These projects are driven by three factors: tight mid-term supply in the global LNG market; the willingness of buyers to agree to long-term price indexation close to parity with oil; and the attraction of Australasia’s political stability (compared to other gas-rich provinces) for international oil companies.

Plenty of Enthusiasm, but a Slow Pace

Table 1 identifies gas liquefaction projects under development and in planning in Australia, Papua New Guinea, and Indonesia’s marine waters adjacent to Australia’s border. The total potential capacity, some 90 million tons (Mt) per year, is impressive, considering the current operational global capacity of some 175 Mt per year. Even if this additional capacity takes a decade or more to deliver, it should have an impact on the tight mid-term global LNG market, with its growing gap between surging demand and limited supply.

Recently China and India have been seen as the major long-term customers for Australia’s new LNG capacity, beginning in 2002 when North West Shelf Australian LNG agreed to a 25-year supply deal with China. It called for delivery of 3.3 Mt per year to Dapeng for about $3 per MMbtu, with limited escalation clauses. (North West Shelf Australian LNG is a venture with six equal owners: BHP Billiton, BP, Chevron, Japan Australia LNG, Shell, and Woodside Energy.)

In April 2008, North West Shelf Australian took delivery at Hudong-Zhonghua shipyard (Shanghai) of the Dapeng Sun, the first of three Chinese-built LNG carriers destined to transport its LNG to the Dapeng receiving terminal. Many of the Australia liquefaction projects are seeking new Chinese contracts, as well as with other East Asian buyers, but at substantially better prices than the initial deal.

Short-term Action vs. Mid-term Plans

The Australian Petroleum Production and Exploration Association and Australia’s Resources Ministry are promoting the idea that, by 2015, Australia should be exporting some 60 Mt per year of LNG, five times more than current capacity. Aside from the $100 billion (or more) of investment this would require, many doubt there is sufficient skilled manpower to achieve this.

The next project due onstream later this year is North West Shelf Australia’s train 5, with a capacity of 4.4 Mt per year. This will bring Australia’s total gas liquefaction capacity to 16.3 Mt per year. In 2010, Woodside expects to finish the Pluto project, with 4.3 Mt per year capacity. The Pluto offshore platform will export 1.6 billion cubic feet per day of gas, via a 36-inch subsea pipeline to an onshore single-train liquefaction plant.

Despite the large number of projects in planning, the construction schedule for the remaining projects is less certain. Indeed, some projects have for so long been touted as imminent (e.g., Gorgon, Sunrise, and Browse) that the Australian government and industry analysts have expressed doubts about the commitment to develop them. There are plenty of issues that must be resolved, including the remoteness of the gas fields (distance to shore), environmental and community objections (e.g., Gorgon, Ichthys), challenges (CO2 sequestration requirements), escalating costs, partner wrangles over development options, border disputes (e.g., Sunrise), and uncertainty about floating gas liquefaction technology (Scarborough).

The inability of LNG plant owners to secure long-term LNG sales agreements at favorable prices, the most frequent cause for large remote gas reserves languishing underdeveloped for years, is no longer a reason for delays. Sustained high Asian gas prices, and a spate of recent deals with East Asian buyers involving LNG prices close to parity with oil prices, have even led to plans for several CBM-supplied projects feeding liquefaction facilities at Gladstone, Queensland. The CBM projects have prompted intense industry interest and competition.

Until this year, BG had focused its growth as an Atlantic basin LNG operator, selling its small equity interest in Tangguh LNG Indonesia a few years ago. BG’s strategic shift underlines the attractiveness of gas liquefaction opportunities in Australia, compared to LNG expansion options in Africa and South America.

In spite of its aspirations to generate 90 percent of its power from renewable sources by 2025, New Zealand is facing a mid-term shortfall in gas supply as the Maui gas field declines. Despite opposition from environmentalists, Contact Energy and Genesis Power are seeking approval to build a 1.1 Mt per year LNG receiving terminal at Port Taranaki, which would be a potential customer of Queensland LNG. BG’s strategy is to be involved at all points along its LNG supply chains, perhaps one consideration in seeking to own Origin Energy.

