The robust growth predicted for China, India, and other Asia Pacific region economies in the coming decades will drive a surging demand for liquefied natural gas (LNG). Among gas exporting countries, nowhere is that prospect having more impact than Australia. With a spate of big new projects coming on stream in the next few years, Australia is soon expected to become the world’s largest exporter of LNG.
With abundant gas reserves and proximity to major Asian markets, Australia in the past 10 years nearly tripled its LNG exports to 1 trillion cubic ft per year [Tcf/y] in 2012. Most of these exports are sold under long-term contracts to Asian electric and gas utilities with additional sales to spot market purchasers. Australia now ranks third in LNG exports behind Malaysia and global leader Qatar. A series of projects now in development is expected to bring more than 3 Tcf/y of new capacity on line over the next 3 years.
LNG Production and Transport
The LNG manufacturing process is used to convert natural gas to a form in which it can be stored and transported over long distance where there are no pipelines. The field-produced gas is processed to remove impurities and cooled in stages in a liquefaction plant until liquefied at approximately −260°F.
LNG transport requires cryogenic tankage to keep the cooled cargo in liquid phase. The vast majority of LNG production operations require outbound gas to be shipped in large, specially designed, seagoing LNG carriers that transport liquefied cargoes to distant terminals where regasification plants convert the LNG to a gaseous state for end-user delivery.
Historically, LNG projects have been a development strategy reserved for gas discoveries that are larger than local markets can accommodate, enabling the commercialization of resources that would otherwise be stranded. However, growing demand is turning LNG into an additional commercial option for gas resources already in production. Several Australian projects are soon to liquefy onshore coal seam gas (CSG), also known as coalbed methane, and North American liquefaction of onshore shale gas will begin shortly.
Regardless of the type of project, investment in plant facilities and LNG carriers when needed is very expensive. Thus, project financing has historically required a large, dependable, and long-term customer revenue stream arranged mainly in advance before a final investment decision (FID) is made.
“The typical LNG EPC (engineering, procurement, and construction) project has cash flow of a Fortune 100 company,” said Richard Davis, manager of oil, gas, and chemical at Bechtel. The Australian projects are no exception.
Capacity to Exceed Qatar
“Once everything under construction is built, which is scheduled to be by the end of 2017, Australia will have more capacity than Qatar,” said Rafael McDonald, director of global gas at IHS CERA.
Another half-dozen projects, including offshore gas and onshore CSG developments, await their FID, which would extend Australia’s growth in LNG production. However, despite a tight Asian market and recent industry projections that regional LNG prices will soon hit record highs, escalating construction costs and budget overruns on current Australian projects are a growing concern that could shelve or delay FIDs on some new grassroots projects or planned expansions of existing projects.
The majority of the country’s gas production, including almost all of its export gas, comes from the Carnarvon basin offshore northwest Australia. However, new field developments in the Browse basin and potentially the Bonaparte basin, both east of the Carnarvon, will bring significant levels of production into the market in the next several years. Much of it will feed planned LNG export facilities. Among the projects is the Shell Prelude floating LNG (FLNG) development, the world’s first FLNG project to receive an FID.
Australia’s onshore CSG resources in Queensland’s Bowen and Surat basins will also become a gas source for LNG export operations with the expected completion of multiple, side-by-side liquefaction projects near Gladstone on Curtis Island offshore northeast Australia in the next 2 years.
LNG Production Today
Current Australian LNG output comes from three projects, the massive Northwest Shelf project, the Darwin project, and the Pluto project.
It was Northwest Shelf that launched Australia’s involvement in LNG production in the 1980s. The project undertook the development of huge gas and condensate discoveries in the Carnarvon basin offshore Western Australia. Gas production began in 1984 from the North Rankin A platform, at the time the world’s largest offshore gas-producing facility, with initial supplies going to the domestic market. With completion of the Karratha Gas Plant and related tanker loading facilities, LNG production and export began in 1989.
Since then, the Woodside-operated project has grown to include four platforms, a floating production, storage, and offloading (FPSO) system—the original FPSO having been recently replaced with a newly built unit—five onshore LNG processing trains, two domestic gas trains, and added export loading capacity. Northwest Shelf sells LNG principally to long-term Japanese and Chinese customers, with additional spot market sales.
