Could A Global Pricing War Dash Australia’s LNG Hopes?

This story features ORIGIN ENERGY LIMITED. For more info SHARE ANALYSIS: ORG

This story was first published on June 13 for subscribers only but has now been opened for general readership.
 

– US companies seeking approval to export LNG
– US LNG is being offered at a steep discount to current pricing
– Asian customers demanding an end to oil-indexed pricing
– Australian LNG export under threat

By Greg Peel

Up until the GFC, the price of West Texas Intermediate crude oil and the price of Henry Hub natural gas – respectively the US oil and gas benchmark prices – traded in a reasonably consistent ratio due to both being fossil fuels with a level of substitutability. But after the prices of both bottomed in 2008, the price of oil very quickly recovered while the price of natural gas wallowed.

One reason the WTI price shot back up again is because crude oil is a globally traded commodity, and while WTI itself is not exported from the US, similar crudes such as North Sea Brent are exported across the globe. After the GFC, central banks across the world, and particularly the US Federal Reserve, began printing currency and thus threatening to spark global inflation. While gold has always been the traditional inflation hedge, the ease of access to commodity investment in the twenty-first century has meant a rise in the number of commodity funds which by default offer a hedge against price inflation. Crude oil is typically included in such baskets or, as the most highly traded global commodity, is often itself used as a hedge against inflation, whereas outside of the Henry Hub domestic US gas price, natural gas is traded on long-dated delivery contracts and thus is not readily accessible as a financial investment.

Another reason the price of WTI shot up but the Henry Hub gas price didn’t is the frenetic pace of technological development this century which has provided for an extraordinarily sharp boom in US gas production from shale. Simple demand-supply metrics have dictated that the US gas price has failed to rebound in line with crude oil.

Yet to this day, the bulk of global gas exports are priced on the basis of the legacy ratio of the price of oil to the price of gas, usually around one-eighth of the Brent crude price. This means that while US domestic gas is being sold at around US$4 per million British thermal units (mmbtu), Asia is paying around US$16/mmbtu.

One might ask: if the ratio of oil to gas prices has blown out quite considerably, why is gas still traded based on the old ratio or indeed, on a ratio at all? There are arguably three reasons for this. Firstly, while the oil/gas ratio has always exhibited volatility, in the past it has always returned to trend at some point. Gas delivery contracts can typically run to twenty years, so even after the GFC there was an assumption the ratio blow-out would eventually regress. It hasn’t though, and is no longer expected to do so.

Secondly, rising demand from global gas importers, particularly in Asia, has left producers in the box seat. As long as producers hold ranks on price, importers have little choice but to pay up.

Thirdly, the construction of LNG conversion plants is a very costly and time consuming pursuit. Investment would not be made in LNG export if prices were marginal, leaving importers potentially energy deficient. Price volatility would also be a factor, such as that offered by commodity spot markets. An LNG project will not typically be sanctioned until after offtake agreements with long term export customers have been signed, for which the basis of pricing is pre-determined.

The prices of US domestic gas and Asian import gas cannot therefore be considered on an apples to apples basis. If natural gas can be piped from producer to consumer, as it is across the US, Europe and elsewhere, there should be little variation in price except perhaps for territorial tariffs. But if the natural gas has to be converted to liquefied natural gas (LNG) for seaborne export, there is a premium for conversion and a premium for shipment. Global shipping costs are consistent but for distances required, but LNG conversion costs will vary depending on the cost of building, operating and maintaining LNG plants in different locations. Thus the difference between a US four dollar gas price and an Asian sixteen dollar gas price must adjust for these premiums.

Even after adjusting for these premiums, it is nevertheless the case that oil-indexed pricing is still greater by a margin than that suggested by domestic prices such as the Henry Hub. Texas-based energy company Cheniere is in the process of building the first two trains of an LNG facility at Sabine Pass which potentially has the resources for six trains. Cheniere recently reached an agreement with Korean gas company Kogas to supply up to 1.8mtpa of LNG, not at oil-indexed pricing but at Henry Hub plus 15%. This represents around about a 33% discount at current levels.

Interestingly, US energy giant Chevron revealed last month that a 2009 agreement with Kogas to supply US$30bn of LNG over twenty years from the Gorgon project in Western Australia fell over in 2011 and another US$29bn supply deal from its WA Wheatstone project was also axed. Even two years ago, Asian customers were demanding lower gas prices. Prices now being demanded by Asia make some high-cost Australian LNG projects potentially uncommercial.

