LNG

Profitable year so far, but cost and demand challenges confront suppliers

 Gas liquefaction projects continue to focus on long-term opportunities in western North American markets to overcome medium-term LNG demand growth constraints in Asia. 

David Wood, David Wood & Associates, Lincoln, UK; and Saeid Mokhatab, Contributing Editor, LNG, World Oil
 

Many base load gas liquefaction projects currently in planning are being hit by high upstream cost inflation, which has increased at unprecedented rates in the past two decades. Projects in Australia (e.g. Gorgon), Nigeria (e.g. OK LNG), Angola and Algeria (e.g. Gassi Touil) are all considering reconfigurations to deal with escalating budgets. They do not want to repeat the massive cost overrun experiences of Shell and partners at Sakhalin in Russia and Statoil and partners at Snohvit in Norway. Shell has also announced substantial cost escalation to its Qatargas 4 project, increasing its budget to $8 billion and its Pearl GTL project also in Qatar, increasing its budget above $14 billion.

Equatorial Guinea LNG, onstream in May 2007, delivering its first cargo some six months ahead of schedule, is a rare exception. The completion of this $1.5 billion project is a great boost to Marathon, the operator and 60% equity holder, and Bechtel, the contractor that installed this ConocoPhillips optimized cascade 3.7 million tons per year (MMt/yr) facility that now offers some 3.4 MMt/yr of LNG, through a 17-year contract with BG, provisionally targeted for the US market. A final investment decision on a second train (4.4 MMt/yr) is expected in 2008, but it will probably not be able to match the first train’s budget.

In spite of these cost obstacles the large IOCs, NOCs and technology providers in the industry continue to push the limits upwards on the size of single liquefaction trains. In 2007, Shell and Air Products have separately presented outlines of single trains with up to 11 MMt/yr capacity. The technology has undergone a remarkable development in the past decade versus its 40-yr history, Fig. 1.

It took 30 years for the industry to progress from less than 0.5 MMt/yr capacity trains in Arzew, Algeria, to 3 MMt/yr trains in the late 1990s in Bonny, Nigeria. In the past decade we have seen several trains in the 4+ MMt/yr come onstream such as Damietta, Egypt in 2004 and have the 7.8 MMt/yr trains of Qatargas II under construction by QP, ExxonMobil and Total using Air Products AP-X technology. An extra refrigerant cycle, a post-liquefaction nitrogen turbo-expander sub-cooling unit appears to be the key addition to achieve this economy of scale.

However, rather than rushing into further capacity increases, there is an argument for waiting to see how much Qatargas II trains finally cost and whether they can operate efficiently. Moreover, while the majors continue to be infatuated by the few giant gas fields remaining undeveloped the reality for future gas supply is that most remote discovered, but yet to be developed gas fields are less than 3 Tcf in size could not sustain a liquefaction train of more than 4 MMt/yr. Hence the long-term future of the LNG industry probably does not rest in development of mega-sized trains.

NEW ASIAN LNG SALES TO CHINA AND JAPAN

In early September 2007, Shell signed a LNG sales agreement supplying PetroChina from Australia’s Gorgon field. The deal involves 1 MMt/yr over 20 yr, rumored to be at a substantial price. Price has been a stumbling block for many would-be suppliers to China since 2003, at that time the low LNG prices agreed with China. In the same week PetroChina agreed to buy 2 to 3 MMt/yr of LNG over 15 to 20 years from the Woodside-operated Browse project. Browse reported to hold some 20 Tcf of gas and 311 million barrels of condensates.

Browse project (Northwest Shelf, Australia) is planned for initial development involving a 7 MMt/yr onshore liquefaction plant starting production in 2014. Provisional development plans involve adding a second unit later to double capacity. PetroChina is reported in the Australian press to have agreed to pay $7 to $9 MMbtu for Browse gas, compared with prevailing LNG prices in Asia in the $8 to $10 MMbtu range. Woodside holds some 34% of Browse with BP, Chevron, BHP and Shell holding the remaining equity.

These two deals suggest that China is now willing to accept market LNG prices and this could open up opportunities for other Australian projects. However, remaining environmental objections over use of Barrow Island by the Gorgon LNG project and remaining territorial issues with East Timor could delay some of these projects. The 10 MMt/yr Gorgon project signed a 4.2 MMt/yr LNG sales contract with Japanese utilities last year for first delivery in 2010, but environmental disputes and rising costs have caused this to slip to 2012.

