Market access remains key for LNG producers

April 22, 2002
Although last year saw some slowing in the rate of growth of LNG demand, it remains one of the fastest growing sub-sectors of the energy business.

Although last year saw some slowing in the rate of growth of LNG demand, it remains one of the fastest growing sub-sectors of the energy business. Prospects for continued growth are good with more new liquefaction capacity being planned than at any time in the past.

Moreover, LNG it is still a business in which sponsors of new liquefaction capacity want to see sales contracts for a substantial part of the planned output before they are prepared to commit the billions of dollars needed for upstream production, liquefaction facilities, and shipping. As a result, the competition for market access is intense.

In addition, markets in the Atlantic Basin and Asia-Pacific regions are developing very differently.

The Atlantic Basin is becoming a market where price and cost are increasingly the driving factors in securing market share.

In the US market, LNG cargoes can always be sold, provided the LNG supplier is prepared to accept a price netted back from Henry Hub (La.) prices. The expectation is that prices will strengthen in the long-term but they are volatile and the seller faces the downside risk that events outside his control will result in low prices over extended periods. The lowest cost supplier is best placed to survive in such an environment.

Europe is likely to follow the US in moving towards gas prices set by the balance of supply and demand so that being a low-cost supplier will increasingly be a key to success for suppliers to that market as well. The low-cost producer should also be well placed to take advantage of arbitrage opportunities as prices vary between markets on either side of the Atlantic.

In Asia, LNG sellers are competing to supply the market growth in existing markets and any opportunities that open in emerging markets such as China and India. Successful projects will be those that can best meet the needs of buyers, including the increasing pressure for lower prices as markets deregulate.

In this region, as in the Atlantic Basin, low-cost producers will be best placed to respond to the requirements of buyers and secure market access.

The challenge to the technical community is to ensure the downward trend in costs is maintained in an environment in which security and safety are increasingly in focus. Building ever-larger trains, likely to be one response to this challenge, nonethe less runs counter to the needs of LNG marketers who are finding that markets are more diversified and that buyers are looking for smaller tranches of supply.

This overview of LNG supply and demand will discuss these broad trends.

A constant among change

There is much discussion in gas journals and at gas conferences about the changes taking place in the LNG industry today; "spot" or "short-term trading" are new buzzwords. There are those who expect LNG to become more like the oil business over the next few years.

Despite all the hype about change, one fact that remains constant: New projects need to find buyers, whether the project involves the expansion of existing facilities or the development of a new green-field facility.

There is also discussion of a so-called "merchant LNG plant" in which the investors build the facility without any long-term sales contracts and with the intention of marketing all the LNG on a spot or short-term basis.

Although, projects are going ahead with only part of the output contracted long term, something unheard of only 10 years ago, no one has yet committed to the billions of dollars in investment required for gas production facilities, liquefaction plant, and ships without a single contract in place for the LNG.

Securing a buyer to underpin the investment in a new LNG facility is still a critical success factor for any project. But achieving this objective is becoming more difficult. Markets are changing as they are deregulated and liberalized.

The all-powerful natural gas or power utility, which often had a monopoly position in its market area, is no longer in a position in most countries to make the commitments that underpinned the development of all the LNG plants in operation today.

The new buyers, independent power producers or new players trying to break into a market previously controlled by a monopoly utility, cannot offer the same security or, in many cases, the same volume of off-take.

There are more LNG developments being planned around the world today than at anytime in the past. As a result, competition is intense to secure commitments from those buyers in position to contract for new LNG supplies. This is putting increased pressure on projects to make offers that meet the needs of potential buyers.

LNG in 2001

Initial figures for 2001 suggest that LNG demand increased by 4.5%, a healthy growth rate in a year characterized by slowing economic activity across the globe. It will probably turn out to be a faster growth rate than for other sector or subsector of the energy industry.

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As Fig. 1 shows, however, growth did slow compared with the previous 2 years, when it averaged around 10%/year.

The reason for the slowdown in the growth rate:

Last year was the first since 1997 in which no new LNG trains were brought into operation. Between 1997 and 2000, five new LNG plants (Qatar Liquefied Gas Co. Ltd.-Qatargas; Trinidad; Ras Laffan Liquified Natural Gas Co. Ltd.-RasGas; Nigeria; and Oman) came on stream with a total of 10 new LNG trains and around 30 million tonnes/year (tpy) of production capacity.

Although more than 10 million tpy of surplus LNG production capacity were available in 2001, there was a shortage of uncommitted LNG ships to move the LNG to market.

