The UK must invest heavily in power plants over the next 10 years just to keep the lights on. How it does this will be a test of generators’ and government’s commitment to cutting carbon emissions.
In these dark economic days many engineers are realising that there is still plenty of money to be made in keeping the lights on.
According to the Association for Consultancy & Engineering, 45% of firms predict the energy sector will be the fastest growing business area for UK construction over the next three years. A further 62% believe they will see their revenues from the sector increase during 2009. But why, when construction projects are grinding to a halt and so many fi rms are making redundancies, is the energy market viewed so favourably?
It is a sector that has been talked up by government within its ongoing dialogue on climate change and the need to cut carbon emissions. The UK has signed up to the European Union’s (EU’s) target of delivering 15% of its energy from renewable sources by 2020. With the biggest gains likely to come in power generation, this equates to roughly 35% of the UK’s electricity demand being met by renewable energy, a huge leap from the current level of 5% in just 11 years. This has led the government to back the largescale development of off shore wind farms and even consider finally building a tidal barrage across the Severn estuary.
Meanwhile, the government has also committed itself to cutting carbon emissions by 80% by 2050. Such is its commitment to tackling climate change, combined with a fear that the country is becoming over-reliant on foreign gas, that in the last two years Labour ministers have made a complete u-turn in their stance on nuclear power.
This renewed support encouraged French-owned generator EDF to buy British Energy for £12.5bn with a view to building new nuclear plants. Many other generators are meanwhile lining up to bid for the redevelopment of ageing nuclear sites that will soon be auctioned off by the Nuclear Decommissioning Authority (NDA). However, there is a far more pressing reason than climate change that makes energy the most alluring of civil engineering sectors at present.
In 2015, 12GW of oil and coal fired plant will be forced to close under EU legislation on power plant emission standards. A further 7.3 GW of obsolete nuclear generation capacity will have closed by 2020 and all but one of the UK’s existing nuclear power stations will have shut by 2025 due to age. In short, more power plants must be built simply to replace what is being lost. If this fails to happen, the lights go out. So, at a time when clients are jettisoning all non-essential expenditure, consultants and contractors can feel reassured by the knowledge that electricity generators must spend their money just to ensure they can guarantee supplies.
There is little doubt among engineers in the energy sector that generators will ensure they have enough capacity to supply their customers – it is just a matter of how they do this. Parsons Brinckerhoff technical director Ian Burdon says there is a very real possibility that in the near future, generators will have to ration electricity supplies to industrial and commercial customers to ensure domestic customers’ lights stay on.
We can expect some form of electricity rationing will be required in the foreseeable future
Ian Burdon, Parsons Brinckerhoff
“Given that we cannot store electricity in any quantity to make provision for the proverbial rainy day, coupled with the fact that even the simplest of power station designs will take at least three years to construct with almost as long again to plan and raise finance for, it is hardly surprising that, at best, we can expect that some form of rationing of electricity will be required in the foreseeable future,” says Burdon. “At worst, swathes of what is left of British industry and commerce will have to make their own arrangements to keep their machines at work and their IT systems functioning.”
Mott MacDonald energy director Simon Harrison is less pessimistic about the chances of power rationing but is certain that any energy gap in the next six years will be plugged mostly by new gas turbine power plants. Right now, the new capacity being planned by generators comprises chiefly of Combined Cycle Gas Turbine (CCGT) power plants and wind farms, on and offshore.
There are over 20 firms supplying electricity and/or gas throughout the UK, but a quick look at what two of the major players have planned for construction over the next few years gives a good impression of the kinds of projects likely to take place.
EDF is investing £400M in its electricity networks this year as part of a project investment of approximately £2bn over the five years to 2010. On the generation front, the French company intends to build four new EPR nuclear reactors in the UK, with the first to be operational by the end of 2017. However, these plans are at a very early stage and to plug the energy gap before it builds these it is turning to combined cycle gas turbines (CCGT). “These are relatively cheap and quick to build and they are flexible, meaning that they are able to respond to market prices,” says an EDF spokesman.
Construction is underway on EDF Energy’s 1.3GW CCGT plant at the site of its existing 2GW coal-fired plant at West Burton. The firm is also investing in renewables, 200MW of projects, primarily on onshore and offshore wind farms which have already been, granted planning consent.
E.on has also stated its commitment to building new nuclear power stations and although, again, its plans are at a very early stage, it has secured a grid connection for a nuclear power station to be built next to the existing Wylfa nuclear site, owned by the NDA. Its 15 onshore windfarms with capacities ranging from 6.9MW to 74MW are at various stages of planning. E.on is also building a 180MW offshore windfarm in the Solway Firth and is also a partner in the development of the 1GW London Array, which would be the world’s largest capacity windfarm.
