16 MARCH Morten Frisch Senior Partner Morten Frisch Consulting. Paul Carpenter Head of Energy Practice The Brattle Group Inc.

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1 THE ADVENT OF U.S. GAS DEMAND DESTRUCTION AND ITS LIKELY CONSEQUENCES FOR THE PRICING OF FUTURE EUROPEAN GAS SUPPLIES TO BE PRESENTED AT THE GASTECH 2005 CONFERENCE, BILBAO, SPAIN, ON 16 MARCH 2005 Morten Frisch Senior Partner Morten Frisch Consulting Paul Carpenter Head of Energy Practice The Brattle Group Inc. and Carlos Lapuerta Managing Director The Brattle Group Ltd. The Brattle Group, Ltd. Morten Frisch Consulting 198 High Holborn 6 Holmwood Close London WC1V 7BD East Horsley United Kingdom Surrey KT 24 6SS United Kingdom Tel: Tel: Fax: Fax: office@brattle.co.uk mfrischconsulting@ukonline.co.uk Web: Web:

2 TABLE OF CONTENTS Disclaimer...2 Executive Summary...2 The U.S. Natural Gas Market...4 The European Natural Gas Market...9 Price review and price re-opener in a changing market...12 Interaction between the U.S. Market and Europe...15 Frisch, Carpenter & Lapuerta 1

3 DISCLAIMER This presentation is meant to provide an insight into current and future developments in North American and European gas markets. Although we believe that the presentation reflects a correct view of the current situation and future developments in these markets at the time of its drafting during late 2004 and early January 2005, the authors of this paper and/or Morten Frisch Consulting (MFC), The Brattle Group Inc and The Brattle Group Ltd. cannot be held responsible if this should prove not to be the case or if any of the conclusions drawn from this presentation should prove to be inaccurate. No representation or warranty is made as to the accuracy or completeness of the presentation and no person is entitled to rely on its contents. This presentation does not purport to offer comprehensive treatment of gas contract clauses and their operation. Any issues presented by specific contracts would require detailed analysis based on the complex text of the contract in question and the relevant commercial circumstances, including the gas market environment and the legal system(s) in which they will operate. Any recipient of this presentation, whether in electronic, hard copy, visual or oral form, 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 analysis to their specific legal and business challenges spanning the entire gas value chain between the gas producing and consuming countries. This presentation in no way offers to substitute for such analysis. EXECUTIVE SUMMARY While the Pacific basin has until recently dominated ship-borne liquefied natural gas or LNG trade, Europe and North America now present significant opportunities for LNG exporters. The consumption of LNG by Europe and North America, the latter driven by gas demand in the United States, has already linked their respective gas markets. The past few years have already witnessed the diversion of cargoes from European destinations to the United States and vice versa depending on where gas prices have been highest. In the future, high spot prices in the United States could drag more LNG cargoes away from Europe, which could in theory raise European gas prices. We analyse the likely extent of future links between the US and European markets. Forecasts indicate the scope for significant increases in LNG exports to the United States in particular, but also to the Bahamas, Canada and Mexico. Developers have proposed approximately forty different projects to construct new LNG terminals that could serve the United States. We analyse the US gas market situation, and conclude that the demand projections are likely too optimistic. We see tension between the twin assumptions that support the LNG forecasts: high prices and expanding gas demand. High US gas prices have caused demand to stagnate over the past five years. Forecasts indicate that high prices will continue. The high prices seem logical given the increased costs of supply. However, we would shave the projections for demand growth. Demand will no doubt expand, but we have serious questions concerning the reliability of the forecasts that dominate industry discussion: those prepared by the US Energy Information Administration (EIA). A likely scenario is that in addition to the existing four terminals only ten of the forty proposed grass-root projects will proceed, and that the US will still have significantly more terminal capacity than needed through Prices in US gas markets will likely demonstrate significant volatility, at times dipping low enough to prompt LNG producers in Europe, Africa and the Arabian Gulf area to divert cargoes to Europe or merely stopping cargoes in Europe on their planned voyage to North America. We analyse the prospective balance between supply and demand in Europe. Europe as a whole should be roughly in balance for the next several years, but we see the potential emergence of significant surpluses in Italy, Spain and the United Kingdom. Surplus gas in the United Kingdom will prompt lower prices, which the UK could export to continental Europe through the Bacton-Zeebrugge Interconnector and through the BBL pipeline (Balgzand in The Netherlands to Bacton in the UK). A similar phenomenon can occur in Italy. Through backhauls, Italian LNG can indirectly serve Germany, Frisch, Carpenter & Lapuerta 2

