Asia's Gas Conundrum

KimFeng Wong, Platts Senior Editor, LNG, and Martin Daniel, Editor, Platts Power in Asia

Asia needs a lot of natural gas to underpin the region's burgeoning economic growth, but so does Europe among other regions. With many potential sources of natural gas, both pipeline and LNG, increasingly accessible to different markets, how will Asia fare in the search for future gas needs?

FEBRUARY 1, 2007 MIGHT HAVE SEEMED like a bad day for the participants in the PNG Gas Project. After more than a decade of development, the project to pipe natural gas 3,000 kilometers from Papua New Guinea to Australia had been shelved.

But far from being subdued, partners in the project were remarkably upbeat. For instance Peter Botten, managing director of local exploration company Oil Search, commented that "alternative development options, including liquefied natural gas (LNG), petrochemicals and other in-country options, which were not present two years ago, are now demonstrably more attractive and cannot be ignored."

Botten pointed out that the "gas prices that can be realized from these projects are not constrained by the local market conditions in eastern Australia, which are dominated by large volumes of competitively priced coal." This meant that Australian east coast gas was priced at a significant discount to the world price and, while the price was likely to rise in the future, would remain capped by the price of coal.

The other partners in the project and other gas developers in the country clearly agreed. Within a few weeks, not one but four LNG export projects with up to 23.5 million metric tons (mt) of annual capacity had been announced in Papua New Guinea. Not all of the projects will proceed, not least because some of them are predicated on using the same gas deposits, but it is quite possible that LNG could be available for export from the country from 2012.

Papua New Guinea's gas developers are far from alone in promoting cross-border projects in the region, with LNG projects of particular interest. And buyer interest is equally strong at a time of tight gas supplies, high and volatile prices, and expectations of strong growth in Asian gas demand.

Rapid growth in Asian gas demand will simply continue existing trends. In 1996 the region consumed 238 billion cubic meters (Bcm) of gas. Demand rose by an average of more than 6% a year to 2006, when the region consumed 438.5 Bcm of gas. This included 135.2 Bcm of LNG, which in turn accounted for about 64% of global LNG trade.

Asian Gas Demand Set to Grow

Looking forward, the International Energy Agency (IEA) projected in its 2006 World Energy Outlook that Asian gas demand would rise by an average of 3% a year from 2004 to 2030above the global annual average of 2%. The IEA anticipated that steady growth would occur in traditional gas markets such as Japan and South Korea. But the Paris-based agency forecast much higher growth in developing markets such as China and India. Together, they accounted for only 20% of total Asian gas use in 2004 but are projected to account for 32% of the total in 2030.

The projections depend, of course, on a range of assumptions that may or may not prove accurate. There is at present a large amount of suppressed demand, which may mean that future consumption levels could be underestimated. But conversely in some key markets the price of gas paid by large users, such as power generators and fertilizer manufacturers, is regulated by the state and often below the economic cost of supply. This means that much existing consumption is inefficient and could fall if market prices were applied.

That said, it appears clear that Asian gas demand will grow substantially, although not all of it will necessarily be natural gas. There is significant potential for coalbed methane production in several key countries, including China, India and Indonesia. Coal gasification has also been mooted as an option, albeit one whose economics appear to be dependent on sustained high gas prices.

But most of the additional Asian gas demand will have to be met by natural gas and much of the consumption will rely on imported supplies. This is unsurprising given that many of the larger gas users such as Japan, South Korea and Taiwan are already wholly or almost wholly dependent on imports. But reliance on imports is also likely to grow in key developing markets. This means that the 61.4 Bcm of net Asian gas imports in 2006 may be expected to grow substantially.

Take China, for example. Demand in 2020 has been projected by the government at 200 Bcm whereas domestic production is projected at only 120 Bcm. Even with at least three major pipeline systems set to deliver western Chinese gas to the main markets in the east and south of the country, the projections indicate a substantial gap that would have to be supplied from LNG terminals or cross-border gas pipelines.

