Monday, July 2, 2007
The Rise of LNG - a global perspective
July 2, 2007
Petroleum Review
Chris Skrebowski provides an overview of IP Week's Thursday conference (15 Februrary 2007), organised in association with Gas Strategies, which addressed one of the key industry topics of the moment - the increasing importance of LNG in the global energy mix.
The conference was chaired and introduced by James Ball, President and Mentor, Gas Strategies. He started by noting the importance of LNG in the UK's gas supply mix by 2010. He then pointed out that by 2010 the LNG business would account for 38bn cf/d of supply, with both Atlantic and Asian markets reaching around 18bn cf/d. This, in his view, confirmed the prospects for the industry and the importance it would attain in less than four years.
He then introduced Andy Flower, who talked to the title 'LNG - The supply and demand outlook for 2007'. Flower started his presentation by looking at what had happened in 2006. Demand growth, at 15.7mn tonnes (11%), was strong and would have been even greater except that 10% of potential supply was lost to delays and supply problems. In 2006, Qatar had become the world's largest supplier, overtaking Indonesia. Rather less positively, there had been no new commitments to build liquefaction capacity in 2006. LNG shipping had gone into surplus, with 28 new vessels entering service. This had led to ship sales from the Atlantic to Asia and the use of vessels for floating storage in the second half of the year.
LNG demand had achieved 7.7% annual growth in the 1980-2006 period. However, in the 2004-2006 period, European imports had risen strongly, Asian imports had slowed and imports to the Americas had actually declined by between 2% and 2.5%. In 2006, nearly 22mn tonnes of new liquefaction capacity was started up. Notable production gains were made by Qatar, Australia, Trinidad and Egypt in 2006, but older suppliers like Indonesia, Malaysia and Algeria recorded output declines.
Flower also noted that final investment decisions (FIDs) had been expected on 33-53mn t/y of new capacity in 2006. In the event, no FIDs were actually recorded. He showed a diagram illustrating the way that inflation in liquefaction plant costs had reversed all the gains of the last 20 years, and suggested this was one of the reasons for the delay in FIDs.
The direct consequences of the delays to new construction was that global liquefaction capacity in 2012/2013 would now be 47mn t/y lower than had been anticipated in January 2006. The reverse situation applies to LNG shipping, where capacity has expanded more rapidly than demand. The order book stood at 134 ships at end-2006, with 218 vessels in operation.
Flower then turned to prospects for 2007, when nearly 20mn t/y of new capacity was expected to come onstream from Qatar, Nigeria, Norway and Equatorial Guinea, adding to the 190mn t/y in operation at end-2006. He showed that up to 80mn t/y could be given the go-ahead in 2007, although he felt around 40mn t/y was more likely. He also noted that it was typically taking four years for FID to first gas. (See Table 1.)
In terms of regasification capacity, 2007 should see new capacity commissioned in the UK, Spain and France. With regas capacity only being used at around 60% of capacity, regas is not really a constraint in the system. Similarly, shipping capacity is running ahead of liquefaction capacity, which may lead to scrappage of some of the older vessels.
In conclusion, Flower stated that for successful development of the industry, cost inflation needs to be slowed or reversed, while new liquefaction capacity needs to come to market and boost supplies in a predictable manner. He also posed the question as to whether surplus shipping capacity would boost short-term trading and bring a global gas market with global pricing closer.
The next speaker was John Baldwin of Gas Strategies, describing Excelerate Energy's system for regasification onboard the vessel and discharge directly into a gas grid. He described the development and use of the Teesside terminal (for a detailed description of the system, see Petroleum Review, January 2007).
The buyer's perspective
Megumu (Meg) Tsuda, Project Manager, LNG Contract Negotiation for Osaka Gas Company, then described the changes in the LNG market from the buyer's perspective. She started by noting that we were witnessing the largest change ever seen in the industry. Initially, the development of the LNG sector had been based on a mutual interest in security of supply by both buyers and sellers. As a result, 20- to 30-year contracts were the norm, with take-or-pay clauses usual. Indexation, in the case of Japan, was to the JCC (Japan crude cocktail - a mix of import crude values).
The so-called 'S' curve effect moderates the price impact of rapid crude price changes on LNG prices. Japanese buyers at this date (pre-1985) formed a buyers consortium. The market started to change with the entry of Korea in 1986 and Taiwan in 1999. As a result, Japan, which had purchased 75% of world LNG supplies in 1985, saw its share fall to under 50% in 2005, and expects to account for just 19% of world LNG imports in 2020. Recent challenges have been shortfalls of up to 10% in Indonesian supplies, nuclear plant outages which boosted Japanese gas demand, and high oil prices which have led to increased global gas demand.