4 France and other countries that currently have transit pipelines to Italy, as Italy backs off of imported pipeline gas delivered from the north and the west. Spain is also forecast to develop significant gas surpluses. Since Spain has limited pipeline capacity with France and therefore few opportunities to serve northern European markets through the backhaul of pipeline gas, Spain is likely to adjust its market position through the onward sale of LNG cargoes. This in turn could influence gas markets in North West Europe as well as Italy. Progress with the implementation of third-party access throughout Europe will be key to these dynamics. If Germany and France make little progress with liberalization, then the price effects of surpluses will focus more directly on Italy, Spain and the United Kingdom. In contrast, successful liberalization will tend to support gas prices in the countries with surpluses, enabling them to export more successfully their surpluses to interconnected countries. In this case a more modest price effect would extend across a larger group of countries. Existing continental European long-term contracts for natural gas contain price review and re-opener provisions that can spread the impact of changed spot prices throughout the gas industry. In continental Europe, we would also anticipate changes to the price and price adjustment provisions in existing medium- and long-term gas supply contracts and in the way that new gas contracts are signed. The expansion of LNG capacity will no doubt strengthen the links between North American and European markets. We outline a realistic scenario involving slower demand growth than currently forecast in the United States, a corresponding desire by LNG producers to divert cargoes to Europe, which intensifies and prolongs the potential export of surpluses from Italy, Spain and the United Kingdom to interconnected European countries. Experience also shows that surpluses themselves can create strong pressure to accelerate the pace of liberalization, which could restrain the price declines in the European countries with surpluses while having profound effects on prices and contracting practices in interconnected countries. Frisch, Carpenter & Lapuerta 3

5 THE U.S. NATURAL GAS MARKET The Energy Information Administration of the United States has forecast a considerable increase in supplies of liquefied natural gas or LNG to the United States, that when re-gasified will correspond to approximately 105 billion cubic metres (BCM) of pipeline quality gas per year by Three factors together would seem to invite substantial quantities of LNG to the United States: gas prices are high, demand is forecast to increase significantly, and domestic production is forecast to decline. Developers have responded favourably to the invitation, proposing over forty different new LNG terminals along the United States coast. Market analysts have noted the intense environmental opposition facing the construction of new terminals in the United States. LNG terminals face significant opposition in heavily populated areas like New England, the Mid Atlantic and California. In New England, two planned facilities were cancelled due to community opposition. 1 Two other planned projects face significant opposition from local governmental officials. 2 Developers cancelled two projects in California due to community opposition, 3 and the California Public Utilities Commission is currently contesting the Federal Energy Regulatory Commission s sole jurisdiction over the siting of LNG facilities in California. While it is difficult to obtain permits for a new terminal in the United States, the difficulty will not prevent a dramatic expansion in LNG capacity. New LNG terminals have been able to obtain permits in gas supply regions along the Gulf Coast and in Canada and Mexico. The Federal Energy Regulatory Commission recently granted permits to three facilities on the Gulf Coast: Sempra Energy s Cameron terminal near Hackberry, Louisiana, the Freeport LNG Development s Freeport LNG terminal near Freeport, Texas, and Cheniere LNG s Sabine Pass terminal in Cameron Parish, Louisiana. The US Coast Guard granted permits to two Gulf of Mexico off-shore LNG facilities: ChevronTexaco s Port Pelican terminal and Excelerate s Energy Bridge project. The Mexican government has granted permits to Sempra Energy s Energia Costa Azul facility in Baja California and Shell/Total s Altamira terminal in Tamulipas along the Gulf Coast. The Canadian government has given permits to the Canaport terminal in New Brunswick and the Bear Head terminal in Nova Scotia. The Bahamas has granted preliminary approval to the Calypso LNG terminal, which would deliver gas to Florida via a sub-sea pipeline. Furthermore, existing US terminals in Cove Point, Maryland, Lake Charles, Louisiana and Elba Island, Georgia are expanding. Currently, LNG terminal base-load send-out capacity in the US is 27 BCM per year. US LNG imports were 18 BCM in If planned expansions at the existing US LNG terminals are completed, and if the permitted facilities are constructed, US base-load terminal capacity will increase to 100 BCM per year, almost four times the current level. If the facilities that have been permitted by Mexico and Canada and the Calypso project in the Bahamas are constructed, this will add an additional 37 BCM per year to North American LNG terminal capacity. The market can offer approximately 110 BCM of incremental LNG capacity from projects that have either won or avoided the fight to secure US environmental permits. We conclude that most of the forty proposed projects will be cancelled. However, only a few of these projects are necessary to supply the large amounts of incremental LNG forecast by the Energy Information Administration. The US will be able to import more than forecast from just the ten new projects that have secured permits, plus the four existing terminals with their permitted expansion capacity. A total of fourteen terminals should be enough. The difficulty of obtaining permits has attracted considerable attention in the press, but our analysis suggests that most projects would suffer cancellation or delay for independent commercial reasons, since their collective capacity would vastly exceed the total amount of LNG consistent with forecast demand growth. Apart from the 110 BCM per year of expansion and new, permitted North American LNG terminal capacity, projects that have been proposed but not yet permitted would add additional capacity of several hundred BCM per year. Environmental issues may dictate the location of new terminals away from centres of major consumptions, but so far are not preventing the US market from consuming as much LNG as demanded. Frisch, Carpenter & Lapuerta 4

