In January RWE announced plans to close seven UK power plants by 2023. At the same time SSE announced its plans to close a further two plants over the same time period. EDF effectively deferred a decision to commit to the long-term operation of some of its major asset power stations and Eggborough has indicated an uncertain future for its Yorkshire power plant.
January also saw speculation that the UK government is about to announce a freeze of the carbon floor price (a charge on emissions) perhaps in recognition that continued emissions costs in conjunction with new emissions legislation is driving accelerated plant closures. All of this at a time when many agencies are highlighting possible electricity shortages and the government is rolling out legislation to encourage renewables and new conventional plants to be built and existing conventional plants to remain in operation.
In Great Britain (England, Wales & Scotland) average generation in 2013 totalled 37.8 GW with a peak of 56 GW recorded in the winter of 2012-13. A large number of power station closures has been completed already in the UK, and the total of plants either announced to be closed down or under threat equates to approximately 18% of GB’s peak electricity demand. EnAppSys has reviewed the background to and impact of these closures on the British electricity market, and the following is a discussion of what this may mean going forward.
Review: coal-fired power stations in the UK
It has now been forty years since Britain built its last coal-fired plant and although it contributed 41% of UK electricity generation in 2013, the average age of Britain’s coal-fired fleet has now reached 46 years. Meanwhile, Britain’s nuclear fleet, which contributed a further 21% of electricity generation in 2013, has been generating for an average of 32 years and must be almost entirely decommissioned within a decade.
By contrast, in Germany the country’s newest coal-fired power station is now barely a month old and, with a conversion efficiency of almost 46% (100 MW of thermal energy delivering 46 MW of electricity) could be using as much as 25% less coal than Britain’s oldest coal-fired plants while creating fewer harmful emissions in the process.
It seems unlikely at this point that Britain will opt to build new coal-fired power plant as Germany has done but over the next decade this ageing fleet of power stations is likely to create numerous problems for a country whose nuclear fleet after 2024 will consist of just one power plant, Sizewell B, and that due for decommissioning in 2035.
Emissions standards
By 2023, Britain’s coal-fired fleet will be approaching 55 years of generation and as European environmental and emissions standards are raised it will be increasingly difficult to upgrade these low-efficiency plants to the required standards, owing in part to the higher volumes of coal they consume compared to more efficient plants, and their aged design.
Already emissions standards coupled with the UK’s carbon floor price have resulted in several closures of some of the country’s older power stations. This is in line with the EU’s Large Combustion Plant Directive which mandated that power stations in Europe either meet certain sulphur and nitrous oxide emissions standards or agree to close, by 2015 or after 20 000 hours of generation whichever occurred sooner. Although 2015 is still a year away, the decreased revenue for coal power stations running on the
’20 000 hour’ regime caused by the introduction of the UK carbon floor price in April 2013 led to their accelerating their use of these hours, with a number of them shutting down prior to April 2013.
The directive and the carbon floor price between them resulted in the loss of 9.6 GW of generating capacity in 2012 and 2013, with a further loss of 3.9 GW expected by 2015. Further closures might be expected in 2015 as Eggborough, a plant that can continue to operate under the Large Combustion Plant Directive, has indicated that it may opt to shut down if it is unable to secure financial support for a biomass conversion.
Nuclear contribution
Within five years from now three nuclear units with a total capacity of 3.5 GW are scheduled to have closed and within ten years a further four units with a total capacity of 4.6 GW are scheduled to close, leaving only one unit of the current generation, Sizewell B with a capacity of 1.3 GW, running until 2035.
This remaining unit is capable of providing only 14% of the 2013 level of nuclear fleet generation.
It is hoped that by 2024 Hinkley Point C and Sizewell C will come online just before 4.6 GW of existing nuclear plants go offline, providing between them 6.4 GW of additional generation capacity. A very recent letter issued to the UK by the EU, reviewing the UK’s submission to have its new nuclear arrangements cleared in terms of ‘State Aid’ restrictions, indicated that there were still several hurdles to clear. Even assuming no delays by 2024 a second directive, the Industrial Emissions Directive (IED), will have further reduced the number of old coal and gas-fired plants propping up the British electricity markets.
Other UK power plant closures
So far RWE, EDF and SSE have announced their plans with respect to the IED. RWE has announced plans to close Aberthaw (coal, 1.6 GW) and Didcot B (gas, 1.5 GW) plus a number of smaller CHP plants by the end of 2023 or after 17 500 hours of generation from the end of 2015. Meanwhile, SSE plans to close Uskmouth (coal, 0.4 GW) and the remaining units at Ferrybridge (coal, 1GW) under the same terms and EDF has announced that it is retaining the option to opt out of Cottam (coal; 2 GW) and West Burton A (coal, 2 GW).
The recent speculation about a change in government policy, to freeze the UK carbon floor price from 2016, might change the stated positions but many of these plants are ageing and less efficient than modern plants.
