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20 | 11th - 17th April 2014 | UtilitY WEEK Policy & Regulation eral offshore windfarms have also been axed, although that is more of an issue for the longer term. On the other hand, the Treasury's carbon tax freeze could make it worthwhile for coal generators to keep running for longer. That is helpful for security of supply, albeit at the cost of higher carbon emissions. The Department of Energy and Climate Change (Decc) is more sanguine than the regulator. By adjusting several of Ofgem's assumptions, notably on demand and inter- connection, it argues that the capacity mar- gin will only drop to a safe 7 or 8 per cent. Decc is more optimistic about the take-up of energy efficiency measures and embed- ded renewable generation (which shows up as reduced demand). On interconnectors, Ofgem has conservatively assumed that we will make net exports of 750MW throughout winter, even when the system is under stress. Decc acknowledges that this is an uncertain area but suggests it is reasonable to expect zero net impact. National Grid, as system operator, is not taking any chances and is assessing its options for reserve capacity (see picture caption on page 19). This could provide an opportunity for mothballed or unprofit- able gas plant to be brought back online as back-up capacity. It is a sign of how dire the market is for gas generation that 7GW of operating plant has been put forward, as well as 2GW of mothballed plant. Only a handful, if any, of those power sta- tions will be awarded reserve contracts, how- ever. The 4 per cent margin forecast under Ofgem's Reference Scenario is just about enough to meet Decc's reliability standard without extra measures. If we do see high demand, Decc estimates 300MW will be needed next winter and 1GW in 2015/16. For the medium term, attention turns to the capacity market. Decc revealed final details of the design last month and develop- ers are broadly satisfied that the 15-year con- tracts on offer will be bankable, but there are still significant risks. Timing will be crucial. The first auction is scheduled for December, to bring on new gas plant by winter 2018/19. Like everything in Electricity Market Reform, the capacity market is subject to state aid clearance from Brussels. If the European Commission raises objections, that could extend the investment hiatus and delay new generation for another winter. The Commission's robust response to the UK's planned support for Hinkley Point C nuclear power station suggests it is not inclined to wave everything through unchallenged. While the Commission mulls it over, the government must decide how much capacity to procure through the market. Decc has set a reliability standard: demand must exceed supply, before intervention, no more than three hours in a year. It will not reveal until summer how many megawatts of capacity that equates to. That calculation depends on assumptions about all the other parts of the mix, which are themselves uncertain. If the government over-orders, consumers will pick up the tab. If the government under-orders, it will miss out on investment now and end up panic-buying down the line. While the final market design appears to work for investors in new-build, the fate of existing gas plant hangs in the balance. Ironically, as developers are paid to bring new capacity on the system, even recently built gas power stations are at risk of closure as high gas prices hit profitability. The capac- ity market offers existing generators rolling one-year agreements. It remains to be seen What's in anD What's Out Going off: Coal and oil In 2009, there was 28GW of coal on the system. Some 8GW of that has already closed or will do so by the end of 2015, having opted out of the European Large Combustion Plant Direc- tive (LCPD). The LCPD has also closed the last 3.6GW of oil-fired power capacity, which was expensive to run, polluting and rarely used. The Industrial Emissions Directive will drive another round of closures. Generators have a choice: enter the UK's Transitional National Plan or take up the Limited Life Derogation (LLD). In the first case, they must invest in kit to meet new emissions standards, convert to run on biomass or close down by 2020. In the second case, they may run for 17,500 hours or until the end of 2023 without upgrades. At the moment, 9GW of coal is on the LLD list, but companies have two years to make a final decision and there could be changes. Confusingly, EDF Energy entered its West Burton and Cottam stations into the LLD but said it was exploring options to keep them open longer term. Coal generators must decide whether the economics stack up to invest in life-extending upgrades. This decision will be heavily influenced by the carbon price. The Treasury's recent decision to cap the UK carbon tax at £18 a tonne from 2016, instead of ramping it up, works in coal's favour. It could mean more plant staying on. However, it is an increase on the £9 a tonne charged this year and remains a mate- rial consideration. The current fleet of stations is four or five decades old. The older it gets, the more costly downtime and repairs they need to keep going. Going off: Nuclear There are currently nine working UK nuclear power stations, with a capacity of 9.2GW. The oldest of these, a 490MW Magnox reactor at Wylfa, is set to cease generating this year. Seven of the others are scheduled for decom- missioning between 2018 and 2023, leaving only the 1.2GW Sizewell B. These dates are not set in stone, however, and owner EDF Energy may decide to keep them going longer. Coming and going: Gas As the government seeks to bring on invest- ment in new gas power stations, some of the older stations are reaching retirement age. Oth- ers have been, or are likely to be, mothballed due to tough market conditions (see picture caption on page 19). High gas prices in recent years have made gas power generation uncom- petitive against cheap coal. There is only one gas-fired power station under construction at the moment – ESB's 880MW Carrington plant. Other developers are waiting for the government's promised capacity market to kick in before committing. Intergen is first in line with shovel-ready plans for two plants totalling 2.1GW. In its Gas Strategy, published in December 2012, the government set its sights on 26GW of gas capacity by 2030. It is seen as a key part of the transition to a lower carbon mix, providing flexibility to back up intermittent renewables. Coming and going: Biomass Several coal generators have dabbled in bio- mass, first with co-firing and then wholesale conversion. While Drax is steaming ahead, others have run into difficulty. Ofgem forecast 2.5GW of biomass capacity coming from converted coal stations by 2016/17 and 1.4GW closing down. This 2.5GW replaces coal genera- tion at slightly lower efficiency, so represents a small net loss of capacity. And some of it is in doubt: since Ofgem's assessment, Eggborough missed out on conversion subsidies and looks likely to close by 2016. Meanwhile, development of dedicated bio- mass has been all but halted aer government got cold feet and axed subsidies. Coming on: Wind Renewable UK estimates there will be 10-11GW of onshore wind and 5-7GW of offshore wind on the system by March 2017. That is up from total installed capacity of 9GW today. Beyond that point, the picture is unclear as the old Renewables Obligation comes to an end and a new subsidy regime kicks in. Ofgem's assessment gives a more bullish, but not incompatible, total of more than 20GW by 2018/19. It considers 17 per cent of that to be "firm" capacity, which can be relied on to be available at any time. On average, wind turbines generate about a third of the time.