Morten Frisch
Morten Frisch Consulting
East Horsley, Surrey
UK
Carlos Lapuerta
Brattle Group Ltd.
London
Europe should play an ever-stronger role in the Atlantic Basin LNG market relative to the US. The demand-supply balance for LNG will fluctuate between balanced and short. Atlantic Basin and Pacific Basin LNG markets will compete for available global LNG supplies.
Particular European countries face some gas surpluses but will resolve them in the next few years. Europe’s demand for LNG could become particularly severe if Russia cannot meet its long-term gas supply obligations with the 25 European Union member countries in 2006 plus Switzerland (hereafter, EU25+). To overcome Russian problems, European gas markets would resort to their positions as dominant LNG buyers within the Atlantic Basin, potentially becoming the LNG price setters on a worldwide basis.
The US gas market in contrast to those of Europe likely will use LNG as a marginal gas supply with the main demand for LNG occurring during peak winter heating and summer air conditioning seasons. Such a US LNG demand pattern will in turn lead to large seasonal variations in Atlantic Basin, and probably worldwide, LNG pricing.
These are some of the major conclusions of analyses of US and European natural gas markets and of the likely future LNG supply balance on each side of the Atlantic Basin and between Atlantic Basin and Pacific Basin markets.
Sources; assumptions
Natural gas supply and demand estimates for these analyses for the US derive from the Energy Information Administration. Forecasts for European gas demand are based on the European Commission DG TREN’s “Scenarios on High Oil and Gas Prices” (2006) while a proprietary database as described herein has been used for EU25+ gas supply data. For the Pacific Basin markets, we have relied on a demand forecast by Paris-based Cedigaz.1 To measure supply we have identified existing and planned additions to liquefaction capacity.
We have included liquefaction capacity at only 90% of its nameplate capacity. If past experience is a guide, however, actual capacity may be as low as 85% of total industry nameplate capacity as operational problems arise with both liquefaction plants and feed-gas supplies. Indonesia, Algeria, Nigeria, Trinidad & Tobago, Egypt, Oman, Malaysia, Qatar, and Australia have all experienced recent operational problems or feed-gas problems.
Some excess liquefaction capacity is necessary to cushion the market against these types of problems, which will likely recur. Although total supply exceeds demand on Fig. 1, the margin is modest and consistent with a balanced market, given the likelihood of technical problems at any point of time. The possibility also exists of delays to the completion of liquefaction trains under construction or being planned beyond the completion dates assumed in our analysis.
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If Fig. 1 had been based on 85% instead of 90% liquefaction-plant nameplate availability, the total worldwide LNG supply in 2007 will be reduced by some 10 million tonnes. This reduction would increase to some 20 million tonnes of LNG product in 2015. These downward LNG supply corrections would be consistent with the current very tight average annual LNG supply situation.
Two winters
Winter 2005-06 displayed unusual characteristics in all major Atlantic Basin gas markets. Average monthly gas prices at Henry Hub (La.) exceeded $13/MMbtu in October 2005 as a result of hurricanes Katrina and Rita. Gas prices spiked again during a cold spell in December 2005, but unseasonably mild temperatures followed.
Gas demand fell, prices softened, and large volumes were delivered to storage. Abundant storage stocks depressed US gas prices in 2006 until the air-conditioning season in July and August. LNG imports in 2006 have been estimated at 12.1 million tonnes (16.3 billion cu m) of pipeline-quality gas.2 Imports were sharply down relative to the 17.8 bcm of pipeline quality gas imported in as LNG 2005.
In contrast to North America, Europe experienced exceptionally cold weather in 2005-06 with record gas demand and high prices both in the liberalized UK gas market as well as in continental Europe. High crude oil prices contributed to high gas prices in the continent due to indexation of long-term gas contracts to oil products.
