still remain such as the cost of construction, energy yield and the reliability of operation and the contract negotiations for FiT CfDs may become extended if agreement cannot be easily reached on how these risks can be adequately covered, delaying potential implementation.  

The unknowns at the moment are who the contracting authority is—the white paper says that a range of organisations could undertake this, including private sector organisations—and how much the FiT CfD annual budget is likely to be.

Capacity Mechanism
The White Paper suggests that an organisation(s) at arm’s length from government will administer the contracts for both FiT CfDs and capacity based contracts (see next section, Capacity Mechanism). It also proposes that the government and delivery organisation(s) will jointly evaluate periodically any changes that are necessary based on possible changes in costs, technologies or new challenges to the energy system. The first of these reviews will take place in 2016.

The concept of some form of capacity mechanism (a means by which stand-by power could be made available at short notice to meet peaks in electricity demand) is necessary as stand-by power plants operate infrequently and thus require a different business model to justify their initial investment. Several commentators have questioned whether strategic intervention in the market through a capacity mechanism is required, whilst others have noted that such a mechanism may be close to self financing on the basis that if adequate generation capacity exists in the market the wholesale electricity cost will reflect this through lower unit costs.

The white paper challenges the notion that the existing arrangements are adequate and confirms that the government will introduce legislation for a new contracting framework for capacity. A further consultation was launched on the capacity mechanism in July 2011 which comprises two different options. The first is a targeted mechanism in the form of a Strategic Reserve. This would involve a centrally procured capability which would be removed from the energy market and only used in certain extreme circumstances. The second option is a Capacity Market, a market-wide mechanism in which all providers willing to offer reliable capacity are incentivised to do so. Each involves tradeoffs, as shown in Box 5. The costs for either option are very similar (see Box 6).

Emissions Performance Standard and Carbon

Floor Price

An Emissions Performance Standard (EPS) is designed to limit the number of hours that a carbon emitting plant may generate, thereby creating a preference in the market place for low carbon generation. The white paper confirms that an EPS will be introduced with an annual limit equivalent to 450g CO2/kWh at baseload, to provide a clear regulatory signal on the amount of carbon new fossil-fuel power stations can emit. This level effectively permits gas plants to continue to operate but restricts the output from coal and oil fired power stations unless they are fitted with carbon capture and storage. The Carbon Floor Price establishes a minimum price for offsetting carbon emissions when traded as part of the EU’s Emissions Trading Scheme (EU ETS). This also has the effect of reducing the number of hours a carbon emitting plant may generate over time as costsincrease from an introductory level of £16/tonne of CO2 in 2013, rising to £30/tonne by 2020, and then to £70/tonne by 2030. The necessity for the floor price is the unrealistically low level of carbon offsetting costs today.

Future Networks

The changes driven by the EMR have a significant impact on future electricity networks and the way supply and demand is balanced. The main challenges in the period to 2030 relates to the changed generation mix with increased levels of intermittent renewable generation and higher levels of inflexible generation, such as nuclear. As these represent low carbon sources, they drive a requirement for the rest of the system to be more flexible. In the short term, this flexibility is likely to come from fossil fuel plants but in the 2020s, demand side response, interconnection, and electricity storage will play a more significant role.

Increased demand on the system will also be experienced due to the electrification of heat, transport, and industrial processes. Present projections suggest a gradual transition to the mid-2020s with a significant ramp-up thereafter. There are also likely to be increased levels of microgeneration from localised and community-based sources, which will present challenges to the local distribution networks. A larger, smarter distribution network will be needed to meet these challenges.

In addition to appropriate network investment, the flexibility of the system will be critical if it is to maximise the delivery of low carbon generation through an optimal network. The main tools to support system flexibility are Demand Side Response (DSR), storage and interconnection.

DSR balances supply and demand by shifting demand from periods where supply is limited to periods where it is more plentiful. The roll out of smart meters, due for completion by 2019, is an important first step in DSR and will be followed by the introduction of new time based tariffs to encourage more dynamic shifting of demand.

For example, instead of being operated manually, appliances will be triggered to start when electricity prices drop below a certain level. Data from smart meters will also assist in managing the network in a more efficient way.


Interconnection links different electricity markets. Its main advantage is that diversity in demand and generation between the markets may benefit both through reduced prices and greater geographic distribution of intermittent generation. The UK’s current 3.5GW of interconnection is expected to increase to eight to 10GW by the 2020s.


The cost benefit analysis undertaken as part of the white paper demonstrates that the proposed reforms involving a FiT CfD and the Strategic Reserve capacity mechanism offer a net benefit of £9 billion by 2030 compared with an unreformed electricity market. The impact of this on household bills would be to limit rises to £160 per year by 2030 compared with £200 for an unreformed market. However, these analyses are very sensitive to the oil price. If the oil price dropped to U.S. $60 per barrel in 2020, the reforms would cost more, and consumer bills would be higher than with an unreformed market. On the other hand, if the price of oil rose to U.S. $120 per barrel in 2020, there would be increased investment in low carbon generation in the shorter term resulting in higher short term rises in consumer bills followed by a longer term reduction compared with an unreformed market.


The critical questions that emerge from the white paper include:

  • Can the 2020 goals be achieved within the £110 billion estimates referenced by the white paper? Parsons Brinckerhoff’s independent cost assessment to meet the 2020 targets gives a figure closer to £140 billion.

  • How much new equity can be attracted into the market to fund the large increase in capital expenditure?

  • What effect will the long term FiT contracts have on cost of capital for new investments?

  • The timing of the proposals is such that much of the investment between 2011 and 2020 will not be initiated until 2014 which will see peak spending levels as much as three times higher than the current UK power market expenditure—does the UK have the resources to manage this large increase in expenditure?

  • If the institutional arrangements to deliver the proposed reforms are not in place until 2014, will this delay new low carbon investment or will retention of the present ROC regime to 2017 be sufficient to prevent an investment hiatus?

  • Will the complexity of the reforms themselves coupled with the technical uncertainties that exist within them compromise achievement of the overall objectives?

There is still a significant amount of detail awaited on aspects of the reforms such as the parameters to be used in FiT CfD contracts, the finalisation of the capacity mechanism, and the new institutions that will be charged with administering them.

In spite of the uncertainties that remain, one thing is clear: the UK power market will see unprecedented levels of investment over the next decade.


Image Header Source: Alice (Creative Commons)