Australia’s two LNG projects exported 19.6 million tonnes per year (tpy) of LNG in 2009/10, according to the Australian Bureau of Agricultural and Resource Economics and Sciences (ABARES). This made the country the world’s fourth-largest LNG exporter, behind Qatar, Malay­sia and Indonesia, and it is now poised to strengthen its standing.

“The Australian LNG market is booming,” claims Alex Cull, a partner at Norton Rose in Perth. “There are more than 20 additional LNG projects at varying stages, from conceptual de­sign through to approaching first gas. While some consolidation and attri­tion is likely, it is clear there is a big appetite for new LNG schemes.”

The combined value of the proposed LNG projects (see table on following page) has been put at $200 billion and ABARES believes that export volumes could top 40 mil­lion tpy over the next five years. This would propel Australia to second in the world LNG export rankings, behind Qatar (which has a 77 million tpy target).

“At present, around 55% of world­wide LNG capacity under construction is located in Australia,” ABARES says in its 2011 report. “By 2015-16, Aus­tralia’s LNG ex­ports are forecast to in­crease to 41 million tonnes, an increase of 126% from 2010-11.”

Analysts cite the demand for LNG in northern Asia as the driving force for expansion. Australia is ideally positioned to offer that market a reliable and efficient LNG supply. It can take as little as a week for a cargo from Australia to reach customers in Japan, China and Korea, which is roughly half the time it can take to transport from the Gulf. To underline this point, the 21 Australian LNG projects already have 27 separate offtake agreements in place (see table).

Australia’s stable political landscape and operating record also give strong assurances towards security of supply. In addition, the problems faced by the Fukushima power plant in Japan following the devastating earthquake and tsunami could increase scrutiny of nuclear power in the region. Japanese purchasers account for ten of the Australian LNG programme’s 27 offtakers, with JX Nippon, Kyushu Electric, Osaka Gas, Tokyo Gas, Tokyo Electric and Kansai Energy leading the charge.

All of this means Australia could be­come the largest supplier in the Pacific Basin market. But its projects come with considerable technical and cost issues. “Australian LNG projects are ex­pensive to develop,” explains Giles Farrer, analyst in the global LNG group at Wood Mackenzie. “On the west coast, the reserves are in challen­ging offshore reservoirs, often far from landfall. For many years, poten­tial LNG projects in Australia were not develop­ed because the major LNG buyers in Japan and South Korea were able to source cheaper LNG from elsewhere.

“In the last few years, however, the long-term price that Pacific LNG pro­jects can command has risen as the mar­ket has tightened,” he adds. “LNG de­mand in markets like China, India and South Korea has surged and sup­ply has struggled to keep pace with de­mand. With the rise in LNG prices, Aus­tralian LNG schemes are now more viable to develop.”

The Australian unincorporated joint venture (JV) also facilitates confidence. It is a well-established structure and, as many LNG schemes are undertaken using a JV model, is an attractive option for structuring multi-party transactions and getting international lenders comfortable with LNG projects as a whole.

“Financiers can take direct security over an unincorporated joint venture participant’s individual interest in the assets, whether of the venture assets as a tenant in common or of their separate assets associated with the joint venture, and therefore rank ahead of unsecured creditors, and share­holders of the participant,” Craig Rogers, a partner in the Brisbane office of Mallesons Stephen Jaques, says. “However, the financiers’ security interest over a participant’s interest in a joint venture will be subject to, and subordinated to, the interests of the other joint ventures, at least to some degree.”

A suppliers’ market

Karratha, located 1,260km north of Perth, was the first Australian LNG scheme to go live 22, years ago. The project company is North West Shelf Venture, formed by Chevron, Shell Development, BHP Petroleum, BP Developments Aus­tralia, Japan Australia and Woodside Energy). The facility is the country’s largest LNG project, providing over 65% of Western Australia’s gas production. The first two trains became oper­ational in 1989, the third in 1992, the fourth in 2004 and the fifth in 2008. Current capacity is 16.3 million tpy. The second project is the ConocoPhillips-backed Darwin LNG, which launched in 2006. It has a two-trains-in-one design with a 3.7 million tpy capacity.

So far, these projects have accounted for all of Australia’s LNG exports. A third project, however, should boost capa­city significantly before the end of the year – Woodside Energy-led Pluto LNG. The facility started processing in March with a safe start-up scheduled for August 2011. The project is for the development of coal seam gas fields in the Surat and Bowen basins, with the construction of a 450km gas transmission pipeline from the fields to a facility at Gladstone. The maximum capacity is 18 million tpy.

