There are four main themes that will characterise the Asian oil and gas space over 2013:
Gas will outperform oil in terms of both production and consumption. A downside risk to demand is a change in policy in Japan, as recently elected Prime Minister Shinzo Abe's Liberal Democratic Party is pro-nuclear and may seek to restart nuclear production;
Liquefied natural gas ( LNG ) development will remain a top priority and both producers and importers will be keen to invest in the sector ;
Shale gas exploration could continue to pick up, though coal bed methane (CBM) production growth could come under pressure;
D ownstream profits across much of the region will continue to be affected . Price regulations will continue to stifle returns in regulated markets, while refiners in competitive markets such as Australia and Japan see the profitability of their operations increasingly challenged by imports produced in more sophisticated plants elsewhere in a very competitive global fuels market.
Although BMI 's Power Team forecasts that coal will remain the dominant fuel for power generation in Asia, gravitation towards gas is underway as policies shift towards greater gas usage to reduce carbon emissions. This will also shift the balance between oil and gas consumption towards gas, especially with China actively pushing for the switch to LNG in the transport sector.
Overall demand for natural gas in Asia will grow faster than demand for oil: gas consumption is expected to increase 73.5% over our 10-year forecast period between 2013 and 2022, while oil consumption will grow at a slower (though still impressive) rate of 24% over the same period. There could be further upside potential for gas consumption growth; India and Pakistan could further boost demand if infrastructure (both pipeline and LNG import terminals) is brought online in time to meet real consumption needs. At present, a series of delays in infrastructure projects have led to a conservative approach in our forecasts.
|% Change In Oil & Gas Consumption, 2011-2022|
A slower rate of economic growth as well as increase s in domestic production and energy efficiency gains will restrain growth in oil imports. This will prove particularly true in China, where oil consumption growth is expected to slow from about 4.3% in 2012 to 2.5% by the end of our forecast period in 2022. This is a downward revision from our previous forecast of about 3.0% by 2022, as our Country Risk team sees increasing signs of headwinds that would limit China's growth.
|Asia's Oil Consumption, 2012 -2022 ('000b/d)|
Pacific Leads Liquefaction Boom, With Challenges
A booming LNG market in Asia and changing dynamics has laid the foundation s for growing regional LNG trade. Papua New Guinea (PNG) and Australia are undergoing large-scale expansions to lead the region's liquefaction capacity growth. PNG is hoping to sign off a third export facility, to be led by Horizon Oil and Osaka Gas , even though a final investment decision (FID) on the second project (Gulf LNG) is still pending. Malaysia and Indonesia will also add to this growth.
|Project||Schedule||Capital Expenditure (US$bn)||Plant Production (mtpa)||Plant Type||Cost Per MTPA (US$mn)|
|*Awaiting FID. Source: BMI, InterOil, QCLNG, APLNG, Chevron|
|Queensland Curtis (Australia)||2014||20.4||8.5||Phased||2,400|
|Australia Pacific (Australia)||2015||24.7||9||Phased||2,744|
|Gulf LNG (Papua New Guinea)||2016*||9.3||3.8||Phased||2,447|
|PNG LNG (Papua New Guinea)||2014||19||9||Phased||2,111|
|Tangguh LNG (Indonesia)||2019*||12||3.8||Phased||3,158|
However, many of these projects have experienced cost blowouts - Chevron reported that Gorgon LNG will cost US$12bn more than original estimates, while Origin (APLNG) , BG Group (Queensland Curtis LNG) and the partners of Gladstone LNG have all raised the capital cost of their projects in 2012.
As expected, project cost inflation has continued to dominate the market discourse in 2013. While existing projects will still proceed, further expansion of Asia's LNG liquefaction capacity - primarily in Australia -could be slow to materialise. With the global gas market remaining in a state of flux as LNG buyers exert pressure for lower prices on the assumption that regional gas markets will converge, project economics are highly precarious. The Browse LNG project in Western Australia has fallen victim to cost pressures, as Woodside Petroleum made the decision to shelve its development in April 2013. Royal Dutch Shell and PetroChina's Arrow LNG could also face the same fate.
