WA LNG projects’ fortunes reflected in Greater Gorgon

Nov. 13, 2006
Problems faced by the Greater Gorgon Project in Western Australia reflect challenges to all the potential LNG projects in the region (map).

Problems faced by the Greater Gorgon Project in Western Australia reflect challenges to all the potential LNG projects in the region (map). Greater Gorgon is the largest among potential LNG export projects in Western Australia.

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Phase 1 will provide 10 million tonnes/year (tpy) of LNG capacity; second phase should deliver the same again.

As with any project of this scale, there have been major challenges. Costs have increased, the schedule has slipped, the development plan has been criticized by environmental authorities, and uncertainties remain over partner alignment.

  • Phase 1 is now expected to cost upwards of A$16.8 billion (US$12 billion), a 53% increase on the 2005 estimate of A$11 billion.
  • The Western Australia (WA) Environmental Protection Agency (EPA) has concluded that the project is environmentally unacceptable. The gas plant and liquefaction trains will be located on Barrow Island, a Class A nature reserve, and there are concerns about the effect of development on local wildlife.
  • ExxonMobil Corp., which is a 25% partner in the project, has yet to announce any sales agreements for its share of planned LNG volumes.

Despite these problems, the fundamental business case for the project is strong. The Pacific Basin LNG market is short of supply over the next 5-7 years, and buyers are beginning to accept the new reality of higher gas prices. Thus rising costs of the Gorgon development can, to an extent, be passed on to buyers.

The final decision on environmental approval rests with WA’s Environment Minister who will consider social, strategic, and economic effects, alongside environmental issues. Wood Mackenzie expects the minister to seek a solution that will mitigate the environmental impact of the project and allow it to proceed, largely as planned.

ExxonMobil’s position is a relatively straightforward commercial consideration. As and when the company secures a price for its gas that accommodates risks attendant to the project and when development costs are clearer, ExxonMobil will likely conclude sales agreements and stand alongside the other partners.


Three major challenges face Greater Gorgon, any of which can seriously impede the entire project, if not addressed in a timely manner.

Rising costs

The estimated cost of developing Greater Gorgon has risen to around A$16.8 billion (US$12 billion) from A$11 billion quoted in September 2005 and could rise further. Cost increases are being encountered in most elements of development, including rig rates, steel, and cost of skilled labor. This puts pressure on project economics and raises questions about whether the sales price will be able to support increasing development costs.

Environmental concerns

On Barrow Island, a Class A nature reserve and proposed location of the processing facilities and liquefaction plant, there are strict quarantine regulations. The island is also a nesting area for flatback turtles, with two nesting beaches adjacent to the proposed LNG plant.

On June 6, 2006, Western Australia’s Environmental Protection Agency issued Bulletin No. 1221 stating that Greater Gorgon’s joint venture posed an unacceptable risk to the marine ecosystem through dredging and possible introduction of non-indigenous species.

It also stated that, because very little data are available on the life cycle and behavior of the turtles, it was impossible to identify management measures that would ensure their wellbeing. Consequently, the EPA considered that the proposals were environmentally unacceptable.

The EPA decision is a recommendation to the state’s environment minister and also sets out conditions to which the project must adhere, if it goes ahead. Operator Chevron Australia is appealing the decisions, both the recommendation and the development conditions set.

Chevron has also stated that it is confident that the project will maintain an appropriate balance between environmental management and development on Barrow Island.

The final decision to approve development rests with the WA Environment Minister, who must take into account social, strategic, and economic impacts of the project, as well as the need for environmental protection. The result of Chevron’s appeals will be announced later this year.

A decision is also required from the federal environment minister, but in recent statements he has suggested support for the project. Given that the WA premier has also spoken favorably, the balance of current evidence suggests that the project will be approved.

ExxonMobil’s position

ExxonMobil has yet to announce any gas sales contracts for its equity volumes of LNG from the development. Most likely, this is primarily a result of commercial considerations from the company’s perspective. ExxonMobil is understood to be operating under a less favorable tax position than the other two partners (Chevron and Royal Dutch/Shell), due to its operations in the Bass Strait.

Under Australian tax rules, companies build up Petroleum Resource Rent Tax (PRRT) credits from exploration losses, which can be transferred between PRRT-liable projects. Neither Chevron nor Shell has any producing assets that are taxed under the PRRT regime, meaning that their PRRT credits may be utilized by Gorgon production.

ExxonMobil will likely be able to conclude contracts to sell its share of the LNG at a price that makes the project attractive within its global portfolio. This may still contribute some delays to the decision-making process, however.

Other issues

Other issues face Greater Gorgon that, while they may not threaten its viability, could still delay progress and dilute project economics.

BP’s position

BP holds 12.5% equity in two of three blocks that cover giant Io/Jansz field, plus a block covering Maenad and Orthrus fields and one over Geryon field. Io/Jansz field is an integral part of Phase 1 development. BP remains outside the framework agreement, signed in April 2005, which aligned the interests of the other three partners and allowed the current development plan to progress.

