Much has been written about the competitiveness of Australian LNG in global markets. Until a few months ago, this discussion centred on comparison of commercial terms of Australian contracts versus the threat of US hub-based pricing terms. However, as oil prices have plummeted by 50% since mid 2014, the debate has now become one about relative cost of supply between future LNG projects. On this basis, Australian projects do not compare favourably to the coming onslaught of US LNG exports into traditional LNG Asian markets. In fact, a recent Harvard study stated that ‘most Australian LNG schemes are unprofitable’ due to their costs in the range of US$3000/t as compared to the US projects which have costs in the US$700-$900/t.1
For consumers of LNG, especially those in Asia that buy most of their gas on oil-linked contracts, the purchase price of LNG has dropped as oil prices have fallen. If their contracts have a ‘floor’ oil price, the impact on LNG prices may be dampened and not as dramatic – but still significant. As coal prices have also fallen (though not as sharply as oil) since mid-2014, LNG spot market prices, which are influenced by electrical generators, have similarly dropped. More affordable LNG will encourage more gas-fired power generation as well as substitution in residential, commercial and transport sectors. Electricity demand is growing in many parts of Asia. In markets where electricity demand is flat, cheaper LNG will encourage switching of fuels from politically sensitive sources such as coal and nuclear to cleaner burning natural gas. Demand for gas for power generation will continue to grow in all scenarios.
Most legacy LNG suppliers, especially those from Qatar and South East Asia that produce natural gas liquids along with LNG, would be able to maintain profitability at current price levels. These projects were built during periods of low capex costs and can operate efficiently at minimal ongoing costs. The two legacy Australian projects, Northwest Shelf and Darwin LNG, are in this group and will generate reasonable returns for project sponsors at these lower prices.
However, all legacy producers, including the two Australian projects mentioned, are unable to increase their production volumes – in fact many of them are struggling to maintain current outputs. Reasons for this include limited remaining reserves, decreasing domestic production, and political pressure to use gas/LNG for growing domestic demand. This is especially true of projects in South East Asia and non-Qatar Middle East, such as Egypt, Oman and Yemen. To meet incremental demand from growth in electrical demand and from increasing gas share of electricity generation, new LNG volumes will be required. Where are these incremental LNG volumes going to be sourced?
In the near-term, Australian projects that have been completed recently and those under construction will be able to add to global LNG supply. However, the economic viability of the projects is uncertain. High-cost projects such as Pluto (in Australia) have endured cost and technical issues over the past few years and require a sustained period of high prices to generate returns of 12% or more. Projects that will begin production over the next two years, including seven projects in Australia, have all suffered, and are still suffering from cost overruns greater than 20% from already sky-high pre-construction capex estimates. Some of these projects, such as Gorgon, have large unsold volumes. Others, such as GLNG and QC LNG, depend to some extent, on the ability of their sponsors who have committed to purchase volumes to resell LNG into Asian markets. Coal bed methane to LNG projects do not have the added benefit of natural gas liquids, further threatening their economic viability at low prices.
At US$100/bbl oil, LNG will be sold at around US$12 - US$14/ million Btu, and these projects would produce rates of return in the low-teens. But at US$60/bbl, LNG will be sold at around US$8 - US$9/million Btu, generating returns of around less than 10%, a level that may be less than cost of capital. Undoubtedly, these projects will come online and begin production – but may only generate revenues that pay their cost of gas and opex, not the massive capex that has already been ‘sunk’ into the projects. Unsurprisingly, investors are worried because, as Maugeri’s Harvard study stated, ‘after the plunge of oil and LNG prices in Asia in the second half of 2014, the Australian LNG chapter risks becoming one of the worst investment stories of the last few decades in the oil and gas sector’.2
Similar to the greenfield Australian projects, proposed Canadian projects face many cost challenges. Long pipeline distances, remote fields and plants, environmental issues, uncertainty of taxation and property rights and high labour costs will overshadow any shipping cost savings that they may purport. It is not surprising that companies such as Petronas and BG have indefinitely postponed their projects and other projects are slowing progress. Alaska suffers from many of the same issues, while Russian projects have the added burden of political risk. Mozambique may be the only other future large greenfield project outside the US that will actually be built – largely due to the massive size of the resource, the large amount of money already spent, relatively simple development schemes, and the strength of the companies involved.
The only potential new source of LNG that is able to supply incremental LNG to satisfy growing demand are projects on the US Gulf Coast. These projects have access to massive volumes of US shale gas and have, so far, proven to be able to avoid the cost inflation experienced in Australia. For example, Cheniere’s Sabine Pass project, which is expected online in 2016, has maintained its original capex estimate of less than US$550/t.3
In a competitive market, the future price will be set by the marginal cost of competitive supply. Due to its low cost base, US Gulf Coast will be the lowest cost incremental supply of LNG to global markets and thus become the market price setter. In December 2014, Deutsche Bank calculated that US Gulf Coast projects can deliver to Asian markets at around US$11.50/million Btu, assuming a US$4.50 feed gas price.
At current US gas prices less than US$3.00/million Btu, Texas LNG estimates Asian delivered LNG at less than $10.00/million Btu. By contrast, the Harvard study calculated a $15.00/million Btu delivered cost for new Australian projects. Projects in North America that have begun construction, such as Sabine Pass, Cove Point, Freeport, and Cameron are in a good position to supply at global marginal cost. These projects will be built at much lower capex (75% or lower on a per tonne basis than greenfield Australian projects) and will be able to operate at cheaper prices due to lower cost ongoing feed gas and labour costs. As US domestic natural gas prices have not deviated (for long periods) from around $3.50 - $4.50 /million Btu (or lower) for the past few years, these – and other future US Gulf Coast projects - can offer delivered LNG prices competitive at current low price levels. Future US projects, that can leverage modular concepts to control capex to ensure competitiveness, are ideally placed to be able to raise funding and secure buyers. Texas LNG is one such project.
Low oil prices may have strengthened the argument to continue oil-linked prices. Whether LNG is sold at oil-linked prices, US gas prices or hybrid formulas incorporating both elements, the key determinant is the absolute delivered price of LNG to the end consumer. The marginal price that the consumer will be willing to pay will be influenced by gas supply, demand and the price of substitute fuels. Because oil, and thus oil-linked prices, have dropped more than coal, LNG demand for power generation will increase in Asia and Europe. Current supply volumes from legacy producers are not sufficient to meet growing LNG demand for power generation. Incremental volumes will be required but these volumes must be supplied at a competitive price. Legacy Australian projects – NWS and Darwin, can meet this challenge. Both Pluto and QCLNG have begun production but will struggle to meet the profit levels promised. The other six Australian projects under construction will become operational over the next few years. But whether or not they can maintain market share and generate sufficient returns will be determined by the relative price of their LNG versus the price from US Gulf Coast LNG projects. The saving grace will be if oil prices regain their high levels – the proverbial rising tide raises all boats. If the tide goes out further, or even stays at today’s levels, US Gulf Coast projects will be the market setters.
- MAUGERI, Leonardo, ‘Falling Short: A Reality Check for Global LNG Exports’, Harvard Kennedy School, (December 2014).
- Cheniere Investment Presentation (April 2014).
Written by Vivek Chandra, CEO Texas LNG.
Edited by Angharad Lock
Read the article online at: https://www.lngindustry.com/special-reports/26112015/us-lng-versus-australian-lng-1691/