Floating Liquefaction for Shell in Australia

Following many false starts for floating liquefaction (FLNG) over the past decade, Shell is now eager to speed the development of its Prelude field discovered in 2007 in the Browse basin, with up to 3 trillion cubic feet of gas potential reported so far. In April, Shell unveiled a 3.5 Mt per year floating gas liquefaction vessel, some 480 meters long and linked with carbon dioxide sequestration, to be located 450 kilometers northeast of Broome. In recent years other LNG projects have muted FLNG solutions (e.g., Scarborough, Sunrise, and Timor Sea), but high costs have prevented them from securing final investment decisions from the joint venture partners. Prelude has a better chance, as Shell has three key advantages. First, it owns 100 percent of the equity in the project. Second, it needs to add Asian liquefaction capacity to its portfolio in order to benefit from the Asian demand surge. And finally, it wants to confirm its position as an LNG technology leader.

The Gorgon Project has a reported gas resource base of some 40 tcf of gas among several fields 200 kilometers offshore in up to 1,300 meters of water. Earlier this year, the Gorgon joint venture, which includes Chevron, ExxonMobil, and Shell, announced plans to increase the proposed LNG project facilities on Barrow Island to three liquefaction trains, each with a capacity of 5 Mt per year. A phased-development of “Greater” Gorgon, beginning with the North Gorgon field, involves sub-sea wells tied back to a gravity-based platform, located in the shallower water east of the field, with the processed gas exported via a trunk line to the LNG plant. The carbon dioxide content of the gas, 12 percent to 15 percent, requires sequestration as part of the development plan. In 2005 the estimate was $10 billion, but for the project as currently described, it is more realistic to expect costs in excess of $25 billion and a start-up delayed to 2015, based on a final investment decision in 2009.

Gorgon’s increased scale belies a history of delays for a project that in the late 1990s was expected to be on-stream in 2003. Indeed, Chevron has a track record of delays in making firm investment decisions in its large international gas development projects (e.g., Angola LNG and Escravos GTL in Nigeria also seem destined to see their planned start-up delayed by as much as a decade). The company has long since stopped providing schedules for these projects on its Web site. With so many other projects vying for contracts and resources, however, the Gorgon partners run the risk of missing the current opportunity for gas suppliers. Chevron’s anxiety is perhaps reflected in its March 2008 announcement to develop its 100 percent equity-owned, 4.5 tcf Wheatstone field, discovered in 2004, as a separate 5 Mt per year LNG project. But it may have trouble persuading the Australian government, buyers, and contractors that it can deliver this project in a more meaningful timeframe.

The main environmental objections to LNG industry infrastructure developments in the past year have focused on the Browse basin, following proposals by Woodside Petroleum, Inpex (Ichthys project), and others to establish plants along the Kimberley coast or on offshore islands. The government favors a single site with multiple trains, and developments will be delayed until that site is selected.

Papua New Guinea (PNG) LNG Agreements Reached

Although Australia is getting most of the attention, progress is also evident in Papua New Guinea. The PNG LNG consortium led by ExxonMobil (with partners Oil Search, Santos, AGL Energy, Nippon Oil, and local landowners) proposes to commercialize the Hides, Angore, and Juha fields, and the associated gas reserves at the operating oil fields of Kutubu, Agogo, Gobe, and Moran in Papua New Guinea’s Southern Highlands and Western Provinces. The proposed project will treat the natural gas at a conditioning plant at Hides and pipe it to a 6.3 Mt per year liquefaction plant 20 kilometers northwest of Port Moresby. The partners signed a joint operating agreement in March and announced a fiscal agreement with the government in April. The government is also expected to exercise its back-in right to a 22.5 percent equity in the gas fields. Start-up schedules are yet to be determined but 2013 seems the earliest, depending on securing sales agreements and making final investment decisions. Front-end engineering and design is likely to begin in 2008.

Clearly, many decisions must be made over the next few years regarding the future of gas liquefaction in Australia and the surrounding areas. But even if a fraction of these projects are actually developed, Australian LNG will have a major impact on the global gas market.