Natural gas prices in Europe

As natural gas markets have changed over the past several decades, the pricing of natural gas in Europe has evolved. Until the 1980s, when the United Kingdom began liberalizing its natural gas market, European markets consisted largely of national or regional monopolies, which held exclusive control over all aspects of natural gas within their territories. Prices most often were set by long-term contracts and were linked to the price of oil. Over time, as regulations have been enacted to encourage free markets, and as new infrastructure has made European markets more interconnected, pricing has begun to change. Although long-term contract pricing has not been abandoned, the influence of spot market pricing is growing. Natural gas prices in Europe are likely to become more competitive in the future as infrastructure expands and as new potential supply sources—such as unconventional natural gas—become commercial.

Belgium, Germany, and France were the first European countries to import natural gas. The imports were sourced from the Netherlands' Groningen field, discovered in 1959. In choosing an approach to commercialization of the Groningen field, the Dutch state had to balance its desire to maximize its own revenues with the need to price the gas competitively and the need to invest in massive new infrastructure to transport the gas to new markets. The resulting contract structure was largely adopted by later exporters to continental Europe, including Norway, Algeria, the Soviet Union, and later Russia.

To justify investment in long-distance natural gas pipelines and other required infrastructure, import contracts were long-term and offered with take-or-pay provisions that required buyers to purchase specified minimum volumes whether or not they accepted delivery of the natural gas. To ensure that natural gas would earn the highest price but still be competitive, it was priced not at the wellhead, based on the cost to produce it, but at the end-use market. Prices to end users were discounted relative to the prices of competing fuels (mainly, heavy fuel oil in the industrial sector and distillate in the retail sector). To ensure that natural gas priced for one market could not undercut natural gas priced for another market, contracts included clauses specifying the destination for the gas. Also, to ensure that the contract price would remain competitive if prices for competing fuels changed over time, the natural gas contracts included price review clauses [69].

The United Kingdom began opening its natural gas markets to competition in the 1980s, and by 2000 the task was largely completed. Continental Europe did not begin liberalizing its natural gas markets until the 1990s, when the European Union (EU) officially abolished national and regional gas monopolies. In the early 2000s, through the EU's Second Gas Directive and other measures, continental gas markets were further liberalized, with elimination of destination clauses in all new import contracts and some existing contracts; requirements for third-party access to natural gas transmission, distribution, and LNG infrastructure; requirements for legal and functional unbundling of transmission operators from competitive businesses; creation of national natural gas regulators; and the establishment of policies allowing consumers to choose their natural gas providers (beginning in 2004 for commercial consumers and in 2007 for retail consumers).

In some respects, the Second Gas Directive stopped short of full liberalization. For example, it did not require third-party access to storage, nor did it mandate full ownership unbundling of transmission assets. However, its biggest weakness was that it failed to directly address market concentration in individual nations, leaving intact companies that were still effectively national gas monopolies [70]. As a result, competition across the value chain was limited by supply and import contracts that encompassed most of the available natural gas. Further, transmission contracts governed most of the available pipeline capacity, and downstream contracts governed most of the existing consumers.

Contracts between national incumbents and downstream customers effectively removed many buyers from the market for long periods. Consequently, the Second Gas Directive initially had little impact on natural gas prices. In 2004, the volume-weighted average duration of downstream contracts was 15 years in Germany, around 6 years in the Netherlands and Poland, around 4 years in France, and less than 2 years in Italy. Further, downstream contracts could include provisions that minimized the possibility for contractual buyers to participate in markets as buyers or sellers—for example, by encouraging or even requiring a buyer under contract to purchase natural gas exclusively from the incumbent seller over the life of the contract, and by use restrictions and destination clauses to make the contracted gas difficult to resell [71].

Since the implementation of the Second Gas Directive, additional measures have been taken in Europe to encourage market development. Europe's natural gas markets have become physically more connected to each other and to the rest of the world. Pipelines have been expanded to link the United Kingdom's liquid gas market to the rest of Europe through Belgium and the Netherlands, and additional pipeline connections currently are planned or under construction to better interconnect nations on the European continent.

Also, Europe's LNG regasification capacity has almost tripled in just 6 years, from 2.2 trillion cubic feet in 2004 to around 6.2 trillion cubic feet in 2010. The United Kingdom, which had no LNG regasification capacity in 2004, had built 1.8 trillion cubic feet of capacity by 2010, accounting for 45 percent of the recent increase in Europe's total regasification capacity [72].

