Market organisation: A European and a US model?

There are various kinds of natural gas prices, whether wholesale prices (hub prices, border prices, city gate) or end-user prices (industrial, household). Components of natural gas prices include the cost of gas supplies, transmission, distribution and storage costs, retailer's margins and taxes. Both wholesale and retail prices vary widely across regions, and regulated prices are still common in the non-OECD world. Competing fuels include oil, electricity, coal (see Section 2.2.1), whose price development therefore impact on gas prices.

There are three price formation mechanisms:

1. Gas-to-gas competition based on offer and demand in wholesale and sales markets.

2. Oil-indexed LTCs for importing gas based on worldwide oil markets/FX.

3. Regulated prices.

Figure 73. Natural gas real prices in the United States, Europe and Japan, 1992-2012

Source: World Bank Commodity Price Data. Notes: Europe: average import border price and a spot price component, beginning April 2010 including the UK; during June 2000 - March 2010 prices excludes the UK; US: spot price at Henry Hub, Louisiana; Japan: import price, CIF. Data in $2005/mmbtu and

$2005/bbl. Annual prices.

There is no such thing as a global natural gas price,¹⁰¹ as shown in Figure 73. Until 2006, average natural gas prices in the United States, Europe and Asia were correlated with the oil price. This

101 As a consequence, each region has one or several price benchmarks that are only partly linked to one another.

For North America, Henry Hub (a distribution hub located in Louisiana) prices are generally taken as a benchmark. When talking about European gas prices, one usually distinguishes at least between BAFA CFI (average German border import prices as reported by BAFA - Federal Office of Economics and Export Control)

correlation ended for US gas prices as early as 2006. European gas prices have deviated significantly from oil price developments since 2010, and at the moment only Japanese LNG import prices follow oil prices.

Figure 74. Global gas price linkages

Source: Rogers (2012).

While the oil price is still highly relevant for wholesale price formation in continental Europe, through long-term contracts (indispensable tools to finance a costly network infrastructure), and the OECD Pacific, one should not forget that most parts of the world, namely those that are not as dependent on imports, follow a different logic. Gas-to-gas (between gas supplies) competition on spot markets is prominent in North America, the United Kingdom and parts of continental Europe (e.g. the Netherlands), representing one third of global gas demand (Figure 74). Prices in many other parts of the world are regulated, however, and may even be set below supply costs to reach specific policy objectives.

In late 2012, world gas markets can be described as follows (adapted from Rogers, 2012):

 North America is a largely self-sufficient gas market with Henry Hub prices of around

$3.50/mmbtu.

 Europe has a ‘hybrid’ gas market:

o Hub spot prices range from $8/mmbtu to $14/mmbtu.

o Oil-indexed contract prices are at $11-$13/mmbtu, meaning buyers will only satisfy their take-or-pay commitments and purchase additional demand on sport markets, while trying to renegotiate their long-term contracts.

 Asia has highly heterogeneous gas prices:

o LNG contract prices range from $4/mmbtu to $18/mmbtu.

o Spot cargoes arrive at around 15$/mmbtu (in Japan – at times linked to European hub spot prices with a transport margin and premium).

and NBP (National Balancing Point: The British virtual gas hub operated by TSO National Grid, covering all entry and exit points in mainland Britain. The British virtual gas hub operated by National Grid, covering all entry and exit points in Great Britain). For Asia, Platt’s JKM (Japan Korea Marker) may serve as a proxy.

While gas producers respond to price signals, it is difficult to adjust production levels at short notice. In case of increasing demand, production cannot be stepped up at short notice but needs longer lead times. The reason is that the process for granting permits, exploratory seismic work, and drilling and connecting wells to pipelines will take at least six months, usually longer. In addition, productivity rates of existing and planned wells are subject to uncertainty.

If demand declines and prices fall below the short-run marginal costs of production, an immediate halt to production may not be an option as reservoir and wellbore characteristics will often not allow simply restarting production once prices go up again. In addition, gas is sometimes a by-product (associated gas) of oil by-production, so even if low gas prices make by-production uneconomic, the combined oil and gas business case may look different. Also, companies may hedge their production at higher gas prices, one of the factors that explain why US gas production remained constant even when US gas prices fell below $2/mmbtu (IEA WEO, 2012). Furthermore, producers sometimes have to accept obligations to produce certain minimum volumes, perhaps as part of the licensing process.

The majority of internationally traded gas is traded under long-term contracts, usually 10-25 years (IEA WEO, 2012). Gas prices are often indexed to the oil price (oil products or crude oil), limiting the possibility for arbitrage.¹⁰² While this was logical in the 1970s when burning gas was an alternative to using oil in both power generation and heating, nowadays this logic has become obsolete in most parts of the world.

As with oil, traded market price transparency for natural gas is high because traded market prices (i.e. spot prices and forward delivery prices) are identified and published by a range of price reporting agencies, as well as by commodity futures exchanges to a limited extent. In addition to the traded markets, much natural gas is sold under long-term supply contracts, where transparency is mixed. Outside of the United States, many long-term gas contracts have historically been indexed to oil prices. But since the precise formulas are hardly ever made public, and since there is a wide range of ways that oil indexation is achieved in practice (e.g. indexed to various specific crudes, and/or to a combination of different oil products such as fuel oil and gasoil in bespoke proportions), levels of transparency for oil-indexed contracts is relatively low. In recent times, there has been a move toward greater use of indexation for spot gas prices in long-term contracts. While again the precise formulas used are confidential to the counterparties and not released, gas indexation arguably improves the degree of price transparency for long-term contracts because transparency in the spot gas markets is high and gas-on-gas indexation provides a high price correlation, unlike gas-to-oil indexation.