If the ships had been available, the US had the terminal capacity to receive additional LNG cargoes and, with prices in the early part of the year reaching nearly $10/MMbtu, the returns to producers would have been very attractive.

Economic problems in Asia restricted the ability of buyers in Japan, Korea, and Taiwan to lift additional quantities of LNG. Taiwan for example increased its import volume by around 10% but was still unable to lift all its contracted LNG.

The slow-down in economic activity in the US and warmer than normal weather in the fourth quarter resulted in lower gas demand and a reduction in prices to a level that could not support LNG imports from distant locations.

LNG demand increased at a similar rate in both the Atlantic Basin and the Asia-Pacific region, but the market dynamics underlying the growth continued to differ between the regions.

A large part of the growth in the Atlantic Basin resulted from increased short-term trading; whereas in the Asia-Pacific region the growth came largely from the build-up of long-term supplies.

Atlantic Basin LNG in 2001

The Atlantic Basin, in particular the US market, has over the last 2-3 years, increasingly become a market of last resort for LNG producers with surplus capacity.

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Fig. 2 shows how the Atlantic Basin LNG was dominated by Algerian supply throughout the 1980s and into the 1990s with Libya the only other significant supplier.

Starting in 1993, with the sales from the Australian North West Shelf project to Spain (via Zeebrugge in Belgium), LNG supply to markets in the region has become increasingly diversified.

By 2000, all the world's LNG plants, with the exception of Brunei and Alaska, had delivered LNG into Atlantic basin markets.

Start-up of the LNG projects in Trinidad and Tobago and Nigeria in 1999 provided new sources of LNG supply within the Atlantic Basin itself. These projects are the first of what could be a wave of new regional supplies starting with expansion of these two projects but soon to be followed by Egypt, Norway and, possibly, Angola, and Venezuela.

The US market has in many ways been the catalyst for the changes in Atlantic Basin LNG.

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The gas market there is deep and liquid, providing LNG sellers with an outlet for LNG cargoes on a spot or short-term basis, provided the seller is prepared to accept a price netted-back from prevailing market prices.

Fig. 3 shows how the US market has grown over the last few years. The growth rate in 2001 was about 8%, well below the 45% increase recorded in 2000. Puerto Rico accounted for much of the growth with imports into the Lower 48 up by only 4%. US imports, however, have increased more than ten fold since 1995.

During the first half of 2001, imports were up by nearly 30% and demand for the first three quarters of the year was running at around 1.5 million tonnes/quarter. As prices fell in response to weaker gas demand, however, LNG imports slowed considerably to only 0.8 million tonnes in the fourth quarter.

With the exception of a single cargo from Oman delivered to Puerto Rico, only the closest suppliers, Trinidad and Algeria, unloaded cargoes in US terminals during the quarter as cargoes were switched to Europe or were not loaded.

The switching of cargoes from the US to Europe in the fourth quarter is part of an increasing trend in the Atlantic Basin of LNG players taking advantage of price arbitrage opportunities.

In the early part of the year, cargoes were transferred from Europe to the US market to take advantage of higher prices.

For example, in the first 6 months of the year, Spain's Gas Natural SDG SA sold all the LNG it has under contract from Trinidad to US buyers. Italy's ENEL Societe per Azioni (ENEL) also delivered five cargoes of Nigerian LNG, originally contracted for Europe, to CMS Energy Corp.'s Lake Charles, La., terminal.

Finally, Gaz de France sold two Algerian cargoes to the US and purchased additional UK gas, which it received via the Interconnector pipeline between the UK and Belgium. This caused an increase in UK gas prices, and we saw for the first time an interaction between European and US prices.

In fourth quarter 2001, European gas prices were higher than US prices and the direction of trade switched. There was a resumption of deliveries from Trinidad to Spain and at least two Nigerian cargoes, originally purchased for the US market, were redirected to the Montoir and Zeebrugge terminals in Europe.

Some Middle Eastern cargoes were also reported to have been diverted to Europe. I will return presently to the implications of prices becoming an increasingly strong driver of demand in the Atlantic basin.

LNG in Asia-Pacific

Initial figures for 2001 suggest that LNG demand in the region grew by about 4.5% in 2001 despite poor economic growth in Japan, Korea, and Taiwan. LNG demand in the latter two countries was particularly robust with increases of about 8% and 10%, respectively. The additional supply came mainly from the build-up in production in Qatar and Oman.

