Australia's LNG Sector Comes Under Strain
Summary
Australia has vast natural gas resources and has positioned itself as a major producer. However, the higher costs of liquefied natural gas (LNG) plant construction likely will lead Australia to delay, cancel or scale down proposed LNG plants. Increasing supplies from other sources, including the United States, could also mean that Australia's LNG producers will not see the returns they once expected.
Analysis
Japan's Tohoku Electric Power and the United States' Chevron Corp. recently signed a 20-year contract for the U.S. energy major to supply the Japanese electric utility with 1.2 billion cubic meters of LNG annually from the Wheatstone project in Australia. Although the volume is small, the contract comes as pressure is building on oil and natural gas firms in Australia's LNG sector.
Though Australia has prodigious natural gas resources, the country's geology, remoteness and economy have put it in a difficult position in competing financially with other growing natural gas producers. However, timing has been on Canberra's side. The technological revolutions that led other producers such as the United States to increase natural gas production occurred after Australia had begun developing its own expensive resources, so Canberra had a few years' head start in getting large quantities of natural gas to the market. As a result, Australia's LNG exports will rival the size of Qatar's, allowing it to become the largest exporter to the Asian market by 2020. Yet Australia's continued growth in natural gas exports could cease after the first wave of LNG projects come online, because capital that could be spent on increasing Australia's export capacity now has other, more profitable destinations that did not exist when Australia's natural gas export development began.
Australia's Natural Gas Resources
Australia has three primary sources of natural gas: conventional deposits, coal bed methane and shale gas. Combined, the country has an estimated 23 trillion cubic meters of technically recoverable reserves, half of which are from shale gas deposits, one-fourth of which are from coal bed methane deposits and one-fourth of which are from conventional deposits. Currently, only coal bed methane and conventional deposits are commercially producing.
Once conventional offshore gas resources off the coast of northwestern Australia and coal bed methane extraction technology became economical in the east, it became apparent that Australia was going to emerge as one of the world's largest LNG exporters in a short time. As the 2000s progressed, Europe and North America experienced declines in natural gas production, so Australia put plans in motion to erect several LNG plants in order to meet growing demand. Right now, Australia has three liquefaction plants in operation and seven under construction that will be completed by 2017, increasing Australia's export capacity from about 30 billion cubic meters to nearly 120 billion cubic meters. Other projects and expansions are being proposed.
By the early 2010s, it became apparent that North America was experiencing technological advances that led to gigantic increases in natural gas production, potentially allowing North American producers to become competitors for shares in the Asian natural gas market. Thus, producers in Australia quickly finalized LNG plans, aiming to bring their plants online quickly and get long-term contracts signed with customers to ensure that they would continue to have a market share.
Expensive Natural Gas
During the construction process, many of Australia's LNG projects have seen significant cost overruns. The budget for Chevron's Gorgon project increased by 40 percent to $52 billion, and Woodside Petroleum canceled its proposed Browse project. At the same time, coal bed methane production has run into problems with environmental groups and new regulations, and because accessing the resources turned out to be more difficult than initially thought, more complex and expensive methods of extraction are required. This could force LNG plants in Queensland to buy conventional gas from the market instead.
These developments have pushed break-even costs for the new LNG projects to between $11 and $12 per million British thermal units loaded at the terminal -- not including shipping costs, insurance or regasification. Even when factoring in Australia's relative proximity to Asian markets, future LNG exporters -- the United States, Canada, Mozambique, Tanzania and Russia -- are all expected to have lower break-even landed costs (or cost at the point of off-loading) to Asian markets. (The United States, for example, is expected to have break-even landed costs of under $10 for its natural gas exports to Asia.)
The plants that are under construction will be finished, and most of the capacity has been locked up in long-term contracts of 15 to 25 years, such as the deal between Chevron and Tohoku. Most of these contracts include prices that are indexed to the price of oil, but this pricing mechanism can be revised if Asian natural gas prices fall. Japanese and Indian companies are already pushing to renegotiate the contracts, and Chevron lost a contract it thought it was about to finalize with Korea Gas Corp., which wanted a different pricing mechanism.
By 2020, new supplies from emerging LNG-exporting countries could lead Asian natural gas prices to drop significantly -- below Australian break-even costs. At that point, the Australian natural gas companies will attempt to force their customers to honor the contracted prices, but in the longer term the firms will be pressured into selling natural gas at market prices, perhaps taking capital expenditure write-downs in the process.
