The recent dramatic drop in global oil prices has taken the world by surprise. Though history is littered with periods when oil prices have overshot as well as ‘undershot’ price expectations, the current drop has been precipitous. As of writing this article, oil prices have dropped around 50% and WTI is priced close to $50/bbl for the first time in over five years.
For consumers of LNG, especially those in Asia that buy most of their gas on oil-linked contracts, 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. Coincidently, prices of coal, a substitute fuel for LNG in power generation, have also dropped over the past six months – though at a lesser extent than drop in LNG prices. Together, these factors have also impacted the LNG spot market where prices have similarly dropped. More affordable LNG will encourage more consumption for power generation, residential, commercial and transport use. Electricity demand is growing in many parts of Asia and even in places where demand is flat, cheaper LNG will encourage switching of fuels from dirty and politically sensitive sources such as coal and nuclear, to cleaner burning gas.
Most legacy LNG suppliers, especially those from Qatar and SE Asia that produce natural gas liquids along with LNG, would continue to be profitable at these floor price levels. Legacy projects were built during periods of low capex costs and can operate efficiently at minimal ongoing costs. However, most legacy projects are unable to increase their production volumes – in fact many of them are struggling to maintain current outputs. This is especially true of projects in S.E 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. In the near-term, non-legacy LNG projects, including those recently complete and those under construction will add to LNG supply. However, the economic viability of these projects is uncertain. High-cost projects such as Pluto (in Australia) and Snovit (in Norway) have endured cost and technical issues over the past few years and require a sustained period of high prices to generate decent returns. Projects that will begin production over the next two years, including seven projects in Australia have all suffered, and still suffering from massive cost overruns 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. At $100/bbl oil, these projects would produce rates of return in the low-teens. At $60/bbl, LNG will be sold at around $8-$9/MMBtu, generating returns 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. After spending billions of dollars on the projects, shareholders would be justified to punish the management of these companies for allowing their capex to get out of control on the assumption oil prices would continue to rise forever and LNG customers will have no choices but to accept high prices.
Similar to the greenfield Australian projects, proposed Canadian projects face many challenges. Long pipeline distances, remote fields and plants, environmental issues, uncertainty of taxation and property rights and high labor 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 – watch for others to follow suit. Optimistically, only one or two Canadian projects of modest size and existing pipeline connections may be able to begin construction over the next few years.
Other expensive project proposals in Russia and Alaska are also in a similar situation, and will have to have other factors such as political motivation and tax breaks to be able to reach FID. Yamal LNG is one such project that has benefited from strong government support and is under construction. Other proposed projects in Russia may not have this level of support and thus are unlikely to move forward. Mozambique may be the only other future large greenfield project outside the US that will actually be built – largely due to the massive resource found, the large amount of money already spent, 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 proven to be able to avoid the cost inflation experienced in Australia. 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.
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 ongoing costs. As US domestic natural gas prices have not deviated (for long periods) from around $3.50 $4.50 /MMBtu for a few years, are not expected to suffer the same fate as oil prices since the two commodities are completely de-linked in the US market, these – and future US Gulf Coast projects can offer delivered prices competitive at current levels.
Projects such as Texas LNG are particularly well placed in this new marketplace. By leveraging modular concepts, proven technology, and optimal equipment sizing, project capex is expected to be competitive with other US Gulf Coast projects under construction. Texas LNG is also focused on extremely low overheads, leveraging local labour skills with shipyard efficiencies, and collaboration with gas suppliers and offtakers to maximize cost transparency and savings. The plant’s proximity to the prolific Eagle Ford shale gas fields will ensure that its feed gas price will be in-line with US domestic gas prices and its partnership with Samsung Engineering will ensure that its facilities can be built in a cost-competitive manner. Texas LNG is fully funded until FID by a sophisticated New York fund. Texas LNG, as well as other projects moving forward, may also benefit from future increase in competition of services, including engineering and construction. All of these factors will favour technically simple, modest-scaled US Gulf Coast projects such as Texas LNG.
To reiterate, the future of LNG markets will not be set by the price of oil, but rather the relative price of LNG to other power-generating fuels and by the marginal cost of new LNG supply. 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. The most competitive new source of supply is the US Gulf coast – and Texas LNG is well placed to among the most competitive of US Gulf Coast LNG projects.
Vivek Chandra - January 6 2015