Figure 4.4. Natural gas prices on the Henry and Waha Hubs, January 2018–April 2019

Source: Bloomberg Financial LP (2019) (subscription required).

The Waha Hub traded at an average discount of USD 1.1/MBtu compared to the Henry Hub through 2018, as pipeline capacity constraints weighed on natural gas prices in the Permian basin.

Global natural gas pricing overview

Natural gas pricing established on the basis of supply and demand fundamentals (also referred to as “gas-to-gas competition”) accounted for 47% of world price formation in 2018, increasing from 31% in 2005 (IGU, 2019). This is more than twice the volumes priced according to oilindexed formulae, which represented 19%. Different types of regulated and bilateral pricing mechanisms accounted for 34% of total natural gas consumption.

However, a breakdown of global aggregates yields different results for each category:

Pricing by gas-to-gas competition accounted for 46% of domestically consumed production in 2018, most of it in North America and Europe. Oil indexation only covered 10% of domestically consumed production, and the remaining 44% was priced via bilateral or regulated pricing mechanisms.

In the pipeline trade a 61% share was priced according to gas-to-gas competition, principally in North America, but increasingly in Europe too. Oil indexation accounted for 30% and covered the majority of trade in Asia, Central and South America, the Middle East and residual volumes in Europe.

LNG, by contrast, is dominated by oil indexation, which accounted for 66% of these volumes, mostly in Asia. The share priced by gas-to-gas competition is only 34% for LNG volumes.

The evolution of gas pricing mechanisms by region is illustrated in Figure 4.5. In North America and Europe – accounting together for 40% of natural gas demand in 2018 – most consumption is priced on gas-to–gas competition as a consequence of market liberalisation and diversified sources of supply (either local or imported). In the case of Europe, the share of gas-to-gas competition pricing has increased gradually over the past decade as references to hub prices progressively replaced oil indexation in long-term supply contracts.

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Gas Market Report 2019 4. Prices and market reforms

Figure 4.6. Expected natural gas demand growth by region, 2018–24

4 200

4 100

4 000

3 900

3 800

IEA, 2019. All rights reserved.

* Accounting for at least 50% of demand in 2018, as shown in Figure 4.5.

Regions where regulated pricing or oil indexation dominate account for over 85% of natural gas demand in the coming five years.

For other emerging markets such as Central and South America and Africa, additional supply is expected to come mainly from domestic production or neighbouring countries rather than from trans-regional LNG trade. Here the development of gas-to-gas competition pricing makes sense from the viewpoint of local downstream competitiveness and upstream development, while the price attractiveness dimension is of lesser importance.

The emergence of market-driven natural gas pricing in fast-growing markets (in particular Asia) is therefore an important feature to ensure the sustainability of these markets in the longer term.

Prospects for natural gas trading hubs in Asia

The development of short-term and spot LNG trading has followed a robust growth trend over recent years. They increased by almost 60% between 2015 and 2018, moving from 65 bcm/y to over 100 bcm/y (Figure 4.7), of which three-quarters were imported by Asian countries. In addition to this volume increase, the trend has also shown increasing diversification within Asia. The Asian LNG spot trade expanded rapidly in the aftermath of the Great East Japanese Earthquake of 2011 and, until 2014, Japan accounted for almost all short-term and spot LNG trade in Asia. Japan’s share halved between 2015 and 2018, from 31% to 14%, when its shortterm and spot LNG volumes decreased from 20 bcm/y to 15 bcm/y. Meanwhile, volumes to other Asian markets increased from 22 bcm/y to 57 bcm/y over the same time period. This reflects not only the development of China’s short-term and spot LNG import market (from less than 2 bcm/y to almost 20 bcm/y), but also the development of new Asian LNG importers that rely mostly on short-term and spot procurement.

This increase in LNG spot trading is a positive and necessary precondition for the establishment of competitive market-driven pricing mechanisms, which, however, require a larger set of factors to be efficient and sustainable. These institutional and structural factors have been summarised in a previous International Energy Agency (IEA) report entitled “Developing a natural gas trading hub in Asia” (IEA, 2013), and are recalled in Box 4.1.

