A new generation of investment

The privatisation of the electricity sector in the UK in the early 1990s established a framework for utility regulation that has been used around the world and which continues to be a reference point for governments and regulators seeking to regulate monopoly transmission and distribution assets whilst retaining competition in electricity generation.

With the UK electricity generating industry undergoing a dramatic change as a result of the need to reduce carbon emissions, the regulatory mechanisms for UK generation that were originally devised are now in a period of fundamental overhaul as the civil servants, regulators and economists who devised them now face the realisation that the various certificate, permit and levy mechanisms are not sufficient to incentivise the market to deliver both low-carbon generating capacity, as well as the fossil fuel generating capacity required as back up when intermittent wind is non-producing.

The regulation of UK transmission and distribution is fundamentally different to that of UK generation. For transmission and distribution, Ofgem, the industry regulator, oversees a framework founded on economic regulation (i.e., an allowed economic return) linked to regulatory asset values (RAVs). This enables investors to forecast with a good level of certainty the returns that they may earn over long time periods. Numerous regulatory settlements have set precedents, as have the infrequent appeals to the Competition Commission by regulated entities, with the result that economically regulated UK transmission and distribution assets have become highly prized by international pension funds, sovereign wealth funds (SWFs) and other risk-averse investors.  As a result, enormous cost-of-capital benefits have arisen for consumers.

Ofgem has until recently used a method of price cap regulation referred to as ‘RPI-x’ to limit the rate of growth in transmission and distribution charges to inflation and to set efficiency targets (‘x’ factor) for regulated entities over time periods of 5 years – referred to as ‘price control’ periods.

Recently the RPI-x approach has been replaced by ‘RIIO’ (revenue = incentives + innovation + outputs) which is intended to provide more regulatory certainty as the UK transmission and distribution industry faces an unprecedented period of investment. RIIO includes a more transparent approach to setting the cost of debt as part of the weighted average cost of capital (WACC) determination, with reference to the long-term trailing averages of forward interest rates rather than an examination of whether a company has financed itself efficiently or inefficiently. RIIO also envisages eight-year price controls, rather than five-year price controls, which are intended to enable utilities to plan with longer-term horizons.


The introduction of specified uncertainty mechanisms which are calibrated at the time of a price control are intended to reduce uncertainty, particularly in situations where utilities are planning large investment programmes. These refinements and mechanisms are intended to ensure that investors benefit from further regulatory predictability, helping to minimise the potential cost of capital increases that may arise from a near doubling of historic capital expenditure in the period to 2020. Consumers’ bills will therefore hopefully rise less than they might have otherwise.

The regulation of the electricity generating sector, in contrast to transmission and distribution, has been subject to market competition, i.e. generating technology and fuel type, since privatisation.  There is no economic regulation and investors in coal, gas and nuclear generation have been exposed to changing commodity prices, environmental policy and renewable policy impacting their ability to produce electricity at a profit. As a result of this situation it is no surprise that power utilities have felt the need to manage risk by having direct relationships with consumers.


The introduction of the renewables obligation in 2002 and corresponding renewable obligation certificate (ROC) was intended to provide an enabling environment for renewable developers to invest by providing a subsidy and floor price for energy produced from renewable sources.  Investment in renewable generation has now grown to 14 gigawatts (GW), and in order to meet a 34 per cent reduction in greenhouse gas emissions by 2020, the UK is in the middle of the Electricity Market Reform (EMR) process which is necessary to create more certainty to encourage investment.

The four key elements of EMR are: 1) a carbon price floor; 2) a Contract for Difference/Feed-in-Tarriff (CfD/FiT) arrangement for renewable producers instead of ROCs, which will be grandfathered; 3) a capacity mechanism; and 4) an emissions performance standard (EPS).

The carbon price floor and the EPS are intended to ensure that unabated coal is no longer economic or environmentally permissible, whilst the CfD/FiT arrangement is a mechanism to provide economic certainty for the price of electricity sold by renewable generators and nuclear. The CfD/FiT arrangement is intended to remove electricity market price risk, as compared to the existing ROC regime which exposes investors to electricity prices for a proportion of the revenues they expect to receive. The CfD/FiT arrangement does not guarantee that generated energy can be sold, but with a top-up payment to a strike price, generators who have CfD/FiT arrangements can sell at zero or near zero confident that fossil fuel generation is not able to compete.

The capacity mechanism is intended to provide revenue certainty for a proportion of the revenues of generators who opt to participate in the capacity auctions. If fossil fuel generators do not participate in the capacity market they will be fully exposed to the increasing variability of electricity prices arising from the further growth of wind generation capacity. As offshore wind installation is projected to grow dramatically, it is consequential that gas- and coal-fired generators require a capacity mechanism to mitigate the risks they face from a decreasing energy market opportunity and price variability introduced as a result of intermittent wind. It is currently envisaged that new-build gas projects will be able to secure long-term capacity contracts encouraging investment in gas generation which will run less and less over time as wind generation capacity increases.

Considering the proposed CfD/FiT regime in more detail, with investors in renewables now benefiting from economic certainty regarding the price of electricity sold, the business risks that remain for investors are crudely construction, wind (for wind farm investors), biomass prices (for biomass investors) and operating and maintenance risks which are far easier to estimate and predict than long-term electricity prices. How infrastructure investors will view these risks taken as a whole, and to what extent investors see this form of revenue support as sufficient to significantly lower the cost of capital for greenfield and operational renewable projects, remains to be seen. Hunger for yield in a low interest rate environment and the increasing appetite for the infrastructure asset class should stimulate tremendous interest.


Likewise, the capacity mechanism is intended to provide long-term revenue certainty to enable new-build gas investments. The success of the capacity mechanism will to some extent be a consequence of whether the contract lengths on offer for new-build projects are attractive to infrastructure investors, who may otherwise remain cautious.

With ‘partial’ revenue support now seen as a key future feature of many parts of the UK generating sector, it is no surprise that a change is underway in the regulation of international interconnectors.  Ofgem’s prior approach to the regulation of interconnectors was that developers should be exposed to the market’s valuation of the interconnector. This has been replaced with the acknowledgement that interconnectors offer wider benefits to consumers and that it is appropriate for an interconnector developer to benefit from a revenue cap and floor arrangement, with the transmission system operator underpinning the revenue floor in exchange for benefitting from revenues above the cap.

The consequence of EMR and other regulatory developments is that we are now seeing the potential emergence of revenue support (whether partial or full) across almost all of the UK generating system. The support mechanisms are helping to limit downside risks and therefore provide greater certainty that investors will achieve their cost of capital targets.

With all these changes in the UK electricity generating sector underway, we can perhaps expect to see infrastructure investors directing more capital to carefully selected investments in UK generation given the regulatory profile and investment returns available, rather than paying significant premiums to secure UK transmission and distribution assets.

Simon Monk is head of funds at IPA Energy + Water Economics, a London-based economic consultancy.