India and Japan issued a joint statement in September 2013 seeking to form a multilateral group of liquefied natural gas buyers to eliminate the premium that Asian importers pay to buy the fuel.
Indian Minister M Veerappa Moily and Japanese Minister Toshimitsu Motegi noted that Asian LNG prices are considerably higher than those in Europe and North America and not reflective of the actual fundamentals of LNG supply and demand. They invited other Asian importers to join a multilateral Joint LNG Study group to explore the formation of a buyers' consortium.
However laudable as an objective, this is unlikely to be effective immediately. Unlike crude oil, the market for LNG is not a global one. Prices are opaque, differ considerably by region and the market is not as deep or liquid as crude oil. Limited, albeit increasing, LNG volumes are traded on the spot market.
LNG trade requires heavy capital investment in the form of export/import terminals and specialised vessels. These costs are reflected in the price disparity. While US natural gas prices are determined freely according to supply/demand fundamentals at the Henry Hub pricing point, in Asia, LNG is bought and sold mainly via long-term contracts linked to the price of oil that is high at the moment.
In Europe, natural gas and LNG prices are a combination of the above. Currently, LNG prices for October 2013 are in the $15-16/mmbtu range for Japan and Korea; $11-12/mmbtu for Europe and $3.50-4/mmbtu for the US (natural gas). Clearly, Asian LNG buyers face a market that is skewed against them.
To assess how long this is likely to continue, a review of the supply/demand balance is useful. Currently, LNG receiving terminals are coming up faster than export terminals.
According to PFC Energy, global regasification (import) capacity was 608 million tonnes per annum (mtpa) at the end of 2011, with Asia accounting for roughly 50 per cent. Global liquefaction (export) capacity was 278.7 mtpa, indicating robust demand. Global LNG trade in 2012 was 239 million tonne, marginally down from 242 million tonne in 2011 (when the Fukushima accident led to a closure of most of Japan's nuclear power facilities and an atypical increase in its LNG consumption).
The overwhelming majority of market participants are extremely bullish about traded LNG volumes (a proxy for LNG demand) going forward. Energy advisers Wood Mackenzie forecast that traded LNG volumes will rise to 440 mtpa by 2025, and most analysts contend that LNG supply capacity will increase to match this demand.
The question then is, when will the market tip from excess demand to excess supply? The focus of new supply growth are proposed facilities in Australia, the US, Canada, Mozambique and Russia.
At stake is a lucrative prize - uncontracted Asian demand that could rise to 90-100 mtpa by the turn of the decade. At the moment, there is competition between all of these players to bring LNG production to the market before others. The following are in the race.
Australia has a two-decade-long history of exporting LNG and has six projects under different phases of construction, with a combined capacity of 52.8 mtpa. Exports will start from three LNG projects operated by Santos, Chevron and the BG Group in 2015, with others following suit in 2016 and 2018.
The surge in US shale gas production has transformed the country into an LNG exporter. Four facilities with 46.5 mtpa of export capacity have now been granted federal approval to ship LNG to countries not covered by US free trade agreements. The first, Cheniere Energy's Sabine Pass facility in Louisiana, will begin initial exports LNG in late 2015, while the others will do so in 2018.
Canada: British Columbia has emerged as the destination of choice for proposed LNG export facilities that seek to take advantage of the surfeit of natural gas being produced in Alberta and BC.
The two most advanced proposals for LNG export plants are the Shell-led LNG Canada project and the Chevron-led Kitimat LNG project.
They represent a combined export capacity of 27.5 mtpa and final investments decisions (FIDs) will be taken in 2015. Energy majors Petronas and BG will also take FIDs by 2014 to 2016 for their projects, and exports will begin after 2018.
Mozambique: ENI and Anadarko have discovered 100 trillion cubic feet of recoverable gas in the Rovuma Basin in offshore East Africa. The companies have announced the joint development of an LNG plant that could eventually be the largest in the world with a total capacity of 50 mtpa.
The first two LNG trains will have a capacity of 10 mtpa and will cost $10 billion. The investment is substantial for Mozambique, (gross domestic product $12.8 billion/2011), a country with no prior experience of large-scale hydrocarbon development that aims to start exporting in 2018.
Russia already exports LNG to the East Asian markets from Gazprom's 11-mtpa Sakhalin LNG terminal. State-owned energy giant Rosneft is planning another facility on Sakhalin Island in partnership with Exxon Mobil, with an initial capacity of 5 mtpa and first exports in 2018. Novatek's Yamal facility, in which Total of France has a 20 per cent stake, will have an initial capacity of 5.5 mtpa and aims to start exports in 2016.
Aggregating these projects indicates that 54.4 mtpa of capacity is slated to be complete by 2015-2016. This figure is corroborated by the International Gas Union (IGU) in its World LNG Report (2011), which states that global liquefaction capacity is expected to be 334.9 mtpa by 2016.
Assuming IGU's average utilisation rates for liquefaction plants in 2016 of 87.5 per cent and applying standard LNG demand models, the market would see a small surplus of about 1 per cent in 2016. The rest of the large capacity additions we have outlined above will only be complete after 2018.
As such, the LNG market will continue to be tight until 2018. This analysis is more optimistic on the supply side and extremely conservative on the demand side. The other determinant is LNG pricing. Most of the new Australian supply is already committed under long-term contracts to Japan/South Korean buyers who hold equity stakes in these projects.
Asian buyers, particularly China and Japan, want to secure new supplies from the other countries on the basis of flexible, hub-based prices, which at current levels would be lower than long-term (15-20 years) oil indexed contracts. However, such a move to hub-based pricing would have a concomitant impact on the ability of companies to finance their LNG liquefaction plants. Greenfield liquefaction plants can cost between $1.5-3.5 billion for each 1 mtpa of capacity.
These mega projects can only be financed if a majority of buyers have been tied up in advance at prices that ensure the viable internal rates of return. Therefore, a shift en masse to a more flexible but considerably cheaper hub-based pricing system will adversely impact the ability of new LNG projects to secure financing/the desired IRR.
If fewer facilities get built because of this, then the market will be tight well beyond 2018. India's nameplate regasification capacity stands at 25 mtpa. Only two receiving terminals (Dahej and Hazira) run at capacity/close to capacity. Including greenfield terminals in Andhra Pradesh and expansions to present facilities, an additional 25 mtpa is in the pipeline over the next five years. In 2012, India imported 13 mtpa of LNG.
While India's major LNG buyers are still able to secure term supplies at small discounts to spot prices by signing up larger volumes from projects being constructed in Australia and the US, a flexible hub-based pricing system remains elusive. To gain adequate leverage with suppliers to negotiate this, India needs a global LNG market amply supplied in the near term, higher proportion of LNG cargoes being traded on spot markets and far higher utilisation rates at regasification terminals across Asia.
Hence, when will M/s Moily and Motegi get their buyer's market? My estimate - after five years at the very least.