Where will the additional gas required in Asia come from? Indonesia has for years been the leading global LNG exporter. In 1997, for instance, its sales to Japan, Taiwan and South Korea accounted for not only a majority of their gas needs but also almost a third of total world supply.

But Indonesia's share of the LNG market has fallen steadily and will continue to do so even when the Tangguh project starts scheduled exports in 2009. In 2006 Indonesia was overtaken by Qatar as the world's largest single LNG exporter and its share of the global market fell to 14%, a fall that could presage an even sharper decline from 2011.

This is when a slew of contracts with Japanese and other importers are set to expire. Jakarta has said that many of these contracts will not be renewed, freeing up gas from Kalimantan to be delivered to Java by a proposed 1,200-kilometer pipeline.

Querying this strategy, international gas developers in Indonesia have pointed out that the price of gas to many domestic users is subsidized and thus lower than that available in the export market. The government has responded by saying that domestic gas users should receive priority since they create value-added products and local employment.

The argument is far from over, but Indonesia appears unlikely to help meet the increase in Asian gas needs. Indeed, the reverse is more likely in terms of internationally traded LNG requirements.

With other Southeast Asian LNG suppliers such as Malaysia and Brunei expected to offer relatively little potential for growth in output, a greater reliance on LNG imports from beyond the immediate region is anticipated.

1. Growth in Asia Pacific Gas Consumption in Billion Cubic Meters. Source: BP Statistical Review of World Energy (June 2007)

Step Forward, Australia

Australia is already established as an LNG supplier to the Asian market through the North West Shelf Venture and, more recently, the Darwin export terminal. Australian exports totaled more than 18 Bcm in 2006, all of which went to Asia. At the end of July 2007 there were 11 operating, constructing and planned terminals with at least 72 million mt of annual capacity, which chimes with the Australian Bureau for Agricultural and Research Economics' projection that LNG exports will reach 67 million mt in 2030.

Concerns have been raised in the industry about the escalating costin cases, near doublingof Australian LNG projects, and growing difficulties in securing environmental and other permits. There nevertheless seems little doubt that the Australian contribution to Asian gas needs will grow, probably very substantially. And given developments elsewhere, in particular in the Gulf Cooperation Council (GCC) member states, this will be more than welcome.

Much of the increase in Asian LNG demand since the mid-1990s has been met by the GCC members, which saw their share of the market rise from under a tenth in 1997 to almost a third in 2006 as LNG exports from the United Arab Emirates were joined by sales from Oman and, most importantly, Qatar. By 2011, some 93 million mt of LNG capacity is scheduled for operation in the three countries, with 77 million mt in Qatar alone.

But growth beyond this level is uncertain, with increasing concerns over the availability of gas supplies in the GCC states themselves. The rapid development of gas-intensive industries such as petrochemicals, power generation, fertilizers, aluminum, and cement is producing a gas crunch.

The concerns were telegraphed in April 2005 when Qatar imposed a moratorium on new North Field projects to assess field performance. Since then there have been several pointers with, for instance, the sixth potline expansion project at Aluminium Bahrain's plant having been postponed in early 2007 because of inadequate gas supplies for power generation. Meanwhile in 2006 Saudi Arabia mandated the use of heavy crude oil instead of gas in new power generation projects to conserve gas resources for higher value uses. In July 2007 Ras Al Khaimah Cement reported falling profits as it substituted coal for gas at its cement works in the United Arab Emirates. And Oman is just one of several GCC countries actively looking at nuclear power and imported coal-fired generation to conserve gas supplies for use in higher value-added markets.

2. Australian LNG Export Projects in Million mt/year. Source: Platts LNG Daily, liquefaction terminal tracker

Iran to the Rescue?

One potential source of gas for the GCC members is Iran, which is discussing the sale of gas to several of the states for use on their own account or, in the case of at least Oman, for conversion to LNG for export from existing facilities. The logic seems obvious. Apart from its proximity, Iran has massive natural gas resources with the country's estimated proven reserve base of more than 28 trillion cu m (Tcm) at the end of 2006 being the second highest in the world.