The total capital invested in Northwest Shelf to date is nominally valued at USD 27 billion. The project is Australia’s largest oil and gas development, responsible for more than 40% of the country’s production, and one of the world’s largest LNG projects with a capacity of 2.1 billion cubic feet per day [Bcf/D]. Development continues, with the next phase to bring in two additional fields from new subsea wells, which will begin production in 2016 through tiebacks to the existing Goodwyn A platform. Nonoperating interest holders in Northwest Shelf are Shell, BHP Billiton, BP, Chevron, Mitsubishi, and Mitsui.
The USD-3.8-billion Darwin project, operated by ConocoPhillips, became Australia’s second development to convert field gas to LNG. The project began with development of the 1995 discovery of the Bayu-Undan gas field in the Bonaparte basin, approximately 830 miles northwest of Darwin, Northern Territory, in the Joint Petroleum Development Area of the Timor Sea administered under a treaty between Australia and Timor-Leste.
Phase one involved the construction of an offshore gas recycling facility that processes wet gas and separates, stores, and offloads condensate, propane, and butane for sales to market. Under phase one, the remaining dry gas was reinjected into the reservoir. Phase two consisted of the construction of a gas liquefaction train at Darwin and the installation of a pipeline linking it with the field. Since 2006, the field’s dry gas has been shipped to the Darwin plant to produce LNG for export to Japan and for spot market sales. The plant is capable of producing 466 million cubic ft per day (MMcf/D). Darwin’s nonoperating interest holders include Santos, Inpex, Eni, Tepco, and Tokyo Gas.
The Pluto project, operated by Woodside, is the most recent development to begin LNG export operations in Australia. The USD 15 billion project produces from the 2005 Pluto gas discovery in the Carnarvon basin 119 miles northwest of Karratha and 500 miles north of Perth.
Five big-bore subsea wells in more than 2,600 ft of water are tied back 17 miles through dual 20-in. pipelines over a steep escarpment to a normally unstaffed riser platform at 53 ft water depth. Production flows through a 36-in., 113-mile pipeline to onshore facilities, including a gas liquefaction train, on the Burrup Peninsula. A continuous monoethylene glycol injection system is used to combat hydrate formation over the long field- to-shore pipeline connection.
Woodside, which holds a 90% interest in the Pluto project, designed its wellbores with 95/8-in. production tubing as a cost-saving strategy to minimize the number of wells. A comparable LNG facility with narrower wellbores might have 10 or 15 additional producing wells with a higher total capital investment required. A further economizing measure was to build the plant with prefabricated megamodules, the world’s first LNG project to do so.
The Pluto LNG facility has a production capacity of 565 MMcf/D. The project has four dedicated LNG carriers that transport gas to Japanese utilities Kansai Electric and Tokyo Gas, each of which holds a 5% interest in the Pluto development.
Woodside will also produce the nearby Xena field, discovered after Pluto, with plans to develop it as a tieback to the Pluto production facility. Combined, the two fields comprise a 5-Tcf gas resource.
Production Soon to Soar
From its current base, Australia’s LNG production will soon begin to soar with capacity more than tripling in the next several years. The huge Gorgon project operated by Chevron is scheduled to begin exporting LNG in 2015, followed in 2016 by the Chevron Wheatstone project. In 2017, the Ichthys project operated by Inpex is slated to come on stream. The Shell Prelude project is expected to begin operation in that year or later. And these four are only the projects sourced from traditional gas.
Three other sanctioned projects, Queensland Curtis, Australia Pacific, and Gladstone, are each building pipeline and plant facilities to transport, liquefy, and export onshore CSG.
Global LNG demand is projected to increase by 6.3 Tcf/y by 2020, according to IHS. “The [global] capacity under construction is 104 million [metric] tons or 5 Tcf per year,” McDonald said. “There are some plant retirements that we expect by the end of the decade, so we anticipate that an additional 1.7 to 2.2 Tcf will need to be constructed. That means we will need another 1.7 to 2.2 Tcf of investment decisions in the next 3 years. The window for these Australian projects—and all liquefaction—remains open, but it is closing quickly.”
LNG spot prices for Asian delivery in the second half of December 2013 were about USD 17.90 per million British thermal units, a 28% year-over-year increase. Bank of America recently reported that LNG demand—often measured by growth in regasification capacity—is expected to rise five times faster than liquefaction capacity in 2014. Thus, robust market conditions are highly likely to prevail as the new Australian projects already committed come on stream.
