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    Morten FrischSenior Partner

    Morten Frisch Consulting (MFC)6 Holmwood Close,

    East Horsley, Surrey KT24 6SS, United

    Carlos LapuertaManaging Director

    The Brattle Group Ltd198 High Holborn,

    London WC1V 7BD, United


    After providing a summary of developments in Atlantic Basin gas markets during thewinters of 2005/06 and 2006/07 (until mid January 2007), the paper presents analyses ofUS and European gas markets, with emphasis on gas market forces that either haveemerged or have manifested themselves during the two last winters. A major theme is theeffect of high and very volatile prices on gas demand. Will there be a shift from gas tonuclear and coal-fired power stations? What does the future hold for energy intensiveindustries in North America and Europe? The paper addresses the likely future demandfor LNG in the US gas market, the growing importance of gas supply diversification in

    European gas markets, and the resultant implications for the construction of LNGreceiving terminal capacity. The paper concludes by assessing the likely demand for andfuture role of LNG in Atlantic Basin gas markets, and hence the likely future importance

    of these markets to LNG producers.

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    When developing a most likely scenario for future LNG supply and demand it hasbeen of invaluable help to discuss LNG project developments and the current and likelyfuture level of operation at existing LNG plants and to compare notes on these topics with

    Mrs Marie-Francoise Chabrelie, Secretary General of Cedigaz in Paris. Both authors aremost grateful to Marie-Francoise for this excellent help and support. All errors andomissions in the paper are however our own.


    This presentation is meant to provide an insight into current and future developmentsin Atlantic Basin gas markets and the likely future role of LNG in these markets.Although the authors believe that the presentation reflects a correct view of the currentsituation and future developments in these markets at the time of its drafting duringJanuary 2007, the authors of this paper and/or Morten Frisch Consulting, The BrattleGroup Inc. and The Brattle Group Ltd. cannot be held responsible if this should prove notto be the case or if any of the conclusions drawn from this presentation should prove to beinaccurate. No representation or warranty is made as to the accuracy or completeness ofthe presentation and no person is entitled to rely on its contents.

    Any recipient of this presentation, whether in electronic, hard copy, visual or oralform, proposing to plan, build or operate projects along the gas value chain or to plan,engage in, or operate gas trading activities along the gas value chain serving markets in

    North America, Europe or indeed elsewhere in the world, should apply dedicated,specialist analyses to their specific legal and business challenges spanning the entire gasvalue chain between the gas producing and consuming countries. This presentation in no

    way offers to substitute for such analysis.


    ACQ Annual Contract Quantity.


    Billion standard cubic meters (of pipeline quality gas, see Sm3 below).Switzerland.

    DG TREN The European Commissions Directorate General for Transportation andEnergy.

    EIA The Energy Information Administration of the United States Departmentof Energy.

    EU 25


    The twenty-five countries that were members of the European Union in2006 i.e. Bulgaria and Romania that joined the European Union in 2007are not included.

    The European gas market area addressed in this paper.


    Million British thermal units.Million metric tonnes (of LNG) per year.

    NBP The National Balancing Point in the United Kingdoms gas pipelinenetwork.

    Sm3 A standardized cubic meter of pipeline-quality gas with gross calorificvalue of 39 MJ.

    ToP Take-or-pay, referring to purchase commitments in gas sales agreements.Zeebrugge The Belgian gas trading hub.

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    The gas markets in both North America and Europe have been through a rollercoasterover the past two winters. The winter of 2005/06 displayed unusual characteristics in allmajor gas markets bordering the Atlantic Basin. The average monthly gas price at Henry

    Hub exceeded US$13 per mBtu during October 2005 as a result of hurricanes Katrina andRita. Gas prices spiked again during a cold spell in December 2005, but unseasonablemild temperatures followed in North America. Gas demand fell, gas prices were soft, andlarge volumes of gas were delivered to storage facilities. Abundant storage stocksdepressed US gas prices in 2006 until the air conditioning season in July and August. USLNG imports in 2006 have been estimated at 12.1 mt/y1 equivalent to 16.3 Bcm of

    pipeline-quality gas. Imports were sharply down relative to the 13.2 mt/y (equivalent to

    17.8 Bcm of pipeline quality gas) that was imported in 2005.

    In contrast to North America, Europe experienced exceptionally cold weather withrecord gas demand and high prices both in the liberalised gas market in Great Britain as

    well as continental Europe. High crude oil prices contributed to the high gas prices incontinental Europe due to the indexation of long-term gas contracts to oil products.

    Gas markets in the UK and Ireland suffered from a very tight combined gassupply/demand balance. These problems were exacerbated by the lack of response fromthe major continental European gas market players to high UK gas prices. As if thisshould not provide a sufficient torment for the UK authorities, the Rough Field gasstorage facility, the largest gas storage in the UK that normally delivers 10 per cent of UKgas demand during peak demand periods, was damaged by fire in early 2006.

    At the beginning of January 2006, a gas contract dispute prompted the Russian

    Federations (Russias) GazProm to interrupt deliveries of gas to the Ukraine, a countrythat transits some 20 per cent of Europes gas supplies. This brief gas supply interruption

    by Europes main gas supplier was compounded by exceptionally cold winter conditions

    in Russia and Central European countries. Austria, Germany, France, Italy, the CzechRepublic, the Slovak Republic and Hungary all witnessed partial curtailments of theirRussian gas supplies during most of January and February, and part of March 2006.

