T R A D I N G Gas

18 PETROLEUM REVIEW JUNE 2011

The rising powerof gas tradersSecuring Europe’s future gas supplies will depend

increasingly on a combination of physical hubs and trading

skills as gas imports rise and Europe’s indigenous gas

reserves dwindle. Crispian McCredie and Ruud Weijermars*,

Alboran Energy Strategy Consultants, explain how trading

works and what action is needed to further improve

liquidity in a nascent pan-European gas trading system.

lative positions start to dominate thenatural requirement to balance physicalgas supply and demand.

Efforts to boost trading liquidityThe European Union’s (EU) ThirdEnergy Directive outlines a require-ment for competitive gas prices andnow Europe has its own federal regula-tory agency, the Agency for theCooperation of Energy Regulators(ACER), legally empowered as of March2011. ACER, headquartered inLjubljana, Slovenia, must transformEurope’s patchy regulatory regime withthe objective of increasing liquidity inthe European gas market. In the US gas market, the Federal

Energy Regulatory Commission (FERC)has been active for decades, improvingliquidity and price transparency. Toachieve better liquidity in Europe’s gasmarkets, a number of issues need to beaddressed. Primarily, the regional trans-mission operators (TSOs) must agree theharmonisation of contracts acrossregional markets to permit onecommon trading platform with a stan-dardisation of balancing fees and tariffsfor transportation. Secondly, an auctionprocess needs to be established to allowprimary base load supply allocationwith long-term contracts for up to aperiod of 10 years. Sufficient sparecapacity on the regional hubs mustallow for spot gas physical contracts tomeet demand peaks, which will requireaccess to sufficient gas storage and fun-gibility between LNG and pipeline hubs.The European Federation of Energy

Traders is a group of more than 90energy trading companies from 23

European countries, dedicated to stimu-lating and promoting energy tradingthroughout Europe. It has been proac-tive in promoting pan-European energytrading and regularly provides theregional TSOs with practical frameworkguidelines.2 The ultimate aim is to inte-grate the regional gas networks into asingle European network, with trueliquidity for supply/demand driven allo-cation of physical gas volumes.However, achieving greater liquidity ingas transmission and trading will notnecessarily result in competitive pricingif past contract practices block progress.

US vs Europe pricing Competitive pricing can only beachieved if gas transmission systems andagreements across borders and hubs areharmonised. The US gas market is therole model, where the Henry Hub pro-vides a national reference price pointfor all gas trades. Two gas commoditytrading systems co-exist – the New YorkMercantile Exchange (NYMEX) for gasfutures and the IntercontinentalExchange (ICE) in Atlanta for gas swaps.Derivatives are indexed with the HenryHub spot gas price. Spot gas indexingis also used in bilateral contracts forlong-term physical gas deliveries.Consequently, all US gas contracts, bothphysical and derivative, are price-indexed to the gas price for physical gasdeliveries at a single reference point,the Henry Hub. Physical gas deliveries atUS gas hubs other than Henry simplyhave an upward or downward pricedifferential relative to the Henry Hubreference price (see Figure 1). Regional gas hubs have also

emerged throughout Europe, after theUK set the example in the 1990s (seeFigure 2). The physical metrics of theUS and EU gas markets are broadlycomparable, with similar consumptionvolumes, converging storage and LNGlanding capacities. However, Europestill lacks a single reference price for itsphysical gas and deals in a range oflocally-indexed derivative contracts.Furthermore, gas contracts in conti-nental Europe are oil-indexed, not spotgas-indexed.

US gas traders’ roleIn the old model, US gas traders onlybought gas from producers and soldphysical gas to consumers. In today’s lib-eralised market, US gas market tradersprovide liquidity in the value chain byprice-making in physical, as well as thefutures and swap markets. US gastraders are a highly diverse group andcan be divided into three main groups:

