Oil indexation: Time to accept the change
Rapidly developing traded gas markets in Europe and a fundamentally changed sales market, will kill oil indexation in gas contracts. It’s time to accept the new market structure. By Sirko Beidatsch*
THE structure of the natural gas market in Continental Europe has changed fundamentally and irreversibly over the last two-and-a-half years. Since the gas year 2008/09, the link between gas prices and, primarily, oil no longer reflects the competitive situation in today’s markets.
The principle of competition-oriented pricing on the basis of one or more competing energy sources (netback-pricing) is severely jeopardised by its link to volatile oil prices. To ensure customers have trust in gas and that long-term investment and supply security are guaranteed, producers and importers must find a market-based alternative to oil-price indexation.
Until the gas year 2008/09, gas-supply contracts linked to oil were almost continuously profitable – and accepted by the industry – because of a lack of competition caused by limited gas-supply sources; and high, and rising demand for gas.
Nonetheless, early on, importers – as well as downstream regional and municipal suppliers – tried to counter the producers’ market power with arbitrage transactions. For example, the development and expansion of gas-storage capacity enabled: the cost-effective injection of volumes during the summer, when demand and prices were low; and profitable withdrawals from storage in winter when demand and prices were higher.
In addition to the traditional take-or-pay obligation, long-term supply contracts commonly have a capacity-related pricing component to reflect the cost of structuring the deal. The maximum hourly or daily capacity procured during a given period (month, quarter, year) is used as the basis of price assessments. This pricing component was also optimised with the help of gas-storage facilities, by reducing capacity peaks through withdrawals.
Usually, there was no competition between gas suppliers because established players worked profitably along the gas-value chain and had almost identical oil-indexed contracts, meaning buyers rarely gained price advantage. And because sales partnerships successfully prevented the entry of new market participants – whose access to essential infrastructure (storage facilities, pipeline networks), was prevented by the incumbents’ long-term capacity reservations.
Unlike the UK market, gas business structures in Continental Europe have maintained the status quo, preserving the dominance of oil indexation in gas contracts and players upstream of end-consumers continued to profit from gas-supply contracts linked to the price of oil more than a decade after the formal liberalisation of the EU gas market.
Following the global economic crisis and recession, however, European gas consumption fell for the first time in years – demand in 2008/09 was down by 6% compared with the 2007/08 gas year. In many cases, customers no longer required even the fixed-minimum gas volumes under their oil-indexed take-or-pay contracts. In the interest of a lasting business relationship and to safeguard the economic future of customers facing total default, the parties to many contracts agreed a postponement of supply and delayed payments.
But the underlying problem was resolved only in the short term. The difficulties facing buyers increased in volume and seriousness because of: continuing below-average gas demand; largely homogenous contract designs and solutions determined by incumbent suppliers; and a lack of market structures to absorb surplus gas volumes.
As demand slowly recovered throughout gas year 2009/10, customers had to accept previously postponed deliveries at prices not based on the existing traded market, but which were tracking rising oil prices. This reduced demand for gas on the free wholesale market, led to a further decline in the price of liquid, traded volumes and expanded the differential with oil-indexed contract prices.
The high availability of unconventional gas in the US has been, and will continue to be, a significant factor. Formerly an important buyer, the US is now effectively ruled out of the liquefied natural gas (LNG) demand picture for the foreseeable future. LNG production originally intended for the North American market, is increasingly available in Continental Europe, where buyers have traditionally procured long-term pipeline supply indexed to oil.
Some European gas traders are already considering this irreversible market change in their procurement and sales strategies. For example, LNG regasification capacity is booked in their corresponding market areas; tanker movements are tracked and analysed; and LNG-carrier arrivals are factored into gas trading and pricing. Once the regasified LNG is in the gas-transmission network, it can directly influence prices – at the moment, in the specific delivered market area, but in future across a uniform, single EU market.
The improvement of capacity-management measures between EU market areas means freely traded gas can already partly replace oil-indexed pipeline supply at interconnection points and indirectly influence downstream prices. This high availability of non-contracted gas volumes has already brought growing competition to continental EU markets and, compared with established oil-indexed gas-supply contracts, low market prices.
New market participants that did not share in the profits generated under the conventional, tong-term, oil-indexation model, have used these excellent starting conditions to attract and supply end consumers. These new players now also have access to flexible, low-cost supplies because of: increased volumes injected into – and remaining in – storage by established suppliers; and these companies’ minimum purchasing obligations under long-term contracts mean volumes are sold at low prices to generate at least some revenue.
