Flexible friends
Forced with dramatically increasing numbers of potential LNG
suppliers, LNG buyers are increasingly reluctant to sign long-term
take-or-pay contracts with prices indexed to oil. LNG buyers today
seek shorter term flexible contracts based on natural gas prices in
the final market. This will have a direct impact on the financing
of new LNG projects due to changes in the risk profiles of projects
that follow the new LNG trend. Below is an analysis of the
traditional and the new LNG trades, including their different risk
profiles, and the financing impacts of each structure. Structural
differences in two important gas markets, the US and European, are
evaluated in their different risk profiles as LNG destinations.
Traditional vs. New LNG Trade
Traditional LNG trade is based on long-term take-or-pay Gas Sales and Purchases Arrangements (GSPA) with standard commitment terms of over 20 years1 and with pricing formulas fixed for the entire life of the contract. Whereas GSPAs give buyers comfort with regards to supply reliability and pricing, such contracts include very low or no volume flexibility2. Some long-term contracts have even included minimum price provisions to lock in secure minimum revenues. Offtakers in traditional LNG contracts have been high investment grade credit-worthy entities, giving lenders more certainty about the quality of the credit.
The 1998 Asian financial crisis had a dramatic impact on the LNG industry. Asia's largest LNG buyers, which include South Korea, Japan, and Taiwan, are traditionally signatories to GSPAs with fixed prices and shipping terms. Due to the drop in energy consumption during the Asian crisis period, Korea curtailed some of its committed take-or-pay gas deliveries in contravention of its contractual terms. Although Korea resumed its LNG shipments after its economy recovered, this example demonstrates the inflexibility, limitations, as well as the exposure to buyer's country and political risks, when using traditional GSPAs.
Today new GSPAs have emerged in the LNG industry and have gained popularity due to their emphasis on flexibility. Such GSPAs may have terms ranging from 10 to 15 years with pricing provisions valid for generally 3 to 5 years, or, they may take other forms similar to those described below in Exhibit 1. The shorter term GSPAs have greater flexibility in terms of take-or-pay with the amounts purchased being less than 100% of a plant's output capacity. Changes in the LNG industry, and in the terms and conditions of GSPAs, combined with surplus production from production plants, have given new opportunities to LNG traders in marketing LNG in the ?spot? or ?short term? market.
The primary driving force behind changes in the LNG industry is the need for buyers to adapt to the new and more deregulated energy sector. Deregulation has helped to promote increased gas demand, as well as investment for strategic value-chain infrastructure such as trading hubs, pipelines and ships. LNG buyers however, now face increased competition from other buyers and other fuels, in addition to greater market risk. As such, LNG buyers have sought to share these risks with LNG sellers by shortening sales contract terms, reducing take-or-pay commitments, and by including frequent price adjustment provisions into contracts. Exhibit 2 summarizes the major differences between the traditional and new LNG trade.
Currently, spot shipments make up nearly 8% of world LNG trade, led by the US as the largest single spot-importer, followed by Spain. Committed spot cargos, where buyers agree to take a certain number of cargos over a year or longer, have also increased. New LNG projects with excess capacity such as Ras Gas, Oman LNG, and Atlantic LNG, can now take advantage of spot market opportunities that have developed in the US, Europe and Asia. Even a traditional buyer, Korea, has purchased spot cargos during the winter months to meet peak season heating demand.
For a truly functioning and efficient spot market to develop, however, several issues will need to be further addressed. The current bottleneck in receiving terminal capacity in key markets for example, must be resolved. New terminals will need to develop sufficient added capacity to receive and process other LNG shipments besides those scheduled under contract. The current shortage in available shipping capacity is also problematic. The growth of LNG shipping not tied to specific projects will need to be accelerated in order to accommodate growing sales from increasingly diverse sources. It is anticipated that most of these critical issues will continue to be resolved through the incentives of deregulation.
In spite of the new changes, the LNG industry is still predominantly reliant upon long-term take-or-pay contracts for financing multi-billion dollar projects. Nevertheless, it has become increasingly difficult for LNG sellers to sign traditional LNG sales contracts, and this has impacted the financing market's perception of risk profile for new projects.