The Asian market in recent years has become increasingly dependent on spot supplies to meet what has become a chronic LNG shortage in the region, she explained. This, in turn, has led to intra-area movements between the Atlantic and Asia-Pacific markets and the emergence of active LNG trading. This has been further stimulated by the strong linkage between LNG and power markets.
Tsuda also noted that, although the market is becoming increasingly globalised, Asia-Pacific prices have tended to be higher than those in European markets. Contract prices have typically been around $5/mn Btu, but spot prices have been as high as $25/mn Btu.
The challenge for buyers was to secure the required supplies at competitive prices in an era when less was sold on long-term contracts but a fully competitive, globalised short-term market has not yet emerged.
Diversity of supply
The next speakers were Adrian Liaker and Abrecht Muller von Blumencron of PricewaterhouseCoopers, talking about diversity of supply. They started by noting that Europe was already importing 50% of its gas supplies and that this would rise to 84% by 2030. This means that Europe will be looking for an additional 300bn cm of gas, of which 40% to 50% is likely to be imported as LNG. Importing such volumes is likely to prove challenging given that the global LNG market is already tight and effectively a sellers market.
Earlier concerns about the availability of regasification capacity were now abating, they reported, with European regasification facilities currently operating at around 45% of capacity. Concerns about vessel availability had largely evaporated in the face of the emerging surplus in the LNG carrier market.
Potential liabilities
Philip Rock, Partner at Norton Rose, then spoke about the potential liabilities associated with LNG shipping. He began by noting the excellent safety record of the sector to date. He explained that the primary risks were the normal seaborne vessel risks of collision, groundings, mooring etc. The key additional risk was the flammability of the cargo. Although there were reports covering this risk, the problem was that because there had so far been no major LNG spill at sea, the risks were not really known.
One increasing challenge was manpower and getting skilled personnel to go to sea. Already, steam engineers (most LNG vessels are propelled by steam turbines) work three months on and three weeks off contracts.
Other areas of risk were vessel mooring and ship-to-ship transfers. The latter may become increasingly important if solutions such as Excelerate Energy's become more popular in the industry.
Meanwhile, terrorism presented a new and important risk that would have to be addressed.
Equatorial Guinea
Steve Ollerearnshaw then gave a dectailed description of Equatorial Guinea's LNG project (the Equatorial Guinea LNG train started up in May and is so far the only LNG project to have started up in 2007 - Ed.) Ollerearnshaw explained that Equatorial Guinea, which is literally in the corner of the Gulf of Guinea, only became independent in 1968. It consists of Bioko Island (which is off the Cameroon coast) and Rio Mundi on the marshland (immediately south of Cameroon). (The exact location is important because one possibility for a second train on Bioko Island is to take gas supplies from Cameroon (due west of Bioko Island) and Nigeria (due north of Bioko Island) - Ed.)
Until the discovery of oil in Equatorial Guinea the economy was dominated by agricultural exports, but since the discovery of oil in the mid-1990s it has come to dominate the rapidly growing economy and accounted for 93% of GDP in 2005.
The shareholders in EG LNG are Marathon (operator) 60%, the state company Sonagas (Sociedad Nacional de Gas GE) 25%, Mitsui and Co 8.5% and Marabeni Corporation 6.5%. According to Ollerearnshaw it is all equity financing with the Equitorial government investing its oil revenues into LNG development.
The EG LNG facility has a capacity of 3.6mn t/y. Production is targetted at two major markets - US east and Gulf coast, and Europe. The EIA has estimated (annual Energy Outlook 2006) that the US will need an additional 4.7tn cf of gas by 2030. EG LNG is scheduled to deliver 170bn cf/y, starting in 2007. The EIA has also estimated that OECD Europe will require imports of 20.5tn cf by 2030, although pipeline supply is likely to dominate it will become a major importer and could become an alternative market for EG LNG supplies particularly if the second train goes ahead. Ollerearnshaw then showed that Atlantic basin regas capacity is running well ahead of LNG supply right out to 2015, clearly showing that it is LNG supply rather than regasification capacity that is the potential bottleneck.
The gas for the EG LNG project comes from Marathon's Alba field, which lies offshore to the north of Bioko Island. The other shareholders in the Alba field are Noble Energy and GEP (the Equatorial Guinea state oil company).
The current treatment of the Alba production stream is that first the condensate is removed and exported. LPG is then removed and exported. The dry gas stream is used to make both methanol and LNG. The LNG is covered by a 17-year sales and purchase agreement with BG, who currently plans to take all the LNG to the Lake Charles terminal in Louisiana.
In summary EG LNG purchases 600mn cf/d of gas from the Alba field. The 3.7mn t/y LNG train 1 uses the ConocoPhillips Optimised Cascade process. BG has contracted 3.4mn t/y of LNG for 17 years from movement to the US. The facility includes two 136,000cm LNG carriers.