    Drought conditions in Spain, Portugal and part of France made the energy economiesof these three countries more dependent on LNG supplies than what normally would bethe case. During the winter 2005/06 the average price for LNG delivered ex-ship toMediterranean LNG receiving terminals oscillated between US$8 per mBtu and US$10

    per mBtu2. Spain was in reality the price setter for LNG in Europe, although higher priceswere achieved by the few LNG cargoes delivered to the new LNG terminal at the Isle ofGrain in the UK that winter.

    1 Gaul, D. and Platt, K. Short-Term Outlook Supplement: US LNG Imports - The Next Wave, EnergyInformation Administration, US Department of Energy, January 2007.

    2 Alvarez, A., Repsol YFP, Presentation to CWCs 7th Annual World LNG Summit in Rome, Italy, 13October 2006.

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    The winter of 2006/07 (until mid January 2007) has so far been relatively similar onboth sides of the Atlantic Basin. Both market areas have seen above seasonal normal

    temperatures with depressed gas demand, falling gas prices and more than adequate gasin storage.

    Wholesale gas prices at Chicago and Boston city gates fluctuated between US$6.00per mBtu and US$8.00 per mBtu during November and December 2006 reflecting theabundance of gas in storage. In early January 2007 gas storage facilities in the Northeastof the USA were filled to between 85 per cent and 95 per cent of capacity. The Chicagoand Boston gas price levels mentioned above are low in relation to normal winter pricesin these wholesale gas markets, making incremental Canadian gas exports uneconomic.This in return resulted in a dramatic reduction in the number of drilling rigs operated inAlberta and British Columbia, Canadas two main onshore gas producing provinces. Thereduction in Canadian gas drilling during 2006 could result in short term gas supply

    problems in the US in 2007. The low level of energy imports to the US experienced in2006 is expected to continue into 2007.

    Gas demand in Northwest Europe during the winter 2006/07 was until mid January2007 well below seasonal normal levels for two reasons. Winter temperatures were well

    above normal levels. Gas prices in the liberalised UK market softened very considerablysince the previous winter. Furthermore, the gas futures market for the winter 2006/07

    peaked in April 2006 and had fallen by some 50 per cent by mid January 2007. This

    sharp reduction in UK gas prices appeared to have a positive impact on demandparticularly from the power generation market and energy intensive industries, many ofwhich were closed down during the winter of 2005/06 as a result of high gas prices. InJanuary 2007 the domestic gas market in the UK had not yet had the benefit of reducedgas prices due to the pricing policies of retail gas suppliers.

    The UK forward price for first quarter 2007 was $7.59 on December 18 2006.3Futures prices for gas delivery to the UK market during the early part of 2007 had by midJanuary 2007 fallen to below US$6.00 per mBtu. In continental Northwest Europe,

    border gas prices for delivery during first quarter 2007 were typically between US$7.50per mBtu and US$10.00 per mBtu depending on delivery point and delivery flexibility.Early indications were that high gas prices based on oil product price indexation werehaving a negative effect on gas demand in continental Northwest Europe.

    As in the previous winter, drought conditions in Spain, Portugal and part of France

    had again prompted high gas consumption in the affected areas. Prices of LNG deliveredto Spanish terminals were very high compared to other destinations in Atlantic Basin

    markets. The value of LNG delivered ex-ship to Spain during the first week of January2007 was some US$10 per mBtu while this value in the UK was less than US$6 permBtu. LNG delivered to terminals on the East Coast of the US also had a value of someUS$6 per mBtu in early January 2007.

    Russia is in total supplying some 25 per cent of European gas demand. During thewinter period approximately one third of this supply, or some 8 per cent of Europeandemand, currently transits Belarus. A gas supply contract dispute between Russias

    3 This price was for the forward contract on the International Petroleum Exchange (IPE) Gas FuturesMarket in London, for the delivery of gas during the first quarter of 2007 at the UK NBP.

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    GazProm and Belarus threatened to disrupt this gas supply, but was resolved in theeleventh hour. If this dispute had not been resolved gas deliveries to Poland, Germany

    and the Czech Republic would again have been hit hard

    Based on the situation prior to mid January 2007, what lessons could Atlantic Basin

    gas market operators learn from the winters of 2005/06 and 2006/07? In the US the gassupply situation appeared better than anticipated only a few years ago. LNG had becomea marginal gas supply source, to a large extent drawn upon during periods of weather-induced high electricity and gas demand.

    European gas markets experienced very tight gas supply conditions with some fuelswitching out of natural gas during the winter of 2005/06. However, energy marketswere generally supplied with gas. Although not perfect, the liberalised gas market in theUK was functioning during the winter of 2005/06. The importance of providing a muchhigher level of gas storage capacity in the gas markets of the UK and Ireland could not beignored.

    The winter of 2005/6 raised more questions about continental European gas markets.With the exception of European gas markets having a border with the Mediterranean, thehigh and rising gas prices experienced were having a negative impact on gas demand inEurope. Russias behaviour towards its gas transit countries and also the operation of thegas market within Russia itself gave rise to very serious concerns about the reliability ofthis country as Europes main gas supplier.