Risk Profiles of Traditional vs. New LNG Trade
Traditional LNG trade insulates producers from volume risk through long-term take-or-pay contracts. Price risk is mitigated through oil price indexation which provides the so-called ?S curve? that protects buyers from extremely high prices and producers from very low ones, or through price floors that further protect producers from downside risk. Offtaker credit risk is very important in the traditional LNG trade and is mitigated through thorough credit analysis or with the use of financing instruments. Normally, serious commitments for funding are not made unless an LNG buyer is found to have mitigated market risk via a signed long-term take-or-pay contract.
In the new LNG trade, volume risk is theoretically limited if sellers can gain access, through an available receiving terminal, to the vast US gas grid, so long as a netback from Henry Hub natural gas pricing is adequate to them.3 Price risk, on the other hand, is considered the biggest risk to prospective LNG project lenders and investors. Under the new structure, LNG trade is increasingly functioning like a commodity trade or oil trade with pricing fluctuations, although it may take years before there is significant liquidity in the LNG market to fully support a true spot market commodity trade.
Under both the traditional and new LNG trade, reserve risk is borne by the gas supplier alone. Prospective LNG project lenders would not be willing to take this risk. Exhibit 3 shows a comparison of the credit risk of traditional single buyer LNG trade versus the entire gas grid risk.
Price and market risk are considered the most critical to an LNG project in the financing community. The financing prospects for new LNG projects will therefore be based on a thorough analysis of the price and market risk components of the specific destination options for the supplier. The structure, depth, breadth, and maturity of the gas market will be critical components in the credit analysis by prospective lenders.
The US and European Gas Markets and Their Implications for LNG Trade
The structure of the US and the European gas markets have historically differed. Europe's gas markets have primarily been import-reliant4 and dominated by long-term, fixed-price take-or-pay GSPAs with indexed prices. In contrast, the US gas market is mainly supplied by domestic gas production with pricing determined by domestic production costs and energy demand.5 These structural differences have yielded different results, with European gas prices not experiencing the extreme price swings that US gas prices have been prone to in recent years. A single European gas market with third-party access and deregulated prices has been proposed, and this could result in a market that is likely to follow the US example. Europe's future gas market dynamics are still uncertain.
The US Gas Market
Natural gas pricing in the US is fully deregulated and subject to supply/demand pressures. The primary pricing point in the US is Henry Hub. All major cities and natural gas delivery points in the US have gas pricing that closely correlates to the Henry Hub price6 reflecting location, transportation and other differences. Over time, set differentials have been established between important pipelines, major cities or key markets.7 The advantage of a single pricing point for most natural gas in the US is that it fosters price transparency and liquidity that in turn enables market makers to create financial products to manage price volatility, commodity price risk and other related risks.
Total US natural gas consumption is projected to increase from 22 trillion cubic feet (tcf) in 1999 to 34 tcf in 2020. Approximately 85% of US gas consumption is supplied by North American production, and domestic production is projected to remain the primary source of US natural gas supply into the future. Over the past several years, the US experienced a widening gap between production and consumption, and in 2000 the nation consumed 18% more than it produced. As US demand for natural gas continues to increase as projected, so will the need for additional imports. Pipeline imports from Canada and Mexico, and LNG imports from several sources, including Algeria, the UAE, Australia, Qatar, Trinidad and Tobago, Malaysia, Nigeria, Oman, and Indonesia will continue to be accessed to fulfill the supply gap.
The European Gas Market
The European gas market is still highly regulated. Gas trading and the spot market8 began in 2000, keeping most transactions in the realm of long-term, fixed price GSPAs with costs being passed through to customers. European gas prices have been indexed to either gasoil, crude oil or a blend of both of these indices maintaining lower and less volatile gas prices compared to US gas prices. Currently, spot prices in Europe continue to be strongly influenced by the pricing of long-term, take-or-pay GSPAs.
