|Issue Number: 113||October 2014|
EU Gas Demand Declines For Third Year Running
'During the last three years, gas demand by EU power generators decreased by 51bcm, or one third from the historical peak reached in 2010'
Natural gas has many advantages over coal in the power sector. For example combined cycle gas turbine plants (CCGTs) offer higher efficiency, lower emissions, quick build times, competitive construction prices and operational flexibility which could be used to support generation from renewable energy sources (RES). Indeed these advantages are evinced by growth in power generation capacity over the past thirteen years. For example since 2000, RES and natural gas installed power capacity has increased by 169GW and 121GW respectively, whereas over the same period the coal fleet has been reduced by 13 GW. Therefore with gas being the cleanest and most flexible of the hydrocarbon fuels there was an expectation that gas demand would continue to be strong with gas displacing the unpopular coal and nuclear options.
Figure 1: EU gas demand (bcm) 1993 to 2013 (Source: Cedigaz, 2014)
However, as can be seen from the above graph, over the last few years instead of gas demand growing within the EU, demand for gas particularly in the power generation market has declined considerably. There are a number of reasons for this decline including loss of load due to recession and improved energy efficiency as more Europeans insulate their homes. However, the main reason is a significant reduction in the consumption of gas in the power generation sector. For example over the past three years the market share of gas in the EU electricity mix fell from 23.6% in 2010 to 19% in 2012, a reduction of some 51bcm. This is roughly equivalent to the entire annual gas consumption of France.
The purpose of this short paper is to ask and hopefully answer the following three questions.
Why has gas demand in the power generation sector dropped so dramatically
There has been a decrease in residual electricity demand
Figure 2: EU electricity demand 1990-2013 (Source: Cedigaz)
As can be seen from the above graph there has been a significant reduction in the growth rate of EU electricity demand falling from a compound annual growth rate (CAGR) of 2% in the 1990s to a CAGR of 1.35% during 2000-2008. Moreover, in 2011 demand decreased by 2.2% and in 2012 it dropped a further 0.6%. Whilst the later reductions are substantially a function of the recession the underlying trend is one of demand erosion.
Coal is now cheaper than gas?
Despite the numerous advantages of natural gas over coal in power generation as highlighted above, the evolution of commodity and carbon prices and the fast development of RES have made gas-fired generation a loss-making business, even for the most efficient and newly-built gas-fired plants.
Figure 3 - Evolution of coal, natural gas and oil prices (Source: Cedigaz, 2014)
As can been seen from the above graph gas competitiveness has been eroded by the decrease in coal prices due a number of contributing factors. The introduction of EU Emissions Trading Scheme (EU ETS) was meant to curb the use of coal, however, the collapse of CO2 prices since 2012 has essentially rendered the scheme useless and reinforced the competiveness of coal against natural gas. Additionally, US shale gas production has displaced coal in its own power mix. Faced with a shrinking market at home, American coal mining companies have turned to overseas coal markets. The inflow of US coal, on a market already well supplied, has created a supply glut and led to a sharp decline in coal prices. Coal prices declined by 32% between the middle of 2011 and the end of 2013. Conversely, gas prices, still largely linked to oil prices, increased by 42% between 2010 and 2013, in line with oil prices. The recent fall in gas prices (a decline of 29% for spot prices in the first four months of 2014) does not change the competitiveness of coal over natural gas. As coal prices have also declined, coal is three times cheaper than natural gas on an energy equivalence basis.
RES push natural gas out of the merit order
Figure 4 - EU electricity generation, gas versus coal and RES 2004-2012 (Source: Cedigaz, 2014)
The above chart highlights the recent change in EU electricity generation with gas generation being squeezed by coal and RES. For example in 2012, RES (including hydro) generated 23.5% of EU electricity and overtook natural gas for the first time. The fast deployment of wind and solar has displaced peak and mid-merit conventional power plants and contributed to a fall in wholesale electricity prices. In addition low power prices have reduced the profitability of power generation. The trend has been particularly acute for gas power generators which have been faced with increasing gas prices. The clean spark spread (the measure of profitability of gas power plants) has been negative since the beginning of 2012, meaning that on average gas power plants have lost money. Comparatively, thanks to the decrease in coal prices and the collapse in CO2 prices, the clean dark spread (the measure of profitability of coal power plants) has remained positive.