The problem is that Iran has a legion of highly ambitious plans for its gas resources. These include proposals for its own LNG plants, with at least seven projects and up to 80 million mt of annual capacity on the drawing board. Based on the South Pars, North Pars, South Gashu, Golshan, Ferdows and Yadavaran fields, the projects include two 20 million mt/year ventures planned with China's CNOOC and Malaysia's SKS Ventures.

On top of that Iran is planning a substantial number of gas-based industrial and power generation projects at home. And it also has plans for the large-scale export of gas by pipeline both to Europe and South Asia.

Development of the country's hydrocarbon resources has, however, proved an uphill struggle to date, with projects having been affected both by limited capital availability and the tension between economic and political goals. As a result, the highly-subsidized domestic market is hamstrung by fuel shortages and most gas export projects remain at an early stage of development.

The $7.4 billion Iran-Pakistan-India pipeline project is a good example of the intertwining of politics, economics and hydrocarbons in Iran. Highly prized by Tehran for the links it would weld between Iran and South Asia, there has been fast progress at the political level. The route of the pipeline has been agreed, and the timing and gas volume set. But some pricing issues remain. Although a general formula relating the gas export price to Japanese crude oil imports was agreed in July 2007, there were unresolved issues relating to transit fees between Pakistan and India.

Political intervention in gas projects is not, of course, limited to Iran. The potential for collision between the political and economic imperatives of gas export projects was highlighted earlier this year at the Shwe project in Myanmar, where the consortium developing the offshore Shwe fields had been weighing up a range of options including piping the gas to China, India or Thailand or converting it to LNG. The decision was, however, short-circuited in March 2007 when the ruling military junta arbitrarily mandated pursuit of the Chinese pipeline option in what it made clear was an expression of thanks for Chinese political support at the United Nations. To add insult to injury, the junta mandated a gas sales price that appeared well below market levels.

Both the destination and price of the Shwe gas remain to be finalized and, on past performance, the junta could well change tack again. But the incident emphasizes the point that gas pipeline projects can have a symbolic importance beyond their economic rationale that may determine which suitors for gas supplies may be successful.

Choosing LNG or Pipeline Gas

The Shwe controversy also highlights the point that many gas fields have the option of either exporting their output by LNG train or pipeline. In general, the economics tend to favor piping gas rather than supplying it as LNG, although the cost equation depends on factors such as the size of the gas deposit, the proposed volume of exports, and the distances involved.

But other considerations are involved which mean that LNG, where an option, currently appears to be in the ascendancy. The LNG option may be favored by the ability to sell to several countries or regions, thus diversifying market risk. Commercial risk may also be mitigated by the potential for selling LNG to a range of customers, whereas pipeline gas deliveries, especially to parts of Asia, may be routed through a single buyer operating in a regulatory regime where state intervention and price distortion is endemic.

In this context a key issue, already noted for the cancelled PNG Gas Project, is the incumbent fuel that the gas will face, and thus the benchmark price that it may be measured against. With low-cost coal the dominant industrial and power generation fuel in much of the region, and especially India and China, this is a potent issue especially given that substantial carbon pricing remains a remote prospect in these jurisdictions. And even if indigenous gas is the alternative fuel the issue may be no different, and no less problematic, if end-user gas prices are subsidized or the indigenous gas industry is protected by tariffs.

On top of all this, political risk may be greater for a pipeline project than an LNG project if it traverses jurisdictions where cross-border or internal disputes could disrupt supplies.

The political risk equation may also be a factor in deciding between rival pipeline optionsin other words, whether gas from a particular deposit or region is best delivered to one or another geographical market. In this context the same market risk considerations that may favor an LNG project over a pipeline may also favor one pipeline option over another. And in the increasingly global gas market this is a key issue for many West and Central Asian gas export projects where, while LNG may not be an option, a pipeline could serve either Europe or points east.

Iran's option of exporting gas by pipeline to Europe as well as South Asia has already been noted. The European option moved forward in July 2007 when a memorandum of understanding was signed for the export of 30 Bcm/year of gas to Europe by way of Turkey from Iran and Turkmenistan.