Even though it has substantial natural gas, Europe is still a net gas importer. Production, primarily from fields situated in the North Sea, the Netherlands and Norway, is slowly decreasing while at the same time consumption is increasing. European imports of LNG are therefore expected to increase by 2005, yet opinions differ regarding the magnitude of such an increase.
The European gas market is set to undergo significant structural changes as per EU directives that call for third-party access to the gas network, and for the strengthening of a liquid spot market.9 National oil and gas monopolies, and state owned gas utility oligopolies are still expected to dominate home markets in Europe, possibly limiting the success of the changes called for by the EU, as well as not permitting the system to reflect true costs incurred. The EU also lacks the extensive internal natural gas pipeline network of the US primarily because of the region's past priority in having transmission systems that ensured national supply security. The integration and upgrade of these networks to effectively transport gas throughout Europe is a costly proposal that will require investments of about US$5 billion for every 350 Bcf per year of additional supply to the EU.
The continued deregulation of the energy sector in Europe has significantly impacted LNG trading in the Atlantic Basin by creating greater arbitrage opportunities across the Atlantic Basin. It is expected that continued deregulation will bring further arbitrage opportunities between both regions by creating a super-regional open market.10 Such trading will be further impacted as regasification capacity in both markets expand and as demand for natural gas increases. Over the longer term, arbitrage opportunities could set floors and ceilings for future gas spot prices in both major markets. This means that the UK spot price could be driven not only by oil-indexed prices prevalent in Europe, but also by US Henry Hub spot gas prices.
Conclusion: Financing an LNG Project Facing the Entire Gas Grid Risk
In an environment faced with increased deregulation, shorter and more tailored energy offers are replacing traditional LNG supply models. Both investors and lenders will have to come to terms with the growing commodity type nature of the global LNG business, as well as cope with the price risk associated in dealing with the entire gas grid. As our analysis shows, the two most important and fast changing gas markets of the US and Europe, have distinctive features that yield different project finance impacts. Both investors and lenders must carefully analyze the differences in each market structure, as well as the fundamental project economics, for a complete assessment of the project's financeability. Our prediction is that new LNG projects should be able to obtain financing based on the netback prices from a final market such as Henry Hub pricing. n
Footnotes
1 Examples of such GSPAs include Atlantic LNG, 20 years; Ras Gas, 25 years; Oman LNG, 25 years; and Australian NW Shelf Train 5 expansion, 25 years.
2 Terms generally stipulate 100% take-or-pay commitments or a majority of a plant's capacity.
3 From a gas grid point of view, there is no volume risk for spot sales because the US has the most extensive gas transmission system and the most liquid gas market.
4 With the exception of the UK, Norway and the Netherlands.
5 Gas prices are expected to strengthen in the long-term but are likely to remain volatile with sellers facing the downside risk that gas market prices will be low over a prolonged period of time.
6 The daily spot price at Henry Hub from 1991 to date has averaged just less than $2.50 per MMBtu and has been above $2.00 per MMBtu more often than below.
7 The key markets include the 4 major US LNG regasification facilities at Lake Charles, LA, Elbe Island, GA, Cove Point, MD and Boston Harbor.
8 Currently there are only spot markets in the UK and Zeebruge (Belgium). Additional trading hubs are scheduled, including one at the German-Netherlands border.
9 In March 2002, EU member states agreed to a liberalization program: i) Liberalization of industrial gas supply by 2004, ii) Decision on public service obligations and supply to remote areas by 2003, iii) Separation of transmission and distribution, vi) Non-discriminatory access for consumers and producers to the network based on transparent and published tariffs, v) Establishment of a regulatory agency in each member state.
10 During the first 6 months of 2001, Spain's Gas Natural resold all of its contracted LNG from Trinidad to US buyers; Italy's ENEL delivered 5 cargos of Nigerian LNG, originally destined for Europe, to the US Lake Charles terminal. GdF sold 2 Algerian cargos to the US and purchased additional UK gas, which it received via the Interconnector Pipeline between the UK and Belgium. This resulted in an increase in UK gas price (to over $6 per MMBtu, from $4.50 per MMBtu), and provided evidence of an interaction between prices in Europe and the US. In the 4th quarter 2001, European gas prices were higher, and the trade direction switched. Deliveries from Trinidad to Spain resumed and at least 2 Nigerian cargos, originally purchased for the US market, were diverted to the Montoir and Zeebrugge terminals in Europe.