In addition RES, which have low or zero marginal costs, push out energy sources with higher marginal costs, in the merit order dispatch of power plants. Gas-fired power plants, which have high marginal costs, have been the first to be pushed out from the system, decreasing their running hours. In Germany, the average load factor of gas fired power plants declined to 21% in 2013. In Spain, the load factor of CCGT plants has plunged from rates consistently over 50% until 2008 to an average of just 11% in 2013. The rapid increase in RES also means that more often the price of electricity is set by lower marginal cost energy sources, preventing gas-fired power plants from recouping their fixed costs, and even in some cases, their operating costs.
What are consequences of this drop in gas demand?
A reduction in investment in power generation infrastructure
The lack of future for some gas and coal power plants has led some European power utilities to write down power generation assets. In 2013 key utilities in the EU reported power generation asset impairments of €15 billion, the same level in one year than what they reported in the 2010-2012 period. Faced with adverse market conditions in the EU, power utilities are adapting their strategy to the new conditions. They are moving from the traditional business model based on large-scale electricity generation to new business models focused on renewable generation and smart products and services. They are no longer investing in thermal power plants in the EU. Most thermal power generation expansion is now focussed away from the region with investment in growth markets (Turkey, Russia, Eastern Europe, Latin America, Asia). Ultimately the EU will pay a high price for this lack of investment just as other countries have in the past, indeed there is an urgent need to rebuild confidence in the European electricity market.
A reduction in gas fired generation
Faced with low running hours and declining margins, gas power operators have started to mothball or close their loss-making plants. At the end of 2013, 24.7 GW of gas-fired power capacity were idled, closed or at risk of closure, most of them in North West Europe. This represents 14% of the lEO installed capacity. The first plants to be closed were the old plants, which have lower efficiencies than new builds. However, the further deterioration of market conditions has led utilities to mothball new build plants with efficiency in the range of 58-60%. lf all gas power plants currently under review by major European utilities are closed, this may lead to the closure of about 50GW of capacity by 2015/16, or 28% of the current capacity, while at the same time this capacity is needed to ensure security of supply when wind and sun are not producing.
A reduction in the environmental benefits resulting from gas
Figure 5 - CO2 emissions by the EUETS power sector 2008-2012 (Source: Cedigaz, 2014)
It is somewhat ironic that at a time when the EU economies aspire to green economics and lower emissions, despite the growth in renewables as a source for power generation, the current switch from gas-to-coal means that CO2 emissions in the EU ETS have not decreased since 2009. The reform of the EU ETS which is urgently needed should allow natural gas to play a key role in the decarbonisation of the EU electricity system. A reduction of CO2 emissions by 40% by 2030 could hardly be met otherwise.
A reduction in security of supply
With gas fired power generation becoming uneconomic and many coal-fired power stations nearing the end of their active lives, capacity of between 115-120GW is closing or at risk of closure, representing a third of gas and coal capacity in the EU. These trends pose a serious challenge for security of supply as thermal power generation is needed to back-up variable RES. The building of flexible power capacity required to support the development of RES is threatened by the lack of market signals and adverse investment environment. The current situation has the potential to unfold into a major structural crisis.
Although reserve margins are currently still adequate in most countries, when the anticipated mothballing/closure of uneconomic plants, retirement of ageing coal plants, as well as delays or cancellations of new projects are taken into account the situation is different in several countries. In the UK, for instance, despite the expansion of RES, the reserve margin is falling. While old coal plants are closing (as expected), the (unexpected) mothballing and early closure of gas plants is reducing the power margin from 6% in 2013/2014 to 4% in 2015/2016, a level which puts the UK system at risk.
How will the future develop?
Gas prices are likely to be going down
There is downward pressure on future European gas prices, coming from indexation on gas hubs, a wave of new supplies (pipeline and above all LNG) and potential shale gas production in the EU. In the short term, the influence of oil prices will still dominate for several years. Despite the declining share of European supplies tied to oil prices, long-term contracts that make up most of European pipeline imports, some of them running until 2030, are still 50% linked to oil. In the coming years, marginal supplies needed to cover an increase in European gas demand (or decline in EU production) will be determined by supplies which either are linked to oil (pipeline gas from Russia) or have to compete with Asia (and Latin America) where LNG prices are still linked to oil prices and much higher than European prices. Seasonal drops in gas prices, as currently experienced, can be expected depending on the availability of uncontracted LNG supplies.
In the medium/long-term, with a growing share of gas supplies sold based on hub prices, prices will be determined to a much larger degree by actual supply and demand fundamentals and by gas-on-gas competition between various suppliers competing for market shares. The move to gas-to-gas competition needs to be accompanied with the development of new gas sources, particularly in southeast Europe. This should include indigenous gas supplies and imports via pipeline and as LNG. A higher share of LNG imports is foreseen. This is in line with the high regasification capacity available in Europe which theoretically would allow the imports of 199 bcmpa. Numerous LNG export projects are being developed by new sellers (US, East and West Africa) that will offer the possibility to further diversify EU gas supplies. In addition, new supplies from the Caspian region, East and West Africa, the Mediterranean, possible production of shale gas in the EU and LNG exports from the US based on Henry Hub prices may add competitive pressure and put a cap on European prices.