6 The total growth in US gas demand poses a more interesting question concerning the prospects for LNG in the United States. Gas demand has stagnated since 1999, largely in response to high prices. From January 1991 to April 2000, US gas prices (represented by the monthly price at the Henry Hub, the most active trading hub in the US) averaged $2.08/million British thermal units (mbtu), and exceeded $4.00/mBtu in only one month. US gas prices averaged $4.57/mBtu from May 2000 to January 2005, and have not fallen below $4.00/mBtu since October Yet throughout the period of stagnation the Energy Information Administration has consistently prepared forecasts showing that gas demand was just about to take off like an airplane over the twenty-year horizon. Each new forecast delays the forecast time of departure, but fails to question the flight. Previous forecasts contemplated total demand of 860 BCM by 2010 or By early 2004 the Energy Information Administration had postponed its projection of 860 BCM to Forecasts were cut further throughout the course of 2004, and the EIA postponed its projection of 860 BCM by an additional 2 years. In Figure 1 below we show the series of past forecasts by the EIA. Figure 1: U.S. EIA Gas Consumption Forecasts U.S. Gas Consumption (BCM) U.S. Consumption = 860 BCM Postponement of Date for 860 BCM In this paper we focus primarily on the outlook to Below we take a different slice of the EIA forecasts, showing that the projections for 2015 have fallen by approximately 100 BCM between the date of the 2001 EIA forecast and its most recent forecast. To put the decline in context, it approximates the entire consumption of the UK natural gas market. Yet we are concerned that the most recent forecast may still overstate demand. We have seen similar forecast revisions in the past. For more than a decade following the oil price shock of 1973, forecasters predicted that oil prices would steadily outpace inflation for the following twenty years. Every year reality provided a new starting point for the forecast. Since prices fell in real terms for the decade following 1973, the starting points were trending down. Few people were willing to connect the dots provided by the starting points themselves, to draw the horizontal trend line that might question the envisioned future of steady oil price increases. Frisch, Carpenter & Lapuerta 5

7 Figure 2: U.S. EIA Gas Consumption Forecasts U.S. Gas Consumption (BCM) Decrease in Forecast for In the graph shown in Figure 2 above, each demand forecast starts by reporting the actual consumption in the previous year. The starting points are all around 650 BCM or less. By the time that we reach the 2005 forecast, the starting point of 2004 consumption is only 633 BCM, yet the 2001 forecast would have predicted 713 BCM by then. Connecting the dots of historical consumption would provide a roughly horizontal line. In contrast, the recent EIA forecast adopts nearly the same slope as the forecasts made in the previous four years. Stagnant consumption reflects, in part, the effect of high prices on demand. The International Energy Agency has commented on the recent stagnation in US gas demand: prices are also boosting manufacturers operating costs and hitting their profits. In particular, high gas prices have a negative impact on the chemical industry, the largest US industrial gas consumer. This industry needs gas prices between $2.5 and $3/mBtu to remain competitive on the world stage. One by one, fertiliser plants are closing. This situation has led some companies to move production overseas where gas is cheaper. The high cost of natural gas coupled with US low electricity prices are keeping most new gas-fired power plants idle because they are too expensive to operate. Gas demand by power generators decreased by 13% in 2003, while their demand for distillate fuel oil increased 40%. 4 The corollary to reduced US demand is the rapid expansion of energy-intensive industries in the Arabian Gulf area and other areas that have access to cheaper gas. High prices are anticipated to persist in the US. The EIA forecasts that US wellhead prices will average $4.08/mBtu from 2005 through This is virtually identical to the average wellhead price of $4.29/mBtu over the past five years, which sufficed to stall demand growth. 5 The high prices in the forecast raise natural questions concerning the prospects for future demand growth. High prices may continue to postpone the forecast time of departure for the EIA s airplane of gas demand. Some other questions surround the EIA forecast. One key driver is the forecast change in energy intensity of the United States economy. Energy intensity has declined in the US since at least 1970, but it tends to decline at a greater rate in years when energy prices are high, reflecting improvements in energy efficiency and a shift away from energy intensive industries. Energy intensity declined at 1.75% per year between 1991 and Since 2000, energy intensity has declined at 1.9% per year. Frisch, Carpenter & Lapuerta 6