Central Asia Beckons

Turkmenistan is in fact one of the best-placed countries in terms of its potential to export gas to various geographical markets. Although not a prospective LNG exporter, Turkmenistan can feasibly deliver gas by pipeline not only to Europe but also to West, South and East Asia.

The westward options include not only the proposed delivery of Turkmen gas by way of Turkey but also the expansion of existing exports to Europe through Kazakhstan and Russia. Turkmenistan agreed to increase these sales in May 2007. The construction of a new pipeline and upgrading of the existing pipeline network will allow the delivery of 20 Bcm/year of additional gas to Europe from Turkmenistan, Kazakhstan, Uzbekistan and Russia after 2012.

The South Asian option would involve the export of Turkmen gas to the subcontinent through Afghanistan. Under consideration for many years, the project was originally envisaged as supplying gas to Pakistan alone. Interest in the project was, however, boosted in 2005 when it was agreed that deliveries could be extended to the much larger Indian market. The 30 Bcm/year project faces a number of sensitive cross-border and security issues but has backing from the Asian Development Bank, with deliveries tentatively slated from 2011.

Another option is to export Turkmen gas eastwards through a pipeline that would link up with China's domestic west-east pipeline system in the Xinjiang Uygur Autonomous Region. Passing through Uzbekistan and Kazakhstan, the Central Asia Gas Pipeline could also access gas resources from those countries for sale to China.

Discussions on a gas pipeline to China from Kazakhstan, which has 3 Tcm of proven reserves, had in fact already been held in 2005 following the completion of an oil pipeline between the two countries. At that stage the supply of up to 30 Bcm/year from Kazakhstan to China was projected from 2012, although Kazakh government projections issued in 2007 indicate that total gas exports will only total 24.8 Bcm in 2015.

Uzbekistan has also been stating its claims. It signed an agreement with Beijing in April 2007 to build a 530-kilometer pipeline capable of exporting at least 30 Bcm/year of gas to China.

Meanwhile the export of 30 Bcm/year of Turkmen gas for thirty years through the proposed Central Asia Gas Pipeline was agreed in principle in April 2006. Based on eastern Turkmen fields, said to include Sag Kenar and Yoloten, the agreement was formalized in July 2007 during a state visit to Beijing by Turkmen President Gurbanguli Berdymukhamedov. The state-controlled China National Petroleum Corporation signed the related gas production sharing contract for the Amudarya River right bank gas field development project at the same time.

But the gas sales agreement included no reference to pricing terms, which were left for later finalization. This may prove problematic, given that there appears to be a wide gulf between China's desire for a formula predicated on low prices and fixed for the duration of the contract, and Turkmenistan's desire for a flexible system related to international prices. Hopes for an early start to deliveries may thus prove optimistic.

With so many options on the table, attention has also focused on how much gas Turkmenistan can supply in the near to medium term. While its gas reserves are undoubtedly very large, most are at an early stage of development. Proven reserves were put at no more than 2.86 Tcm at the end of 2006, while gas production of 62.2 Bcm in 2006 was in early 2007 officially projected to soar to 250 Bcm a year by 2030.

3. Main LNG Import Projects in China in Million mt/year. Source: Platts LNG Daily, Asia terminal tracker

Russia flexes its muscles

Limits to proven reserves are not a problem for Russia which, with 47.65 Tcm of proven reserves at the end of 2006, hosts far and away the largest single national block of gas resources. Output is also substantial, at 612 Bcm in 2006, and expected to growin June 2007 production was officially projected to reach 850 Bcm by 2020. In common with Turkmenistan, Russia is well positioned at the crux of the ever-decreasing energy divide between Europe and Asia but, unlike Turkmenistan, has the option of exporting gas as LNG as well as by pipeline.

Russia has several operating or well advanced projects based on sales into the European market, but also has substantial plans for the sale of gas into Asia. The availability of gas resources to meet all of the projects does not appear to be an issue, but the order in which the projects will be implemented remains to be decided.

