It is fair to say that uncertainty over levels of future gas demand is at the highest in decades.
Despite worldwide demand for gas falling in 2009 due to the economic downturn, the International Energy Agency (IEA) forecasts average growth of 1.5% per annum through 2030, with non-OECD countries the focus.
Actual growth, however, will be influenced by various unpredictable factors including the strength and speed of economic recovery, future gas prices, government energy and environmental policies and the impact of new technology.
Future gas supplies are equally difficult to predict. The world’s proven reserves are estimated at 7,200trillion cu.ft (180trillion cu.m) by the IEA, with unconventional gas accounting for 4% of that total.
However, unconventional gas resources, such as shale gas, tight gas and coal-bed methane, could be considerably higher than the IEA estimate, but their impact on local and international markets is currently unclear.
Adding to the pressures from increasing shale and other unconventional gas production, there has been strong growth in global LNG (liquefied natural gas) liquefaction capacity, with around 2.26trillion cu.ft (64billion cu.m) due to be commissioned by 2014.
Asia remains the likely battleground for market share, with increasing LNG supply capabilities into the region from the Middle East, Southeast Asia and Australia, along with increasing pipeline capacity from the Caspian and Russia.
Additionally, long-term growth in shale gas production should play an important role in the region and Europe, not just in North America. Whilst unconventional gas resources have the potential to change the game, that potential is currently unproven and subject to uncertainties including economic recovery and growing environmental concerns.
These uncertainties make planning future investments difficult for companies. However, if the uncertain outlook for demand and supply, and short-term pricing pressures dissuade companies from investing, future supplies may fail to meet projected growth demands.
The US shale gas bonanza
At the end of 2008, the US Department of Energy (DOE) estimated the shale gas resource to be 32.8trillion cu.ft (928billion cu.m), just over 13% of total US natural gas reserves. However, proven reserves of shale gas are thought to be relatively small compared with total technically-recoverable reserves.
Shale gas development and production has emerged due to refinements of cost-effective horizontal drilling and hydraulic fracturing technologies. These two processes have allowed gas shale development to move into previously inaccessible and uneconomic areas.
US shale production growth is currently depressing short-term gas prices in North America. Prospects for continued or even more rapid growth in production, both in North America and potentially elsewhere, are also pressuring mid and longer-term price assumptions.
The DOE’s latest long-term energy forecast expects shale gas production to reach more than 12billion cu.ft (339.8million cu.m) per day by 2020, and almost 17billion (481.4million cu.m) by 2035.
Increased shale and other unconventional gas production will likely displace LNG in North American markets and shale gas is expected to be particularly competitive to higher cost LNG in the Atlantic Basin. Additionally, the continued de-coupling of oil & gas prices will result in increased pressure on oil-indexed gas prices.
Achieving security of supply in Europe
Shale and other unconventional gas resources have been identified in Austria, France, Germany, Hungary, Italy, Netherlands, Poland, Romania, Spain, Sweden, Switzerland and the UK, with land and licence acquisition and early-stage exploration under way in many of these countries.
There are a number of challenges to exploiting the shale gas potential in Europe, meaning it may not offer the same promise as in the US.
Higher population density may make stages of the operation more difficult and, while companies operating in Europe may learn from US operational experiences, opponents may seek to highlight examples of environmental impairment in an attempt to block developments.
Additionally, subsurface mineral rights tend to be state owned in Europe and there is a dearth of drilling rigs and other equipment required for shale gas development.
Compare Europe’s 50 onshore gas-drilling rigs in operation at any time to the 2,000 in the US. Furthermore, extracting gas from shale is a complicated process; what has been learned in the US may not directly transfer to Europe.
European governments are looking to reduce their reliance on imported gas supplies before the renewed interest in shale gas across the region. Their diversification strategies include increasing LNG imports from the Middle East – Qatar in particular – pipeline infrastructure growth from the Caspian and the Middle East and increased domestic production.
The Ukrainian government has reportedly authorised the Energy Ministry and state-owned Naftogaz Ukrainy to investigate the feasibility of constructing a regasification terminal on its Black Sea coast. If constructed, it would help reduce Ukraine’s heavy dependence on imported Russian gas, thus mitigating the threat of repeating pricing disputes with its neighbour.
Europe, which this year planned an additional seven LNG regasification terminals, will find its ability to attract sufficient LNG supplies will be challenged by competition from buyers in China, other Asian countries and the Middle East.
Presently, the main LNG suppliers to the region are Algeria, Nigeria and Egypt with Spain being the largest LNG consumer in Europe.
The move away from long-term contracts for flexible LNG supply means European buyers will have to compete with Asian customers on price to attract spot supplies.
Russia stands to be particularly challenged by the shale gas boom. Along with other Atlantic Basin gas suppliers, Russia’s Gazprom now finds prospects for a strong mid to long-term market for LNG imports into North America greatly diminished.
First gas from Gazprom’s Shtokman LNG development is now targeted for three years later than originally planned, while other high-cost developments targeting Atlantic Basin gas markets are being delayed by industry participants.
Russia’s strategic focus is likely to shift from ‘west’ to ‘east’ as Gazprom looks to develop fields and infrastructure to supply domestic customers in Russia’s remote eastern regions while targeting new customers in Japan, China and other Asian countries.
However, as Russia has the world’s largest reserves of conventional gas it will remain an important supplier to European markets.
Pipeline projects stall
The urgency to develop giant gas fields and progress pipeline projects across Europe has been moderated by the increased near-term availability of gas and projections for a slow recovery in demand across the continent following the economic downturn.
However, some of the proposed large-scale cross-border pipeline projects were facing delays before the collapse in gas prices due to political differences and the difficulty of securing agreement from some governments for gas transit through their countries.
A number of new cross-border pipelines have been proposed to supply gas from Russia and the former Soviet states to Europe and most have a start-up date around the middle of the next decade.
The European Union-backed Nabucco pipeline project, which would bypass Russia, is rival to the Kremlin-backed South Stream gas pipeline.
Both projects aim to supply natural gas to Southern and Central Europe. The Nabucco pipeline is intended to carry Caspian and Middle East gas to Central Europe thus reducing their dependence on Russian gas supplies.
A final investment decision, which has been delayed by politically sensitive negotiations over supply agreements, is now expected by the end of 2010, with a start-up date between 2014 and 2018.
A global market in the making?
Increased LNG trade and additional inter-regional pipelines will help promote more international trade in natural gas markets, but the prospect of a truly global gas market is still 15-20 years away. There remain significant variations between regions in how gas prices and level of government subsidies are set.
The US has the most developed spot gas market but the majority of gas in Europe and many Asian countries is still sold under long-term contracts. Only two markets worldwide are considered to be fully liberalised: the UK and US.
There will be increased market regionalisation in the short-term as new pipeline projects connect markets across borders. However, there are difficulties that must be overcome to achieve greater integration between markets. Companies transporting gas across national borders may encounter technical problems, such as differences in system pressure and directionality in pipelines.
The expectation that the lower gas price environment will prevail for a couple of years and may result in more LNG being traded on a spot basis or under short-term contracts as cargoes are diverted from their original destinations.
Additional capacity coming onstream may not have buyers lined up for all of the output resulting in more uncontracted gas available, which might be sold on a spot basis. Nevertheless, the majority of LNG produced is still sold on long-term contracts with prices linked to price of competing fuels.
A truly global gas market will not emerge until there is greater flexibility in gas supplies, increased transportation between regions and more gas-on-gas competition.
Alec Carstairs is head of oil&gas for Ernst & Young in Scotland
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