    The Effect of High Gas Prices. High gas prices are having considerably different

    effects on demand in North America and Europe. In the United States, high prices haveled to a significant revision of demand forecasts, with serious implications for futureLNG imports. The effects in Europe, although clearly present, are far more attenuated.The differences lie in a combination of demand and supply factors. High prices in theUnited States have prompted higher investment in domestic gas resources. High pricesalso make coal more attractive than gas in the United States as a fuel for thermal powerstations. These two factors distinguish North American gas markets significantly from

    Europe: The European gas market area that is addressed in this paper, can only in a verylimited way respond to high gas prices by accelerating the development of indigenousresources, and Europeans pay roughly twice as much for coal as in the United States.

    Gas Demand. The EIA has recently published a new base case for future gasdemand in the United States4. The new base case shows gas demand increasing at a rateof 1.7% through 2015, from 615 Bcm to 717 Bcm. Two years ago we discussed thesuccessive postponement of gas demand forecasts by the EIA5. We noted that gas demandhad stagnated in the United States since the onset of high gas prices, and that it seemedunreasonable to predict such large future increases in demand. We had referred to thedemand forecasts as the planned trajectory of an airplane about to take off, but each year

    4 Annual Energy Outlook 2007/ Reference Case, Energy Information Administration, US Department ofEnergy (15th December 2006).

    5 Frisch, M., Carpenter, P. and Lapuerta, C., The Advent of US Gas Demand Destruction and its Likely

    Consequences for the Pricing of Future European Gas Supplies, paper presented at the GasTech 2005conference, Bilbao, Spain, 16 March 2005.

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    its takeoff seemed to be postponed. We produced a figure showing the successiveforecasts from 2001 to 2005. We now reproduce the figure, with the last two years

    forecasts added.


















    20012002 2003





    2006 forecast now

    postponed until 2018

    Figure 1: EIA Gas Demand Forecasts

    The new 2007 base case confirms our previous concerns. The contrast with the 2000

    EIA forecast is remarkable. As we suspected, demand has continued to stagnate. In early2001, the forecast was for growth of 105 Bcm by 2006. None of that growth hasmaterialized. Actual consumption in 2006 was even less than in 2000.6 Growth has beenzero. The most recent forecast shows that the previous target for 2006 has now been

    pushed out to 2018. What was supposed to happen in six years will now take a totaleighteen years to materialize.

    The forecasts for 2015 have been slashed by even more. The 2001 forecasts

    anticipated a total of 895 Bcm by 2015, while the new forecast is for only 717. The dropof 178 Bcm approximates thecurrent total consumption of the United Kingdom and Italycombined, which are two of the largest national markets in Europe.

    6 The EIA has estimated that US gas consumption in 2006 was 615 Bcm. In 2000 it was 660.

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    2002 2003





    Decrease in

    Forecast for 2015

    Figure 2: Reduction in EIA Gas Demand Forecasts for 2015

    The US power sector is responsible for much of the change in forecast demand. In2001, increased demand from the power sector was forecast to drive roughly threequarters of the total growth by 2015. The 2007 forecast now shows that there will be no

    net growth in gas demand from the power sector in the long run. In 2030, the UnitedStates power sector is anticipated to consume 209 Bcm of gas, which is virtually

    unchanged from the 208 Bcm consumed last year.

    The new forecast has reached levels that we find credible. It is difficult to foresee anylong-term increase in consumption of natural gas by the power sector, when the average

    price of coal is so low. Although there is an international market price for coal, it appliesonly to a few geographic areas in the United States that must import coal from overseasdue to the lack of available local resources. Many power companies in the United Statesare located in areas with abundant coal reserves, where local market prices liesignificantly below international levels.

    The Department of Energy provides information concerning the average cost paid for

    coal in each state of the United States.7

    The most recent data confirm the effect ofproximity to coal reserves. Wyoming is the center of the Powder River Basin, which hasthe cheapest coal reserves in the United States. The basin is characterized by deep coalseams with minimal overburden, making the coal extremely economic to mine using

    surface methods. The coal is naturally low in sulphur. The Department of Energy showsthat the average price of coal produced in Wyoming was $7.71 per ton in 2005. The price

    paid for coal tends to increase in the United States heading from Wyoming to the southand east, due to the costs of railroad transportation. Texas is a relatively distant state,which nevertheless has imported substantial volumes of coal from the Powder RiverBasin. The average price paid for coal produced in Texas was $17.39 in 2005. The

    7 Energy Information Administration, Average Open Market Sales Price of Coal by State and Mine Type:2005, 2004.

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    differential relative to Wyoming reflects the rough magnitude of rail costs. The costs ofPowder River Basin coal plus rail costs places a competitive constraint on the prices paid

    for coal produced in Texas. Similar factors affect the price of coal sold in states as far eastas Illinois, Indiana and western Kentucky.8 The average coal price across the UnitedStates was only $24/ton.

