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Chapter 4 Gas Pricing
The physical properties of oil and the fact that it is relatively easy to transport and to store facilitated the emergence of commodity pricing mechanisms in the oil sector. However, these considerations do not apply in the same way to natural gas. The question is whether gas will follow the same development as the oil sector. In North America and in the UK the movement toward a commodity-type market pricing mechanism is already well advanced in the natural gas sector. Natural gas spot and futures markets have developed in the US and the UK. LNG is starting to be traded on a spot basis, even though long-term contracts are still the dominant feature.
However, it is open to question to what extent physical, technical, and economic differences, as well as different traditions, will result not only in a delay but also restrict the application of these pricing mechanisms for gas outside of the US and the UK, and what will be the relationship between commodity pricing mechanisms and traditional long-term pricing mechanisms.
Chapter 4 describes in detail the various pricing mechanism in North America, the UK, and Continental Europe, as well as for LNG, keeping in mind the following question:
4.1 Will Gas Follow Oil to Become a Global Commodity?
While oil has developed into a global commodity market, the situation with gas is more complicated (see Table 4).
the supply side
In North America and the United Kingdom there was a certain similarity between the development of oil and of gas as a commodity, based on natural endowments of and distribution of resources and on successful sector reform. A liquid gas market has developed in both North America and the UK during the past 20 years.
The indicator for liquidity is usually called ‘churn’. Churn is the ratio between traded volumes and delivered volumes. A churn of at least 15 is usually considered to be the threshold for a liquid market. The gas hubs in North America were created by industry at appropriate places, with Henry Hub in Louisiana being the most prominent and important of these. Henry Hub has a churn of about 100, indicating high market liquidity. For comparison: on the oil side the churn of WTI and Brent is about 500.
By contrast, the National Balancing Point (NBP), a notional point at which gas is traded in the UK, was created by regulation. The churn on the NBP rose to about 15 until 2004 and then dropped for some time to 10, placing the NBP at the edge of being considered as a liquid market. European players, who prefer a strategy of vertical integration, have now replaced US firms in the UK power market, leading to lower volumes on the traded market. Both the UK and the North American markets have many players and show substantial demand elasticity based on gas demand for power generation.
There are specific features of the UK and North American gas markets which have favoured the development of gas as a commodity in these markets. Firstly, and most importantly, the development
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of the gas industry in these countries was based on domestic resources. North America was self-sufficient until the end of the 20th century. The UK was not only self-self-sufficient, but was even briefly a gas exporter at the end of the century.
Another common element between North America and the UK is the existence of standardised rent-taking regimes and licensing procedures for the development of new fields. In the US it is the landowner who gets the rent (by law as a royalty limited by 12.5%, and until the 1980s based on a regulated wellhead price). In the UK and in Canada (where resource issues are under the control of the provinces) it is the government which designs a framework for licensing and clearly defines the rules of rent-taking (as extra petroleum tax and royalty regimes). This framework, and especially the rules of rent-taking, has been adapted over time to the changing worldwide competition for upstream investment or to the depletion stage of the respective hydrocarbon province. Both in North America and in the UK the decisions on field development are made by private players reacting to market signals and to market fundamentals within the framework defined by government, but their decision is not directly influenced by government. With the UK and North America starting to import LNG, LNG investments in exporting countries are being developed to target these markets.
It should also be noted that the geology of North America (except for fields adjacent to the Beaufort Sea) as well as on the UK Continental Shelf is characterised by a large number of small to medium-sized gas fields and an absence of giant structures.
In North America and in the UK, gas-to-gas competition is well developed and gas prices are no longer contractually pegged to oil prices but follow a development of their own. However, a de facto long-term average correlation between oil and gas prices remains due to substitution effects over longer periods, even though gas price development is having more peaks than oil price development, reflecting more volatile electricity demand.
In contrast to the situation in North America and the UK, gas markets in the rest of the European Union (excluding the Netherlands), and in Japan and Korea have developed based on imported gas.
These markets have been shaped by the wish of exporting countries to maximise the rent from gas exports as a compensation for the depletion of their finite resources, and to sell their gas at a price that allows the marketing of the gas, while maximising their resource rent.
The EU depends for 50% of its consumption on three large gas-exporting countries: Algeria, Norway and Russia. Moreover, gas exports into the EU come largely from eight super giant fields: the Russian fields Yamburg, Urengoy and Medvezhye, and after 2000 also Zapolyarnoye, Groningen in the Netherlands, Hassi R’Mel in Algeria, and Troll in Norway.