In January 2006, a gas contract dispute prompted Russia’s GazProm to interrupt gas deliveries to Ukraine, a country that moves some 20% of Europe’s gas supplies. This interruption was compounded by exceptional cold in Russia and Central Europe. Austria, Germany, France, Italy, the Czech Republic, the Slovak Republic, and Hungary, all witnessed partial curtailments of their Russian 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 economies of these three countries depend more than normal on LNG supplies. During winter 2005-06, the average price for LNG delivered ex-ship to Mediterranean LNG receiving terminals ranged $8/MMbtu-$10/MMbtu.3 Spain in reality set the LNG price for Europe, although higher prices were achieved by the few LNG cargoes delivered to the new LNG terminal at the UK’s Isle of Grain that winter.
Winter 2006-07 was relatively similar on both sides of the Atlantic Basin. Both markets saw above seasonally normal temperatures with depressed gas demand, falling gas prices, and more than adequate gas in storage.
Wholesale gas prices at Chicago and Boston city gates fluctuated $6-8/MMbtu during November and December 2006, reflecting abundant gas in storage. In early January 2007, gas storage in the US Northeast was filled 85-95% of capacity. Chicago and Boston gas price levels mentioned previously are low relative to normal winter prices in these wholesale gas markets, making incremental Canadian gas exports uneconomic. US winter gas demand season was saved by relatively cold weather in March 2007.
The low prices available for Canadian gas exports resulted in a dramatic reduction in drilling rigs operated in Alberta and BC. Reduction in Canadian gas drilling during 2006 could result in short-term gas supply problems in the US in second-half 2007. The low level of energy imports to the US in 2006 will continue into 2007 with the exception of LNG as outlined below.
Gas demand in Northwest Europe during winter 2006-07 was until mid January 2007 well below seasonal normal levels for two reasons.
1. Winter temperatures were well above normal. Gas prices in the liberalized UK market softened considerably since the previous winter.
2. Gas futures market for winter 2006-07 peaked in April 2006 and had fallen by some 50% by mid January 2007.
This sharp reduction in UK gas prices appeared to have boosted demand particularly from the power-generation market and energy-intensive industries, many of which were closed down during winter 2005-06 by high gas prices. In January 2007 the UK domestic gas market had yet to benefit from reduced gas prices due to pricing policies of retail gas suppliers.
As in the previous winter, drought conditions in Spain, Portugal, and part of France had again prompted high gas consumption in affected areas. Prices of LNG delivered to Spanish terminals were very high, compared with other Atlantic Basin destinations. The value of LNG delivered ex-ship to Spain during the first week of January 2007 was about $10/MMbtu, while this value in the UK was less than $6/MMbtu. LNG delivered to East Coast terminals also had a value of some $6/MMbtu in early January 2007.
Russia is supplying some 25% of European gas demand. During winter, about a third of this supply (8% of European demand) currently transits Belarus. A gas-supply contract dispute between Russia’s GazProm and Belarus threatened to disrupt this gas supply but was resolved in the 11th hour. If this dispute had not been resolved, gas deliveries to Poland, Germany, and the Czech Republic would again have been hit hard.
By spring 2007 the very mild European winter had led to gas oversupply in all markets within EU25+. The value of incremental LNG supplies was nearly half of what could be obtained at US East Coast LNG receiving terminals. The US acted as a supply sink for surplus Atlantic Basin LNG cargoes, and US LNG imports have increased during second and third-quarter 2007 in sharp contrast to a year earlier.
The situation in the liberalized UK gas market has been most unusual during late winter and early spring 2007. That market has acted as a sink for higher priced surplus continental European gas quantities. This has been the case, although gas prices at the National Balancing Point (NBP; the main gas trading hub in Europe, a virtual point within the UK gas transmission system) have been less than half of gas prices in continental Europe that have price indexation based on oil product prices.
What lessons could Atlantic Basin gas market operators learn from winters 2005-06 and 2006-07?
In the US, gas supply appeared better than anticipated only a few years ago. LNG had become a marginal gas supply source, to a large extent drawn upon during weather-induced high electricity and gas demand.