    In contrast, the average price of coal purchased in Europe has exceeded $60 per ton.9While the United States also imports some coal, and pays international market prices,international imports go to only a minority of those states that are the most distant fromindigenous coal resources. Alabama is so far from the Powder River Basin andsufficiently distant from the higher-cost Illinois Basin, as to make imported coaleconomical. Coal produced in Alabama sold for an average of $53.63 in 2005. This is notquite as high as the average price of coal in Europe, in part because the proximity ofAlabama to Colombia, a large coal exporter, enables US consumers to realize savings oninternational shipping costs. Almost 80% of US coal imports are from Colombia andVenezuela. To import coal from the same countries, a European power generator would

    have to pay substantial more in shipping costs to move the coal across the Atlantic.

    The Brattle Group has performed in-depth financial analyses concerning the relative

    economics of nuclear, coal and gas-fired power stations. One of the authors has publishedthe results of this work at a conference for the International Association of EnergyEconomists (IAEE) in Wellington, New Zealand.10 Our analyses confirm that the current

    era of high gas prices has rendered coal-fired power stations more economic than gas-fired ones. Even the prospect of future carbon trading does not make natural gas attractivefor the power sector in the United States. Our analysis suggests that, at current fuel prices,emissions would have to cost $24 per tonne of carbon dioxide before gas would becomemore attractive than coal. This exceeds the current forward prices of $21 for carbonquoted on the German power exchange, EEX.11

    Supply. Earlier we mentioned the second factor affecting prospects for LNG importsto the United States: investment in indigenous resources. Natural gas reserves havedeclined consistently for several years in the United States. However, drilling activity hasdemonstrated a significant sensitivity to natural gas prices in both the United States andCanada, the latter being a substantial exporter of gas to the US. High gas prices have

    prompted significant increase in the number of active rigs in the US, from 720 in the year

    8 Illinois and Kentucky also produce coal. Their distance from the Powder River Basin is sufficient topermit a significantly higher market price, commensurate with the much higher costs of extraction.However, even in Illinois the costs of coal lie significantly below international market prices. The average

    price paid for coal in Western Kentucky, where the coal is produced, was $39.68 per ton in 2005.

    9 Source: Eurostat import data show an average price of $67/ton from October 2005 through October 2006(see online data at

    10 Lapuerta, C., Analysing financial risk and the relative economics of natural gas, coal-fired and nuclearpower stations (presented at the IAEE Conference: Wellington, New Zealand) (February 2007)..

    11 Quoted at 16 per tonne CO2 by on January 15, 2007 (we have converted this price in intoUS$ at a rate of US$ 1.29 to the ).

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    2000 to 1,351.12 Figure 3 shows the extremely tight correlation between prices anddrilling activity in the United States.











    1997 1998 1999 2000 2001 2002 2003 2004 2005













    Source: EIA.

    Figure 3: Average Gas Prices and US Drilling Activity

    The response of the market to higher prices is promising to slow down the anticipatedreduction in indigenous gas sources. Furthermore, we anticipate significant investmentinto unconventional gas sources, primarily coal bed methane. To this picture we shouldadd the prospects for two large pipeline projects that would bring natural gas to the lower48 states from the McKinsey Valley in Canada, and Prudhoe Bay in Alaska.

    Investment in indigenous resources and the switch to coal will together constrainsignificantly the scope for LNG imports to the United States. Imports should still grow

    relative to current levels, but at a far slower pace than previously thought. Figure 4 showsa projected supply and demand balance for the US, with LNG imports filling the gap

    between demand and the supplies available to serve domestic sources. We calculate the

    available domestic sources to serve the United States by including domestic production,

    Canadian gas pipeline imports, and by deducting anticipated exports from the UnitedStates to Mexico. We show the two large pipeline projects from Canada and Alaska inyellow, first appearing in 2011 and then expanding significantly in 2019 and 2020.

    12 EIA, Table 5.1: Crude Oil and Natural Gas Drilling Activity Measurements The 1,351 is the average

    for the twelve months extending from December 2005 through November 2006, the last month for whichthe EIA had information available.

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    Figure 4: Projected Supply and Demand for Natural Gas in the United States


    Gas Demand. We have analysed closely the gas demand forecasts prepared by theEuropean Commissions DG TREN.13 More recent demand projections are availablefrom national sources for some EU countries. However, the work by DG TREN reflects a

    comprehensive European effort with consistent projections for each of the first 25member countries of the European Union, plus Switzerland (EU 25 + CH)14. Wetherefore base our demand forecast on the work by DG TREN after analysis and

    modification. Below we discuss some factors suggesting that demand will be less thanforecast. We see strong grounds for a reduction in the forecast by 10 Bcm by 2015, whichapproximates 10% of the forecast growth. However, our principal conclusion is that high

    prices in Europe will not lead to a stagnation of gas demand anywhere near the scale thathas occurred in the United States.

    Recent trends have involved a reduction in the percentage of total GDP consumed bythe industrial sector in Europe. The services sector has increased in importance. This

    trend has a moderating effect on natural gas demand, because the services sector usesnatural gas less intensively than industry. The current era of high energy prices shouldonly accelerate Europes shift from the industrial sector to the services sector. However,

    13Scenarios on High Oil and Gas Prices (2006).