8 However, the EIA has forecast that energy intensity will decline at a significantly slower rate in the future. In its 2005 forecast, the EIA forecasts that energy intensity will decline at an annual rate of 1.6%. Another interesting question for LNG demand involves the timing and extent of Alaskan and new Canadian natural gas supply availability to major US markets. One project is the Alaska Highway Pipeline Project, which would carry natural gas from Prudhoe Bay in Alaska through Canada to major markets in the United States. Initially, the pipeline would have the capacity to supply between 30 and 50 BCM per year, but it could eventually supply 60 BCM per year. A second project is the Mackenzie Valley Pipeline, which could supply between 13 and 20 BCM. At their peak, these two projects would supply 80 BCM per year, equivalent to approximately eight years worth of forecast increase in US demand. Changes in the timing of these projects could have serious effects on the economics of LNG. Sponsors of the Mackenzie Valley Pipeline have just filed their application for regulatory approval with the Canadian National Energy Board. It is highly likely that this project will proceed. The Alaskan and Canadian gas will likely constitute base load supplies into US markets. Pipeline tariffs in the United States and Canada recover the fixed costs of pipeline investments primarily through fixed annual charges. Gas suppliers commit to paying the tariffs regardless of actual throughput. Project sponsors and lenders will require that these projects be underpinned by year transportation agreements, creating a tremendous incentive for shippers to base-load supplies over the new pipelines. This has been the experience with the Alliance pipeline project from Western Canada to Chicago that began operation in The gas at the wellhead in Alaska will have no local commercial value and almost no extraction costs, since most of it represents associated gas that has been re-injected over the years to maintain oil field pressures and to improve petroleum recovery rates. Large fixed pipeline costs and the minimal variable costs of production would together provide sufficient grounds to question the sanity of any supplier who saved the gas for use during peak periods. Domestic United States gas production from the lower 48 states will have higher variable costs than either Alaskan or Canadian gas. The total incremental costs of lower 48 states production, including capital costs, will likely set the long run market price for natural gas. However, this does not mean that LNG will be base load. Given the capital-intensive nature of natural gas production and pipeline transportation, the total delivered costs for domestic supplies can approximate $4/mBtu while the variable costs remain quite low. Some LNG projects also have minimal variable production costs, because they involve associated gas or projects that find sufficient economic justification in the production of liquids. Nevertheless, a proper definition of variable costs should consider the opportunity cost of sacrificing the next best use of the gas. Variable opportunity costs will likely involve the diversion of cargoes to alternative destinations. From the perspective of an Arabian-Gulf area producer, the variable costs of delivering to the United States will include both the revenues and the savings in shipping costs obtainable from diverting cargoes to Europe. We have seen estimates suggesting that the diversion of cargoes from the United States to Europe could save $0.60/mBtu in shipping costs from the Arabian Gulf. 6 Adding this figure to the market price of natural gas in Europe, the total variable cost of delivering LNG to the United States is actually several dollars per mbtu. Middle East and North African LNG exporters would rationally respond to low US prices by diverting cargoes to Europe well before prices fell low enough to curtail US domestic gas production. An LNG exporter can use the local LNG storage tanks at the re-gasification terminal to optimise deliveries, injecting re-gasified LNG only during peak periods, leaving LNG in storage during off-peak periods, and accommodating the reduced withdrawal rates by reducing the frequency of LNG cargoes. This would permit the LNG exporter to divert additional cargoes to European destinations, utilising more fully the peak send-out capacity at re-gasification terminals in Europe. Frisch, Carpenter & Lapuerta 7

9 While Alaskan and Canadian gas pipeline projects involve base-load supplies to the United States market, the forecast demand growth is likely to focus on peak periods. Power stations currently represent less than one quarter of US gas demand, but the EIA anticipates that new power stations will account for more than half of the total forecast increase in gas demand. The forecast high prices would imply a continued role for power stations at the peak end of the United States electricity market, especially when compared to projections for continued low coal prices. EIA forecasts that mine-mouth coal prices will decline from about $17.90/short ton in 2003 to $16.90/short ton in 2013, then remain at that level until 2020, when the construction of coal-fired electric generating capacity will contribute to an increase in the price to $18.25/short ton (all coal prices in 2003 dollars). When new Alaskan and Canadian gas sources come on as base-load supplies, and a higher percentage of natural gas consumption shifts to peak periods, the resulting volatility could be quite high for new LNG projects that serve the United States. Another contributing factor to volatility will be the concentration of new LNG capacity in the Gulf Coast region. Projects with permits stand to increase deliveries into the Gulf Coast region by 65 BCM per year. US production may decline in the Gulf Coast area, creating some room for new LNG. The EIA s 2004 forecast predicted that gas production in the Gulf Coast and Southwest regions 7 would fall from 185 BCM in 2003 to 170 BCM in This implies that roughly 50 additional BCM could be delivered into the Henry Hub area over this twenty-two year period based on existing gas pipeline infrastructure. If LNG supplies focus on peak periods, they may face serious questions concerning transmission constraints in deliveries to markets in the Midwest and Northeast. Transmission constraints could prompt market area prices to rise in the congested regions, particularly the Northeast. Henry Hub prices would fall relative to markets elsewhere in the United States. FERC Chairman Pat Wood III has already expressed concerns that transportation constraints would prevent Gulf Coast LNG from reaching Atlantic or West Coast markets. He said that more Gulf Coast LNG capacity cannot solve the problem of $9 gas in these markets. The solution to the $9/mBtu problem would require new terminals on either the Atlantic or the Pacific Coasts. 8 The various risks identified above would seem to raise the prospect of delaying some of the LNG projects that have already secured permits. However, a rational strategy would be for the existing projects to proceed, and to tolerate a potential situation of excess capacity relative to demand. Significant delays to a project could force the developer to apply for permit extensions, to repeat environmental impact analyses, and to face the risk of a deteriorating regulatory climate. Delay could in theory avoid a period of weakening US prices, but periods of tightness will no doubt arise some time over the life of the proposed projects. Since LNG is more economic than marginal lower 48 states domestic production, moving forward and tolerating price volatility would appear to be the best strategy. Frisch, Carpenter & Lapuerta 8