Looking at the plants that are the subject of recent IED-related announcements, Uskmouth will have been generating for 64 years if it continues on until 2023. Meanwhile, Ferrybridge will have generated for 58 years, West Burton for 56 years, Cottam 54 years, Aberthaw 52 years and Didcot B for 26 years (a respectable age for a gas-fired plant).
The loss of these ageing plants is perhaps inevitable but EnAppSys estimates that by 2023 under a scenario of high carbon prices, the closure of coal-fired plants under IED could potentially amount to as much as 12.5 GW of lost generating capacity, with combined coal and nuclear capacity potentially falling by as much as 75% from 37.5 GW in 2013 to 9.4 GW in 2023.
Cost and policy factors
Figure 1 shows a projection of future cost per MWh of coal-fired generation including the current carbon floor price escalation charges with the equivalent figure for gas plotted on the same scale. It shows the squeeze on profits at coal plant against increased capital costs for upgrading to meet the IED and shows why those coal stations that do not intend to or cannot switch to biomass are considering closure.
Current UK government policy seeks to achieve further growth of renewable generation, the building of new nuclear and conventional capacity and to encourage gas-fired generation to remain operational. This is being achieved through tax support for shale gas, the introduction of a generation capacity mechanism and price support for renewables (the latter two via the Electricity Market Reform bill).
Whilst renewable price support (‘Contracts For Difference’) is likely to lead to renewables’ providing ever-increasing volumes of generation over the next decade or so, much of this will have its generation output dependent on the weather. With government incentives being linked to generation output and the nature of weather these renewable generators are not able to provide electricity that can follow the demand pattern. Whilst storage technologies could provide a solution to this problem the government is not directly incentivising the build of larger grid scale storage beyond grant type support and less than 1GW of grid scale storage capacity is currently in planning.
Options for the UK
The current EMR legislation arguably favours gas-fired generation as the reserve technology of choice, possibly owing to its lower installed cost compared to coal plant, lower emissions and perhaps hopes that shale gas discoveries will moderate gas prices. Since 2010, however, the GB CCGT fleet has seen average levels of generation fall from 17.9 GW in 2010 to 9.2 GW in 2013 as favourable economics for coal have made it largely unprofitable to run gas fired plants outside of peak demand periods. These economics have been driven by the ‘shale’ effect in the US, driving a shift from coal to gas generation and from rising global natural gas prices resulting from some countries’ rejection of nuclear generation. So the government’s direction of travel and general consensus is for gas-fired power stations to fill the gap left by the retiring coal plants. Existing gas-fired plants may suffice to cover half of the generation shortfall should combined current coal and nuclear capacities fall but the remaining shortfall must be met by new power plants if Britain’s ageing coal plants continue to close.
New super-efficient coal plants remain an option to fill the gap and, combined with technology to reduce emissions, could provide coal-fired generation without the current environmental cost, albeit at the high financial cost of installing that technology. However, currently new coal-fired stations – even with emissions reductions technology – look politically unlikely. The more politically palatable carbon capture equipped coal-fired power stations are still not commercially proven, have high energy use overheads and require significant investment in new infrastructure to get the carbon dioxide from the source of emission to a place where it can be stored indefinitely.
The gas option
The remaining option is to construct new gas-fired stations and without being sure that Hinkley Point C and Sizewell C will be online and generating power by 2024, or that extensions will be granted on existing plants for long enough to cover any delays on new nuclear plants, the UK may need as much as 20 GW of new gas-fired capacity.
Figure 2 shows a future projection by EnAppSys of a GB fuel generation fuel mix with gas-fired generation filling most of the gap left by retiring coal plant. This assessment uses demand forecasts and some scenarios from the National Grid’s ‘UK Future Energy Scenarios’. The chart indicates that to maintain the same generating capacity margin in 2023 as existed in 2010 (ie 50% excess capacity) would require new UK build of approximately 10-20 GW of generation capacity between 2014 and 2020 with exact levels dependent on assumptions of how much renewable capacity could be assumed to provide margin.
Should coal-fired power plants opt to continue on in light of a carbon floor price freeze, getting through the IED pinch point in 2023 will be a far more straightforward process not requiring extensive new plant build. However, a second pinch point is likely to follow as the older coal-fired fleet’s age catches up with it and they are shut down, along with gaps created by the shutdown of older gas-fired plants due to the IED, such as Didcot B (1.5 GW).
As indicated the consensus view is that any new build generating assets to provide capacity backup will be gas-fired, but from a strategic view, new super efficient and/or carbon capture coal plants should also be part of the fuel mix to provide some fuel diversity. However, both government-funded reviews and industry commentators do not forecast coal new build of any significant quantity.
In addition to the new UK build options, opportunities provided by new interconnectors and European electricity market and grid integration initiatives may provide alternatives for capacity located outside of the UK to meet its electricity demand and requirement for excess margin, but with the EU in/out referendum and the Scottish referendum on independence still to come, this is a difficult area to factor into any future UK plans.
Author notes
Paul Verrill, EnAppSys, Stockton-on-Tees, UK