In traded natural gas markets, pricing is straightforward with contracts generally agreed on an absolute price (fixed price) basis. They can also sometimes be agreed in reference to a natural gas fixed price in a neighbouring market (a cross-border basis trade), or a fixed price for a different time period (e.g. a Q4-Q1 spread contract), but usually with a fixed price market at its centre. This type of contract takes into account regional differences, since its use is driven by the aim to maintain a stable relationship due to high sunk costs invested in pipelines and networks to link with the other party.

Financial instruments do not normally play a direct role in the pricing of a physical product. To the extent that financial contracts in natural gas are actively traded, their primary purpose is as tools for the management of price risk (e.g. swaps, options, etc.). While most LNG is traded under long-term contracts, just like internationally traded pipeline gas, there has been a shift to more flexible arrangements, partly as a result of very liquid markets (Figure 75). Besides North American projects, Rogers (2012) expects Australia, Qatar and Nigeria to become the most important players in global LNG supply.

102 Excluding the possibility of renegotiation, there are two scenarios that limit arbitrage opportunities. First, if spot prices are higher than oil-indexed prices, the annual contract quantity level (ACQ) represents the maximum availability of oil-indexed imports. Second, if spot prices are lower, take-or-pay clauses represent the minimum level of oil-indexed imports.

Figure 75. World short-term LNG trade, 2000-2011

Note: Short-term means trade under contracts of four-year duration or less, including spot transactions.

Source: IEA WEO (2012).

Transportation and trade may be affected by government intervention both positively, through pipeline subsidies, and negatively, by failing to provide the regulatory incentives for network expansion or export restrictions (the United States is very reluctant to grant export licences for natural gas). (Trade) wars as well as resource nationalism come to mind. Also, long-term gas supply may increase as a result of government spending on innovations in drilling or exploration technologies. But governments may also enter into (free) trade agreements, facilitating the transportation of natural gas across national borders.

Figure 76. European trading hubs and connectivity

Source: Rogers, 2011.

In Europe, gas pricing is undergoing major changes. The traditional oil product-linked gas is increasingly being questioned in the European Union, and the price for oil, as a competing source of energy, no longer plays a role in several major European wholesale markets. It is reasonable to expect that hub-based pricing will gradually take over. This poses challenges to existing long-term contracts, some of which may become untenable. The period up to 2014-15 is often considered a transitional one, which may eventually result in a new pricing and contractual gas framework. Yet, how this will look is still uncertain, partly because it does not only hinge upon economic fundamentals, but also has an important legal dimension. Here, the outcome of the antitrust case that the European Commission has brought forward against Gazprom may question the practice of oil-indexed gas pricing.

Granted, the future is always uncertain, but with a view to gas pricing it nevertheless seems worth pointing to major market developments. Rogers (2011) singles out four of them:

 Asian Natural Gas and LNG demand.

 US Future Shale Gas Production Growth and potential scale of North American LNG exports.

 Timing/slippage of new non-North American LNG projects.

 Production versus pricing policy for European pipeline gas suppliers post oil-indexation.

As a consequence, drawing upon scenario analyses, Rogers (2012a) points to the key challenges for major players:

 European pipeline suppliers will have to hope for high Asian demand, otherwise the availability of LNG will effectively push down European prices. Large-scale North American LNG exports could de facto imply a price ceiling for pipeline suppliers as well.

 The commercial viability of North American LNG exports depends on high Asian demand and a European hub (NBP) ‘target price’, maintained at the expense of volume sold by European suppliers.

 US upstream gas producers are vulnerable to low Asian demand when US production is high, even when European pipeline suppliers maintain a target supply floor. This does not make for

“an attractive environment for upstream producers as it perpetuates the problems observed in 2011 of supply-driven inventory surpluses and low prices [...] an intensely competitive environment”.

 For Asian LNG producers and buyers, low Asian demand would imply finding ‘new customers’ in the Atlantic Basin markets (or delaying projects in anticipation of such).

Finally, in order to handle important changes such as greater production flexibility and risk management of a more competitive environment (with liberalisation), futures markets are indispensable tools to deal with seasonality factors. As mentioned above, there is no global benchmark price for natural gas, but rather a futures index for Europe (NBP run by ICE) and a futures contract for the United States (Henry Hub natural gas traded and cleared on NYMEX). Futures markets, however, play a limited role for pricing of spot natural gas transactions through long-term contracts. The size of open interest over physical market is in a low range (see Section 1.3.1).

Table 38. Natural gas market organisation

Physical market setting Pricing complexity Liquidity futures market Delivery points

Competitive Medium Medium Limited (EU, US)

Source: Author.

Due to multiple sources of natural gas spread across different locations, the physical market setting is fairly competitive, and complexity is limited to pricing formulas for long-term contracts.

Futures markets are liquid but benchmark for specific regional areas; no global benchmark has emerged. Delivery points for the futures contract are limited to a few regional locations set by the exchange, but this does not affect the efficiency of market structure since futures for this commodity reflect fundamental changes in their respective region.

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