Coal prices are likely to be going up!
In contrast with natural gas, the coal market is a global and competitive one. Prices are similar on the Pacific and the Atlantic basins. The supply glut that has developed on international markets has led to a large decline in coal prices. China, which was still a net exporter in 2008, has become a net importer since 2009 and became the world's largest coal importer in 2011. It now represents almost a quarter of world steam coal imports. Due to its size on the international coal market, China has become a price setter for steam coal and policy decisions taken in Beijing affect the price of coal delivered to other Asian countries and European buyers. Yet China remains the world's largest producer of coal. Its imports are only a small part of its supply. They are driven by coal price arbitrage between domestic and international coal prices. This makes the forecasting of future global steam coal trade and prices difficult as it depends on China's market development and government policies. The Chinese government is determined to reduce the share of coal in the energy mix. This may drastically reduce China's coal imports. However, while the commitment of the government is clear, the speed of change remains uncertain.
Despite these uncertainties, the growth in global trade is expected to slow down in the next few years. The global supply overhang is expected to persist in 2014 and 2015. As prices have certainly reached a bottom, no further declines are expected. Mining companies have started to close their highest cost mines and focus on cost reductions. The rebalancing of the market is not expected before 2016 and only a slight recovery in coal prices is expected as there are plenty of new coal mine developments in the pipeline.
The EU Emission Trading Scheme is neither up nor down!
While the EU Emission Trading Scheme (EU ETS) was introduced to provide a price signal for investment in low-carbon technologies, the massive oversupply of allowances has driven down carbon prices to such low levels that the EU ETS plays virtually no role at all in influencing investments into new generation capacities. With the adoption, at the beginning of 2014, of short-term measures (backloading) and proposed in-depth structural reforms, the European Commission hopes to address the present EU ETS flaws and promote a well-functioning carbon market. The reform is urgently needed to give the appropriate signal for future investment in the power sector. However, while CO2 prices have settled at €5-6/t since the beginning of 2014, a level of €30/t would be required to foster switching from coal to gas at prices observed at the beginning of May 2014 (€50/t at gas and coal prices in January 2014), a level which is not attainable, nor desirable, in the short term. It should also be mentioned that before any major investment decisions in the power sector are made based on the EU ETS, the price needs to reach a significant level and stay there for a prolonged period of time.
A new market design is required
As the market does not provide the right signal for investment in conventional capacity, a new market design might be urgently needed. A sustainable electricity market design needs to ensure that low carbon and fossil fuel-fired power plants have viable business models with manageable investment risks. To address the immediate security of supply concerns, several EU countries are introducing capacity markets in order to provide additional stimulus to investors and ensure that a sufficient amount of capacity will be available. The design of such mechanisms is however extremely complex with the need firstly balance the amount of capacity needed to ensure security of supply with demand-side response and secondly integrate interconnection capacity and the development of cross-border trade with the aim of achieving a fully EU integrated Internal Electricity Market.
The fall of gas demand in the EU appears to be a symptom of a serious problem in the EU energy market that could ultimately lead to countries, such as the UK, struggling to keep the lights on. Due to the prevailing economics in the energy sector, gas-fired power stations are currently experiencing a lack of investment. Even the most efficient stations are being mothballed. This is increasingly leading to less capacity in the market, as well as depriving Europe of the power source which provides the best foil to renewable energy. The dependence of RES on uncontrollable factors increases the importance of CCGTs as they are able to produce electricity when needed and therefore the lack of availability of gas-fired power stations increases unreliability and the chance of disruptions.
The market mechanisms suggested in the above paragraph do not answer to the immediate concern of keeping the lights on. A more profound reform of the entire power system will nevertheless be necessary, including structural reform of the EU ETS, integration of RES into the market and completion of the Internal Electricity and Gas Markets. In particular addressing the investment issue is of utmost importance to ensure future security of electricity supply. Capacity markets properly designed, should allow a recovery of investment in gas capacity, and in particular, to restart the numerous mothballed gas plants and unlock frozen CCGT projects.
 Cornot-Gandolphe, Sylvie, 'Gas and Coal Competition in the EU Power Sector', Paris: Cedigaz, June 2014.