Traditional vs. New LNG Trade
Traditional LNG trade is based on long-term take-or-pay Gas Sales and Purchases Arrangements (GSPA) with standard commitment terms of over 20 years1 and with pricing formulas fixed for the entire life of the contract. Whereas GSPAs give buyers comfort with regards to supply reliability and pricing, such contracts include very low or no volume flexibility2. Some long-term contracts have even included minimum price provisions to lock in secure minimum revenues. Offtakers in traditional LNG contracts have been high investment grade credit-worthy entities, giving lenders more certainty about the quality of the credit.
The 1998 Asian financial crisis had a dramatic impact on the LNG industry. Asia's largest LNG buyers, which include South Korea, Japan, and Taiwan, are traditionally signatories to GSPAs with fixed prices and shipping terms. Due to the drop in energy consumption during the Asian crisis period, Korea curtailed some of its committed take-or-pay gas deliveries in contravention of its contractual terms. Although Korea resumed its LNG shipments after its economy recovered, this example demonstrates the inflexibility, limitations, as well as the exposure to buyer's country and political risks, when using traditional GSPAs.
Today new GSPAs have emerged in the LNG industry and have gained popularity due to their emphasis on flexibility. Such GSPAs may have terms ranging from 10 to 15 years with pricing provisions valid for generally 3 to 5 years, or, they may take other forms similar to those described below in Exhibit 1. The shorter term GSPAs have greater flexibility in terms of take-or-pay with the amounts purchased being less than 100% of a plant's output capacity. Changes in the LNG industry, and in the terms and conditions of GSPAs, combined with surplus production from production plants, have given new opportunities to LNG traders in marketing LNG in the ?spot? or ?short term? market.
The primary driving force behind changes in the LNG industry is the need for buyers to adapt to the new and more deregulated energy sector. Deregulation has helped to promote increased gas demand, as well as investment for strategic value-chain infrastructure such as trading hubs, pipelines and ships. LNG buyers however, now face increased competition from other buyers and other fuels, in addition to greater market risk. As such, LNG buyers have sought to share these risks with LNG sellers by shortening sales contract terms, reducing take-or-pay commitments, and by including frequent price adjustment provisions into contracts. Exhibit 2 summarizes the major differences between the traditional and new LNG trade.
Currently, spot shipments make up nearly 8% of world LNG trade, led by the US as the largest single spot-importer, followed by Spain. Committed spot cargos, where buyers agree to take a certain number of cargos over a year or longer, have also increased. New LNG projects with excess capacity such as Ras Gas, Oman LNG, and Atlantic LNG, can now take advantage of spot market opportunities that have developed in the US, Europe and Asia. Even a traditional buyer, Korea, has purchased spot cargos during the winter months to meet peak season heating demand.
For a truly functioning and efficient spot market to develop, however, several issues will need to be further addressed. The current bottleneck in receiving terminal capacity in key markets for example, must be resolved. New terminals will need to develop sufficient added capacity to receive and process other LNG shipments besides those scheduled under contract. The current shortage in available shipping capacity is also problematic. The growth of LNG shipping not tied to specific projects will need to be accelerated in order to accommodate growing sales from increasingly diverse sources. It is anticipated that most of these critical issues will continue to be resolved through the incentives of deregulation.
In spite of the new changes, the LNG industry is still predominantly reliant upon long-term take-or-pay contracts for financing multi-billion dollar projects. Nevertheless, it has become increasingly difficult for LNG sellers to sign traditional LNG sales contracts, and this has impacted the financing market's perception of risk profile for new projects.