Interestingly, companies that are still interested in LNG export projects in Australia have all proposed floating development concepts. Some of the proposed floating LNG (FLNG) projects are ExxonMobil's Scarborough, GDF Suez' Bonaparte and PTTEP's Cash Maple. Woodside has also increasingly warmed to partner Shell's push for a FLNG development for Browse over an onshore terminal. This novel concept has been deployed by Petronas in Sarawak, Malaysia, as a means of monetising gas from stranded fields far away from its onshore Bintulu LNG complex. Indonesia's Abadi LNG, led by Inpex, has also turned to a FLNG concept. These projects are of a smaller scale, but the flexibility in constructing facilities will allow firms to overcome local cost constraints to bring fields into production as early as possible.
|Balance Of LNG Trade|
|LNG Trade Pattern By Country (bcm)|
LNG Demand Stays Buoyant
Asian consumption of LNG is expected to increase over the next decade. Japan's move away from nuclear in the wake of Fukushima, rapidly expanding LNG demand in China and India , clean energy policies and economic growth in the region will drive a boom in demand for LNG . Other countries expected to contribute to this increase in demand include Thailand, Singapore and Pakistan. Vietnam and Philippines could also become LNG importers as import projects have been proposed to meet their rising gas consumption.
The region is currently a net LNG importer. According to our long - term forecasts, the region's LNG export capacity (based on its liquefaction capacity) is expected to double between our forecast period of 2013 and 2022. However, it will still be insufficient to catch up with the region's import requirement, which is expected to increase 62 % over the same period. Hence, Asia will remain a net LNG importer for the foreseeable future . This is also a reason for Shell 's optimism about the Asian growth market , which has led the Anglo-Dutch major to consider moving the headquarters of its integrated gas business to Singapore ( see 'Gas Move Reaffirms Shell's Asia-Centred Growth Strategy' , December 7 2012 ).
There is, however, the possibility that Japan will restart some nuclear power plants - posing some downside risks to our forecasts, though regulations and political resistance are likely to make the return of nuclear power a gradual process. Growing demand from China and India are also expected to more than make up for this downside risk.
|More Than It Can Bear|
|Comparison Of Asia's LNG Import Requirement* With Export Capacity† (bcm)|
The region's unconventional segment is gaining a lot of momentum and presents upside risks to our natural gas forecasts. We believe that shale gas exploration will continue to pick up in 2013, especially in China. Santos has already developing a commercial shale gas project in the Cooper Basin. Shell also made a FID for the Fushun-Yongchuan shale gas block in the Sichuan Basin, China in March 2013, and expects early production by mid-decade.
|Comparison Of Shale Gas Estimates & Proven Gas Reserves At Start-2013 (tcm)|
The EIA's updated study of the world's shale resource estimates also includes provisional figures for shale oil. These new estimates suggest that shale oil could add significant upside to China an d India's proven oil reserves and long-term production potential, though this will most likely be realised only towards the tail-end of our forecast period for China and beyond our ten-year timeframe for India.
|Shale Also Promises Oil Boom|
|Comparison of Technically Recoverable Shale Oil And Proven Oil Reserves, Start-2013 (bn bbl)|
China is officially targeting annual shale gas production of 6.5bn cubic metres (bcm) by 2015 and a further 60bcm to 100bcm by 2020 - targets that the country may miss given the need to dramatically ramp-up production from the current non-existent levels. As part of its bid to incentivise the development of domestic shale gas, China has introduced fiscal incentives which will see a subsidy of CNY0.4 per cubic metre (/cm), or US$0.06/cm, of shale gas produced from 2012 to 2015. An official from the Ministry of Land and Resources (MLR) also suggested that Beijing could directly fund early exploration and production (E&P) as part of new terms in an upcoming third shale gas round, in order to de-risk E&P for small independents in particular.
In the medium term, India and Pakistan could also see shale gas exploration pick up once regulations have been established. ONGC and ConocoPhillips are poised to formalise an agreement to develop India's shale gas resources in advance of an ongoing overhaul of shale gas regulations and a planned (although already delayed) licensing round sometime in 2013. Eni has also expressed interest in Pakistan's shale gas potential, though the Asian Development Bank (ADB) has warned that embarking on the water-intensive extraction of shale gas could deprive the agricultural sector of water in Pakistan. Indonesia joins the line of countries seeking to open up its shale resources, having handed out its first shale licence to NOC Pertamina in May 2013. Geological challenges, water scarcity, infrastructure issues, state-regulated prices and environmental concerns could prevent a shale revolution from sweeping through Asia in the short term, but in the longer term it could be difficult to stop. Crucially, the technology is available, and it is constantly evolving. In time to come, geological understanding of shale formations and their properties in Asia are likely to improve. Research into more efficient use of resources - water among others - in fracking could also reduce the environmental risks of operations. The long-term demand for gas is undeniable and political pressure could swing in favour of tapping into domestic shale resources in order to reduce energy costs.
What will particularly differentiate this shale revolution from the one in the US will be its leading actors. In the US, it was a bottom-up effort - technology developed by the private sector was tested and deployed on private land, spurred on by high natural gas prices determined by market forces of demand and supply. In Asia, with the exception of Australia, the effort is likely to be a top-down, state-led one done through private collaboration with national oil companies (NOCs).