European gas markets experienced tight gas supply conditions with some fuel switching from natural gas during winter 2005-06. Energy markets, however, were generally supplied with gas. Although imperfect, the liberalized UK gas market was functioning during winter 2005-06. The importance of providing a much higher level of storage capacity in the UK and Irish gas markets could not be ignored.
Winter 2005-06 raised more questions about continental European gas markets. High and rising gas prices depressed gas demand in Europe except for the Mediterranean countries. Russia’s domestic gas demand and its behavior towards its gas transit countries gave rise to serious concerns about its reliability as Europe’s main gas supplier.
US scene
High gas prices are having considerably different effects on demand for LNG in North America and Europe. The differences lie in a combination of demand and supply factors.
In the US, high prices have led to a significant revision of demand forecasts, with serious implications for future LNG imports. The effects in Europe are far more attenuated.
High US prices have prompted higher investment in domestic gas resources. High prices also make coal more attractive to fuel thermal power stations.
These two factors distinguish North American gas markets significantly from Europe: The European gas market cannot respond to high gas prices by accelerating development of indigenous resources. The gas markets of EU25+ can only increase their gas supplies through increased gas imports. Furthermore, Europeans pay roughly twice as much for coal as in the US.
Gas demand
The US Energy Information Administration’s base case for future US gas demand shows gas demand increasing at 1.7%/year through 2015, to 717 bcm from 615 bcm.4
Two years ago, we discussed the successive postponement of gas demand forecasts by the EIA.5 We noted that US gas demand had stagnated since the onset of high gas prices. Predicting such large increases in demand was unreasonable. Fig. 2 is based on that earlier presentation, showing successive forecasts for 2001-05 and adding the last 2 years’ forecasts.
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The new 2007 base case confirms those previous concerns, contrasting sharply with the 2000 EIA forecast. As suspected, demand has continued to stagnate.
In early 2001, the forecast was for growth of 105 bcm by 2006. None of that growth has materialized. Actual consumption in 2006 was even less than in 2000.6 Growth has been zero. The most recent forecast shows that the previous target for 2006 has now been pushed out to 2018.
Forecasts for 2015 have been slashed by even more (Fig. 3). The 2001 forecasts anticipated 895 bcm by 2015, while the new forecast is for only 717 cm. The drop of 178 bcm approximates the current total consumption of the UK and Italy combined, which are two of the largest national markets in Europe.
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The US power sector is responsible for much of the change in forecast demand. In 2001, increased demand from the power sector was forecast to drive roughly three quarters of 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 US power sector will consume 209 bcm of gas, virtually unchanged from the 208 bcm consumed last year.
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It is difficult to foresee any long-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 applies only to a few geographic areas in the US that must import coal from overseas due to the lack of available local resources. Many US power companies are in areas with abundant coal reserves, where local market prices are significantly below international levels.
Supply
US natural gas reserves have declined consistently for several years. Drilling activity, however, has demonstrated significant sensitivity to gas prices in both the US and Canada, the latter being a substantial exporter of gas to the US. High gas prices have prompted significant increases in the number of active rigs in the US, to 1,351 in 2007 from 720 in 2000. There is an extremely tight correlation between prices and drilling activity in the US.7
Investment in indigenous resources and gas-on-coal competition will together constrain the scope for LNG imports to the US. Imports should still grow relative to current levels, but more slowly than previously thought. Fig. 5 shows a projected supply and demand balance for the US, with LNG imports filling the gap between demand and supplies available to serve domestic sources.
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We calculate the available domestic sources to serve the US by including domestic production, Canadian gas pipeline imports, and by deducting anticipated US exports to Mexico. The two large pipeline projects from Canada and Alaska first appear (in orange) in 2011 as part of Alaskan supply with anticipated start up of the McKenzie Valley pipeline and then expanding significantly 2019-20 when the planned gas pipeline from Alaska to the Lower 48 reaches capacity.