In all these fields, governments have been strongly involved in the development and marketing decisions, using state-owned or state-dominated companies as an instrument to implement their policy to collect rents and information. In the Netherlands, this was done via Gasunie and a detailed depletion policy for Groningen; in Algeria via Sonatrach as a national oil and gas company. In Soviet times, ministries were responsible for field development and for gas exports, and in Russia after 1991 this role was inherited by Gazprom, a company under dominant state influence. In Norway, the state-owned company Statoil was created as an instrument of government policy, later complemented by the GFU (Gas negotiation committee) and the SDFI (the State direct financial interest). The giant size of the fields resulted in large export contracts often in the order of 5-10 Bcm/year with a duration of
101 twenty years and more with a few large gas import companies. Gas import into Continental Europe still continues to be dominated by long-term gas contracts with large volumes.
Imports of LNG into Japan and Korea were also based on large gas fields – in Indonesia, Malaysia and Brunei – whose export was handled by national companies under large contracts.
The structure and concentration of gas supply to Continental Europe and to Japan and Korea, and their dependence on imports, makes these cases very different from North America and the UK. In turn, this suggests that differences in market structure are not only a question of sector reform.
the demand side
There are also important differences on the demand side: In all regions gas is used in the captive sectors, residential and commercial, which not only have little price elasticity but also a demand that is strongly dependent on weather conditions. In North America and the UK, gas is also to a large extent used in a power sector, which has substantial price elasticity. By contrast, gas in power generation plays a different role in Continental Europe, Japan and Korea. In some parts of Continental Europe, gas has only a small share in power generation, as domestic or quasi-domestic energies like nuclear are preferred, based on commercial considerations of the industry and often promoted by policy choices, as in France and Germany. In other countries that have no domestic energy, gas was by tradition imported with a high load factor for base load generation.
Continental Europe, Japan and Korea are characterised by a relatively small number of large players both in the gas sector and in the electricity sector, and by large mergers between gas and electricity companies.
The hubs that have developed in Continental Europe (Zeebrugge, Bunde and TTF in the Netherlands) all have a churn of clearly below 10, a sign of low liquidity. While Continental Europe has developed some hubs, Japan and Korea so far have no hubs at all: Korea only has one gas company, Japan has a maximum of two per region (one gas, one power utility) and there is practically no pipeline connection between the regions, although the companies do swap LNG cargoes with each other in short-term lend / borrow arrangements.
the role of LnG
The fast growing trade in LNG is regarded by some as a factor that will lead to the creation of a global gas market. The fast growing import needs of North America and the UK offer a large potential to absorb substantial amounts of LNG. As a result of substantial cost reductions of liquefaction plants and LNG tankers (which has been partly reversed lately due to buoyant demand for tankers and liquefaction plants), LNG now has a worldwide reach. With a growing number of LNG liquefaction plants and receiving terminals, and with some over-capacity in the LNG tanker fleet, LNG trade has also become much more flexible especially due to the deep and liquid demand from the US. Demand for LNG from the US now competes with demand from the EU and Japan and Korea. By being directed to higher price markets, LNG trade is functioning as a price transmitter for higher prices between regional markets. However, LNG terminals – unlike oil terminals – have not developed into trading hubs of their own, and in view of the high costs of storing LNG this is not likely to happen soon.
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Table 4: Will Gas follow Oil to Become a (Global) Commodity?
Source: Energy Charter Secretariat
Will Gas Follow Oil to Become a (Global) Commodity? north america and United KingdomContinental Europe and Japan / Korea development based on own resources, no initial dependence on importshigh import dependence from the start supply based on small to medium sized gas fieldssupply based on imports from giant / super giant fields standardised rent taking development decision by private playersrent maximisation of exporting countries development decision by exporting country demand elasticity from gas to power generationlimited demand elasticity gas-gas competition but price path for gas still tracks oil pricesoil prices as reference in price formula Linkages market restructuring as of 1980s model for reformmarket restructuring as of late 1990s north america
UKLnG tradeContinental EU
Japan/Korea Hubs created by industry, churn 100, many players, high LNG absorption potential.
NBP created by regulation, churn 15 to 10, many players, limited absorption of LNG.
no LNG Hub but LNG as price transmitter
few industry hubs, churn <10, few strong players, dominance LTCs.
no hub so far, few strong players, dominance LTCs.
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