In addition, future LNG projects and expansions may not materialize anytime soon, as they simply are not competitive. The increased costs of Australian LNG projects could mean that Canberra will miss out on new LNG contracts signed in the 2020s. In order to prevent this, Australian LNG project costs need to be reduced by 30 percent. For instance, U.S. LNG plants are being proposed with costs of about $2,000 per metric ton of capacity, while Australia's have a cost of about $3,000 per metric ton of capacity.
The Reasons for High Production Costs
Several factors have helped drive up the costs of Australian LNG projects. The simplest explanation is the concurrent boom in Australia's mining and energy sectors. LNG projects have to compete for material supplies and labor pools with massive coal and iron ore projects. Australia's remote regions, where the natural gas is located, simply cannot metabolize the influx of demand for workers and materials like concrete without significant inflation. Moreover, multiple offshore production platforms and LNG projects are competing with each other, leading to cost hikes as projects increase wages by as much as 30 to 40 percent.
The remoteness of the projects is another factor in higher labor costs. It is difficult to entice families to relocate to small remote towns with little else but the construction site. This forces producers to offer high wages, at times in addition to the cost of building accommodations or flying workers in and out of the work sites if they remain with their families in populated areas. The strength of labor unions will continue to contribute to the high labor costs. In addition, workers' productivity has been low; according to a report by the McKinsey consultancy, Australian workers take 30 percent longer to do engineering, procurement and construction work than workers in the United States. In addition to the labor problems, Australia also has a complex environmental regulatory process that is longer than those seen in North America, adding time and costs to projects.
The natural gas projects' remoteness causes other problems as well. These projects require considerable investment in infrastructure besides the liquefaction plants. For instance, one plant involves the world's fourth-longest subsea pipeline. In the United States, infrastructure is developed enough that only the plants themselves have to be built. Existing reservoir problems for coal bed methane development could decline with further technology advancements, but a lot of the technological improvements that would lead to lower production costs for coal bed methane likely would also translate into lower production costs in North American shale. Additionally, Australia needs more coal bed methane wells than the United States does to produce the same amount of natural gas.
The Outlook for Australian Shale Gas
Most of Australia's LNG projects under construction will be processing feedstock from conventional and coal bed methane sources, so if Australia is to develop its shale gas, it will need new LNG plants. In the longer term, shale gas could supplant or supplement coal bed methane, but this highlights the real problem: Australia's natural gas infrastructure. Half of Australia's shale gas is believed to be in the Canning Basin in Western Australia. The complete lack of existing infrastructure and the scarcity of water for hydraulic fracturing means that the development of the Canning Basin on a commercial scale will not occur until far into the future.
Initial shale production will come from the Cooper Basin, which also produces conventional hydrocarbons. However, the existing infrastructure was built only to serve the domestic market. Capacity is only a few billion cubic meters, so any more production would require the construction of massive pipelines spanning a great distance. Moreover, unlike most shale basins in the United States that are marine shales, the Cooper Basin is home to lacustrine shales, which have not proven to be nearly as successful for development as marine shales. In addition, the formation is overpressurized, requiring greater strength and more expensive proppants -- solid materials used to keep a hydraulic fracture open -- for production. Both of these contribute to higher development costs -- in the $6 to $9 per million British thermal units range, compared to the $2 to $3 per million British thermal units cost in the United States.
It will be a long time before Australia can support the drilling industry needed to sustain shale gas exports. Wells drilled into shale formations have high initial recovery rates but quick declines in output. In order to sustain production, new wells have to be drilled often to replace the quick declines in wells drilled just a few months earlier, and frequency of drilling needed will cause problems for Australia. The sheer number of rigs required is staggering and also raises the risk of many of the same factors affecting the construction of LNG plants. Sustained drilling and hydraulic fracturing will require a large workforce -- not only a great number of engineers and geologists for drilling and production planning, but also truck drivers for delivering fracturing fluids, proppants and other materials from the service industry. All of this will lead to significant costs for shale gas extraction and could cause Australian shale gas prices to become inflated for several decades.
Natural Gas Europe is pleased to provide this article in cooperation with Stratfor, a Natural Gas Europe Knowledge Partner. For more visit http://www.stratfor.com/ Follow Stratfor: @stratfor on Twitter | Stratfor on Facebook