European market Demand
This analysis uses gas demand forecasts prepared by the European Commission’s DG TREN, which reflects a comprehensive European effort with consistent projections for each of the EU25+.8 9 This analysis indicates European demand will be less than forecast.
Strong grounds exist for reducing the forecast by 10 bcm by 2015, which approximates 10% of the forecast growth. The principal conclusion, however, is that high prices in Europe will not lead to a stagnation of gas demand anywhere near the scale that has occurred in the US.
Recent trends suggest a drop in the percentage of total GDP consumed by Europe’s industrial sector. The services sector has increased in importance. This trend has a moderating effect on natural gas demand because the service sector uses natural gas less intensively than industry.
The current era of high energy prices should only accelerate Europe’s shift from the industrial sector to the service sector. The European Commission, however, forecasts assume an unexplained sharp stagnation of this trend. Fig. 6 shows the historical decline of the EU service sector and the forecast assumed by the commission when developing gas-demand projections.
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The commission produces its forecasts once every few years, the latest in 2006. The realism of the forecast can be checked in part by comparing with actual data. The European Central Bank publishes data concerning the size of 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 for 2030.
A more reasonable scenario would entail two adjustments to the commission’s forecast: departing from the actual data witnessed for 2006, and projecting a continuation of the historical shift from the industrial to the services sector.
Together these adjustments suggest the commission has overstated the consumption of gas by the industrial sector, and slightly underestimated the consumption of gas by the services sector. The net effect, however, is an overstatement of the total demand forecast. Our proposed adjustments would reduce demand by about 7 bcm in 2015.
In the commission’s forecasts for gas consumption by the power sector, the main weakness is the assumed retirement of nuclear power stations in Sweden and Germany. This is forecast to prompt construction of more gas-fired power stations as a substitute.
High energy prices exert strong commercial pressures to extend the lives of the nuclear power stations. We assume a continuation of these power stations through 2015. This amendment reduces forecast gas demand by another 3 bcm in 2015.
These proposed adjustments combine to reduce the forecast for Europe by 10 bcm. The total extent of the revision could be higher, but no grounds appear that question a principal aspect of the forecast: increased demand for natural gas by the European power sector.
Based on the Brattle Group’s work concerning the economics of nuclear, coal, and gas-fired power stations referred to earlier,10 nuclear power is now economic in the era of high gas prices. Europe may therefore witness a shift to nuclear power.
The first step would be to extend the lives of existing nuclear power stations, a step now included in our demand forecasts. The next step will be the eventual construction of new nuclear power stations. The political debate on nuclear power, however, has not yet settled.
The timing of new nuclear power stations will depend on the resolution of regulatory uncertainty and on the naturally long lead times for constructing new nuclear power stations. It is difficult to believe that the European market will complete substantial new nuclear capacity before 2015.
We have also considered whether high gas prices might lead to a resurgence of coal-fired power stations in Europe. While coal is more economic than gas in the US, coal has no clear advantage in Europe. Most of Europe pays more than $60/ton for coal, a price that combines with the prospective cost of carbon permits to give the power sector a relatively high tolerance for natural gas prices.
The era of high gas prices has renewed interest in coal, and coal could become clearly more attractive depending on technological breakthroughs in carbon sequestration. Barring a technological breakthrough, however, no major shift to coal in Europe before 2015 is imminent.
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Fig. 7 shows our forecast of demand and supply being based on the annual percentage demand growth developed by the commission’s DG TREN, which we have applied to historical gas consumption data11 with the adjustments as previously described. The forecast entails a growth of 96 bcm in natural gas consumption by 2015.
Supply
Estimated supplies in Fig. 7 come from our proprietary database that looks at existing import contracts, infrastructure developments, and data on likely domestic European production as well as the major producing countries from which Europe imports pipeline gas. Domestic production volumes (defined domestic as EU25 plus Switzerland), again reflect projections in the European Commission DG TREN8 and from the ministries or state oil and gas companies of particular gas-producing member states.