Risk Profiles of Traditional vs. New LNG Trade
Traditional LNG trade insulates producers from volume risk through long-term take-or-pay contracts. Price risk is mitigated through oil price indexation which provides the so-called ?S curve? that protects buyers from extremely high prices and producers from very low ones, or through price floors that further protect producers from downside risk. Offtaker credit risk is very important in the traditional LNG trade and is mitigated through thorough credit analysis or with the use of financing instruments. Normally, serious commitments for funding are not made unless an LNG buyer is found to have mitigated market risk via a signed long-term take-or-pay contract.
In the new LNG trade, volume risk is theoretically limited if sellers can gain access, through an available receiving terminal, to the vast US gas grid, so long as a netback from Henry Hub natural gas pricing is adequate to them.3 Price risk, on the other hand, is considered the biggest risk to prospective LNG project lenders and investors. Under the new structure, LNG trade is increasingly functioning like a commodity trade or oil trade with pricing fluctuations, although it may take years before there is significant liquidity in the LNG market to fully support a true spot market commodity trade.
Under both the traditional and new LNG trade, reserve risk is borne by the gas supplier alone. Prospective LNG project lenders would not be willing to take this risk. Exhibit 3 shows a comparison of the credit risk of traditional single buyer LNG trade versus the entire gas grid risk.
Price and market risk are considered the most critical to an LNG project in the financing community. The financing prospects for new LNG projects will therefore be based on a thorough analysis of the price and market risk components of the specific destination options for the supplier. The structure, depth, breadth, and maturity of the gas market will be critical components in the credit analysis by prospective lenders.
The US and European Gas Markets and Their Implications for LNG Trade
The structure of the US and the European gas markets have historically differed. Europe's gas markets have primarily been import-reliant4 and dominated by long-term, fixed-price take-or-pay GSPAs with indexed prices. In contrast, the US gas market is mainly supplied by domestic gas production with pricing determined by domestic production costs and energy demand.5 These structural differences have yielded different results, with European gas prices not experiencing the extreme price swings that US gas prices have been prone to in recent years. A single European gas market with third-party access and deregulated prices has been proposed, and this could result in a market that is likely to follow the US example. Europe's future gas market dynamics are still uncertain.
The US Gas Market
Natural gas pricing in the US is fully deregulated and subject to supply/demand pressures. The primary pricing point in the US is Henry Hub. All major cities and natural gas delivery points in the US have gas pricing that closely correlates to the Henry Hub price6 reflecting location, transportation and other differences. Over time, set differentials have been established between important pipelines, major cities or key markets.7 The advantage of a single pricing point for most natural gas in the US is that it fosters price transparency and liquidity that in turn enables market makers to create financial products to manage price volatility, commodity price risk and other related risks.
Total US natural gas consumption is projected to increase from 22 trillion cubic feet (tcf) in 1999 to 34 tcf in 2020. Approximately 85% of US gas consumption is supplied by North American production, and domestic production is projected to remain the primary source of US natural gas supply into the future. Over the past several years, the US experienced a widening gap between production and consumption, and in 2000 the nation consumed 18% more than it produced. As US demand for natural gas continues to increase as projected, so will the need for additional imports. Pipeline imports from Canada and Mexico, and LNG imports from several sources, including Algeria, the UAE, Australia, Qatar, Trinidad and Tobago, Malaysia, Nigeria, Oman, and Indonesia will continue to be accessed to fulfill the supply gap.
The European Gas Market
The European gas market is still highly regulated. Gas trading and the spot market8 began in 2000, keeping most transactions in the realm of long-term, fixed price GSPAs with costs being passed through to customers. European gas prices have been indexed to either gasoil, crude oil or a blend of both of these indices maintaining lower and less volatile gas prices compared to US gas prices. Currently, spot prices in Europe continue to be strongly influenced by the pricing of long-term, take-or-pay GSPAs.
Even though it has substantial natural gas, Europe is still a net gas importer. Production, primarily from fields situated in the North Sea, the Netherlands and Norway, is slowly decreasing while at the same time consumption is increasing. European imports of LNG are therefore expected to increase by 2005, yet opinions differ regarding the magnitude of such an increase.