The exploration and production (E&P) of CBM is also ongoing in the region. Australia leads the way, with the Gladstone LNG, Queensland Curtis LNG and Australia Pacific LNG projects tapping gas produced from this unconventional source for feedstock for these liquefaction projects. China and India are also tapping this resource, though production is miniscule in both countries. Indonesia has roped in companies, notably ExxonMobil and BP, for to search for gas in its coal beds. Its first CBM-fired power plant is set to come online later in 2013. The speed of CBM production is likely to take a fall, particularly in light of new regulations passed in Australia in June 2013. Coal projects - which include CBM ones - that will affect the country's water reservoirs are now subject to a lengthy approval process at the federal level before they can proceed. The industry has criticised this move for slowing project development. Moreover, investment could also be hit by proposed regulations in New South Wales where many prospects are located - that will prohibit extraction within areas in close proximity to residential housing or agricultural interests. Prior to the passage of these regulations, firms have already been withdrawing from CBM projects and we expect that this will only intensify in the near future.
Asia has the largest refining capacity globally, and we estimate that it accounted for 32% of global refining capacity in 2012 . In growing markets such as Vietnam and Indonesia, domestic refining capacity remains far too small to meet local demand.
Singapo re, Japan and South Korea are the region's refining giants, while China and India c ontinue to expand their capacities to meet growing domestic demand. By 2022, we expect Asia's share of global refining capacity to rise to 36% as mega-refinery projects come online.
|Asia's Share Of Global Refining Capacity, 2012 & 2022|
Downstream expansion could also come from Vietnam and Indonesia; for instance, Indonesia could see at least three newbuild refineries of 200,000b/d in joint projects with Saudi Aramco, Kuwait Petroleum International and PTT Chemicals if favourable tax breaks are given for these projects.
Indeed, Asia's refining market is characterised by an unfavourable investment climate in many countries - notably China, India, Indonesia, Malaysia, Thailand and Vietnam. In addition to state dominance of the downstream segment, price controls have also acted to stifle private or foreign investment into these sectors.
There could be increasing willingness to revise domestic fuel prices as the state-owned refiners in emerging Asia see profits suffer from having to effectively subsidise their countries' fuel consumption - many of these NOCs have had to import crude or fuel at global prices but sell refined goods at lower prices fixed by the state in the domestic market. This has either narrowed the refining margins of producers as global crude prices rise to historic highs or undercut their profit altogether.
Some steps have been taken to revise fuel prices. China's National Reform and Development Commission (NDRC) adjusted its fuel price mechanism in March 2013, allowing domestic prices to more closely track changes in global crude oil prices. Indonesia also took a significant step in reducing fuel subsidies, which would not only give the government more breathing room but also relief some pressure for Pertamina. Nonetheless, the need to promote economic growth and contain inflation and to maintain political popularity will limit the extent to which price revisions will take place. Consequently, refining margins are likely to remain under pressure in the state-dominated downstream environment throughout much of emerging Asia.
|Demand Fuelling Expansion, At The Risk Of Traditional Players|
|Asia's Refining Capacity, 2012-2022 ('000b/d)|
Refiners in markets with competitive pricing - such as Japan and Australia - are also under pressure. Due to their less sophisticated ref ineries with smaller capacities and higher crude oil import dependency, they are losing out to more exports manufactured in larger plants from both Asia Pacific refiners such as Singapore and the global market. Australia saw a shutdown of its Clyde refinery in September 2012, and may have only five operating refineries by 2015 when Caltex cease operations at its Kurnell plant in 2014 . If Shell fails to find a buyer for its Geelong refinery, its domestic refining capacity will take a further hit. Cosmo 's Sakaide refinery in Japan has also fallen victim to this tough climate and will close by July 2013.
These two trends mean that profits in the downstream segment will come under price pressures across the region. It could prompt private players to continue divesting downstream assets in smaller demand markets such as Malaysia and Philippines. The possible exit of smaller refineries opens up room for existing players to dive into newly available markets, though these players such as Singapore's large refineries will have to ensure that their plants are sufficiently equipped and modernised to withstand competition from emerging players such as China.
NOCs are also likely to pick up the slack in highly regulated markets, to reduce fuel import dependency. There has been plans for many of the region's NOCs to establish joint ventures (JVs) with foreign partners to fund large refinery projects deemed to be more profitable ( see 'Downstream Expansion Looms In South East Asia', January 21). Whether or not these will fall through will depend on the incentives that governments are willing to offer foreign partners.