10 THE EUROPEAN NATURAL GAS MARKET European natural gas markets differ from North American markets significantly. However, Europe and North America share an increasing dependence on imported gas supplies, in the form of pipeline gas as well as LNG, located at ever greater distances from major consumption points. Many LNGproducing countries either supply or are planning to supply both Europe and North America. Examples have already arisen of intertwined LNG supply chains for North America and Europe. Companies have diverted LNG cargoes to the market paying the best price, or have engaged in swap arrangements that have the same effect. Several European developments in the short to medium term will shape the likely links with North American markets. The most important factor is likely to be the projected balance between gas demand and supply. We analyse the period up to and including 2015, relying on demand projections developed by the European Commission s DG TREN. 9 More recent demand projections are available from national sources for some EU countries. However, the work by DG TREN reflects a comprehensive European effort with consistent projections for each of the 25 member countries of the European Union, plus Switzerland ( EU 25 + CH ). 10 The forecasts show annual percentage demand growth, which we apply to Cedigaz 2003 gas consumption data. 11 We forecast gas supplies by analysing domestic production, pipeline gas imports and LNG imports. The domestic production volumes (meaning gas production within EU 25 + CH countries), reflect projections in a recent report by the European Commission, 12 and from the Ministries or state oil and gas companies of particular gas-producing Member States when such information could be obtained. To estimate gas imports we considered existing contracts for Algerian, Libyan, Nigerian, Russian, Trinidadian and Ukrainian supplies. For Norwegian imports we considered the latest gas production projection issued by the Norwegian Ministry of Petroleum and Energy, modified to match available gas transportation infrastructure. LNG supplies from Egypt, Oman and Qatar were derived from a mixture of contracted quantities and LNG infrastructure investments tied to the particular producer in European countries. Gas trade between EU 25 + CH countries has been based on information about individual gas sale and purchase agreements as well as swap arrangements. We consider both annual contract quantities (ACQs) and delivery flexibility expressed as take or pay (ToP) levels. The difference between ACQ and ToP levels indicates the supply flexibility for each country as well as EU 25 + CH as a whole. As is the case in the European gas market today, long distance gas pipeline supplies have been assigned a high ToP level reflecting the base-load nature of these contracts. For LNG receiving terminals ACQs have been set at 90% of the design capacity while ToP levels reflect the ability to divert LNG cargoes to markets outside Europe. Figure 3 below shows the gas supply and demand balance for EU 25 + CH expressed as ACQ as well as ToP. Our analysis suggests that EU 25 + CH is likely to have a balanced position between projected demand and supply over the next few years, since the demand curve intersects supply between the ACQ and the ToP levels. We note that the gas demand forecasts for individual countries as well as the EU 25 + CH market area are likely to prove optimistic, since they assumed much lower energy prices than Europe has witnessed in the last year, and than current forward price curves would imply. 13 This is particularly the case over the next few years, when oil price indexation could raise average gas prices to levels not previously seen in continental Europe. At the same time, our projected imports from Norway would tend to be conservative, since we did not assume the removal of any existing transportation bottlenecks. A different picture emerges when focussing on particular countries or market areas within Europe. In Figure 4 below we show the anticipated combined gas supply and demand balance in the United Kingdom and Ireland. We include Ireland because it is well connected by pipeline to the UK and depends on the liberalised UK gas market to meet its gas requirements. Frisch, Carpenter & Lapuerta 9

11 Figure 3: EU 25 + CH Supply/Demand Balance BCM (39MJ/Sm 3 ) ToP Supply ACQ Supply Demand Figure 4: UK and Ireland Supply/Demand Balance BCM (39MJ/Sm 3 ) We see a significant surplus emerging in the UK and Ireland with the completion of several large infrastructure projects in the UK in the next few years, such as the addition of the Langeled and BBL gas pipelines from Norway and the Netherlands, respectively, and of significant new LNG capacity. At first glance it might not seem rational for the UK to shift into a surplus position. Delaying some of the proposed infrastructure projects might seem to be the most logical way of maintaining the balance between supply and demand. We discussed a similar issue in the United States, and we suggest the same answer for the United Kingdom. It makes sense to proceed with all the large LNG Frisch, Carpenter & Lapuerta 10

12 projects, to take advantage of the currently favourable regulatory climate that at least in part is driven by a political fear that the UK could face a gas supply shortage. Delaying a project would expose the developer to the risk of increased environmental opposition or a deteriorating regulatory climate. Prices in the United Kingdom could fall significantly for a few years without threatening the long-term economics of new LNG projects, so it seems best to proceed and tolerate the risk of lower prices beginning in the 2007 through 2010 time frame. Moreover, the liquidity of the UK gas market provides considerable safety for these large projects. European gas markets such as Germany may actually need the gas more, but constructing a terminal in Germany would, at the present time, expose the developer to the risks of inadequate progress with gas market liberalisation in general and the potential lack of proper third party access to gas pipeline systems in particular. It therefore makes more sense to build LNG terminals in the UK where a liquid market assures an outlet for the gas. As the surplus emerges, UK developers will try to re-export to continental markets, through either the Bacton-Zeebrugge Interconnector or the BBL pipeline to the Netherlands currently being constructed. We forecast a large surplus emerging in Italy as well. Figure 5 below shows that Italy will soon confront take-or-pay problems, unless it can sell the excess gas via backhaul to countries located to the north and west. Transit pipes serving Italy currently pass through Austria, Germany, France and Switzerland. Italy could reduce its imports and sell the gas instead to these countries located to its north and west. 140 Figure 5: Italian Supply/Demand Balance 120 BCM (39MJ/Sm 3 ) ToP Supply ACQ Supply Demand In addition to the UK and Italy, the gas market on the Iberian Peninsula will also develop a significant gas surplus, a surplus that based on our projection will last until If the construction of the second gas pipeline between Algeria and Spain, Medgaz, takes place, as now seems likely 14, this surplus is likely to be prolonged by 2-3 years. Spain has limited pipeline capacity with France and therefore few opportunities to serve northern European markets through the backhaul of pipeline gas. Spain is likely to adjust its market position through the onward sale of LNG cargoes. Indeed, in total, Spanish LNG contracts have the flexibility to re-sell the equivalent of 10 BCM of pipeline quality gas on a yearly basis. 15 The Spanish oversupply together with this flexibility could in turn influence gas Frisch, Carpenter & Lapuerta 11

