12. Natural Gas

Natural gas transportation costs between producer and consumer countries are an important aspect of competitiveness of gas supplies. In general, liquefying natural gas and shipping it via ocean transport becomes cheaper than transporting natural gas in offshore pipelines for distances of more than 1000 km or in onshore pipelines for distances greater than 3500 km (Mokhatab and Purewal 2006). However, the actual break-even point depends on numerous parameters, which, besides distance, include volumes, project financing, market size, and geo-politics.

To further add complexity, some contracts will have varying slope percentages used at different oil price levels. Broadly speaking, there can be four basic forms: the simplest is a straight-line constant slope that exposes both the buyer and seller to adverse price movements. A second type is the so-called ‘S-curve’, which will have a flatter slope at low oil prices to protect sellers and a flatter slope at high oil prices to protect buyers. The other two types are variations on the S-curve, where either only sellers have some protection (an oil-linked contract with a floor) or only buyers have protection (an oil-linked contract with a ceiling) (EY 2013).

The effects have not been isolated to Japan. South Korea is the world’s second largest LNG importer. Although not affected by a nuclear disaster, the cost of LNG procurement has increased from US$13.9 billion in 2009 to US$30.6 billion in 2013, with the average cost per unit increasing by 43 per cent during the same period.

In the context of this chapter, a reference to Asia includes East Asia, South Asia, Southeast Asia, Oceania, and Russia’s far eastern regions.

In Australia, CBM is referred to as CSG.

The following LNG projects have experienced cost overruns of between 12 and 32 per cent: Gladstone, Gorgon, Ichthys, Queensland Curtis, Pluto, and Wheatstone. Ichthys LNG, sanctioned in 2012, currently is the world’s most expensive liquefaction project on a per unit basis, and Chevron’s Gorgon LNG project cited cost increases of over 40 per cent in US dollar terms from US$37 billion to US$52 billion.

The most important regional policy-making institutions include the East-Asia Summit (EAS), the Association of South-East Asian Nations (ASEAN), ASEAN+3 (China, Japan, and South Korea), ASEAN’s Regional Forum (ARF), the Asia-Pacific Economic Cooperation (APEC), and the Shanghai Cooperation Organization (SCO).

In January 2007, representatives of the EAS member states met in the Philippines and adopted the Cebu Declaration on East Asian Energy Security. However, the declaration offered nothing more than a non-binding agreement based on a series of non-binding principles. The APEC Energy Security Initiative is another example of a non-binding, regional initiative.

A neo-mercantilist approach to energy implies that states should not rely on energy markets to provide optimal energy outcomes, but rather should steer markets to benefit the state. In this context, national energy policy is considered a security challenge and, as such, is ‘securitised’, as opposed to being conceived as largely an economic issue. State intervention via subsidies to specific energy sources, diplomatic activity designed to enhance access to energy resources and energy security (energy diplomacy), and support for national energy champions exemplify this approach (Phillips 2013; Stoddard 2013; Hancock and Vivoda 2014).

Most liquefaction projects in the US have been signed on a free on board basis, where Asian companies agree to pay the project developer a $2.50–$3.00/MMBtu liquefaction fee to lift the volumes from the Gulf of Mexico facilities, along with 115 per cent of the HH price to source the volumes from the US natural gas pipeline system.

LNG for spot and short-term trading is available due to excess production (above the fulfilment of the producers’ supply obligations), or is available from plants with marginal capacity obtained by de-bottlenecking. Such LNG often is an outcome of the time lag between the production and shipping starts of LNG projects. Spot and short-term LNG also becomes available as a result of conflict between parties to contracts, amortised plants, or expired contracts. Factors that free-up spot and short-term LNG are technical or contractual matters, which are part of individual projects (Namikawa 2003).

Platts’ JKM is a daily assessment of LNG prices for spot cargoes delivered to Japan and South South Korea based on the most recent trades and/or bids and offers from buyers and sellers in the spot market. Although not a physical spot market, JKM serves as a proxy for all Asian prices. It is the first index that reflects regional LNG supply and demand fundamentals. JKM reached an historic high of $20.20/MMBtu on 14 February 2014 (Rogers et al. 2014).

ENI originally was called Ente Nazionale Idrocarburi.

Originally referred to as the 1966 as North Sumatra Offshore Petroleum Exploration Co., Ltd.

In May 2014, China and Russia (through China National Petroleum Company (CNPC) and Gazovaya Promyshlennost (Gazprom) signed a $400 billion natural gas deal. Russia will supply 38 billion cubic meters (28 mtpa LNG-equivalent) of natural gas per annum via pipeline for 30 years. The cost is estimated at $10/MMBtu (Russell 2014). In June 2014, China National Offshore Oil Corporation (CNOOC) agreed to pay a ceiling price of US$8/MMBtu for LNG imported from the Tangguh project in Indonesia (Cahyafitri 2014).

In November 2012, the Japanese government proposed to establish an LNG futures market in Japan that sets a price based on domestic supply/demand factors. The aim was to launch the market in 2015. Critics have suggested that, given that the electricity sector represents approximately two-thirds of total natural gas demand, deregulation or liberalisation in the gas market would be hindered if competition is not introduced in the power-generation sector, which has been dominated by ten regional monopolies (IEA 2013). In response, in November 2013, the Japanese Diet passed the first of three electricity market reform packages. One of the aims of these reforms is to encourage efforts for the reduction of LNG procurement costs through competition between electric utility monopolies. In 2014, the ‘top-runner approach’ has been under METI’s consideration. If adopted, for long-term LNG contracts reviewed after 2015, METI may use LNG price-estimates, which partly reflect linkage with gas prices (mainly HH) for the rate assessment (Kihara 2014).

The key requirements for a hub are: a defined physical location (from which shipping costs to importing centres could be assessed by buyers considering trades); and development (and impartial enforcement) of a trading code, which would apply to all participants, whether conducting bilateral, over-the-counter, or (later) exchange-based trades. On both these points, Singapore currently appears to be a viable option (Rogers and Stern 2014).