Pluto is set to lead a cascade of LNG deals. Four headline projects have already received final investment decision (FID) or are close to approval: Asia Pacific LNG (APLNG); Gladstone LNG; Queensland Curtis LNG (QCLNG); and Gorgon LNG (see box). The combined maximum capacity of the quartet is 28.1 million, more than double the existing capacity in the country. There is a long list of other LNG developments, backed by PTT, GDF Suez, ECW and MEO Australia, amongst others.

Planned Australian LNG projects

The Chevron-led Gorgon LNG is the most advanced of the crop. Construction began in late 2009 with the project earmarked to go live in 2014. Chevron announced in March it was reviewing the option to add a fourth train, pushing capacity from 15 million tpy to around 20 million tpy. A front-end engineering and design (FEED) contract is likely to be complete next year. Chevron has a second proposed project, the two-train Wheastone LNG, which will process gas at an onshore facility located at Ashburton North, 12km west of Onslow in Western Australia’s Pilbara region, and have a combined capacity of 8.9 million tpy. At present, the FEED process for Wheatstone is reaching its conclusion.

Gorgon and Wheatsone are just two of the LNG projects poised to get the green light this year. Gladstone LNG was approved in January, APLNG was given Federal environmental approval in February, Ichthys LNG opened invitations for FEED bidders in February and Prelude is due a FID before year-end. Seiya Ito, managing director at Inpex, sponsor of Ichthys, said in February: “[We should make] a final investment decision in quarter four 2011 ... Once all the environmental and development approvals are in place and we have reached a final investment decision we will be in a good position to start construction on Ichthys in early 2012.”

Finding funding

A topic of discussion remains where the $200 billion of capital expenditure needed to make these ambitious pro­duction estimates a reality will come from. Inpex says it will use a mixture of cash in hand, bank loans and “other methods” to develop Ichthys. These include project financ­ing, debt financing from JBIC and loans from commercial banks (Mizuho Finan­cial Group has also been linked to the funding) combined with guarantees from the Japan Oil, Gas and Metals National Corporation.

Sponsors are finding equity funding, at least for development activities, plentiful. Inpex issued new shares and a secondary offering in July 2010, which generated $6.6 bil­lion. “We intend to use the proceeds from the issuance of new shares in particular to fund the development expenditures of Ichthys, which is expected to account for approximately half of [our] aggregate expenditures and investments,” the firm said.

Other examples saw Santos raise $900 million in a hybrid issue to cover the early costs of Gladstone LNG, while Origin Energy has indicated it too could approach the capital markets for APLNG (although it did not rule out project finance in the future).

The strong liquidity of sponsors, their access to existing credit lines and the risk profile of the deals means banks’ project finance teams are unlikely to be early benefactors of LNG surge. Observers claim that banks are putting deals to sponsors but companies either have sufficient cash reserves or sufficient access to corporate financing. “Many of the oil and gas majors have incredibly strong balance sheets from which they can fund,” adds Rogers. “Alternatively, bond issues, at a corporate, rather than project level, are a source of funds for LNG sponsors.”

Out of the big LNG projects so far, only Pluto LNG had a project finance angle. When it closed in 2008 it featured a $1 billion JBIC loan and a $500 million commercial bank tranche, arranged by Bank of Tokyo-Mitsubishi. Even so, that $1.5 billion was a small component of the total $13.5 billion capital expenditure.

One niche for project lenders, particularly export credit agencies, could be supporting offtake and equity agree­ments. Tokyo Gas closed a $102 million loan with JBIC for its 1.1 million tpy contract with, and subsequent acquisition of a 1% stake in, Gorgon LNG.

“ECA involvement will be so important in getting any debt-financed LNG projects off the ground,” Cull remarks. “With likely development costs in some cases exceeding $40 billion, the project economics have to be robust, with strong long-term offtake agreements and with ECAs committing to large direct lending tranches and guarantees over commercial debt.”

Hope floats

The other hurdle to Australian projects closing non-recourse debt in any quantity is their use of cutting-edge technology. Amongst the proposed projects is a floating LNG (FLNG) scheme – the first of its kind – as well as coalbed methane (CBM) to LNG technology.

FLNG involves gas being processed at sea, but has not been tested on a large scale. Shell is developing the first FLNG – fittingly called Prelude – which will centre on a 500m vessel deployed off the coast of north-western Australia. Environmen­tal approval was granted in November 2010 with a final investment decision due in the middle of the year. “For me, Prelude, as the first floating liquefaction facility in the world, is a real game-changer,” Cull comments. “It is a big step in com­mercialising what might otherwise be stranded gas reserves.”

Developers have identified over 150 gas fields in which FLNG could be deployed and Australia and Asia, with a large number of gas fields far off shore, are high on the list of targets. Even so, the lack of precedents means a lack of financing confidence. Shell is likely to fund all of Prelude with a mixture of equity and maybe some corporate debt.