13 markets in North West Europe, as well as Italy, if LNG terminals in these two geographic areas should be the only viable outlet for Spain s surplus LNG cargoes. Since we show that Europe as a whole should have a rough balance between supply and demand, the surplus gas in the UK and Italy should be able to find a home in other European countries through delivery by pipelines. This could also be the case for LNG cargoes surplus to Spain s needs. However, much of this depends on progress with liberalisation and in particular the development of third-party access to pipeline systems in countries such as France and Germany. Successful liberalisation will facilitate re-exports of gas from the United Kingdom, exports via backhaul from Italy, and diversions of cargoes from Spain, mitigating serious price declines in those countries while avoiding potential price increases elsewhere in Europe. A failure to implement proper third-party access would leave Italy, Spain and the UK witnessing significant price decreases while affecting pipeline interconnected countries located between these national markets to only a modest extent. Our experience is that the mere emergence of a surplus in a neighbouring country can create significant political pressure to proceed with liberalisation. If prices fall dramatically in the UK, and German industrial customers are not witnessing the benefits despite the existence of ample export capacity in the BBL pipeline and its connections to the German market, the German government and regulator will no doubt witness increased pressure or receive additional support to reform and improve the third-party access arrangements in Germany. It should not be forgotten that gas bubbles in both the United States and the United Kingdom coincided with the effective implementation of third-party access. We return now to Figure 4, which forecasts the combined gas supply and demand balance in the UK and Ireland. A surplus gas position based on ToP could develop as early as 2006 and persist until This situation exists although we have assigned LNG imports a 50% ACQ ToP level to reflect the possibility of diverting cargoes to serve the United States. As we explained in connection with the US market, the ability to divert cargoes is economically equivalent to a high variable cost that will place LNG at the margin in the UK market, despite having total delivered costs below those of alternative gas sources. 16 New pipeline and LNG supplies entering the UK market are all priced in relation to spot prices and the forward price curve at the UK national balancing point or NBP. Figure 4 shows that the UK and Ireland market area will have an annual surplus over ToP levels in excess of 9 BCM developing between 2006 and This excess is, in effect, the UK gas supply position after exports to Ireland. It represents some 8% of UK gas demand. Past experience in the UK market has shown that a developing surplus of this magnitude exerts a major downward adjustment in NBP gas prices. The gas supply/demand balance shown in Figure 4 suggests a commencement of this process during the second half of 2006, manifesting itself properly during spring of Nominal prices at NBP could fall to some $3.20 to $3.80/mBtu reflecting the marginal cost of LNG supplied to terminals in England. As indicated earlier, our analysis assumes that 50% of LNG terminal capacity in England can be diverted elsewhere. If less than 50% can be diverted, perhaps in part because price declines in the US market limit the demand for cargo diversions there, then UK NBP prices could fall to even lower levels. PRICE REVIEW AND PRICE RE-OPENER IN A CHANGING MARKET Gas price fluctuations caused by oversupply and gas-to-gas pricing in the UK market are likely to affect the existing gas pricing regimes under long-term gas supply agreements in continental Europe. These so called continental European legacy contracts all have base prices set in relation to fuel oil prices and are indexed against the price of other forms of energy, again primarily fuel oils. These indexed prices operate together with price review and price re-opener clauses. Frisch, Carpenter & Lapuerta 12

14 Figure 6: North West European Natural Gas Infrastructure Source: GTE & Morten Frisch Consulting; Figure modified by The Brattle Group. Frisch, Carpenter & Lapuerta 13