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 Petroleum Directorate,12 modified to match available gas transportation infrastructure. LNG supplies from Egypt, Oman, Qatar, and Yemen were derived from a mixture of contracted quantities and LNG infrastructure investments tied to the particular producer in European countries.
Observations in the European gas market led to modification of LNG supplies to reflect actual deliveries as outlined presently. We project gas trade among EU25+ countries, based on information about individual gas sale and purchase agreements as well as swap arrangements.
Both annual contract quantities (ACQs) and delivery flexibility expressed as take-or-pay (ToP) levels were considered. For LNG supplies, we have set the ACQ for LNG receiving terminals at 90% of the design capacity. Similarly we have set the ACQ under long-term LNG supply agreements at 90% of the ACQ. As the norm we have applied 75% of this “adjusted ACQ” as the regular annual delivery under each contract. When the buyer and the seller of the LNG are the same, we include only 50% of the adjusted ACQ to reflect the merchant nature of such projects.
The difference between ACQ and ToP levels indicates the supply flexibility for each country as well as EU25+ as a whole. Consistent with current practice in the European gas market, we assign long-distance gas pipeline supplies a high ToP level, 85% ACQ to reflect the base-load nature of these contracts.
For long-term LNG contracts as well as LNG merchant or trading arrangements, we set ToP levels uniformly at 50% of the adjusted ACQ, reflecting the ability of suppliers as well as buyers to divert LNG cargoes to markets outside Europe.
Fig. 7 shows the gas supply and demand balance for EU25+ expressed as ACQ as well as ToP. Our analysis suggests that EU25+ is likely to have a balanced position between projected demand and supply until 2013, since the demand curve intersects supply between the ACQ and the ToP levels.
Some 25% of the gas demand within EU 25+ is supplied under Russian gas export contracts, most of which are of long-term. The reliability of these contracts has come into question after continental European countries’ experiences with their Russian gas supplies during winter 2005-06.
A closer analysis of Russian gas production and transportation facilities and arrangements poses serious concerns for the short and medium-term security of supply of Russian energy including natural gas. These concerns are independent of the Ukrainian gas supply episode in January 2006 and of the Belarusian oil transits situation, which reflected a gas supply dispute between Russia and Belarus, during January 2007.
Looking further ahead, Russia’s gas consumption will continue to grow rapidly unless its domestic gas prices adjust to reflect international levels. Such price adjustments are needed for two reasons:
- To stem domestic demand.
- To provide GazProm with necessary funds to step-up dramatically its investments in gas exploration and production in Russia and maintain and upgrade the vast gas transmission system.
Although the country has the largest gas reserves in the world and possesses a huge gas production potential, it currently extracts 50% of its gas production from fields already in advanced stages of decline.13
Russia had hoped to import large quantities of gas at low prices from central Asian republics, Turkmenistan and Kazakhstan in particular, at least in part to compensate for Russia’s difficulties shoring up declining gas production. Turkmenistan, however, possesses the largest gas reserves among the central Asian republics and has started gas-sales negotiations with China.
Russia could face a gas supply gap of up to 126 bcm/year by 2010 even under the most optimistic import scenario for gas deliveries from central Asia with the supply of 105 bcm/year.14 Increasing internal gas prices, however, to reflect international levels better could curtail Russian domestic gas demand significantly, reducing the predicted supply gap to manageable levels.
Close observers of the Russian gas industry agree that GazProm must allow independent oil and gas producers in Russia access to its pipeline system and must pay a reasonable price for such gas supplies.13 14 This is likely the only way to remove the predicted gas supply gap in 2010. Currently some 60-80 bcm of gas is flared in Russia due largely to the lack of access to GazProm’s pipeline system. GazProm must provide clear price signals to independent oil and gas producers without delay, however, to motivate necessary gas developments and infrastructure investments.