There was a significant increase in the short-term trading of LNG in the region in 2001, but, in contrast to the Atlantic Basin region, it was undertaken mainly by LNG buyers to manage fluctuations in demand and the disruption caused by the shutdown of the Arun facility in Indonesia.

There was no evidence of LNG traders playing any role or of price being an important factor behind the short-term trading which did take place.

There were several key events in short-term trading in the Asia-Pacific region in 2001. Korea Gas Co. Ltd. has become a regular player in the short-term market as it manages the swing in demand between the winter and summer months in the residential and commercial sector. In first quarter 2001, Korea Gas secured some 17 short-term cargoes, mainly from Middle Eastern suppliers.

In Taiwan, slower than expected growth in power demand has left the Chinese Petroleum Corp. (CPC) without markets for a significant proportion of the LNG that it has committed to purchase from Malaysia and Indonesia. It has found some novel ways of dealing with the problem including "time swaps" with other buyers in the region.

Under this arrangement, Chubu Electric Power Co. Inc. in Japan agreed to purchase some of the surplus cargoes from CPC in 2001. CPC will buy these cargoes back around 2004-05 when Chubu Electric expects to have surplus LNG as the result of the commissioning of nuclear and coal-fired power plants.

Japan's Osaka Gas Co. Ltd. dealt with its surplus LNG supply, in part, by selling one of its Oman cargoes to the US. Osaka Gas's purchase of LNG from Oman is on FOB terms and control of shipping helped to facilitate the sale.

The shutdown of the Arun LNG plant in Indonesia from March to August because of political unrest in the Aceh Province in Sumatra presented Asian LNG buyers, for the first time, with the need to deal with the extended shutdown of a major production facility.

At the time of the shutdown, Arun was producing about 10 cargoes/month of LNG and its main buyers, Japan's Tohoku Electric Power Co. Inc. and Korea Gas, had to look to other projects to meet the deficit.

Some of the supply was replaced by Indonesia's second LNG plant, at Bontang, and some came from other producers in the region.

The shutdown lasted for nearly 6 months, but the buyers were able to cover their LNG needs, helped in part by Korea Gas's lower LNG requirements in the summer months.

In the early stages of the Arun shutdown, there was an interesting three-way swap of LNG cargoes. CPC agreed to sell a cargo to Korea Gas to replace some of the lost volume from Arun. A few days after the deal was finalized, one of Taiwan's nuclear plants had to be shut down and output from gas-fired plants was increased to replace the lost power. CPC had to buy a cargo of Oman LNG from Osaka Gas to meet the unexpected increase in gas demand.

The events of 2001 demonstrate that the dynamics of the two regional markets are diverging despite the increased volume of inter-regional trade.

There are also many similarities between the regions, not least of which is the number of new projects-both expansions of existing facilities and new green-field developments-on the drawing board.

Accessing to markets will be a critical success factor for all the potential projects, wherever they are located, but the way in which market access will be secured differs between the regions.

Atlantic Basin LNG supply, demand

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Table 1 lists the liquefaction facilities in the Atlantic Basin that are in operation or under construction. The facilities currently in operation have a production capacity of 33.75 million tpy.

There is a further 14.5 million tpy of capacity under construction in Trinidad, Nigeria, and Egypt. These facilities should all be in operation by 2005 when total production capacity will be close to 50 million tpy, especially if the inevitable over-design in new facilities is taken into account.

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Table 2 shows the planned facilities in the Atlantic Basin, divided into those plants that are at an advanced stage of planning, in the sense that front-end engineering design (FEED) is complete or sales agreements have been signed.

The additional capacity in these plants is slightly more than 20 million tpy, and it seems likely that all this capacity will be in operation by 2006 or 2007.

Finally, there are a number of plants where plans are less well advanced. The total capacity of these plants is around 40 million tpy. If all the plants listed in Table 2 are eventually developed, then total production capacity in the Atlantic Basin would reach nearly 110 million tpy.

It appears that the terminal capacity to absorb all this LNG and more is in operation, under construction, or being planned.

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Table 3 summarizes actual and planned terminal capacity on both sides of the Atlantic.

Capacity in operation will amount to about 50 million tpy when Cove Point in Maryland, the second of the two US terminals mothballed in the 1980s, is recommissioned later this year.

There are about 15 million tpy of capacity under construction in Europe. Plans for a further 100 million tpy of capacity on both sides of the Atlantic have been announced in terms of new terminals and expansions of existing terminals.