However, looking further ahead, market risk could increase for Australian projects awaiting FID and for some capacity expansions, especially if Asia Pacific regional economic growth tapers and the LNG market begins to soften.
“The one concern about Australia that is sticking out in the global LNG industry is that it has become the most expensive place in the world to build liquefaction facilities,” McDonald said. “There have been significant cost overruns and delays for these projects. And that is the biggest challenge. It’s how do they keep their costs in check? So far they have not done so.”
Currently, the expectation of high prices has attracted investment in new LNG export projects globally, including some geared toward spot rather than long-term contractual sales. Some projects are adopting tolling business models in which plant developers have no investment interest in upstream field development and do not bear the associated costs. Future Australian projects could be at a disadvantage for competitive new projects with lower cost structures.
In particular, low-cost shale gas is expected to enter the LNG market with the planned startup of US export operations in 2015. Initial volumes may be low but expansion is highly likely. There is a raft of new North American LNG export development proposals, among them projects using the tolling model. In the long term, the question arises whether Asia Pacific LNG prices will eventually be pulled downward by the lower price basis of North American gas or remain firmly linked to the higher price basis of Asia Pacific oil.
In any case, Australia is ideally located to supply the world’s largest LNG markets, including those growing the fastest. Japan is the world’s No. 1 LNG importer, followed by South Korea and China. “By 2020, we think China will have passed South Korea for that No. 2 spot,” McDonald said. “There is a lot of room for growth in India, which by that time should be the world’s fourth largest importer of LNG.”
Australian projects continue to rely on long-term contracts as the foundation of their business model. “They already know who is going to buy from them for 20 years with a general idea of the transaction price, at least for a majority of the capacity, before they go ahead,” McDonald said.
New LNG Projects
Australia’s biggest new planned project is Gorgon, one of the world’s largest gas projects and the largest single-resource investment in Australian history with an estimated cost of USD 54 billion.
Gorgon will develop major gas and condensate resources in the Carnarvon basin offshore northwest Australia and bring the production to LNG and other processing facilities being built on Barrow Island. Using subsea well completions and tiebacks to shore, Chevron will develop the Gorgon field in 660 ft of water 80 miles offshore and the Jansz-Io field in 4,300 ft of water 125 miles offshore. First gas is slated for late 2014 with LNG shipments to begin early the following year.
The project will also inject and store up to 3.75 million metric tons per year (T/y) of CO2 in a deep geologic reservoir beneath the island, making Gorgon the world’s largest commercial-scale greenhouse gas storage site.
The Barrow Island complex will include three liquefaction trains with a production capacity of 2 Bcf/D, condensate-processing facilities, a plant to supply up to 275 MMcf/D of gas to the Western Australia market, and the CO2-handling facilities. LNG will be exported primarily under long-term contracts to customers in Japan, South Korea, China, and India, with some additional spot market sales. Nonoperating interests in Gorgon are held by ExxonMobil, Shell, Osaka Gas, Tokyo Gas, and Chubu Electric Power.
The Chevron Wheatstone project will develop gas from the Wheatstone and Iago fields of the Carnarvon basin in 600 ft of water, approximately 125 miles north of Onslow, Western Australia. Subsea wells at the fields will be tied into a processing facility on the water’s surface, from which a trunk line will transport the gas to an onshore hub facility 71⁄2 miles west of Onslow at Ashburton North. There a two-train facility is under construction that will produce 1.2 Bcf/D of LNG for export, along with a gas plant to supply the domestic market. Gas and LNG production are slated to begin in 2016.
Much of Wheatstone’s LNG is committed under long-term contracts to Japanese electric and gas utilities, including Kyushu Electric Power which holds an equity position in the project. There are also plans for gas production from the future Julimar and Brunello subsea fields, operated by subsidiaries of Apache and Kuwait Foreign Petroleum Exploration Company, to be sent through the Wheatstone processing facility to the Ashburton North hub. Chevron has signed joint-venture agreements with both companies, giving them equity interests in the project. Wheatstone will be Australia’s first LNG development to attract large amounts of third-party gas. Other nonoperating interests in Wheatstone are held by Shell and PE Wheatstone Pty (part owned by TEPCO).