Except for Spain and Portugal, LNG still represents a small fraction of Europe’s total gas supplies. LNG should in the future, however, become of greater interest to the Europeans because of the diversification it offers. With diversification comes safety. The EU’s recent inquiry into competition in the natural gas industry points to LNG as a hope for both enhanced security and increased competition.15
LNG in Atlantic Basin
Multiple price drivers are developing in Atlantic Basin gas markets as the growth in LNG promotes interconnection. The strongest drivers over the past 2 years have been the unusual circumstances in Spain: Drought reduced generation of hydroelectric power, requiring significantly higher outputs from gas-fired power stations and raising natural gas demand. Spain’s 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 2005-06.
In the future, weather conditions and the Russian situation will determine whether Europe or North America will drive winter LNG prices. Europe will be more important for LNG exporters in terms of its annual demand. The air-conditioning peak in the US summer markets, however, will exert a strong influence. The capacity of US regasification terminals will likely exceed the demand for LNG.
We have compared EIA’s forecast of LNG imports to the maximum realistic capacities for the existing regasification terminals and those likely to be built. We again set the ACQ as 10% of nameplate capacity for the regas terminals and the sustainable annual capacity as 67% of the nameplate capacity corresponding to 75% of the ACQ.
Our analysis reveals a prospective utilization of US re-gas terminals in the range 25-30% of total nameplate capacity, corresponding to 38-44% of the 75% ACQ sustainable capacity, through to 2015. The resulting excess capacity and prospective low utilization of regas terminals is consistent with our view of the US exerting a strong seasonal influence on the Atlantic Basin.
We have performed the same LNG analysis for Europe, comparing the sustainable capacity of European regas terminals with our own LNG demand forecasts based on the proprietary database described earlier. We have verified this forecast against Cedigaz’ forecast of demand for LNG.16
In Europe, terminal utilization will be closer to baseload operations, particularly if Russia should have difficulty meeting contractual obligations. Our analysis suggests utilization rates ranging 78-93% of the total sustainable annual regas capacity over the forecast period.
The Pacific Basin is another strong and growing influence on the Atlantic Basin.17 To date, available Atlantic Basin liquefaction capacity has been roughly equal to baseload demand for Atlantic Basin regas capacity. It was technically feasible for Atlantic Basin consumers to rely exclusively on Atlantic Basin producers, although there has been active trade with LNG producers in the Arabian Gulf and LNG cargoes from the Pacific Basin have been delivered to Atlantic Basin markets.
Atlantic Basin demand growth will soon increase its reliance on Arabian Gulf supplies. As Fig. 1 shows, demand in both Atlantic and Pacific basins will exceed liquefaction capacity in either area. Each basin will therefore seek Middle East supplies to balance respective markets. Although it has been assumed that no Iranian LNG project will come on stream before 2015 and that Qatari LNG capacity in this period will not exceed the 77.2 million tonnes/year currently operational or under construction, LNG capacity could in fact nearly double by 2015 to accommodate forecast demand.
Acknowledgment
Marie-Francoise Chabrelie, secretary general of Cedigaz, Paris, has provided invaluable help in our development of future LNG supply and demand scenarios. LNG
References
1. World LNG Outlook-2006 Edition (preliminary LNG supply and demand data), Paris: Cedigaz, Jan. 15, 2007.
2. Gaul, D., and Platt, K., Short-Term Outlook Supplement: US LNG Imports - The Next Wave, Energy Information Administration, US Department of Energy, January 2007.
3. Alvarez, A., Repsol YFP, presentation to 7th Annual World LNG Summit, Rome, Oct. 13, 2006.
4. Annual Energy Outlook 2007/ Reference Case, Energy Information Administration, US Department of Energy, Dec. 15, 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, presented to GasTech 2005, Bilbao, Mar. 16, 2005.
6. The EIA has estimated that US gas consumption in 2006 was 615 bcm. In 2000 it was 660 bcm.
7. EIA, “Table 5.1: Crude Oil and Natural Gas Drilling Activity Measurements.” The 1,351 is the average for the 12 months extending from December 2005 through November 2006, the last month for which the EIA had information available.