    14 When analysing the European gas market and discussing its future development we define Europe as the25 countries that were members of the European Union in 2006 (EU 25). We also include Switzerland (CH)in this definition of Europe since this country is fully integrated in the gas market of the EU 25 countries.

    Norway is not a full member of the European Union. We treat Norway as a gas supplier to the EU 25 +CHcountries. Our analyses do not yet included Bulgaria and Romania in the definition of Europe, because theyhave just become members of the European Union on 1 January 2007. As neither country is an LNG

    supplier or importer, their inclusion would not have made any significant changes to our gas marketanalyses.

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    the European Commission forecasts assume an unexplained sharp stagnation of this trend.Figure 5 shows the historical decline of the services sector in the EU, and the forecast

    assumed by the Commission when developing its projections for gas demand.







    1995 1999 2003 2007 2011 2015 2019 2023 2027


    EU15 DG TREN ForecastHistoric Trend


    Figure 5: Historical and Projected Size of Industrial Sector in Europe

    The European Commission produces its forecasts only once every few years. Thelatest forecast was published in 2006. We can check the realism of the forecast in part by

    comparing to actual data. The European Central Bank publishes data concerning the sizeof the industrial sector. In 2005 the industrial sector represented 18.2% of gross domestic

    product. This percentage is already below the level that the Commission had forecast for2030.

    A more reasonable scenario would entail two adjustments to the Commissionsforecast: departing from the actual data witnessed for 2006, and projecting a continuationof the historical shift from the industrial to the services sector. Together these adjustmentssuggest that the Commission has overstated the consumption of gas by the industrial

    sector, and slightly underestimated the consumption of gas by the services sector.However, the net effect is an overstatement of the total demand forecast. Our proposed

    adjustments would reduce demand by approximately 7 Bcm in 2015.

    We have examined the Commissions forecasts for gas consumption by the powersector. The main weakness appears to be the assumed retirement of nuclear powerstations in Sweden and Germany, which is forecast to prompt the construction of moregas-fired power stations as a substitute. High energy prices exert strong commercial

    pressures to extend the lives of the nuclear power stations. We would amend the forecaststo assume a continuation of these power stations through 2015. The amendment has theeffect of reducing forecast gas demand by another 3 Bcm in 2015.

    Our proposed adjustments combine to reduce the forecast for Europe by 10 Bcm. The

    total extent of the revision could be higher, but we do not see major grounds to question aprincipal aspect of the forecast: increased demand for natural gas by the European power

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    sector. Earlier we referred to The Brattle Groups work concerning the economics ofnuclear, coal and gas-fired power stations.15 Our analysis shows that nuclear power is

    now economic in the era of high gas prices. Europe may therefore witness a shift tonuclear power. The first step would be to extend the lives of existing nuclear powerstations. We include this step in our demand forecasts. The next step will be the eventual

    construction of new nuclear power stations. However, the political debate on nuclearpower has not yet settled. The timing of new nuclear power stations will depend on theresolution of regulatory uncertainty and on the naturally long lead times for constructingnew nuclear power stations. It is difficult to believe that the European market willcomplete substantial new nuclear capacity before the end of our forecast horizon in 2015.

    We have also considered whether high gas prices might lead to a resurgence of coal-fired power stations in Europe. While our analysis suggests that coal is more economicthan gas in the United States, coal does not have a clear advantage in Europe. Most ofEurope pays more than $60/ton for coal. This high price combines with the prospectivecost of carbon permits to give the power sector a relatively high tolerance threshold for

    natural gas prices. The era of high gas prices has renewed interest in coal, and coal couldbecome clearly more attractive depending on technological breakthroughs in carbon

    sequestration. However, barring a technological breakthrough, we do not anticipate amajor shift to coal in Europe prior to 2015.

    Coal is not equally expensive in all European countries. Greece and Germany have

    domestic lignite reserves, and the German tax regime is favourable to coal. Poland is anet exporter of coal. However, these countries do not account for a substantial portion offorecast new power stations prior to 2015. Three countries account for the majority offorecast new construction: England, Spain and Italy. Coal is expensive in all threecountries. The most recent information suggests that 71% of all new planned powerstation capacity in the United Kingdom will be fired by natural gas, and the percentagesfor Spain and Italy exceed 90%.16

    Figure 6 shows our forecast of demand and supply. This forecast has been based onthe annual percentage demand growth developed by the Commissions DG TREN, whichwe have applied to historical gas consumption data17 with the adjustments that we havedescribed above. The forecast entails a growth of 96 Bcm in natural gas consumption by2015.

    15 See Note 10.

    16Platts, Power in Europe (September 16, 2006).17 Cedigaz, Trends & Figures in 2005, from Natural Gas in the World (October 2006)(for all countriesexcept the Netherlands, United Kingdom, Spain, Denmark and Ireland). The Netherlands data come fromthe Central Bureau for Statistics (Statistics Netherlands, Voorburg/Heerlen (2/1/2006)). For the United

    Kingdom we relied on National Grid, Ten Year Statement2005 (December 2005). For Spain, Denmark andIreland we used BP, Statistical Review of World Energy (June 2006).