Amajor difference between theworld’s two leading liberalisedgas markets is that US gas

imports are less than 5% of total con-sumption; Europe’s imports are over45%. The decline in Europe’s indige-nous gas production continues. TheInternational Energy Agency’s (IEA)data shows that of the 16 EuropeanOECD members, only Norway, theNetherlands and Denmark can coverdomestic demand. All other EuropeanOECD members had become net-importers of natural gas by 2009.1Norway and the Netherlands exportgas to the rest of Europe, but 33% ofimported gas comes into OECD Europeby pipeline from Russia, Algeria, Libyaand Azerbaijan, and a further 12% viaLNG imports from Algeria, Qatar,Nigeria, Trinidad and Egypt. As of 2011, international gas trading

from outside the OECD accounts fornearly half of Europe’s gas supply. Moregas imports will be delivered tonorthern Europe by the Nord Streampipelines. The first pipeline with atransmission capacity of approximately27bn cm/y is due for completion thisyear. The second line is due to be com-pleted in 2012. Further into the future,either the South Stream or Nabuccopipelines will supply gas from Asia. International gas trading has become

a critical strategic component inEurope’s energy security. The trader’srole is to guarantee the future matchingof gas supply and demand. Gas tradershave not only a powerful position in thephysical gas market but also in the gasderivatives market. Their trades mayaffect wholesale gas prices when specu-

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19PETROLEUM REVIEW JUNE 2011

Gas producers that sell physical gasover the hubs and who hedgeagainst low prices by using NYMEXgas futures and ICE gas swaps.Gas utilities and other consumersthat buy gas priced at physical net-work exits and hedge against highprices by using NYMEX and ICEderivatives, often as counterpartiesto the producers.Speculators, including hedge funds,that trade in the gas market’s finan-cial derivatives purely for financialreturn without any direct interest inowning physical gas volumes, theso-called ‘non-commercial players’in the US Commodity FuturesTrading Commission’s jargon.The traders are supported by banks

acting as clearing houses and brokersthat offer aggregated gas trading ser-vices for gas buyers. A minor role isplayed by transmission system opera-tors, who must buy or sell spot gas tobalance their physical gas transmissionsystem. Any gain or loss in spot gastrades is passed on to users in theirtransmission system tariffs.A cursory review of the major physical

gas marketers in the US shows major gasproducers acting as sellers, sometimes asaggregators for smaller producers, withmajor financial institutions (LouisDreyfus, JP Morgan, Citigroup,BOA/Merrill Lynch) acting as clearinghouses. The average daily volume mar-keted and reported to EnergyIntelligence is about 125bn cf/d – doublethe 62.5bn cf/d US gas consumption, asboth buyers via clearing houses acting forthe third-party buyers and sellers (mar-keting subsidiaries of the gas producers)report their traded physical volumes. Inthe US, the majority of gas derivatives atNYMEX and ICE are traded as pure finan-cial transactions – churn rates are close to100, meaning that only one out of 100trades is linked to a physical delivery.

UK gas trading In the UK, the counterpart of NYMEXgas futures and ICE gas swaps aretraded on the APX-ENDEX futuresmarket with swaps at ICE UK. It usesphysical reference prices from theNational Balancing Point (NBP), a virtualhub with a UK price average, for gasdeliveries under a mix of long andshort-term contracts, which are, in turn,indexed by NBP spot prices. The churnrate of APX-ENDEX (NBP) trades isbelow 20, one fifth of the US liquidityindicator. The UK gas trading market isdominated by producer traders, banksacting as clearing houses and hedgefunds. The same US clearing housebanks operate in the UK, comple-mented with EU banks (Credit Suisse,Deutsche, BarCap). European producertraders include Gazprom. Hedge funds(Centaur, Citadel) are joined by a rangeof other proprietary traders (EDFtrading, Gunvor, Hetco, Koch, Mercuria,Noble, Vitol).

Continental Europe gas tradingFrom a liquidity point of view, gas pricesin continental Europe are set mostly bygas producers who allocate oil-indexedgas deliveries to ‘preferred’ traders,commonly via their own gas marketingdivisions. For example, Dutch gas traderGasTerra is owned by the same partiesthat own Dutch gas producer NAM(Shell, ExxonMobil, state). In other EUcountries, the relationship betweenproducer trader and producer parent isobvious, as they trade under similarnames – BG Group, BP, ConocoPhillips,Eni, ExxonMobil, Gazprom, Shell, Statoiland Total. Speculative traders are eitherSwiss-based (Alpiq, EGL, Mercuria,Vitol, Gunvor) or subsidiaries of US con-glomerates (Hetco belongs to HessCorporation; Koch Energy to KochGroup).