Japan is also a recent buyer of Australian LNG in the post-2010 period. For example Tokyo Gas and Kansai Electric Power finalized LNG purchase agreements plus the acquisition of 5% equity positions in Woodside’s Pluto LNG project with costs for the full 4.2 MMt/yr project budgeted at more than $10 billion. The development involves onshore liquefaction facilities on the Burrup Peninsula, the home of its existing Northwest Shelf (NwS) LNG multi-train facility. Japan has to consider replacing supplies from another of its traditional LNG suppliers, Indonesia, in the post-2010 period. In recent years Indonesia has struggled to meet contract delivery volumes to Japan and South Korea from its aging Arun and Bontang liquefaction plants. To compound the problem BP’s Tangguh LNG project in Irian Jaya (Indonesia) has suffered a number of delays but should finally deliver in 2008.

Indonesia will need to compete with other Northwest Shelf Australian projects now queuing up to sign new long-term gas deals with China and Japan. A case in point is the Ichthya 7.6 MMt/yr project in which Total and Inpex are targeting a 2012 start-up.

Japan, under contracts now agreed, will buy some 20 MMt/yr from four Australian liquefaction projects by 2012 (NwS, Darwin, Gorgon and Pluto). On top of this independent Santos has proposed in June 2006 a ground-breaking project to build a liquefaction plant-up to 4 MMt/yr-at Gladstone on the Queensland coast supplied by coal bed methane gas supplies. Subject to final investment decision the plant could be built in 2010 to supply LNG for export by 2014.

LONG-TERM PLANS FOR LNG

In July, following the G8 summit meeting, it was announced that Total had secured a deal with Gazprom with Total operating and paying $5 billion of the $15 billion projected capital costs for phase 1 of the project. In return Total would earn a 25% interest in a special purpose company and own that share of first phase infrastructure. Gazprom retains the gas marketing rights and says it intends to sell 23.7 Bcm/y of Shtokman gas to German utilities by 2013 through new pipelines linking into the 2006-sanctioned trans-Baltic Nord-Stream pipeline.

The field development is subject to a final investment decision from Total in 2009 following detailed engineering, and the deal is believed to involve Gazprom’s participation in some of Total’s international LNG assets under development. Total will not hold an interest in the licence in which the Shtokman field is located, thus making some suggest that this is a service contract that will not enable Total to book the Shtokman gas reserves under SEC rules. What is clear is that Gazprom’s other suitors-Statoil-Hydro, ConocoPhillips and Chevron-are wondering what they could have done to secure a part of the Shtokman deal and hope that they can gain access to the 25% still thought to be available. Statoil has provisionally agreed to explore Sakhalin 5 with Gazprom and that may help its case. Politics have clearly played a role in the initial Shtokman deal with Total, but the attraction of France as a market for large volumes of new Russian gas supplies was also undoubtedly a factor.

From 2014 Gazprom also plans to sell up to an additional 7.5 MMt/yr LNG from a phase 2 development of Shtokman. This may involve other foreign partners to fund the capital cost of that and subsequent stages of development, which could bring gas supply from Shtokman up to 94 Bcm/y by 2020. Gazprom is likely to be targeting the North American gas market with the LNG.

The future for the major IOC’s in Russia appears to be with Gazprom very much in the driving seat. BP ceded control to Gazprom of their East Siberian Kovykta asset in June and Shell of Sakhalin II in January following long struggles to maintain control through production sharing agreements. Both companies are now on record as seeking future international cooperation agreements with Gazprom in order to maintain future position in those assets. Gazprom is eager to develop its international LNG business opening up access to gas markets outside Europe. Hence cooperation with Total, BP and Shell in gas liquefaction projects in North Africa, Middle East and West Africa can be expected.

GAZPROM EXTENDS ITS INFLUENCE

In June 2007 Gazprom and ENI (Italy) announced a 50:50 agreement to construct, beginning 2009 and online by 2012, the “South Stream” gas pipeline, 30 Bcm/y capacity. The pipeline would run from Beregovaya on Russia’s Black Sea coast some 900 km to the Bulgarian coast reaching water depths of more than 2,000 m. Onward onshore sections, with routes yet to be finalized, would transport gas north to Austria, through Serbia or Romania and Hungary, and south to Otranto in Italy through Greece. When completed this will have a significant influence on LNG trading into the Italian and wider Mediterranean markets.

