The reserve margin problem
As European countries move towards a larger proportion of intermittent renewables in their generating mix, which all require backup, some have also seen a contraction in reserve margins – the difference between peak demand and guaranteed supply. This trend has been exacerbated by emissions-led programs to phase out coal, and the closure of nuclear plants, while new-build gas and other conventional capacity is being made less commercially attractive as renewables displace usage and put downward pressure on market prices.
In the UK for example, the government says more gas-fired plant is required as a back-up for renewables and a replacement for coal, which it plans to phase out by 2025 - the first of the world’s major developed economies to do so, although others are likely to follow. UK government plans indicate about 20-25GW of new flexible capacity will be required by 2025. Energy Minister, Amber Rudd says she favours gas, and that “lots of new low carbon generation cannot be relied upon in the same way that gas fired power stations can.”
But with gas-fired plants facing lower prices and reduced market access due to higher renewable supply, returns appear insufficient to attract investors, leaving the grid operators and policy makers searching for ways to persuade companies to build new CCGT plants. The UK has come up with the capacity market, but even this is unable to compensate for anticipated new-build utilisation rates that could fall as low as 27% of capacity, according to the UK’s Department for Energy and Climate Change (DECC) - simply filling in the gaps between renewable surges. It’s a self-reinforcing cycle - as more renewables are installed, gas and other plants are used less, pushing up the cost per MWh of using them. But the flexible capacity must be built to ensure supply when intermittent renewables are low.
The UK’s National Grid is already having to enlist the support of standby generators and big consumers to keep peak demand within supply capacity limits. This winter’s UK reserve margin – the difference between available power supply and expected peak demand – was 1.2%, the lowest since 2005-6, and down from 16.8% as recently as 2011-2012. Large consumers were recently paid up to £2400/MWh to switch off during a period of calm winds – providing a strong market signal that more flexible backup capacity is needed as reserve margins contract.
Estimates of the cost per MWh of new build gas from DECC recently suggested that gas plant would need an average return of about £68/MWh to cover investment, almost double current prices of around £32/MWh. Richard Howard, head of energy at analysts Policy Exchange, said such plants might require guarantees of up to £40 million in subsidies per year, for 15 years – roughly double the level currently on offer – in order to get built. Variable renewables also create huge uncertainty for gas suppliers, with last winter’s gas demand predictions from the National Grid ranging from 15 to 78 mcm per day depending on renewable flow - a range of 63 mcm/d.
Even existing gas-fired plants are finding it difficult to make money in the new environment. In Germany, RWE was forced to mothball even its most efficient gas plant due to high renewable output and related low market prices. According to a study by Oxford University, Europe’s biggest utilities mothballed 21.3 GW of gas-fed stations in 2013 alone, as a result of changed market conditions. Gas prices today are more competitive relative to coal - despite falling European gas output - and are likely to remain so in the medium term due to US exports and a weak global LNG market, but CCGT economics have not yet improved sufficiently to attract fresh capital.
The reserve margin problem is expected to get worse in coming years, as aging nuclear plants are closed and old fossil fuel plants are shut down in line with emissions and other policy commitments. In the UK, regulator Ofgem, says the grid's spare capacity could fall to between zero and 4% by 2016/7, based on anticipated closures of nine power stations or 7.4GW in 2016.
The failure to attract gas fired plants in markets that include subsidised renewables, castes doubt over the ability of governments to use the market to achieve policy goals. CCGT developers will either want some form of price guarantee or to be able to run their plants more of the time. In the UK, where imports are less available than in continental Europe, the government may need to raise the flexibility premium, or ensure gas generators have more sustained access to the market, in order to keep the lights on as more coal and nuclear plants close.
Gas’ green credentials
The UK government says switching to gas would also go a long way to ensuring it meets carbon reduction targets - both through lower emissions from gas compared to coal, and from facilitating further renewable expansion by providing flexible backup. Even the solar industry agrees: “We have talked to Greenpeace and other environmental groups about this and they understand we need to cooperate with relatively clean fossil fuels like gas in order to expand solar and wind further, but they still won’t say anything positive about gas,” said Oliver Schafer, President of trade body SolarPower Europe (formally the EPIA). Although the UK is also planning new nuclear, the government acknowledges that it is more suitable to baseload production and cannot easily be varied to compensate for fluctuations in wind and solar power.
So while consumer and environmental groups may be praising the way renewables push down wholesale market prices – highlighted in a recent report from Good Energy1 - they fail to recognise that the prices must be high enough and available for a sufficient amount of time to make backup capacity commercially viable, otherwise it will not get built. If prices are pushed down too much and gas and other conventional suppliers get pushed to the margin, the lights may end up going out when the wind doesn’t blow. Longer term, however, technology may be the answer to the margin squeeze, with demand side management, storage and decentralised grids all working to improve reserve margins.
Jeremy Bowden currently works as a freelance journalist and energy analyst, serving a variety of clients across the world, with work ranging from editing and features, to in-depth reports and public relations material. His experience spans over twenty years in the energy, specialist energy media and utility sectors in a variety of positions in both Europe and Asia, including five years at IHS in Singapore as Midstream Manager for the Asian region, followed by a short spell as IHS-CERA Associate Director, Emerging Markets. Before IHS, he was employed as Senior Asian Energy Correspondent for Dow Jones in Singapore, where work included contributions to the Asian Wall Street Journal. Prior to Dow Jones he worked at Energy Argus for five years in London and Singapore, where he was editor of the daily Asia-Pacific refined products news and price report. Jeremy also reported for Argus and PH Energy in the early days of the deregulated UK gas market, and spent four years involved in regulatory reporting for Thames Water. His qualifications include a Master’s degree in International Business and Finance from Reading University in the UK, and a degree in Economics.