Not all this capacity will be built. Indeed there are already reports that some of the US terminal plans announced during first half 2001, when each week seemed to bring a news of plans for a new facility, have already been abandoned. However, even if half the planned terminals for the Atlantic Basin were cancelled, there would still be sufficient import capacity to receive all the planned production capacity listed in Tables 1 and 2.

On the basis of these figures, it therefore appears that there will be sufficient import capacity to absorb all the LNG production planned in the Atlantic Basin over the next decade or so.

So, what are the barriers to their development? The answers are price and cost.

LNG can always be delivered to the US, provided the seller accepts the prevailing price set by gas-on-gas competition in a market where more than 98% of supply is delivered by pipeline. The continental European gas market has not yet reached the stage at which prices are set by competition in the market place, but as markets are liberalized it is moving in that direction.

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As a result, the developers of a new LNG facility to supply Atlantic Basin markets must be able to take the price risk. Fig. 4 shows US Henry Hub gas prices from 1986 to 2001. The underlying price level has risen over the period but so has the volatility.

In 2001, the maximum daily price was close to $10/MMbtu and the lowest below $2/MMbtu. Looking at the 16-year period as a whole, prices were more often below than above $2/MMbtu.

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In a market where prices are volatile, the most robust projects will be those with the lowest costs. Table 4 shows estimates of the cost of delivering LNG to Cove Point in the US from new capacity in a number of locations.

The estimates can be no more than approximate because they are based on broad assumptions, but they show that expansions of projects reasonably proximate to the market appear to be in a much stronger position to withstand low prices.

One message is very clear, however. Projects with the lowest costs will be in the best place to secure access to markets where prices are set by gas-on-gas competition. Thus, the challenge to the designers and builders of new liquefaction capacity is to continue the downward pressure on costs.

The need to achieve this objective without compromising safety or reliability has been further emphasized by the reaction to the events of Sept. 11, 2001. In the immediate aftermath of the terrorist attacks, attention focused on the risks of attacks on LNG carriers entering US ports to discharge. LNG ships were banned in September from entering Boston harbor for several weeks.

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The increased concern about safety means that any incident, even if relatively minor, is going to be reported and analyzed in great detail and could affect the whole industry.

Asia-Pacific LNG supply, demand

The overhang of potential new supply in the Asia-Pacific region is similar to that in the Atlantic basin, as Tables 5 and 6 show.

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Table 5 lists LNG plants in operation supplying Asian markets. Total capacity amounts to about 87 million tpy, some 12 million tonnes higher than actual demand in Japan, Korea, and Taiwan in 2001. A further 17 million tpy of capacity is under construction (Table 6).

All this capacity will be on stream by 2005, taking the total to around 105 million tpy.

Plant expansions totaling about 30 million tpy are possible on the Australian Northwest Shelf project (5 tpy) and at RasGas (4-5 tpy), Qatargas (4 tpy), Oman (3 tpy), Brunei (6 tpy), and Bontang (9 tpy).

Other greenfield developments totaling 60-80 million tpy are possible for northern Australia (Bayu-Undan, Sunrise, and others) and the Northwest Shelf (Gorgon, Scott Reef, and others); Indonesia (Tangguh, Natuna); Russia (Sakhalin); Yemen; Iran (two projects); and Alaska.

All are at various planning stages to supply Asian LNG markets. In the unlikely event that all these projects were to be developed, production capacity would more than double to more than 200 million tpy.

The markets into which these projects are trying to sell their LNG are very different from those in the Atlantic Basin. Japan, Korea, and Taiwan rely almost entirely on LNG to meet their demand for natural gas.

Therefore, sellers of new LNG production must capture new demand growth rather than compete with pipeline gas for existing (and new) market demand.

In these markets, price has been less of an issue than security and reliability of supply.

Indeed, prices have generally been at a premium to those in the Atlantic Basin, as buyers have wanted to ensure the stability of their supply sources.

The existing buyers in Japan, Korea, and Taiwan suffer from a combination of low or unpredictable natural gas and power demand growth and increased competition and uncertainty as governments deregulate markets to reduce prices.

Buyers are certainly not in a position to commit to the type of long-term contracts they signed in the past, contracts that underpinned the development of all the LNG plants in operation today in Southeast Asia, Australia, and the Middle East.

Faced with the lack of demand in the existing markets, sellers are increasingly turning to such new markets as India and China.

The emergence of these markets, however, is taking longer than most potential investors imagined.

There have been many plans for new terminals in India.