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    Figure 6: EU 25 + CH Gas Supply/Demand Balance

    Supply. The estimated supplies in Figure 6 come from our proprietary database that

    looks at existing import contracts, infrastructure developments, and data concerninglikely domestic European production as well as the major producing countries fromwhich Europe imports pipeline gas. The domestic production volumes (defining domesticas EU 25 + CH), again reflect projections in the European Commission DG TREN 18 and

    from the Ministries or state oil and gas companies of particular gas-producing MemberStates. To estimate gas imports we considered existing contracts for Algerian, Libyan,Nigerian, Russian, Trinidadian and Ukrainian supplies. For Norwegian imports weconsidered the latest gas production projection issued by the Norwegian PetroleumDirectorate19, modified to match available gas transportation infrastructure. LNG

    supplies from Egypt, Oman, Qatar and Yemen were derived from a mixture of contractedquantities and LNG infrastructure investments tied to the particular producer in Europeancountries. Based on observations in the European gas market, we modified LNG supplies

    to reflect actual deliveries as outlined below. We project gas trade between EU 25 + CHcountries based on information about individual gas sale and purchase agreements as wellas swap arrangements.

    We consider both annual contract quantities (ACQs) and delivery flexibilityexpressed as take or pay (ToP) levels. In respect of LNG supplies we have set the ACQfor LNG receiving terminals at 90 per cent of the design capacity. Similarly we have setthe ACQ under long term LNG supply agreements at 90 per cent of the annual contractquantity. As the norm we have applied 75 per cent of this adjusted ACQ as the regularannual delivery under each contract. When the buyer and the seller of the LNG are thesame, we include only 50 per cent of the adjusted ACQ to reflect the merchant nature ofsuch projects.


    See Note 13.19 The Shelf in 2006, the Norwegian Petroleum Directorate, Stavanger, Norway (5 January 2007)

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    The difference between ACQ and ToP levels indicates the supply flexibility for eachcountry as well as EU 25 + CH as a whole. Consistent with current practice in the

    European gas market, we assign long distance gas pipeline supplies a high ToP level toreflect the base-load nature of these contracts. For long-term LNG contracts as well asLNG merchant or trading arrangements, we set ToP levels uniformly at 50 per cent of the

    adjusted ACQ, reflecting the ability of suppliers as well as buyers to divert LNG cargoesto markets outside Europe.

    Figure 6 above shows the gas supply and demand balance for EU 25 + CH expressedas ACQ as well as ToP, as both terms have been defined above for pipeline gas and LNGrespectively. Our analysis suggests that EU 25 + CH is likely to have a balanced position

    between projected demand and supply until 2013, since the demand curve intersectssupply between the ACQ and the ToP levels.

    Some 25 per cent of the gas demand within EU 25 + CH is supplied under Russiangas export contracts, most of which are of long term in nature. The reliability of these

    contracts has come into question after continental European countries experiences withtheir Russian gas supplies during the winter 2005/06. A closer analysis of the Russian gas

    production and transportation facilities and arrangements presents a number of serious

    concerns in relation to the short and medium term security of supply of Russian energyincluding natural gas. These concerns are independent of the Ukrainian gas supplyepisode in January 2006 and of the Belarusian oil transits situation, which reflected a gas

    supply dispute between Russia and Belarus, during January 2007.

    The Russian gas pipeline system faced enormous strain during the winter of 2005/06,in large part due to the demands of the domestic Russian gas market20. Domestic gasdemand remains over-stimulated by price caps that make natural gas consumptionartificially inexpensive. Furthermore, a cold winter in Russia such as the winter of2005/06 creates high peaks in electricity demands, fuelling even higher gas demand bythe sector on top of the demand for gas to heat residences, offices and factories. Thewinter of 2006/07 (until mid January 2007) was mild in the European part of Russia, anddemand for both gas and electricity was below seasonal normal levels. A harsher wintermight have prompted electric power blackouts and gas rationing as during the winter of2005/06. The Russian authorities have received bad press and harsh criticism from theEuropean Union and the heads of state of European countries that rely heavily on Russian

    gas imports, in response to Russias failure to deliver contractual quantities of gas duringthe winter of 2005/06. Public pressure has spurred the Russian Federal Government to

    guarantee gas supplies under export contracts with EU 25 + CH countries, at the expenseof needs of the Russian population. However, elections to the Russian parliament, theDuma, and also the Russian presidential elections will take place in 2007and 2008respectively. To please the electorate, the Russian Federal Government is using its controlof GazProm to invest US$770 million to connect new domestic gas customers to the gridin 2007. By the end of 2007 an additional 13 million Russian citizens will have becomegas consumers21. The Russian government appears to be trying to please the electorate byextending low priced for gas supplies to a larger part of the population. Additional strains

    20 Frisch, M. The 2005/06 Winter and Russian Gas Export to Europe. (Morten Frisch Consultings EnergyNewsletter, Issue 1) (28 February 2006).

    21 GazProm Connection Plans, Business in Brief, The Moscow Times (20 December 2006).

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    will confront an already overstretched gas supply infrastructure. Furthermore, the RussianFederal Government will not likely allow the Russian electorate to freeze in the dark if

    the 2007/08 winter should prove to be cold. Serious consequences could arise for theEuropean gas supplies.