According to Ollerearnshaw the project achieved the shortest time from FEED (front-end engineerig and design) to first LNG for any LNG project. Long lead time equipment was committed to in late 2003. The agreement with government was also signed in early 2004 with the FID and the EPC (engineering, procurement and construction) contract awarded in mid-2004. First cargo loading was achieved in May 2007.
The success of the project was attributed to a close alignment of government and shareholders, the early ordering of long lead time equipment and the experience of the contractor (Bechtel) with the LNG process ( Conoco Phillips Optimised Cascade).
Ollerearnshaw noted that the EG LNG project had caught the market right, in that it was ahead of the recent inflation, with an EPC cost of $270 t/y.
He then showed the impact of the project in terms of jobs and other positive impacts on the community before turning to the longer term prospects.
There is the potential for a regional gas hub in Bioko Island and space for multiple LNG trains. According to him the potential is there for up to 20mn t/y of LNG supply. There are considerable reserves of gas within a 100 km of radius of Bioko Island - possibly as much as 30tn cf. Heads of agreements (HoAs) have already been signed with Nigeria and Cameroon for gas supplies. In addition there are further gas resources in Equatorial Guinea's offshore. FEED work is already underway to determine if the next stage should be one or two new trains or whether a much larger train would be appropriate for Phase 2.
The ending of gas flaring at the Zafiro field could provide 100mn cf/d for train 1 or 2 as well as 50,000 b/d of condensates and 40,000 b/d of LPGs.
Future challenges
The final speaker of the day was Robert Fenton, Managing Consultant, Gas Strategies Consulting. He spoke to the title 'The challenge of commercial operations in LNG'. He started by noting the very rapid expansion of the LNG business over recent years and expected this to continue. Success, however, depended on aligning interests and overcoming a series of challenges which if not successfully addressed could undermine projects.
To reach the all important FID when money is committed and construction is initiated, investors must be confident of the technical and economic viability of the project.
The recent sharp upturn in unit costs is in direct contrast to the longer term experience of falling costs driven by technical innovation and increasing sizes of ships and liquefaction trains. Commerical arrangements have also evolved with arrangements becoming increasingly complex as the industry moves away from long-term contracts to a variety of more flexible arrangements.
The trend to more liberalised gas markets and the return of the US as a significant LNG buyer after 2000 have been important drivers.
He then went on to describe some of the main challenges, noting that along the chain gas or LNG will change hands under sale and purchase agreements (SPAs) which, in addition to price and volume specify a range of variables such as delivery point, delivery schedule, destinations, quality, size and type of ship etc.
Although every aspect of an SPA could throw up challenges to the parties involved, Fenton felt four areas presented particular problems:
- Determining value - Asian markets traditionally index LNG to crude prices usually the JCC index while in Europe indexation is to competing oil products - fuel oil or gas oil, but occasionally to coal or electricity depending on the application of the gas. Long-term contracts usually include 'meet to discuss' clauses or price review provisions. This can lead to expensive and lengthy contentions negotiations.
- Quantities and invoicing - many agreements have upwards and downwards tolerances on volumes that provide some flexibility to manage volume risk. Complication provisions cover make up, cover forward and make good in contracts but is a complicated and cumbersome process that needs careful monitoring.
- Scheduling deliveries - another area that can cause difficulties. Buyers demand profiles may not match the desire of LNG plants to operate as close to capacity as possible. Production planning aims to reconcile these, but considerable complications can arise.
- Force majeure (FM) - each agreement specifies when parties can claim FM and the recourse available to them. FM events such as the Skikda explosion are rare but can be complex and expensive when they do occur, particularly if the declaration of FM is contested.
According to Fenton there are two solutions to some of these commercial challenges. The simplification of provisions and improvements in competence of staff and the efficiency of the organisation in administering contracts.
Simplification had made only limited progress because LNG has flipped from being a buyers market to being a sellers market which has restricted pressure to move to master agreements.
In terms of improving the effectiveness of organisations and their staff, Fenton identified four areas of improvement:
- Better understanding of a company's portfolio of agreements.
- Developing business processes to administer key contractual provisions.
- Staff-training and readiness training.
- Building a commercial support system.
His conclusion was that the first evolution of the LNG industry had thrown up a number of administrative challenges which have yet to be fully addressed but remain threats to the smooth running and further development of the industry.
TABLE 1: POSSIBLE LIQUEFACTION CAPACITY FIDS IN 2007 (SEE ALSO PAGE 38)
Project Capacity (mn t/y)
Peru 4
Angola 5
Nigeria - OK LNG 11
Nigeria - Brass LNG 10
Nigeria LNG train 7 8
Australia - Gorgon 10
Australia - Pluto 6
Algeria - Skikda rebuild 4
Algeria - Gassi Touil 4
Iran - Pars LNG 10
Egypt - Idku train 3 3.6
Egypt - Damietta train 2 5
Total 80.6
