At the end of September, the UK’s last coal-fired power plant stopped operating – marking a welcome milestone in our efforts to drive carbon emissions out of the UK’s power supply. But the disappearance of reliable, dispatchable coal-supplied electricity, alongside pressures on other sources of baseload power, has some serious unintended consequences for the UK’s power system – and for large corporate consumers in particular.
In electricity systems, baseload refers to the minimum volume of electricity needed to supply a power grid. The supply of baseload power underpins the proper functioning of an electricity market. It has typically been supplied by coal, nuclear, and, in some markets, natural gas-fired generators. But, in the UK, all three of these sources of baseload are disappearing or under pressure.
For industrial and commercial (I&C) consumers of power, baseload also underpins the way they manage their exposure to power prices. These consumers typically buy their power using flexible supply contracts; these contracts enable them to manage movements in wholesale energy prices by making multiple buying decisions or trades. This is done by buying baseload blocks of power for future periods such as months, quarters or seasons ahead, at various times throughout the contract period. The wholesale power price or energy rate paid by the I&C consumer is based on the average price of multiple trades made over time.
The combination of dispatchable coal and gas generation combined with nuclear meant that delivering baseload or peakload power was extremely easy. If generators wanted to hedge, they would sell power to a trader or a utility or, if they were vertically integrated, to their internal trading group. I&C consumers also found it easy to buy power along the forward curve, as there was a deep pool of baseload power offered in the market.
The changing face of UK generation
Ever since the Industrial Revolution, Britain’s rich seams of coal have powered our economy. As recently as 1980, coal met 76% of our power demand. In the early 1990s, the UK began the so-called ‘dash to gas’, when cheap, plentiful and cleaner-burning gas from the North Sea helped push the share of coal-fired generation down to 32% by 2000.
The carbon-intensity of coal explains why the UK has abandoned its use for power generation in favour of gas. However, although natural gas produces half the carbon emissions of coal, large-scale gas generation will still be incompatible with the UK’s climate goals, unless its carbon emissions are captured and buried underground.
Nonetheless, it represents an important transition fuel on the way to a net-zero power system. In 2023, it met around a third of UK power demand. However, the decline of North Sea gas, war in Ukraine, and large volumes of cheap wind and solar have combined to make it too expensive to profitably run gas plants much of the time: for half of the time in 2024, only 20% of the UK’s gas-fired capacity has been in operation.
That leaves nuclear power. The UK generates around 15% of its electricity from its c. 6 GW nuclear fleet. Much of that capacity is due to be retired by the end of this decade. The previous UK government had plans in place to increase nuclear capacity to 24 GW by 2050, with the 3.2 Hinckley Point C plant expected to begin generating by 2030, and the 3.2 GW Sizewell C to follow sometime in the 2030s.
Renewables to the rescue?
The rapid growth of wind and solar in the UK power mix has helped to fill the gap. In 2023, wind, solar, biomass and hydro supplied 41% of the UK’s power. But how that power is delivered to the grid is changing how the power market operates, which promises to dramatically change the ability of large consumers to manage their electricity costs. Some of the supply of power from renewables, such as the 5% from solar, is broadly predictable. Biomass and hydro generation, contributing 5% and 1.8% respectively, can be dispatched as needed. Power from wind – which made up almost 30% of total supply in 2023 – is, of course, much more dependent on weather conditions than solar.
To ensure that sufficient wind is built to meet the UK’s climate goals, the government has offered developers contracts-for-difference (CfDs) to smooth their earnings and reduce the risks they face. These involve generators entering into financial contracts with the government-backed Low Carbon Contracts Company (LCCC), and selling their power, as generated, into the spot market. If the price they achieve is lower than the pre-agreed spot price, the LCCC pays the developer; if it’s higher, the developer pays the LCCC.
CfDs have proved very successful in bringing forward new renewables capacity – so much so that the government extended the concept to new nuclear generation, using CfDs to finance Hinkley Point C, which is due to come online by 2030.
The latest CfD auction involved an additional 131 energy projects striking CfDs with the LCCC, meaning that a total of 39 GW of capacity is subject to CfDs, out of total UK power generating capacity of around 75 GW.
To get to the government’s 2030 target of a carbon-free energy grid, it is estimated that, in addition to Hinkley 3, the UK will need 50-60GW of offshore wind, 35GW of onshore wind and 55GW of solar. This is a massive amount of generation and most of it will be contracted under a CfD.
Liquidity drains away
Whilst CfDs have been very successful at underpinning the build-out of renewables and nuclear in the UK, there are some drawbacks. Key amongst those is the removal of any need for a CFD-supported generator to hedge power in the forward market. Over time, this will significantly drain forward liquidity from the wholesale market, constraining the ability of I&C consumers to hedge.
The remaining generation not under contract through CfDs will therefore increasingly be made up of intermittent renewable generation that was built under previous support schemes, such as Feed-in Tariffs and Renewables Obligation Certificates, and dispatchable gas generation. Any trader or supplier looking to construct a baseload hedge would have to enter into a pay-as-produced power purchase agreement (PPA). The supplier would then have to hedge the volume, balancing and capture risk of that facility – that is, the risk created by the intermittency and variability of that generation. This rapidly becomes extremely expensive as you move along the forward curve, as weather patterns and gas prices become increasingly difficult to predict.
The increasingly fractured ownership of generation and the fact that two-thirds of renewable generation isn’t owned by the major suppliers means that constructing these forward hedges will increasingly be controlled by the major gas generators like RWE, Vitol, Uniper and Intergen. Because they will also have different hedging strategies for gas pricing medium to long term, and because they will sell their flexibility to other suppliers, the cost of constructing a baseload hedge and therefore its price will start to diverge significantly between these different players.
Finding solutions
So, what are the options? Eventually, sufficiently cheap long-duration storage will help solve this problem, allowing the trader to combine as-generated wind power with stored clean electricity to smooth out intermittency risk. That, unfortunately, is years away.
A more likely scenario is growth in gas-fired capacity that can meet short-term spikes in demand caused by low solar and wind power output. However, this will be expensive, and – assuming these plants are built without carbon capture – it will have a negative impact on the UK’s emissions profile.
Whatever the longer-term solution is, large I&C power consumers will increasingly face expensive hedging costs over the short to medium term. Those companies that want to avoid these risks will have to develop a much broader approach to the market and engage with multiple counterparties to find the best possible solution to their hedging needs.