The only one that has nearly been completed is the Dabhol terminal and related power plant, but construction there was halted in 2001 because of well-publicized disputes over the price of power between the project and the Maharastra State Electricity Board. The bankruptcy of Enron, the main shareholder in Dabhol, has further complicated the situation.

The only other receiving terminal under construction in India is at Dahej, in Gujarat State, where Petronet plans to be in a position to commence imports of LNG from Qatar in 2004.

China has also taken longer than expected to emerge as an important LNG buyer.

The planned Guangdong terminal, however, now seems to be progressing towards completion by 2006. The bidding for supply to the terminal illustrates the strength of the competition to secure market access.

Six potential suppliers, Australia North-West Shelf, Indonesia (Tangguh), Qatar (Ras Laffan), Malaysia (Tiga), Russia (Sakhalin), and Yemen, are all reported to have made bids. It was announced in January 2002 that Australia, Qatar, and Indonesia have been short-listed.

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Fig. 5 illustrates the reason for the strong competition to secure any market opportunity that opens. It shows estimates of LNG demand over the period to 2015 together with the capacity of existing liquefaction plants and those under construction.

The low, base, and high case demand forecasts include estimates for Japan, Korea, and Taiwan and for such new markets as China and India. Fig. 5 shows that, on the base-case demand estimate, further new production capacity will not be needed until around 2007-08, while on the low case it may not be needed until after 2010.

The high demand case only brings forward the need for new capacity by about 1year.

These estimates suggest it will be many years before a number of the possible new projects will be required. Furthermore, no account is taken in the demand estimates of possible long-distance pipelines from Eastern Siberia and Sakhalin.

These pipelines could provide strong competition for LNG after 2010.

The Asian LNG market has all the elements of a buyers' market. In such a market, the successful sellers are those who are best able to meet the requirements of their customers.

Price is increasingly one of the key factors in the buyers' choice of supply in both emerging markets. There, a large part of any imported gas will be used for power generation in competition with low-cost domestically produced coal.

In existing markets, price is growing in importance for buyers who, in the past, often rated security of supply as the main criterion in their choice of supply source.

The low-cost producer is always in a best position to respond to the requirements of buyers, so that even in Asia, where prices are not as transparent as in the Atlantic Basin, the need to reduce cost is important. This cannot be at the expense of security and reliability of supply because buyers who do not have access to alternative supplies of pipeline gas will continue to want these issues addressed in any sales agreement.

Economies of scale

Building ever-larger LNG trains to take advantage of the economies of scale has been one of the main ways in which liquefaction costs have been reduced over the last 30 years. Indeed, it can be argued this has accounted for nearly all the reductions in cost that have been achieved.

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Fig. 6 shows the evolution of LNG plant costs between 1965 and today. The graph has been overlaid with a line showing how costs would have come down using a two-thirds power rule to estimate the cost per unit of capacity as output is increased. This is a rule that can be applied to some other types of process plant.

If it is assumed that LNG plant costs behave in the same way, then the increase in train size from 1 million tpy to 3.5 million tpy between 1970 and 2000 should have been accompanied by a reduction in unit costs of about 50%. Actual data show that unit costs did fall by about half between 1970 and 2000.

The race to increase the size of trains continues. The most recently announced new LNG plant, at Damietta in Egypt, has a train with a design capacity of 4.97 million tpy.

The problem with the upward trend in train size is that it runs counter to the increasing diversification of the market and the emergence of buyers whose individual requirements are smaller than those of the big monopoly buyers who dominated markets in the past.

As a result, sellers need to bring together several buyers, often with very different requirements, to market the output from a single train.

This is particularly the case in the Asia-Pacific region but can also be a problem in the Atlantic basin where a large train means that to secure markets the seller has to take the price risk on a large volume of LNG.

The challenge therefore is to find ways of applying the cost savings to smaller trains or, alternatively, to design trains that can be expanded at a relatively low additional cost.

The initial output from the train would be sized to meet the initial market demand and the plant would be expanded as the market develops, allowing the project to enjoy at least some of the economies of scale.

The author

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Andy Flower ([email protected]) is currently working as an LNG and natural gas consultant and lectures on LNG courses. He recently retired from BP PLC after 32 years. For the last 22 years, he was involved in BP's LNG and natural gas business activities with his last post being senior adviser, Global LNG. At various times, he managed BP's interests in projects in Nigeria, Abu Dhabi, Australia, and Qatar. Flower holds a BA (1968) in mathematics from Oxford University and an MSc (1969) in statistics from Birmingham University, UK.