That deal enables ENI to add further value to its recent acquisitions of Russian assets of Arctic Gas and Urengoil. Eni “bought” the production companies at a Yukos auction in April 2007, although Gazprom has the option to re-purchase that stake at $3.7 billion. At the same time ENI acquired a 20% stake in Gazprom’s oil subsidiary Gazprom Neft. However, it is Gazprom and Russia that accrue substantial strategic benefits from this line by providing it routes into Southern Europe that avoid the traditionally problematic transit countries of Eastern Europe.

Italy is Europe’s third-largest gas market behind the UK and Germany and imports some 86% of its gas, mainly from Algeria and Russia. Gazprom is already supplying about 25 billion cubic meters of gas a year to Italy, making it Gazprom’s second-largest country gas purchaser after Germany. However, ENI is Gazprom’s largest single gas purchaser enabling ENI to have achieved the status of the largest gas company by sales in Europe, with some 18% of the total market.

POLITICAL AND COMMERCIAL PRESSURE FOR PROPOSED NABUCCO PIPELINE

Competition between South Stream and the EU-backed Nabucco pipeline project (Fig. 2), a $6.2 billion plan, led by OMV of Austria, will be intense. The Nabucco 3,300-km gas pipeline, with capacity potentially reaching 30 Bcm/y by 2020, is planned go through Turkey, Bulgaria, Romania, Hungary and Austria. It remains shakily scheduled for construction from 2008 to 2011. The EU forecast that it will probably need an additional 200 to 300 Bcm/y of gas supply over the next 25 yr, suggesting that there is room for both pipeline projects and new LNG imports to improve diversity and security of supply.

Gazprom also secured in May 2007 a cooperation agreement toward taking an equity position in the OMV inspired Central European Gas Hub at Baumgarten, Austria. Linking a branch of the South Stream pipeline into Baumgarten with Gazprom, an equity holder in the hub, would further constrain Nabucco’s independent-of Russian influence-supply ambitions from the Caspian and Middle East.

MEDIUM-TERM LNG SUPPLY DEMAND TRENDS

Increased demand in Europe and the US for imported gas, in part fueled by dwindling domestic production, is feeding demand for LNG supplies in the Atlantic basin. In 2007 many LNG cargoes have been diverted from Europe to the US to benefit from strong prices-$6-8/MMbtu, first half of the year-and compensate for weaker short-term gas demand in Europe. This highlights growing competition for short-term spot LNG cargoes between North America and Europe. The growing number of receiving terminals in both markets and new entrant suppliers (e.g. Equatorial Guinea and Norway following on from Egypt) will continue to feed this competition.

Production from NLNG Trains 4 and 5 in Nigeria has been boosting LNG supply for Shell, Total and ENI and Train 6, due onstream in late 2007, will add further Atlantic Basin capacity along with Norway’s SnØhvit plant due to deliver before year end.

In contrast, demand in the Pacific Basin is progressing at a slower pace and is still dominated by Japan and South Korea and long-term contracts. New LNG supply deals to China mentioned above may increase the pace of expansion of that market. However, at the moment there remains a queue of supply projects with capacities not yet fully subscribed (i.e., a number in Australia mentioned above, two rival projects in Papua New Guinea Hides-InterOil and ExxonMobil-BP’s Tangguh project) and substantial additional liquefaction capacity of Sakhalin II due onstream in 2008. Hence many of the Pacific basin suppliers are positioning themselves for entry into the potentially lucrative western North American LNG import market, for when it finally realizes that it has to overcome the environmental obstacles to secure its future energy supplies, Fig. 3.

THE AUTHORS
	David Wood is an international energy consultant specializing in the integration of technical, economic, risk and strategic information to aid portfolio evaluation and management decisions. He holds a PhD from Imperial College, London. Research and training concerning a wide range of energy related topics, including project contracts, economics, gas/LNG/GTL, portfolio and risk analysis are key parts of his work. He is based in Lincoln, UK, and operates worldwide. Please visit his web site www.dwasolutions.com or contact him by e-mail at woodda@compuserve.com.
	Saeid Mokhatab is currently consulting for multinational companies and research organizations in the natural gas and LNG industry worldwide. His areas of expertise include technical and commercial areas learned while working in senior technical and managerial positions at several international oil and gas EPCM projects, partnerships and joint ventures as a solution integrator and key source of expertise.