Speculative gas traders provide animportant market driver for bothvolume and liquidity. They take posi-tions as counterparts to the physicalgas traders, who otherwise might findprice hedging options limited due tolack of market trade liquidity.Continental European hubs’ spot mar-kets still have relatively poor liquiditydue to relatively few market partici-pants. In terms of churn rates, the 2009average was 6.6 for TTF, 3.7 forZeebrugge and 1.1 for NCG. At TTF, thevolume of speculative trades is about40% of the total. The most aggressive European traders

are gas utilities with little gas produc-tion but increasing storage capacity,who combine physical gas stock withderivative price hedging and price spec-ulation. It is these organisations thatcan lead the way in Europe to negotiatelong-term contracts for base-load gasdeliveries from gas producers, and helpdevelop spot gas price indexation todecouple gas prices from an oil-basedindex. By oil-decoupling, utilities willincrease their ability to reduce gasprices when the spot markets providethe liquidity to do so. European spot gas prices are raised

by the high price of gas delivered tothe continental gas network underlong-term contracts, which are at pre-sent oil-indexed on a six-month rollingoil price average.3 These physical gasprices cannot immediately respond toprice volatility in spot gas, but mayresult in take-or-pay (TOP) arbitrage atpreset intervals when spot gas providesa cheaper alternative to the oil-indexgas price.

A word of caution Much of the gas derivative trade in theUS is driven by spreads on the price dif-ferential between winter and summergas. This is most dramatically illustrated

Figure 1: Major US gas hub prices – 2009 averages ($/1,000 cf,% drop relative to 2008) Source: ICE data

Figure 2: Major EU gas hubs – 2009Source: Gas Hub report

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investigation report for the original2007 hearings showed how Amaranthtrades controlled up to 80% of the totalvolume on NYMEX gas futures. Thecompany found no buyers to offload itspositions as gas prices fell. The US con-gressional investigation report shouldbe recommended reading for anyorganisation that wants to boost liq-uidity in the European gas markets byincreasing trading volumes.4

Benefits and pitfallsGas producers naturally want high gasprices and short domestic supply is intheir favour. If the utility gas tradersdo not succeed in delinking long-termbase-load gas from oil, then they willnever be able to pass on lower spotgas prices to their end consumers, andprices for LNG imports and pipelineimports will remain under the firmcontrol of the gas producers.Whether or not spot markets are

delinked, market prices will continueto be driven by tugs of war betweenthe producers, consumers and specula-tors. If Günther Oettinger, theEuropean Commissioner for Energy,has his way, European gas consumerswill win cheaper gas. That means pro-ducer prices must come down. So, nowis the time to move rapidly forward inestablishing a reliable, pan-Europeangas trading system. �

References1.Natural gas report, OECD/IEA, 2010.2. Framework guidelines, EFET, 2010.3.Petroleum Review, March 2011,pp14–17.

4.Excessive speculation natural gasmarket, US Senate Report, 2007.

* Also at Delft University of Technology

by the 2006 demise of Amaranth, thethen largest US gas trader, which lost$6.6bn by being on the wrong side ofthe market. Figure 3 shows the twofinal sets of spreads that cost Amaranththe house and the chief trader his job.Centaur Energy, the counter party,made over a billion dollars profit fromAmaranth’s final trades. Amaranth col-lapsed in September 2006. The detailed US Senate Subcommittee

Figure 3: Amaranth’s purchases of March 2007 contracts and March/April spread pricesSource: US Senate report

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� Roy Hartley FEI, Operations Director, Aurelian Oil and Gas� Toni Harvey, Snr Geoscientist – UK Onshore, DECC� Mark Miller, Chief Executive, Cuadrilla Resources� Dominic Murphy, Senior Manager, Energy intelligence� Nick Perry MEI, Perry Energy Services� Mike Stephenson, Head of Energy, BGS� Nigel Smith, Principal Geologist, Shale Gas and Coal Bed Methane, BGS� Kerry Thomas, Environmental Sustainability Knowledge Transfer Network� Dr Jim Gaiser, Chief Scientist, Geokinetics Inc� Adrian Needham, Principal, Golders� Luisa Shelenko, Consultant, GL Noble Denton� Speaker from Environment Agency, Scottish Environment Protection Agency

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