The European gas market is set to undergo significant structural changes as per EU directives that call for third-party access to the gas network, and for the strengthening of a liquid spot market.9 National oil and gas monopolies, and state owned gas utility oligopolies are still expected to dominate home markets in Europe, possibly limiting the success of the changes called for by the EU, as well as not permitting the system to reflect true costs incurred. The EU also lacks the extensive internal natural gas pipeline network of the US primarily because of the region's past priority in having transmission systems that ensured national supply security. The integration and upgrade of these networks to effectively transport gas throughout Europe is a costly proposal that will require investments of about US$5 billion for every 350 Bcf per year of additional supply to the EU.
The continued deregulation of the energy sector in Europe has significantly impacted LNG trading in the Atlantic Basin by creating greater arbitrage opportunities across the Atlantic Basin. It is expected that continued deregulation will bring further arbitrage opportunities between both regions by creating a super-regional open market.10 Such trading will be further impacted as regasification capacity in both markets expand and as demand for natural gas increases. Over the longer term, arbitrage opportunities could set floors and ceilings for future gas spot prices in both major markets. This means that the UK spot price could be driven not only by oil-indexed prices prevalent in Europe, but also by US Henry Hub spot gas prices.
Conclusion: Financing an LNG Project Facing the Entire Gas Grid Risk
In an environment faced with increased deregulation, shorter and more tailored energy offers are replacing traditional LNG supply models. Both investors and lenders will have to come to terms with the growing commodity type nature of the global LNG business, as well as cope with the price risk associated in dealing with the entire gas grid. As our analysis shows, the two most important and fast changing gas markets of the US and Europe, have distinctive features that yield different project finance impacts. Both investors and lenders must carefully analyze the differences in each market structure, as well as the fundamental project economics, for a complete assessment of the project's financeability. Our prediction is that new LNG projects should be able to obtain financing based on the netback prices from a final market such as Henry Hub pricing. n
Footnotes
1 Examples of such GSPAs include Atlantic LNG, 20 years; Ras Gas, 25 years; Oman LNG, 25 years; and Australian NW Shelf Train 5 expansion, 25 years.
2 Terms generally stipulate 100% take-or-pay commitments or a majority of a plant's capacity.
3 From a gas grid point of view, there is no volume risk for spot sales because the US has the most extensive gas transmission system and the most liquid gas market.
4 With the exception of the UK, Norway and the Netherlands.
5 Gas prices are expected to strengthen in the long-term but are likely to remain volatile with sellers facing the downside risk that gas market prices will be low over a prolonged period of time.
6 The daily spot price at Henry Hub from 1991 to date has averaged just less than $2.50 per MMBtu and has been above $2.00 per MMBtu more often than below.
7 The key markets include the 4 major US LNG regasification facilities at Lake Charles, LA, Elbe Island, GA, Cove Point, MD and Boston Harbor.
8 Currently there are only spot markets in the UK and Zeebruge (Belgium). Additional trading hubs are scheduled, including one at the German-Netherlands border.
9 In March 2002, EU member states agreed to a liberalization program: i) Liberalization of industrial gas supply by 2004, ii) Decision on public service obligations and supply to remote areas by 2003, iii) Separation of transmission and distribution, vi) Non-discriminatory access for consumers and producers to the network based on transparent and published tariffs, v) Establishment of a regulatory agency in each member state.
10 During the first 6 months of 2001, Spain's Gas Natural resold all of its contracted LNG from Trinidad to US buyers; Italy's ENEL delivered 5 cargos of Nigerian LNG, originally destined for Europe, to the US Lake Charles terminal. GdF sold 2 Algerian cargos to the US and purchased additional UK gas, which it received via the Interconnector Pipeline between the UK and Belgium. This resulted in an increase in UK gas price (to over $6 per MMBtu, from $4.50 per MMBtu), and provided evidence of an interaction between prices in Europe and the US. In the 4th quarter 2001, European gas prices were higher, and the trade direction switched. Deliveries from Trinidad to Spain resumed and at least 2 Nigerian cargos, originally purchased for the US market, were diverted to the Montoir and Zeebrugge terminals in Europe.
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