15 When gas prices in the UK market in the future again fall below those in continental Europe due to oversupply, surplus gas quantities will be re-exported to the Belgian and Dutch gas markets through the Bacton to Zeebrugge Interconnector and the BBL pipeline. The gas price paid for such supplies will influence the reported spot prices at the local trading hubs at Bunde and Zeebrugge and also the Dutch gas balancing point called Title Transfer Facility or TTF. These trading hubs, together with North West European LNG receiving terminals and the pipeline systems linking the Belgian, Dutch and UK gas markets and gas markets further afield, are shown in Figure 6 above. If Dutch and Belgian spot gas prices remain lower than the prices prevailing under continental European legacy contracts in these markets over an extended period of time, buyers will likely invoke price review and price re-opener clauses in continental European legacy contracts. Such contracts supply Norwegian and Russian gas to the Dutch market and Dutch and Norwegian gas to the Belgian market. Successful reviews and/or arbitrations could in turn provoke price reviews under continental European legacy contracts serving Austrian, French, German, Italian and Swiss gas markets, and eventually the gas markets of Denmark, Finland, Greece, Spain and Sweden. Continental European price review and price re-opener clauses operate on two main principles. They are: 1. if the seller and the buyer of the gas have agreed, or it has been determined by an expert or an arbitration, that the economic conditions including the energy market environment in the buyer s gas market area have changed significantly compared to the time the price adjustment was last agreed, and such changes are beyond the control of both the buyer and the seller, then the price arrangement in the contract will be adjusted or changed to reflect the new economic conditions in the buyer s gas market area; and 2. if the buyer can demonstrate to the seller, or it has been determined by an expert or an arbitration, that the buyer in spite of operating a sound and efficient gas marketing practice is unable to make a reasonable profit when selling the gas taken delivery of under the gas sales agreement with the seller, the contract will be adjusted or changed to restore the buyer s position in his market. The second principle and test overrides the first and in effect guarantees the buyer a positive margin on the gas taken delivery of under the gas supply contract concerned. Price review and price reopener clauses normally also include a safeguard preventing the seller from making a loss on the gas sales agreement while the buyer operates at a healthy profit margin. Originally price review and price re-opener clauses could only be triggered every three years but many contracts have now reduced this period to two years due to rapidly changing market conditions. We understand that some gas buyers and sellers are now discussing annual price reviews. If large quantities of LNG can enter the wider EU 25 + CH gas market from Italy and the UK and to a lesser extent from LNG terminals in Belgium and France, then price review and price re-opener clauses in continental European legacy contracts could lead to changes in the prices themselves, and in price adjustment arrangements. The logical trend would be a move away from prices based on and indexed to fuel oil. Eventually and most likely after two or three waves of price review and price reopener negotiations that would probably involve arbitrations, gas-market-based pricing would emerge as has already largely happened in the UK. To our knowledge all medium and long-term gas supply agreements entered into by UK-based buyers after 1996 have adopted some form of market-based pricing. This situation is also starting to emerge in Belgium and the southern part of The Netherlands. This is the result of gas trading activities at the Zeebrugge hub and the link between the gas markets in Belgium and the UK on the one hand and Zeebrugge with the market in The Netherlands on the other. Frisch, Carpenter & Lapuerta 14

16 INTERACTION BETWEEN THE U.S. MARKET AND EUROPE Several market factors in the United States will create an attractive opportunity for diverting cargoes to Europe or merely stopping cargoes in Europe on their planned voyages to North America. A realistic scenario is that diverted cargoes from the US will increase and extend the emerging surpluses that we discussed above in the UK and Italy, surpluses that could be augmented by the resale of LNG cargoes originally intended for Spain. While environmental restrictions are not choking the supplies of LNG to the US market, they will have an influence on Europe. First, the difficulty of building new terminals on the East Coast of the US will raise LNG shipping costs to the US, because of the larger distances to the Gulf Coast. The additional shipping costs could be about $0.30/mBtu. Mediterranean and Arabian Gulf area producers can save these costs by diverting cargoes to Europe. The additional shipping costs to the US will make cargo diversion more attractive when US gas market prices dip. Second, we indicated above that environmental restrictions are focussing LNG supplies in the Henry Hub area. The liquidity of the Henry Hub area will permit LNG exporters to sign contracts linked to the Henry Hub spot price. In contrast, fuel-oil-price based and indexed gas prices remain prevalent in continental Europe due to the continuation of legacy contracts as outlined above. The Henry Hub price has been far more volatile than oil prices, and should continue to be so in the future. This suggests greater opportunities for arbitrage between the US and European markets through cargo diversions. Italy would prove an especially attractive place for Mediterranean and Arabian Gulf area LNG producers to divert cargoes. Italy s geographic proximity to sources of LNG would prompt significant savings in shipping costs, and Italy s backhaul possibilities with countries to its north and west would create the possibility of serving a broader continental European market. While Spain and Portugal import significant quantities of LNG, and both are also close to major LNG exporters, the Iberian Peninsula currently has limited pipeline capacity with France and therefore far fewer opportunities to serve northern markets with pipeline quality gas. Spain and Portugal are likely to export their surplus gas quantities by selling or diverting LNG cargoes. After Italy, the logical places to divert LNG cargoes (whether originally intended for North America or the Iberian Peninsula) would therefore be Belgium, England and France. Belgium and England face the disadvantage of a greater transportation distance from major LNG exporters. However, market liquidity in the United Kingdom and Belgium s direct pipeline link to the UK market would provide a considerable offsetting advantage in the event that gas market liberalisation remained inadequate in France. Surplus gas quantities can be dispersed within or from these two national markets, but probably at the cost of a lowered price. The prospects for diverted cargoes will depend in part on the size of ships used, the capacity of available LNG receiving terminals and gas quality. The new ExxonMobil/QatarGas terminal in the United Kingdom will have the advantage of accepting all different ship sizes up to the new tankers that exceed 200,000 cubic metres in capacity, and which Qatar will simultaneously be using to serve proposed terminals in the Bahamas and the Gulf of Mexico. These large vessels would currently be unable to dock at several other terminals in Europe. England has a relatively lean gas quality like the United States and Qatar. The domestic petrochemicals industry in the United States strips out the C2, C3 and C4 for sale as separate products, leaving the pipeline gas with a lower energy content. The same occurs in Qatar because of its large and rapidly growing domestic petrochemicals industry. These factors will permit Qatar and ExxonMobil to balance cargoes between markets in England and the United States. We conclude that our analysis reveals potentially significant future changes in the links observed to date between North American and European gas markets. The construction of additional LNG capacity will intensify these links. During the last five years we have witnessed the diversion of US cargoes to Europe and even Far East Asian markets during North American gas price troughs. Over the last two years most of this activity has involved the diversion of cargoes from Europe to the US in response to extraordinary spikes in US natural gas prices, a trend likely to continue for a period of three to five Frisch, Carpenter & Lapuerta 15

