6 minute read 19 May 2020
Wind Power Pland in a Grassy Field with Cows Grazing

How the power market model for Great Britain creates cause for optimism

Authors

Anthony Legg

EY UK&I Head of Power & Utilities, Economic Advisory

Economist focused on the Power & Utilities sector. Consultant with worldwide experience. Husband and father of two. Proud gardener.

Anthony Tricot

UK&I Head of Generation and Power Markets, Economic Advisory

Economist focused on the Power & Utilities sector. Consultant with experience in industry and government. Trustee of two community charities.

6 minute read 19 May 2020

Our proprietary market model suggests the price of power will gradually increase over the next three decades.

This article is part of the 55th edition of the Renewable Energy Country Attractiveness Index (RECAI).

The COVID-19 pandemic has thrown energy markets around the world, including those for electricity, into turmoil. Despite, the current shock, however, a new proprietary model of the Great Britain power market suggests that a combination of technology evolution, changing patterns of supply and demand and, crucially, policy decisions could help to support and gradually increase wholesale power prices over the next three decades.

The EY Great Britain power market model forecasts that the combination of market dynamics, technology development and government policy will deliver a power price that gradually rises over the next three decades – from between around £40/MWh and £55/MWh by 2025 to between around £35/MWh and £70/MWh by 2050, in real 2020 terms. This price should support the UK’s decarbonization, while incentivizing and compensating sufficient low-carbon generation, and, at the same time, provide a clear incentive for corporate energy buyers to lock in forward power prices through PPAs.

Forecasting is a challenging, but vital, task

The effects of the pandemic on supply and demand will be temporary; developers of long-lived infrastructure – such as renewable energy generation – or corporates entering into multi-year power purchase agreements (PPAs) need to take the long view on power prices.

Long-term forecasting of power markets is challenging. It requires modeling of complex market dynamics on an hourly basis over a long horizon. It is particularly challenging in the context of the energy sector undergoing an unprecedented transition, impacted by continuous policy intervention, in the midst of a very uncertain global macroeconomic outlook.

However, it is also vital. Power price forecasts can dictate whether a developer goes ahead with an investment in a wind farm or solar park, or whether a corporate energy manager locks in the cost of buying power or takes a bet on a volatile wholesale market.

These decisions are particularly difficult in an era when some analysts believe the rapid increase in renewable energy capacity will push down wholesale power prices through a process known as “cannibalization.” This is where supply from power sources with an extremely low marginal cost of operation – such as wind turbines or solar panels – swamps demand for power, periodically pushing prices to zero or, in some cases, into negative territory.

As we note above, markets for power are some of the most regulated in the world. Policy decisions and changing policy priorities can have profound impacts on the price of electricity paid by consumers.

EY teams have developed a new model

Over the past six months, EY teams have developed a new, proprietary power market model for Great Britain (covering the wholesale power market for England, Scotland and Wales), while another model is in development for Ireland. It draws on factors including:

  • Macroeconomic drivers, such as oil, gas and coal prices, and GDP growth
  • Emissions, carbon prices and net-zero targets
  • Demand forecasts, including the growth of electric vehicles (EVs) and behind-the-meter generation, energy efficiency improvements and the electrification of heating
  • Commercial drivers, such as technology costs
  • Dispatch decisions, including load factors and dispatch optimization
  • Changes to the energy mix from plant retirements and new capacity
  • Assessments of policy changes

The model then applies linear optimization techniques to forecast dispatch decisions and market prices over the short and long term. It assesses several scenarios, incorporating different assumptions around commodity prices, decarbonization trajectories and the regulatory framework, to generate central, low and high views of market power prices.

Our modeling of the power market in Great Britain suggests that a combination of technology evolution, changing patterns of supply and demand and, crucially, policy decisions could help to support and gradually increase wholesale power prices over the next three decades.

The starting point for any model of contemporary power markets is that the process of price forecasting is different, and more complex, than in the past. Before, power prices were mainly a function of commodity prices – especially energy commodities such as coal and natural gas – and economic growth. Now, pricing models need to also account for technological innovation, policy change, the responsiveness of consumers to price signals, and the role of power generation in decarbonizing the rest of the economy.

The model includes some reasonable assumptions

While much is uncertain, there are some clear signposts created by policymakers – such as the UK’s 2050 net-zero target. Some assumptions can therefore be made with reasonable confidence, such as continued renewable technological innovation and a growing demand for power as the heat and transport sectors are decarbonized.

For example, we assume that power demand will grow by around 70% over the next 30 years, driven primarily by EV penetration and the decarbonization of residential heat. In response – and given the intermittent nature of wind and solar – we expect installed capacity to almost double by the same date.

EY projection of annual Great Britain power demand to 2050

EY projection of annual gb chart

It would be reasonable to assume that such growth in capacity would severely depress average wholesale power prices, and lead to significant periods when prices were at or near zero. However, because such a scenario would deter investment in needed capacity, we expect government and regulators to step in to support the energy transition.

The state has the means and incentive to address distortions

Negative power prices are a market distortion and, typically, the unintended consequences of government policy. Government has the tools at its disposal to address these distortions, as well as the incentive to do so when they threaten other government priorities such as addressing climate change.

For example, support to low-carbon generators – through the contracts-for-difference program or an equivalent mechanism – could be amended in future to pay out only at times of positive prices. Or to pay on the basis of whether plants were available to run, rather than whether they actually dispatched.

The potential for low or negative prices in some periods of the year could also stimulate a growth in “responsive demand” – such as from power-to-gas (producing hydrogen through electrolysis), battery storage, smart charging of EVs, industrial and commercial demand-side response and increased use of smart tariffs. This can help stabilize prices and shift demand from periods of high power prices to times when prices are low. Here, we expect technological development to be complemented by supportive policy to grow markets, such as through investment in EV charging infrastructure or a network for transporting hydrogen.

Negative power prices are a market distortion and, typically, the unintended consequences of government policy. Government has the tools at its disposal to address these distortions, as well as the incentive to do so when they threaten other government priorities such as addressing climate change.

The deployment of carbon capture and storage (CCS), assisted by government, could also constitute a low-carbon source of power that helps stabilize power price as it seeks to recover its fuel costs when generating. The UK Government’s 2020 budget included an £800m CCS infrastructure fund. This, combined with increasing opportunities for re-use of UK carbon storage infrastructure and depleted aquifers, plus a rising carbon price, could help boost investment in CCS technology in future.

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Summary

Long-term forecasting of power markets is challenging, particularly in the midst of a global pandemic and a very uncertain macroeconomic outlook. The new EY Great Britain power market model will help developers of long-lived infrastructure and corporates entering into multi-year PPAs to take the long view on power prices. It forecasts that market dynamics, technology development and government policy will deliver a power price that gradually rises over the next three decades.

About this article

Authors

Anthony Legg

EY UK&I Head of Power & Utilities, Economic Advisory

Economist focused on the Power & Utilities sector. Consultant with worldwide experience. Husband and father of two. Proud gardener.

Anthony Tricot

UK&I Head of Generation and Power Markets, Economic Advisory

Economist focused on the Power & Utilities sector. Consultant with experience in industry and government. Trustee of two community charities.