CBM – or coal mine methane (CMM) to LNG – in­volves extracting gas from coal deposits, and is the basis of ConocoPhillips’ and Origin Energy’s APLNG. “The tech­nology is not new,” Farrer comments. “The real chal­lenges come through the scale of the facilities and the number of wells. We do not see FLNG taking off in the same way. It is entirely new technology and, if the pilot projects were not sponsored by oil giants, it would be hard to see them actually get off the ground. That said, in the long term FLNG could still carve out a decent niche in the sector.”

The issues for CBM are more likely to centre on water management (the salty nature and poor quality of CBM water means that it has the potential to cause environmental harm if released) and land access and use (such as the nego­tiation of purchase, access and use of land and competing interests with mining and petroleum peers). “Perhaps most importantly, [these projects require] a commitment of funds before the reserves risk window has narrowed and overall decline curves firmed up anywhere near the degree that banks are used to for conventional gas projects,” Cull remarks. “Banks will need to get comfortable taking on more risks, and that may come at a price. As such, non-recourse debt is perhaps unlikely to be available in the construction stage. Once a project is up and running, there could be scope to refinance on a non-recourse basis.”

Rogers echoes this, in particular the assumptions lenders make in terms of the nature, quality and quantity of reserves as compared with conventional LNG projects. “CBM to LNG projects have extended development periods before full field production can be achieved, and require significantly more drilling to sustain the gas flow required for liquefaction,” he says. “Proving up CBM reserves can be more difficult than for conventional gas, and may not occur until after each well has been completed – creating debt sizing and timing challenges.”

In addition, new tax legislation could affect projects. The Australian Government introduced the petroleum resource rent tax (PRRT) recently, which “applies to all petroleum projects in offshore areas” and means the projects are subject to the excise and royalty regime. The Government also re­cently announced plans for a carbon tax. No starting price has been confirmed but it is anticipated to be at least A$20 per tonne of carbon dioxide, with a fixed annual increase. A transition to an emissions trading regime is anticipated within three to five years, creating further uncertainty for lenders.

“[Both the PRRT and carbon taxes] have created debt sizing and other financing issues for borrowers, with some lenders taking a very conservative approach,” Roger states. “Draft legislation in respect of the PRRT will be released in the next six months and will be subject to further consideration and debate. This profit-based tax, which can poten­tially have a significant effect on project economics, will apply from 1 July 2012.”

The financial barriers are, perhaps, not as significant as the logistical ones. Farrer believes the biggest issue that Australian LNG faces is project delivery, specifically labour and resources, especially when competing with the already intense mining and natural resources developers.

“The current programme would have at least seven LNG trains on both sides of the country under construction at one time. Is there enough labour, equipment or expertise in the country to meet this demand? As construction resources tighten there is a danger that costs will start to spiral and development plans will be delayed. If that happens, then Australian LNG could become less competitive against some alternative suppliers of LNG.”

As such, the success of the LNG programme may not be down to funding; liquidity is very strong. While the hefty price tags for the LNG projects mean that banks will need to be involved in some capacity, project finance will prob­ably not be the most popular solution in the short term.

 The big four projects

Gorgon LNG
Status: In construction
Size: $42 billion
Description: The scheme centres around 18 wells off Barrow Island. A 70km subsea pipe will be developed for the three LNG trains, which will each be able to produce 5 million tonnes per annum of LNG.
Sponsor: Chevron, ExxonMobil and Shell
Completion date: 2014
Maximum capacity: 15 million tpy

APLNG
Status: Awaiting FID
Size: $18 billion
Description: The development of existing coal seam gas fields in the Surat and Bowen basins. It will involve the construction of a 450km gas transmission pipeline from the fields to a facility at Gladstone.
Sponsor: Origin Energy and ConocoPhillips
Completion date: 2015
Maximum capacity: 8.6 million tpy

Gladstone LNG
Status: Approved
Size: $16 billion
Description: An innovate project that will see coal seam gas (CSG) processed into LNG. The scheme is being developed in the Gladstone region of Queensland. It will involve a 420-kilometre gas transmission pipeline and a two-train LNG plant on Curtis Island plus associated infrastructure.
Sponsors: Santos, Petronas, Total and KOGAS.
Completion date: 2015
Maximum capacity: 7.8 million tpy

Queensland Curtis LNG (QCLNG)
Status: Approved
Value: $7.9 billion
Description: The expansion of QGC’s existing coal seam gas production in the Surat Basin of southern Queensland. The project will see the construction of 540km of gas pipeline as well as a natural gas liquefaction plant on Curtis Island, where the gas will be converted and exported.
Sponsor: BG Group
Completion date: 2014
Maximum capacity: 8.5 million tpy