Moreover, the value of additional storage capacity developed for specific market areas in recent years and has fallen because changes to balancing systems in several countries, such as Germany. Individual market areas – such as Germany and the Netherlands – have achieved high liquidity, enabling market participants to sell or buy gas in sufficient quantities and at market prices directly at the virtual trading point (VTP) – NCG in Germany and the Netherlands’ TTF – without requiring transport across market areas. Consequently, volumes can be offered at prices far lower than those under the long-term oil-indexed supply contracts of the established gas suppliers, resulting in growing competition.
Gas purchasers had to accept more swiftly than producers/exporters that they are competing with new providers who are successfully targeting their customers through new distribution channels and with different gas-to-gas price models. The only factor crucial for end consumers is price – ordinarily fixed for a term of one to two years. Incumbent suppliers have responded slowly to the fundamentally changed market situation having been convinced this was only a temporary phenomenon. But during this period, severe sales declines were experienced with the loss of large customers to competitors.
Facing rising competition and the continuing problem of minimum-purchase volumes in their oil-indexed contracts; many established gas suppliers opted to price supply based on prices outside their own market area. Consequently, traded-market purchasing structures were used for the first time outside the context of oil-indexed gas-supply contracts and gas was traded successfully at market prices.
Delivery to an external market aimed to ensure the price structure, or price level, within the supplier’s own sales market was not destroyed. But with almost all established suppliers facing the same challenges and looking beyond their own markets, a truly competitive market has evolved.
Many gas producers/exporters see this change from a seller’s to a buyer’s market as a temporary problem and, for now, are willing to make only minor adjustments to their long-term, oil-indexed contracts. But buyers recognise this as an irreversible development and a threat to their profitability. In this context, neither party questions the principle of competition-oriented pricing; but there is disagreement regarding relevant competing energy sources in the gas market. For producers, it is still oil; while for buyers it is gas – traded at market prices, at regional hubs and offered to their customers by competitors.
Depending on the extent to which national markets were previously supplied with gas under long-term oil-indexed contracts, they are responding differently to the changed market structure (see Figure 2). Markets with high consumption and a former dominance of oil-indexed contracts (such as NCG) have seen trading volumes increase more swiftly at VTPs.
Although for the last four decades, long-term gas-supply contracts linked to oil constituted the benchmark for gas pricing in Continental Europe, a market price consisting of the following elements will now evolve in the region’s individual markets: standardised products traded at the VTP; procurement contracts based on gas-to-gas competition; and contracts based on substitute fuels, such as oil and coal.
While the first two options are swiftly growing in importance, the third is increasingly redundant, as contracts previously negotiated, or yet to be renegotiated, no longer reflect gas-price development. For practical reasons alone it seems illogical to base a gas-procurement contract at market prices on an oil-indexed agreement if natural gas is the relevant competing energy source in the sales market.
Standardised trading products, which are now offered on the most important market platforms across Continental Europe, permit almost full, market-based structuring of the customer portfolio at market prices in combination with a balancing regime in line with the gas market’s daily system.
More mature markets, such as TTF, permit faster purchasing and selling of more long-term products, such as calendar years, and are characterised by a high market depth – the presence of several providers and/or consumers (see Figure 3). On younger trading markets, such as Germany’s, long-term standardised products can also be traded; but interest focuses on prompt and spot-market products. (The aim is to avoid situations where minimum purchase volumes under long-term gas contracts are not reached, while providing short-term optimisation of these contracts through standard trading products, such as day and weekend.)
Medium- and long-term gas contracts that previously formed the basis for gas-industry investment (both upstream, reserves development, and down, gas-fired power plants), can maintain their profitability and competitiveness for suppliers and buyers by linking prices to a gas index. Consequently, changes in the market price for natural gas can be passed on to customers without putting the long-term relationship in question.
EEX, for example, publishes the EGIX-European Gas Index for the Continental European gas market on its website, with all trading transactions in the respective front months used for indexing. Referencing to the front month corresponds to the market standard in the gas industry and allows the simple replacement of monthly oil quotations in long-term gas contracts.
Sirko Beidatsch is manager for strategy, market and business development, natural gas, at European Energy Exchange