Global oil prices are dominated by three key markers, but gas prices show much larger regional variations – shaped not just by local supply and demand imbalances but also by different pricing strategies.
Wholesale gas prices vary enormously. America has a fully liberal and liquid gas market where prices are typically around $4/mmBTU (‘mmBTU’ being million British Thermal Units, a unit of energy). European prices vary depending on whether the gas is bought from the spot market, typically for ~$9/mmBTU, or via oil-indexed contracts for ~$12/mmBTU. Spot LNG cargoes in the Far East are more expensive still, valued at around $16/mmBTU, although these have fallen more recently to nearer European oil indexed prices.
Gas prices are not unified in the same way that oil prices are because gas is less fungible than oil. Gas trade used to be consigned to flow along pipelines, but the rise of LNG is challenging the paradigm of geographical restraints to global gas trade; moving gas not just across borders but beyond continents, with implications for future market dynamics and prices. However, pipelines are still responsible for moving the most gas, having shifted 68% of exported gas in 2011.
This blog will consider key price drivers in North America, Europe and the Far East and explore how recent advances in shale and LNG are changing global gas markets.
Gas markets across Europe come in two types: free market virtual trading hubs, as seen in the UK with the National Balancing Point (NBP), to markets with long-term oil-indexed contracts traditionally favoured by exporters such as Gazprom and Sonatrach. According to Oxford Institute Energy Studies, 58% of gas sold in Europe during 2011 was under an oil-linked contract. It is expected that this balance will tip towards a more liquid market in the longer term future. The Economist reported that gas-on-gas competition set the price for 20% of the European market back in 2005.
In recent years, Hub based prices have almost always delivered cheaper gas to the UK than prices seen in mainland Europe. With Brent oil priced above $100/bl throughout 2011, many mid-stream utility companies on the continent were trapped between expensive oil-indexed contracts on the supply side and customers demanding cheaper hub-based prices on the other. This has led to renegotiated contracts and at least three arbitration cases against Gazprom, who have now acknowledged that the long-term contract formula needs to be addressed to enhance the competitiveness of Russian gas in Europe.
Russia has substantial swing capacity and is a key supplier to Europe’s gas market. The country is faced with the choice of supplying more gas to Europe in order to capture market share, recognising that this would cause spot prices to fall as a consequence, or alternatively to restrict trade flows; tightening the market with the corollaries of raising spot prices but losing market share to any excess LNG.
The impact Russian supplies have on European spot prices was demonstrated in early 2012, when Gazprom was unable to meet the demand of its major clients due to extreme weather conditions. Deliveries fell well below requested nominations; the result manifested itself in Britain with a short, sharp 30% price increase in early February, as the market responded to signals of imbalance in mainland Europe which is linked to the NBP via the Interconnector.
Despite its huge reserves and strong geostrategic location between Europe and energy hungry China, Russia has not secured any contracts for eastern pipeline routes to supply Asian markets, as was hoped for by President Putin. Negotiations continue. Turkmenistan sent 14.3 billion m3 of natural gas to China by pipeline in 2011, so Russia would be competing with the mid-Asian block in terms of supplying pipeline gas to China. Russia did send 14.4 billion m3 of LNG to the Asia Pacific region from Vladivostok, so Russian gas is not solely dependent on European sales.
At the turn of 2000, North America was readying itself to receive large volumes of LNG cargo; building 200 billion m3 of import capacity. However, the shale gas “game changer” saw domestic gas production rise by 27% and the US supplant Russia as the largest producer of gas in the world. This increase in production, coupled with high demand for LNG in the Far East following the Fukushima incident in March 2011, meant that only 6% of US regasification plant capacity was used in 2011. Due to its newly found energy independency, the North American market is effectively isolated from the higher prices present in the rest of the world.
In a scenario where US shale production remains high and the American government does not allow excess gas to be exported as LNG, then Henry Hub prices will stay low. This is of concern to American gas producers, as the breakeven price is estimated by OIES to be around $6/mmBTU, 50% higher than the current price. Ceteris paribus, the American shale boom is unlikely to be economically sustainable, but is likely to be sustainable should the gas price rise to $6/mmBTU.
The Asia Pacific region has several industrial countries with no natural resources of their own, so it is unsurprising that in 2011 the region imported over 250 billion m3 of gas – a quarter of world trade.
A 76% increase in Asian gas production is not nearly enough to prevent the Far East becoming increasingly dependent on gas imports, which have increased five-fold between 2000 and 2011, because gas consumption has more than doubled in this timeframe. This demand was led by China, which overtook the US to become the world’s largest energy consumer in 2010. Since 2003, China has seen double digit percentage increases in gas demand year-on-year and this trend shows no sign of slowing. Gas makes up just 4% of China’s primary energy consumption, but in absolute terms this is still enough to make China the 4th largest consumer of gas in the world and the biggest gas consumer in the Far East.
Japan has become increasingly dependent on LNG, consuming a third of the LNG flows in 2011, as Japan hungered for readily available alternatives to nuclear power. LNG came to Japan principally from Malaysia, Australia and Qatar, but also from as far afield as Peru!
How far will the "shale gale" blow?
The North American market has been turned on its head by shale gas, but will this happen elsewhere? Indications from the Royal Geological Society are that the global distributions of shale beds are extensive.
In Europe, shale is unlikely to be quite the game changer it was in the US because there are significant logistical, political and social barriers to be overcome. Currently the number of rigs available in Europe is far below that seen across the Atlantic and at the time of writing, France and Bulgaria have banned fracking outright over environmental concerns. Frustratingly for Poland, a country eager to gain energy independence from Russia, early shale exploration has produced poor results.
China has grand designs for its large shale plays, with production expected to reach 150 billion m3 by 2015, of which 29% is forecast to come from unconventional sources. The difficulty for China is that most of the northern shale plays do not have readily available water supplies and fracturing for gas is water intensive: 19,000 m3 of water will operate a hydraulically fractured well for a decade – a similar amount is needed to water a typical North American golf course for a month!
In the UK, Cuadrilla claim that an estimated 200 trillion ft3 (tcf) of shale gas is in place in the Bowland shale. Not all of this will be recoverable, but in 2011 UK gas consumption was 2.8 tcf, so even a 10% recovery factor could make a substantial contribution to UK gas security.
With LNG technology, gas from Doha and Darwin can be super-cooled to form a readily transportable and highly energy dense liquid, and shipped far afield. This globalises options for gas exporters with LNG facilities. If LNG becomes the dominant way of moving gas, it would lead to a more liquid market, smoothing out regional fluctuations in demand and supply – leading to more unified global gas prices. However, this is unlikely because pipelines are a more cost effective means of moving large volumes of gas over long distances.
Asian LNG imports have shown strong year-on-year growth since 2010 (+15% 2010/11, +~13% 2011/12). This demand, driven largely by Japan’s need to replace lost nuclear capacity, has mopped up the excess LNG that existed in 2010 and 2011. In the longer term, should Japan follow Germany in a decision to phase out nuclear power, the global LNG market will tighten and this will give Russian gas a competitive advantage in Europe.
Prices in the three key regions discussed remain distinct, but gas markets are becoming increasingly linked and will continue to evolve as new technologies come to the fore: fracking has made shale plays economic and LNG capabilities have started to smooth out global supply and demand imbalances.
In the future, advances made in deepwater drilling could unlock the large (100tcf) discoveries off east Africa and new technology could open up the Arctic, where substantial resources are believed to exist.
Gas Works? Policy Exchange
Oil & Gas UK’s Economic Report 2012