Recent press speculation has BP looking to sell out of the acreage. Any sale would be subject to pre-emption rights by the other partners, and Shell Australia has said it may look at the stake, if it came onto the market. If a third party were to purchase BP’s stake, it would remain outside the framework agreement and may only be able to negotiate a small equity stake in the project.

Domestic gas allocation

In February 2006, WA’s government issued a consultation paper regarding future domestic gas-supply arrangements for the state. The North West Shelf gas project (NWSGP) currently supplies around 70% of the WA domestic market, but essentially all gas reserved under the NWSGP state agreement has been fully contracted.

The state government is seeking to reserve an additional amount of NWSGP gas to meet future demand, as well as alternative supplies from proposed LNG developments on the WA coast.

Gas fields supplying the proposed developments lie in federal not state waters. As such, the state government has no direct rights to the gas, but it must approve onshore developments and grant export licenses.

The paper declared that it would be prudent to impose domestic-gas reservation requirements on future LNG export projects. WA Premier Alan Carpenter has proposed that 15-20% of gas reserves should be allocated to the domestic market. The Gorgon State Agreement reserves 1.85 tcf of gas for the domestic market, but the joint venture only has an obligation to supply this gas if it is economic to do so.

From a commercial perspective, the major stumbling block is price. Wood Mackenzie believes that NWSGP sells domestic gas at around a 60% discount to the price realized under its current Japanese LNG contracts, a discount well more than the cost of liquefaction.

Additional gas resources, such as the Chandon discovery, could increase the pressure on Greater Gorgon to supply the domestic market simply because current proven and probable reserves are already well in excess of requirements for a 10-million-tpy LNG project.

While the state government appears to back intervention, the federal government has taken a diametrically opposed view. In May 2006, the federal minister for Industry, Tourism and Resources stated that “artificial constraints on export capacity, such as domestic gas reservations, are not part of this government’s approach.”

Gas-transfer pricing

Residual pricing mechanism (RPM) is a method of generating a gas-transfer price, which is an accounting value, calculated solely for taxation when there is common ownership of upstream and downstream phases of a gas-to-liquids project. The upstream phase of a development will be taxed under PRRT terms, while the downstream phase will be subject only to corporation tax.

RPM calculates the transfer price between phases of a development. A feature of RPM is that the transfer price tends to rise throughout the project’s life, a function of greater ongoing capital expenditure in the project’s upstream phase. This will gradually shift more revenue to the upstream (higher tax) phase and steadily increase the project’s overall tax burden.

Within the scope of the regulations, however, lies room for an “advanced pricing arrangement” (APA), which would take priority over RPM. An APA is a negotiated transfer price, agreed between a project joint venture and tax authorities. It is understood that Chevron is looking to negotiate an APA for Greater Gorgon, but this could take up to 2 years to conclude.

Wider implications

The decision of Western Australia’s Environment Minister could have wide implications for the Australian gas export industry.

Five major projects, with capacity totaling around 40 million tpy, are proposed for the WA coast over the next 10-15 years.

If the minister were to rule against locating LNG facilities on Barrow Island, then those projects that propose to use other greenfield sites-specifically Ichthys and Browse-could be under threat.

INPEX-led Ichthys is located in Browse Basin and proposes to use two islands for its LNG facility. The Woodside-led Browse project will operate in and around Scott Reef, which could invoke environmental concerns.

If the minister rules in favor of locating of LNG facilities on Barrow Island, it may be because it has been treated as a special case, as there have been oil operations on Barrow for more than 40 years. It has been the oil industry, specifically Chevron, that has effectively quarantined and helped maintain the island’s environmental integrity.

Possible beneficiaries of any tightening of environmental regulations are developments planned for brownfield sites. These include Pluto and Scarborough.

Pluto is planned for a quasi-brownfield site, adjacent to NWSGP and within the Burrup industrial area, while for the proposed Scarborough LNG facility, BHP Billiton plans to utilize a site south of Onslow in an area that has already been zoned for industrial development.

A major tightening of WA environmental restrictions could be of greatest benefit to Darwin, in the Northern Territory. There are currently 3.2 million tpy of LNG capacity at Darwin, with consent to raise this to 10 million tpy. The Darwin plant came on stream in February 2006 with an estimated 25 tcf of proven and probable gas reserves within 500 km.

The author

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Chris Meredith ([email protected]) joined Wood Mackenzie in 2005 as a research analyst in the Australasia team. He has worked on all aspects of Wood Mackenzie’s Australasian Upstream Service, as well as a number of consultancy projects in the region. Before joining Wood Mackenzie, he worked as an equities analyst for an asset manager. Meredith is a chartered financial analyst (CFA) charterholder and holds a BSc (honors) in chemistry from the University of St. Andrews.