In the more traditional forms of power generation the company is developing a 1.22GW CCGT plant at Drakelow, Derbyshire and its proposed 1.6GW coal-fired plant at Kingsnorth is currently awaiting the outcome of a planning inquiry.
For its part the National Grid is busy formulating two visions of the UK energy mix in 2020. One is a “business as usual” scenario, where power generators build the quickest and cheapest plants – mostly coal and gas. The other “Gone green” scenario envisages a mix broadly in line with government’s ambitions.
The government admits that it will be challenging to achieve the “Gone Green” scenario and that any short or medium term gains in capacity are most likely to come through CCGT.
The Department for Business, Enterprise and Regulatory Reform Berr’s Energy Market Outlook published in December 2008 estimates that 47GW of new capacity would need to be built by 2020. This represents about 57% of current total capacity and requires an average new capacity deployment rate of roughly 4GW per year. This level of power construction has only ever been achieved three times: in 1967 when 5.6 GW of new capacity was commissioned; in 1971 when 4.7GW was commissioned and in 1974 when 4.24GW of capacity came onstream. “A sustained period of new build at this rate represents a significant challenge,” says the report. “It is possible that supply chain constraints will act as a barrier to the market’s ability to deliver this amount of new construction.”
Indeed, as Harrison points out, the sheer scale of construction demand for offshore windfarms alone is unprecedented. These projects are likely to deliver the lion’s share of the UK’s renewable generating capacity. “There are 300 to 400 offshore structures in the North Sea from all the years we have been exploiting the oil and gas reserves – we may need to build 1,000 per year to meet the renewables targets,” he says. For some, the National Grid’s “Gone Green” scenario is only likely to be achieved if a level of national coordination is reintroduced to the market.
In the years when more than 4GW energy capacity was delivered annually, the programme was overseen by one body – the Central Electricity Generating Board (CEGB). This was scrapped at the start of the 1990s to make way for privatisation. “Central planning to a 25-year horizon by organisations such as the CEGB, to ensure that the lights did not go out, was consigned to the dustbin,” says Burdon. “Commercially unsound and technically naive beliefs imbued politicians of all hues with the idea that “the market will deliver”, but market drivers have not had a huge effect other than to deliver a lot of gas plant, which is the quickest and cheapest to build.”
ICE president Jean Venables agrees. “In 1990 I was a member of the South East Consumer Consultative Committee of the Office of Electricity Regulation, when deregulation occurred,” she says. “The view then was that ‘the market will provide’ and the ‘dash for gas’ was just beginning. I was concerned then about the security of supplies in the future. Now I believe that we still have to take steps to ensure that we have sufficient energy supplies for our needs.”
Venables believes that some kind of national oversight and a return to long-term strategic guidance is needed to deliver a green, balanced and secure energy supply for the UK, although she stops short of calling for a renationalisation of the industry. Even in these days of the major banks being owned by the taxpayer, few believe a return to the “good old days” of the CEGB is on the cards. Rather, there is hope that the work being done by National Grid and its necessary market overview, combined with traditional market forces, may yet deliver the energy systems the government promises.
“The generator won’t care about the mix of power supplies the government wants but what it will care about is future exposure to carbon prices,” says Harrison. “They will take a view and that will underpin their decisions on striking a balance between nuclear, gas, coal and renewables. The way generators get incentivised to behave is like each other. If you have a similar mix then you all charge similar prices. If you are all in on nuclear, for example, while your competitors keep a broad mix and the carbon price stays low, then your charges will be higher. As a generator you don’t want that situation as you will be squeezed out of the market.”
Burdon is more circumspect. “While the market may eventually deliver the capacity we need to keep the lights burning, the way it will be done, and the price that we in the UK will have to pay for that luxury will, in the main, be ultimately decided by French, German and Spanish boards of directors.”
Nuclear and renewables: If the price is right
Despite European nations agreeing to cut carbon emissions and increase renewable power use by 2020, politicians have so far failed to identify how a pricing mechanism for carbon will work beyond 2012.
The EU Emissions Trading Scheme (ETS) puts a cap on emissions from around 12,000 installations throughout the EU, including the energy and heavy industrial sectors.
Each nation is allocated a number of carbon allowances which it auctions. However, it has yet to be determined how the scheme will work and how allowances will be allocated beyond 2012 when the EU trading scheme ends. The CBI report Climate Change: Everyone’s business, claims that an effective price for carbon is essential if we are to create a low carbon economy and meet the government target to cut carbon emissions by 60% by 2050, or even by 20% before 2020.
A high carbon price would make investment in low carbon technologies more attractive to energy firms. Mott MacDonald energy director Simon Harrison says: “The long term construction and massive investment in nuclear means that carbon needs to be something you can forecast with relative certainty, so that you know nuclear will reap the financial benefit of being low carbon,” he explains.