The order will partly depend on technology developments, since some of the prospects will involve the use of ground-breaking techniques. More important, however, will be their relative economic attractiveness and thus access to capital. An enormous amount of investment will be required to develop all the Russian gas prospects – the figure to 2030 was officially estimated in July 2007 at $420 billion.

There is no doubt that the first project predicated on gas sales into Asia will be the Sakhalin-2 project in Far East Russia. In the first instance the project will sell 9.6 million mt/year of LNG to Japan and South Korea from 2008, but the substantial expansion of the terminal may be anticipated.

This likelihood grew when the state-controlled Russian gas giant Gazprom acquired a majority stake in the Sakhalin-2 project in the first half of 2007. Gazprom officials subsequently said that the expansion of the Sakhalin terminal could be based on the use of gas resources from other projects in the Sakhalin area, including the Exxon Neftegaz-led Sakhalin-1 project. At the same time they criticized an agreement signed in October 2006 for the export by pipeline of 8 Bcm/year of Sakhalin-1 gas to China.

That project had been agreed within the framework of a bilateral agreement signed in March 2006 for the supply up to 80 Bcm/year to China through two pipelines. The 3,000-kilometer western Altai pipeline would run from fields in West Siberia to the Xinjiang Uygur Autonomous Region, while a pipeline system to the east would supply gas from East Siberia and possibly Far East Russia.

Both pipeline projects remain on the table with Russian officials saying in mid-2007 that the western system could deliver 30 Bcm/year from 2011. The eastern route would be developed subsequently, the officials said, and from 2016 would deliver 38 Bcm/year to China as well as an unspecified amount of gas to South Korea. Part of the gas could come from Rusia Petroleum's Kovykta field in East Siberia, which is also now controlled by Gazprom and has 1.41 Tcm of proven reserves.

Prices have, however, been a stumbling block in negotiations between Russia and China. China's position hereas elsewhereappears to be that imported gas must be broadly aligned with the price of local fuels at destination, primarily meaning indigenous coal. The Russian view is that the resultant netback price is too low compared with that available from European sales, and that the contracts must also offer more flexibility than the fixed, long-term agreements that China is seeking.

In this context, Russia's limited capital resources might be expected to flow to European-bound gas projects. And if China is not prepared to move on the terms that Moscow requires, the long-standing option of piping eastern Russian gas to South Korea and Japan may come into play.

What, then, does all this mean for the future level of Asia gas demand and how it will be met? For the traditional LNG importersJapan, South Korea and Taiwanthere will be a continued emphasis on long-term LNG contracts, backed by investment in contributing gas fields and LNG export terminals, plus renewed interest in spot purchases of LNG if prices weaken. But pipeline gas could also be an option for Japan and South Korea, if Sino-Russian negotiations on tariffs are deadlocked.

China and India are, as so often, the big question marks. If high international gas prices persist, China may be expected to scale down its gas import expectations with more emphasis on the development of indigenous natural gas and coalbed methane resources. While three Chinese LNG import terminals seem certain to proceed in Guangdong, Fujian and Shanghai, many of the other LNG import projects proposed in recent years appear doomed to gather dust. It also appears likely that, while pipeline imports from Central Asia and Russia will almost certainly occur, any concessions by Beijing on prices will require significant trade-offs in terms of Chinese involvement in the supplying fields and pipelines. They will also almost invariably be pursued, as in the case of Shwe, in a wider political context.

But again, all this could change if significant movement occurs in China on issues such as carbon pricing, energy deregulation and tariff reform, resulting in gas becoming more competitive with local coal. With China, it is never wise to be too categorical.

It will not be much different in India, the other key Asian market for substantial gas growth. Imports face substantial obstacles in the form of subsidized end-users and protected domestic energy producers, as attempts to sign up both LNG and pipeline supplies have indicated. These problems are compounded by the fact that several of India's potential pipeline import options could involve significant political risk issues.

What is certain is that the days of a segmented global gas market where events in Asia had no impact on Europe, or vice versa, are now over. And one clear implication is that the state regulation of the gas markets in many Asian jurisdictions may come under pressure as the resultant inefficiencies and price distortions mean that, without change, access to traded gas supplies could become ever more difficult.