17 years. After this period, however, we can see the reverse occurring. Stalled demand growth in the US, combined with the completion of major pipeline infrastructure projects in Alaska and Canada and an excessive concentration of LNG capacity in the US Gulf Coast, could again send cargoes the other way. Price spikes will no doubt recur in the United States as a result of natural volatility, but the price spikes have occupied considerable attention while the troughs have not. Several factors give reason to anticipate troughs that could even intensify and prolong emerging surpluses in Italy, Spain and the United Kingdom, which will try to re-export their surplus to other European markets with tighter supply and demand conditions. Looking five to seven years ahead we can assume significant progress with the development of thirdparty access to gas transmission and distribution systems throughout EU 25 + CH, facilitating the dispersal of national and/or regional gas supply surpluses throughout Europe. Continental European gas contracting practices should change by then, in particular the price determination and adjustment mechanisms. We anticipate the combination of gas surpluses and progress with liberalisation to prompt continental European buyers to trigger price review and price re-opener clauses. These actions will insert gas-to-gas pricing into continental European legacy contracts. Such a pricing mechanism will be more flexible than the oil-product-based pricing and price adjustment arrangements operating today, and will facilitate the absorption of additional quantities of natural gas diverted from North America at short notice. Reverting to Figure 3 showing the EU 25 + CH supply/demand balance, we note that after 2012 to 2013, Europe will need additional gas supplies to those currently under contract. LNG will likely be a major source of gas for the whole of Europe by then, reducing continental Europe s dependence on Russian pipeline gas supplies. Seven to ten years from today, diverted LNG cargoes could be very positively received by all players operating within the wider EU 25 + CH gas market. By 2015, countries such as Germany, The Netherlands and Sweden should build LNG receiving terminals to join the LNG revolution and improve the flexibility and diversification of their gas supplies. At this point in time, we believe that the gas demand destruction combined with the construction of a large number of LNG receiving facilities in the US might be viewed as a blessing by European energy utilities, gas consumers and politicians alike. Frisch, Carpenter & Lapuerta 16

18 1 Maine. The Fairwinds LNG project in Harpswell, Maine, and the Hope Island LNG project on Hope Island, 2 The Weaver s Cove project in Fall River, Massachusetts, and the Providence LNG facility in Fields Point, Rhode Island The Humbolt Bay facility in Eureka, California and the Mare Island LNG project in Vallejo, California. IEA, Security of Gas Supply in Open Markets: LNG and Power at a Turning Point, (2004), Chpt. 6, p. Both the $4.08 and the $4.29 are calculated in real 2003 dollars. 6 Golar LNG, The Floating Gas Pipeline Increases Capacity, presented at Pareto Offshore Seminar (Aug. 2003)(showing costs of $1.25/Mcf from Qatar to the United States, which involves at least twice the distance between Qatar and Europe) and Jensen, J.T., US Reliance on International Liquefied Natural Gas Supply, A Policy Paper Prepared for the National Commission on Energy Policy (February 2004), p. 83, Figure Texas and Louisiana, but also part of New Mexico plus Mississippi, Alabama, and Florida. FERC Gives Final OK to Sabine Pass LNG Project, Gas Daily (Platt s), Dec. 16, 2004, pp. 1, 5. DG TREN, European Energy and Transport - Trends to 2030 (January 2003). 10 Excluding Cyprus and Malta, which do not currently use natural gas. Cyprus is currently exploring the possibility of importing LNG or gas by pipeline. Switzerland is not a member of the European Union, but is important to consider because its gas infrastructure interconnects with France, Germany and Italy Trends & Figures in 2003 from Cedigaz, Natural Gas in the World (July 2004). European Energy and Transport Trends 2030, Appendix The baseline scenario assumed that the average border price of crude oil imported by EU 25 countries would be US$20.1 in 2010 and US$23.8 in 2020, expressed in real 2002 US$. Similar price assumptions were adopted for natural gas and hard coal. 14 Go Ahead Soon for Second Spain-Algeria Gas Pipeline, in European Gas Markets, issue of 14 January 2005, p Statement made by Tom Quigley, Managing Director, Mediterranean Gas & Power, BP, during his presentation The Spanish Gas Market A New Entrant s Perspective, made to the 19th Annual European Gas Conference, Barcelona, Spain, 9 November BP indicated that Algerian, Egyptian and Qatari LNG now could be delivered in the form of pipeline gas into the gas transmission system in the UK at a price lower than new Norwegian and Russian pipeline gas supplies (Anne C Quinn, Group VP BP, presentation to the 19th European Autumn Gas Conference, 8 November 2004, Barcelona, Spain, titled Adding a Global Dimension to Europe LNG: Implications and Opportunities ).