8. European Energy and Transport: Scenarios on High Oil and Gas Prices, Belgium: European Communities, 2006; http://www.trb.org.
9. When analyzing the European gas market and discussing its future development, we define Europe as the 25 countries that were members of the European Union in 2006 (EU 25). We also include Switzerland in this definition of Europe because this country is fully integrated in the gas market of the EU25 countries. Norway, not a full member of the EU, we treat as a gas supplier to the EU25+ countries. Our analyses do not yet include Bulgaria and Romania in the definition of Europe because they just became EU members on Jan. 1, 2007. As neither country is an LNG supplier or importer, its inclusion would not have made any significant changes to our gas market analyses.
10. Lapuerta, C., “Analysing financial risk and the relative economics of natural gas, coal-fired and nuclear power stations,” presented to the IAEE Conference, Wellington, NZ, Feb. 18-21, 2007.
11. Cedigaz, Trends & Figures in 2005, from Natural Gas in the World (October 2006); for all countries except the Netherlands, UK, Spain, Denmark, and Ireland. Netherlands data come from the Central Bureau for Statistics (Statistics Netherlands, Voorburg/Heerlen; Jan. 2, 2006). For the UK, we relied on National Grid, 10-Year Statement 2005, December 2005. For Spain, Denmark, and Ireland we used BP, Statistical Review of World Energy (June 2006).
12. The Shelf in 2006, the Norwegian Petroleum Directorate, Stavanger, Jan. 5, 2007.
13. Chabrelie, Marie-Francoise, “Medium-term prospects for the gas industry (preliminary),” Cedigaz, Jan. 15, 2007.
14. Riley, A., The Coming of the Russian Gas Deficit: Consequences and Solutions, Centre for European Policy Studies (CEPS), CEPS Policy brief No. 116 (October 2006).
15. Communication from the commission, Inquiry pursuant to Article 17 of Regulation (EC) No 1/2003 into the European gas and electricity sectors (Final Report)(10 January 2007).
16. World LNG Outlook-2006 Edition (preliminary LNG supply and demand data), Paris: Cedigaz, Jan. 15, 2007.
17. Frisch, M., and Lapuerta, C., “The Value of Middle East LNG in the Atlantic Basin After the 2005/6 Winter Price Shock,” GasTech 2006, Abu Dhabi, Dec. 4, 2006.
Based on a presentation to the 15th Conference and Exhibition on Liquefied Natural Gas-LNG15, Barcelona, Apr. 24-27, 2007
The authors
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Morten Frisch is senior partner, Morten Frisch Consulting. His more than 35 years’ experience includes working for the Norwegian government, multinational oil companies, and as an independent consultant since 1990 providing strategic, commercial and operational natural gas advice to clients world wide. Frisch was instrumental in the original structuring and drafting of key contract clauses such as the price review and price re-opener clause now extensively used in Atlantic Basin LNG sales and purchase agreements. He has acted as an expert witness in major arbitrations and court cases concerning commercial and operational gas issues in general and price issues in particular. Frisch is a chartered engineer in Norway and an economist. He holds degrees from the University of Newcastle upon Tyne, UK, and Massachusetts Institute of Technology. He is a member of the Society of Petroleum Engineers (SPE), the International Association of Energy Economics (IAEE), and the British Institute of Energy Economics (BIEE).
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Carlos Lapuerta directs from London the European practice of the Brattle Group, an international consultancy specializing in economic and financial analysis of the energy industry. His practice focuses on the valuation of natural gas businesses, analysis of competition in natural gas markets, and on appropriate design of regulations, tariff structures and third party facilities use arrangements for the liberalization of the gas industry including LNG terminals. His experience also spans the design and optimization of tolling arrangements for LNG chain facilities. Lapuerta has presented expert witness testimony in major commercial arbitrations concerning economic and financial issues in the electricity and gas industries. He holds degrees in law and economics from Harvard University.