In the Browse basin underlying the Timor Sea, Japan’s Inpex is developing the Ichthys field in 853 to 919 ft of water 137 miles off the northern coast of Western Australia. Subsea wells will be tied to a floating central processing facility (CPF) for gas and an FPSO vessel for condensate, from which the produced condensate will be transferred to tankers delivering to markets. Gas will flow through a 550-mile pipeline that will connect the CPF with a two-train LNG processing plant being built at Blaydin Point on the Middle Arm Peninsula in Darwin Harbor.
The pipeline will be the longest offshore gas line in the Southern Hemisphere and the fifth longest in the world. While the Blaydin Point facility primarily will produce LNG, plant processes will also yield some liquefied petroleum gas (LPG) and additional condensate.
At peak levels, the planned facilities will produce an estimated 1.1 Bcf/D of LNG for utility customers in Japan and Taiwan, as well as 100,000 B/D of condensate and 52,000 B/D of LPG that will be sold on world markets. The estimated resources of the USD-34-billion Ichthys development are 12.8 Tcf of gas and 527 million bbl of condensate, with production slated to begin in 2017 and expected to continue for some 40 years. Ichthys nonoperating interest owners include Total, Tokyo Gas, Osaka Gas, Chubu Electric, and Toho Gas.
Shell FLNG Technology
The Shell Prelude project is also scheduled for startup in 2017. All production, storage, and offloading operations will take place from the FLNG vessel, which when completed will be the world’s largest offshore floating facility. The project, estimated to cost between USD 10.8 billion and 12.6 billion, will produce gas and liquids in 820 ft of water from the Prelude field of the Browse basin about 125 miles offshore northwest Australia.
The vessel, being built in South Korea, is designed to produce 473 MMcf/D of LNG, 106,000 B/D of liquids, 26,000 B/D of condensate, and 12,600 B/D of LPG. Cargoes will be offloaded directly to vessels bound for Japanese and other markets. When done with field production in 20 or 25 years, the vessel can be moved and deployed in another production operation, possibly with some reconditioning in dry dock. The hull has a 50-year life design. Prelude’s nonoperating interest holders include Inpex, Kogas, and OPIC, a unit of CPC.
Adding to Australia’s anticipated gas export surge are the three CSG-to-LNG projects. The Queensland Curtis project, led by BG Group subsidiary QGC, will be the world’s first to convert CSG to LNG with the planned startup of liquefaction and export operations in 2014. QGC has built a 336-mile pipeline to connect its CSG fields in the Surat basin with a two- train LNG facility soon to be completed on Curtis Island. The company has rapidly expanded drilling activity in its ongoing production operations to meet the expected demand increase from the new plant.
Major customers of the project, currently valued at USD 20.4 billion, will be utilities and other gas users in China, Japan, Singapore, and Chile. Among them, China National Offshore Oil Company (CNOOC) has taken a 50% interest in the first liquefaction train while acquiring additional interests in CSG reserves and exploration licenses held by BG and obtaining an option to invest in potential plant expansion. BG and CNOOC have jointly invested in four LNG tankers that will serve the project. Tokyo Gas has taken a 2.5% interest in the second liquefaction train with additional interests in reserves and exploration licenses. Together, the trains will be able to produce 1.1 Bcf/D of LNG.
The Australia Pacific project is a joint venture between Origin Energy and ConocoPhillips, each holding a 37.5% interest. The project, with a current cost estimate of USD 25.3 billion, will transport CSG from Origin’s ongoing production operations in the Bowen and Surat basins to liquefaction and LNG export facilities under construction on Curtis Island. Australia Pacific is designed to produce 1.2 Bcf/D of LNG and is slated to begin export operations in 2015.
Origin is responsible for the field development and CSG transportation portions of Australia Pacific, including construction of a 323-mile transmission pipeline connecting the fields with the LNG facilities. ConocoPhillips is responsible for building the two-train LNG processing and export complex. The remaining interest in Australia Pacific is held by Sinopec, the project’s foundation customer. Sinopec has contracted to receive an average of 1 Bcf/D of LNG from Australia Pacific on a 20-year basis, the largest LNG supply agreement in Australian history. Japan’s Kansai Electric will be the project’s other principal customer.