    Looking further ahead, Russian gas consumption will continue to grow rapidly unlessRussian domestic gas prices adjust to better reflect international levels. Such priceadjustments are needed for two reasons: to stem domestic demand and, equally important,to provide GazProm with the necessary funds to dramatically step-up its investments ingas exploration and production in Russia, and to maintain and up-grade the vast gastransmission system on which its gas supply operations rely. Although the country has thelargest gas reserves in the world and possesses a huge gas production potential, thecountry currently extracts 50 per cent of its gas production from fields that already are inan advance stage of production decline22. Russia had hoped to import large quantities ofgas at low prices from central Asian republics, Turkmenistan and Kazakhstan in

    particular, at least in part to compensate for Russias difficulties shoring up declining gas

    production. However, Turkmenistan that possesses the largest gas reserves among thecentral Asian republics has started gas sales negotiations with the Chinese. Iran already

    imports gas from Turkmenistan, but is facing a critical gas shortage in the northernheavily populated part of the country, including the capital Tehran. This gas shortage ledIran to stop its gas exports to Turkey during a period in January 2007. Iran has formally

    proposed to swap gas with Kazakhstan and Turkmenistan at its border withTurkmenistan., Iran would redeliver the same amounts of gas to the two countries in theArabian Gulf and hence give them an economic access to new export markets. Such aswap, if it takes place, could create a win win situation for all parties involved, offeringlarge savings in infrastructure investments for Kazakhstan, Turkmenistan and Iran.

    Security analysts have concluded that Russia could face a gas supply gap of up to 126Bcm/y already in 2010 even if the most optimistic gas import scenario for gas deliveriesfrom central Asia materialises with the supply of 105 Bcm/y.23 However, increasinginternal gas prices to better reflect international levels could curtail Russian domestic gas

    demand significantly, reducing the predicted supply gap to manageable levels. Closeobservers of the Russian gas industry24 agree that GazProm must allow independent oiland gas producers in Russia access to its pipeline system, and must pay such gas

    producers a reasonable price for their gas supplies. This is likely the only way to removethe predicted gas supply gap in 2010. Currently some 60 to 80 Bcm of gas is flared inRussia due largely to the lack of access to GazProms pipeline system. However,

    GazProm must provide clear price signals to independent oil and gas producers withoutdelay, to motivate the necessary gas developments and infrastructure investments to take


    Asia Minor has in general attracted recent interest as a potential supply route toEurope. However, the recent experience in Turkey would question its ability to provide

    22 Mrs Chabrelie, M-F, Medium-term prospects for the gas industry (preliminary) (Cedigaz: Paris,France) (15 January 2007).

    23 Riley, A. The Coming of the Russian Gas Deficit: Consequences and Solutions, Centre for EuropeanPolicy Studies (CEPS), CEPS Policy brief No. 116 (October 2006).

    24Supra, Notes 22 and 23.

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    the reliability sought by major European gas companies. With the exception of Spain andPortugal, the two countries that together constitutes the Iberian Peninsula, LNG still

    represents a small fraction of Europes total gas supplies. However, LNG should in thefuture become of greater interest to the Europeans because of the diversification it offers.With diversification comes safety. The European Commission has recently completed its

    sectoral inquiry into competition in the natural gas industry, and points to LNG as a hopefor both enhanced security and increased competition.25


    Multiple price drivers are developing in Atlantic Basin gas markets as the growth inLNG promotes interconnection. The strongest drivers over the past two years have beenthe unusual circumstances in Spain: drought reduced the generation of hydroelectric

    power, requiring significantly more despatch of gas-fired power stations, raising thedemand for natural gas. Spains influence has also stemmed from its position of

    prominence as the largest importer of natural gas in the Atlantic Basin. Spain also had a

    severe winter in 2005/6.

    In the future, weather conditions and the Russian situation will determine whetherEurope or North America will drive winter LNG prices. Europe will be more importantfor LNG exporters in terms of its annual demand. However, the air-conditioning peak inthe United States summer markets will exert a strong influence. The capacity of US re-gasification terminals will likely exceed the demand for LNG. We have compared theEIAs forecast of LNG imports to the maximum realistic ACQs for the existing re-gasification terminals and projects that are likely to proceed. We estimate the ACQs asroughly 67% of the nameplate capacity of the terminals. Our analysis reveals a

    prospective utilization of the terminals of around 30% to 40% during the period to 2015.

    The resulting excess capacity and prospective low utilization of terminals is consistentwith our view of the US exerting a strong seasonal influence on the Atlantic basin.

    We have performed the same analysis for Europe. We compare the sustainablecapacity of European re-gasification terminals to the Cedigaz forecast of demand forLNG.26 In Europe terminal utilization will be closer to base-load operations, particularly

    if Russia should have difficulty meeting its contractual obligations. Our analysis suggestsutilization ratios ranging from 78% to 93% over the forecast period.

    The Pacific basin is another price driver exerting a strong influence on the Atlanticbasin.27 We foresee a growing influence of the Pacific basin. To date the available

    liquefaction capacity in the Atlantic basin has approximated a base-load demand level forthe Atlantic basin re-gasification capacity. It was technically feasible for Atlantic basinconsumers to rely exclusively on Atlantic basin producers, although there has been activetrade with LNG producers located in the Arabian Gulf.