The EU's Third Gas Directive was adopted in 2009, requiring implementation by March 2011. It seeks to improve EU-wide coordination of transmission regulations and strengthen third-party access requirements and transmission unbundling requirements. It still does not require full unbundling of the ownership of transmission assets, nor does it deal directly with the market concentration of incumbent national gas companies [73]. However, the European Commission took more direct action in 2007, launching antitrust cases against German natural gas transmission owner and marketer RWE, as well as Italy's Eni, for denying third-party access to their natural gas pipeline systems. The lawsuits have had mixed results. The case against RWE was closed when the company offered to sell its transmission assets, but Eni decided instead to fight its case [74]. Gas de France, which also was under investigation, decided to release capacity on some of its import pipeline routes and at some of its LNG import terminals to appease European competition authorities [75].

Although the EU gas directives did not directly challenge the dominance of national incumbents, the 2008-2009 economic downturn did. Natural gas demand in Europe declined sharply after the economic downturn in late 2008, while at the same time the supply of "free gas" (natural gas not controlled by incumbent gas companies, mainly in the form of LNG) was increasing. Long-planned increases in Qatari exports to the United Kingdom and Italy began to materialize in 2009, and additional quantities of LNG imports became available to the relatively liquid markets of Belgium and the United Kingdom as a result of declining demand in Japan and growing availability of shale gas supplies in North America.

The increase in available natural gas supply caused spot prices for natural gas in European markets to fall. However, long-term contract prices, because of their lagged linkage to oil prices, did not fall as far or as fast after the economic downturn. The significant differential that opened up between natural gas prices in spot markets and the prices under oil-linked contracts incentivized many European customers to abandon the incumbents with their oil-linked contracts and instead buy gas from the developing spot markets, causing a "take-or-pay crisis" that left incumbent natural gas companies in continental Europe committed to buying too much gas at too high a price and with too few customers wanting too little gas.

The pressures on Europe's incumbent gas companies as a result of their take-or-pay commitments have so far been managed through price review clauses in the contracts and through quantity flexibilities beyond the amounts normally allowed by the contracts. Neither long-term contracts nor contract prices linked to oil were entirely abandoned as a result of the take-or-pay crisis. Even in the United Kingdom, with its liquid natural gas hub, term contracts still existed 18 years after liberalization began, with the prices in just over half of the contracts linked to something other than the hub price [76].

In continental Europe, contract price reviews have resulted in some incorporation of hub natural gas prices into formulas that previously linked contract gas prices to oil prices, but the extent to which hub prices have been adopted varies. Norway was the most willing to incorporate hub prices; Algeria was not at all willing. Russia in small measure incorporated hub prices into some contracts to North European customers, where relatively liquid gas hubs exist, but refused to incorporate them into Southern European contracts, citing the limited liquidity at natural gas hubs in the region. The additional quantity flexibility comes at a high price. Companies that have been unable to take their minimum quantities still have had to pay for them, but they will be allowed to take them at a later point, sometime in the next few years.

Natural gas volumes paid for but not delivered under take-or-pay provisions grew in 2009 and 2010 as LNG imports into Europe, and especially the United Kingdom, continued to increase, and imports from Russia continued to decline. It is still unclear whether take-or-pay volumes will continue to increase in 2011, or whether companies will instead be able to take delivery of some accrued volumes in addition to their minimum volumes for 2011. Several factors have helped lessen the pressures on European long-term contracts. Demand for natural gas in Europe and for LNG in Asia recovered in 2010, helping to keep global LNG markets and European spot markets from loosening further, even as LNG production increased by almost 20 percent from 2009. In addition, as a result of political unrest in Libya, flows on the Greenstream natural gas pipeline to Italy were suspended in February 2011. Finally, the tragic earthquake, tsunami, and meltdown at the Fukushima nuclear plant in Japan in March 2011 has resulted in greater demand for LNG in Japan. With little additional growth in global liquefaction capacity expected until after 2015, LNG markets are likely to tighten somewhat in response to the additional demand.

European spot markets for natural gas are likely to continue to grow steadily as a result of continued improvement of physical and regulatory infrastructures. Progress could be slowed, however, by regulation that is relatively weak in comparison with still-powerful national incumbents that often are championed by their home governments. Other factors could push markets to develop more quickly. Significant additional LNG liquefaction capacity is under construction or proposed for 2015 and beyond, and while most of it is in the Pacific basin, it could still indirectly affect Europe, by pushing more flexible LNG back into the Atlantic basin and into European markets. Further, a significant amount of new LNG export capacity has been proposed for the U.S. Gulf coast; and while most of the new Pacific liquefaction capacity is likely to be tied up in relatively inflexible long-term oil-linked contracts, adding little short-term liquidity to Pacific markets, the same cannot be said for any potential U.S. exports. Finally, European spot markets could develop more rapidly than expected if natural gas production from shale formations comes online more quickly or in greater quantities than European incumbents are expecting, as happened in North America. And, with physical and regulatory barriers continuing to lessen over time, the next time such a boom in "free" market-oriented natural gas occurs, the consumer shift from incumbent wholesalers with oil-linked purchase obligations to spot purchases at gas hub prices could be much greater than was seen in 2009 and 2010.