The Santos-operated Gladstone project, currently valued at USD 18.5 billion, will link Bowen and Surat basin CSG production with a planned two-train LNG facility on Curtis Island through a 270-mile pipeline that is under construction. Nonoperating interests in Gladstone are held by Total, Petronas, and Kogas, the latter two to be the project’s main customers. Plant startup is anticipated in 2015, and peak production will be 1 Bcf/D of LNG.
All three CSG-to-LNG projects have engaged Bechtel as the EPC contractor for the Curtis Island facilities. Joint teams for procurement, human resources, travel, accounting, legal, and community relations activities serve the LNG portions of the projects.
Costs Create Doubt
As the projects under development move toward completion, there is growing doubt about the next wave of projects awaiting FID and some planned expansions of existing projects because of the potential for cost overruns and delays.
Building massive LNG plants in remote places is inherently expensive because of the need to provide on-location living arrangements and pay travel expenses for large numbers of workers. Australia has high labor costs, and the influx of new projects has bid up the demand for skilled workers. This has led to shortages affecting not only the LNG projects but also Australia’s large mining sector.
Beyond the short supply of individual workers is a shortage of experienced subcontractors and specialist suppliers, which David Knox, chief executive officer and managing director of Santos, said may be Australia’s biggest skills hurdle.
Additionally, the rising value of the Australian dollar vs. the US dollar over several years has raised project procurement costs, although this effect has lately diminished.
A 2012 Credit Suisse report on global LNG estimated that development costs for several projects in North America and east Africa ranged from USD 1,500 to 2,200/T, while costs to develop most Australian greenfield projects ranged from USD 2,500 to 3,500/T. Concurrently, the Australian Bureau of Resources and Energy Economics estimated that the unit development cost of the Ichthys project could reach USD 4,000/T.
The current cost estimates for the Queensland Curtis, Australia Pacific, and Gladstone projects also reflect substantial increases announced over the past 2 years.
Last April, Woodside and its joint venture (JV) participants canceled the estimated USD-48-billion Browse project in favor of exploring less expensive alternatives. The project had called for the development of remote deepwater gas fields to be linked to a three-train onshore plant to produce 1.6 Bcf/D of LNG. In September 2013, Woodside said the JV had chosen the Shell FLNG technology as the development concept to move through the basis of design phase of the potential new Browse gas fields project.
In May 2013, Roy Krzywosinski, Chevron Australia managing director, said that more than a hundred billion dollars in future Australian LNG project commitments by numerous companies “hangs in the balance” unless changes in tax and workplace policies and work practices occurred. Government and industry had an 18- to 24-month window to make these changes, he said.
“We remain optimistic about the Australian investment environment, but it requires significant national leadership to improve our international competitiveness, including fiscal stability, increased productivity, and industrial relations changes that focus on Australia’s long-term interests,” Krzywosinski said.
In November 2013, Chevron said it was suspending plans to build a fourth train at Gorgon until it had a firmer understanding of development costs for the initial three trains. The company had already announced a USD-9-billion cost increase at Gorgon in 2012, citing labor costs and bad weather. In December 2013, Chevron said that the project cost had risen by another USD 2 billion to its current level of USD 54 billion.
For the Ichthys project, an August 2013 report by Sanford C. Bernstein Research said that the development could run as much as USD 10 billion over its USD-34-billion budget and come in as much as 18 months later than scheduled, although the report said that a weakening Australian dollar could mitigate some of this impact.
FLNG Looks Attractive
As project developers look for strategies that can better control costs and ensure long-term competitiveness, FLNG is beginning to look attractive as more than a means of economically developing small to modest-sized stranded reserves. Because FLNG avoids the need for onshore manufacturing facilities with their escalating construction costs, it could become an LNG technology of choice, and the use of multiple FLNG vessels could enable the development of larger discoveries. Additionally, the ability to reuse FLNG vessels in subsequent developments could reduce initial project investment risk.
Five Australian offshore gas export projects awaiting FID over the next several years are looking at using FLNG technology: Bonaparte (GDF Suez), Scarborough (BHP Billiton), Cash Maple (PTTEP), and Sunrise and Browse (both Woodside).
Many questions remain and how well FLNG technology performs in the field has yet to be seen. But it clearly is a concept gaining traction.
Equally clear is that LNG from a wide variety of projects will play a huge role in the future of Australia and the Asia Pacific region for decades to come.
Joel Parshall is the Features Editor for the Journal of Petroleum Technology.