    25 Communication from the Commission, Inquiry pursuant to Article 17 of Regulation (EC) No 1/2003 intothe European gas and electricity sectors (Final Report)(10 January 2007).

    26World LNG Outlook-2006 Edition (preliminary LNG supply and demand data), Cedigaz, Paris France(15th January 2007).

    27 See Frisch, M. and Lapuerta, C., the Value of Middle East LNG in the Atlantic Basin After the 2005/6Winter Price Shock, (presented at the GasTech 2006 Conference, Abu Dhabi, UAE)(4 December 2006).

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    Demand growth in the Atlantic basin will soon increase its reliance on Arabian Gulfsupplies. Figure 7 shows our forecasts. Demand in both the Atlantic basin and Pacific

    basin will exceed the liquefaction capacity in either area. Each basin will therefore seekMiddle East supplies to balance the respective markets. Although it has been assumedthat no Iranian LNG project will come on stream prior to 2015 and that Qatari LNG

    production capacity will be caped at 77.2 mt/y, we foresee the availability of a neardouble LNG liquefaction capacity by 2015 to accommodate the forecast demand.











    2006 2007 2008 2009 2010 2011 2012 2013 2014 2015


    Atlantic Basin Demand

    Pacific Basin Demand

    Pacific Basin Supply

    Atlantic Basin Supply

    Middle East Supply

    Figure 7: The Atlantic Basin in the Context of World LNG Supply and Demand

    Our demand estimates for the US derive from the EIA. For Europe we havedeveloped our own forecasts based on the proprietary database described earlier. For thePacific basin we have relied on a demand forecast by Cedigaz.28 To measure supply wehave identified existing and planned additions to liquefaction capacity. We have includedliquefaction capacity at only 90% of its nameplate capacity. However, if past experienceis a guide, actual capacity may be even less as operational problems arise with both

    liquefaction plants and feed-gas supplies. Indonesia, Nigeria, Trinidad & Tobago, Egypt,

    Oman, Malaysia, Qatar and Australia have all experienced recent operational problems orfeed-gas problems. Some excess liquefaction capacity is necessary to cushion the market

    against these types of problems, which will likely recur. Although the total supplyexceeds demand on the figure, the margin is modest and consistent with a balancedmarket, given the likelihood of technical problems at any point of time.

    In this paper we have focused on the period up to 2015. We see competition betweenAtlantic and Pacific Basin LNG markets for available supply in a global LNG market thatwill fluctuate between being balanced and being marginally short of product supply. IfRussia should experience problems meeting its long-term gas supply obligations with theEU 25 + CH countries, it will likely resolve any surpluses facing particular countries in

    28Supra, Note 26.

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    PS3 7 18

    Europe today. To overcome Russian problems, European gas markets would resort totheir positions as dominant LNG buyers within the Atlantic basin, potentially becoming

    the LNG price setters on a world-wide basis.


    Morten Frisch, Senior Partner, Morten Frisch Consulting (MFC)

    Mr Frischs has more than 30 years of hands-on experience addressing strategic,commercial and operational issues along the entire value chain for LNG and pipeline gas.This experience stems from work for the Norwegian Government, multinational oilcompanies and from work as a consultant since 1990.

    The first time Mr. Frisch led a gas sale negotiation was in 1976, the year his firstdealings with LNG receiving terminals (Everett and Cove Point terminals, USA) also

    took place. His first LNG marketing work was conducted in 1980 (the then PhillipsPetroleums Bonny LNG project in Nigeria). Since 1990 Mr. Frisch has conductedextensive work related to natural gas in the Middle East, Iran, Russia, and Central and

    Western Europe. He has also provided consulting services to clients or projects in Northand West Africa, Japan, Australia and New Zealand, and he has acted as an expertwitness in major arbitrations and court cases concerning commercial and operational gasissues. Mr. Frisch is a chartered engineer in his home country of Norway and aneconomist (degrees from University of Newcastle upon Tyne, UK and MassachusettsInstitute of Technology (MIT), USA). He is a member of the Society of PetroleumEngineers (SPE) (since 1975), the International Association of Energy Economics (IAEE)and the British Institute of Energy Economics (BIEE). He has published a number ofmajor articles addressing strategic and commercial gas issues.

    Carlos Lapuerta, Principal, The Brattle Group Inc and Managing Director, The

    Brattle Group Limited

    Mr Lapuerta directs the London office of The Brattle Group, an internationalconsultancy specialising in the economic and financial analysis of the energy industry.His practice focuses on the valuation of natural gas businesses, the analysis ofcompetition in natural gas markets, and on the appropriate design of regulations for the

    liberalisation of the gas industry. Much of the work involves business economics,performing rigorous numerical analyses of business questions. His regulatory expertisefocuses on the liberalisation of the gas industry, particularly its rules for third-partyaccess to pipelines, and its effects on commercial gas operations. He has considerableexperience with the electricity industry, which natural gas companies find useful to tapwhen assessing future developments in the European power market and their likelyimpact on natural gas markets. Mr. Lapuerta has presented expert witness testimony inmajor commercial arbitrations concerning economic and financial issues in the electricityand gas industries. Mr. Lapuerta has degrees in law and economics from HarvardUniversity.