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Figure 4.7. Evolution of spot and short-term LNG trade by main importer, 2015–18

120 bcm

100

80

60

40

20

0

Source: ICIS (2019), ICIS LNG Edge, www.icis.com/energy/liquefied-natural-gas/lng-edge/ (subscription required).

The share of Asian buyers in short-term LNG trade has increased in recent years and become more diversified as new players have entered the market.

Box 4.1. Institutional and structural requirements for creating natural gas hubs

Initial institutional requirements need to be met to support competition in a natural gas market, where governments have to start actively creating the foundations for natural gas trade. In general, a successful attempt at increasing competition will meet the following institutional requirements (in no specific order):

•A hands-off government approach to natural gas markets: this implies an administrative mindset that is carried on through the respective natural gas market governing entities. It also implies a shift from direct policy making and market involvement to market monitoring through an independent regulatory agency.

•Separation of transport and commercial activities: The natural gas industry is known for its ability to behave as a natural monopoly, since the high costs of infrastructure investment prohibit the development of parallel infrastructures to supply the same customers (especially at the retail level). It is widely recognised that these vertically integrated supply systems need to be broken up. Subsequently, the independent transport entity will levy a fair and indiscriminate transmission fee on a proportional basis for all shippers.

•Wholesale price deregulation: Part of the governmental hands-off approach involves letting the market set the price level for natural gas in the wholesale market. It allows large customers to seek a supplier who can deliver the product that suits their need at the least possible cost. Eventually, this freedom of choice can also be offered to individual households, but this is not strictly necessary for a functioning wholesale market to emerge.

In addition to institutional requirements, market participants need a minimum degree of certainty that a market is genuinely competitive and is functioning as such. To ensure continued

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functioning of a spot market, structural requirements need to be secured (by the government or the independent entity) as follows (in no specific order):

•Sufficient network capacity and non-discriminatory access to networks: Essential to a well-functioning natural gas market is its accessibility via non-discriminatory access to networks, and the availability of capacity on these networks. An independent transmission system operator (TSO), either divested or functionally separated, and a clear and unbiased investment regime based on a well-developed network code are essential to guarantee these structural requirements.

•Competitive number of market participants: Lowering barriers to entry through a wellregulated network code should increase competition for the incumbent natural gas company. However, a meaningful number of parties, each with a competitive market share, is generally needed along a non-regulated value chain (upstream and downstream) to create a genuinely competitive gas market.

•Involvement of financial institutions: To allow a market to efficiently service supply and demand, investment will be needed along the natural gas value chain (in upstream development, transport, storage and distribution capacity). Apart from capital investments that will be recouped by operational revenues, a competitive natural gas market will also need financial parties that are willing to cover financial/operational risks for parties involved in the natural gas trade, providing tools for customers to smooth out and optimise revenue streams from their activities in the natural gas market.

These structural requirements are essential to kick-start a natural gas market, and should be guaranteed by a regulator (ideally independent from companies and government) that monitors the market and can act independently when needed (e.g. force an incumbent company to facilitate more competition).

Source : IEA (2013), Developing a Natural Gas Trading Hub in Asia, www.iea.org/publications/freepublications/publication/AsianGasHub_FINAL_WEB.pdf.

This analysis in 2013 focused on several Asian markets with ambitions to develop natural gas hubs and pricing references at that time, highlighting their respective strengths and weaknesses (see Table 4.1).

Updating this analysis in the context of 2019 shows several positive developments toward the establishment of natural gas hubs in Asia, and thus of market-based pricing references for the region:

Japan completed its domestic market liberalisation reform programme in 2017 with full liberalisation of the downstream market, the establishment of a Gas Market Surveillance Commission as a regulatory body, and the introduction of gas transport unbundling – to be fully effective by 2022.

Korea’s natural gas market is still dominated by state-owned incumbent KOGAS. However, the number of “direct importers” – major consumers allowed to import LNG for their own needs, but only for volumes in addition to existing supply contracts with KOGAS – doubled in 2017 from four to eight. Direct buyers’ share of the country’s total LNG imports more than doubled between 2015 and 2018, rising from 6% to 16%.

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