While the bulk of LNG contracts are set over twenty year timeframes, spot LNG transactions do also occur to satisfy more immediate demand, such as in the case of natural disasters. In 2003 transactions represented 10% of global LNG trade but by 2011 that figure had grown to 25%. Japan was a sudden, large order buyer of LNG on spot after the tsunami and subsequent shut-down of nuclear power, no doubt helping to push up the numbers, but cheaper spot transactions have shown that LNG can be traded at lower than oil-indexed pricing. Other seaborne commodity markets, such as iron ore, are moving rapidly towards spot pricing.

There would arguably not be a global demand-side challenge to oil-indexed gas pricing were it not for the rapid development of shale gas technology and the subsequent sudden surge in US gas production. Not so long ago America was building coastal LNG terminals to receive gas imports, expecting to remain non self-sufficient in energy supply, but as the Cheniere project indicates, America is now building LNG conversion and export terminals to tap into burgeoning Asian demand for gas. To date, the US cannot restrict exports to countries with which it has a free trade agreement, one of which is Korea. The US has FTAs with Australia, Canada and Mexico, themselves energy exporters, and a host of smaller countries which are not. But not with Japan or, importantly, China. Export to non-FTA countries requires a government-granted licence.

Last month the US Department of Energy granted only its second licence for the export of LNG to non-FTA customers. Freeport LNG joins Sabine Pass as the only two projects thus to be granted approval. Within the US, the granting of such licences has met with the glowing support from one powerful lobby group, and stern criticism from another powerful lobby group.

The first lobby group supports free markets and points to the export revenues available from LNG export, particularly given US gas can be sold at competitive, non oil-indexed prices. The second lobby group points to America’s long history of being beholden to its enemies for crude oil imports, advocates keeping domestic gas for domestic consumption, and denounces talk of exporting US resources to the likes of China. China is a very unpopular trade partner with more parochial politicians. The two groups have forced the current administration into a difficult position.

President Obama is supportive of greater domestic gas consumption, through coal-to-gas substitution for electricity production (which is now prevalent) to eventual gas conversion for heavy vehicles (which is a long way off). Tick one box for the anti-export lobby. But he also suggested early last month that the US will likely be a net LNG exporter by 2020. Tick a box for the pro-export lobby. On a wider scale, sharing one’s abundance of gas domestically through global trade pushes up the price paid for gas by domestic consumers, hence a strong argument can be made for maintaining cheap pricing for industries and households at a time of heavy sovereign debt and a tenuous post-GFC economic recovery.

If one needed evidence of how gas exports can push up the price of domestic gas for domestic gas consumers, just look at anyone’s recent gas bills in Australia. Australia is one of the very few countries in the world which has no policy of restricting the export of economically and strategically vital commodities.

The LNG supply agreement between Cheniere and Kogas at a Henry Hub-based price and the earlier withdrawal of Kogas from Western Australian LNG purchase agreements on a price basis is a stark example of what impact a free for all US LNG export industry could have for Australia’s significant LNG export aspirations. In Australia, LNG has been touted as the new iron ore.

JP Morgan has counted up to 170mtpa of proposed US LNG export projects in various stages of development and seeking export approval. Were they all to be approved, which is unlikely, US gas production would have to increase by 36% over 2012 levels to feed all of these LNG plants, which is significant. The Sabine Pass and Freeport projects together require a 5% increase. But if we assume the unlikely, and assume Henry Hub-based pricing will shatter the longstanding oil-indexed model, the implications for Australian LNG producers, says JP Morgan, “are dire”. US LNG could erase the majority of planned Australian growth projects and may risk current projects finding themselves uncommercial.

Just how worried should Australian LNG aspirants, and investors in Australian LNG companies, be?

The Supply Side

Clearly the supply-side outlook from here to 2020 depends on just how quickly the US moves on ramping up LNG export capacity. The fact that there are two lobbies exerting strong contrary influence on the Obama Administration would tend to suggest a concerted rush is not on the cards. Aside from strategic issues, JP Morgan makes the point that if US manufacturing and transport can exploit lower energy costs than other nations, the value-add into margins on exported goods can be greater than the value of exporting the energy itself.

JP Morgan believes those lobbying from this perspective are likely to provide a persuasive enough argument to ensure the US regulators will be in no rush to commit to large amounts of export LNG, rather preferring to take a measured approach.

The supply-side is nevertheless not wholly dependent at the margin on the US. Canada, too, is an LNG export aspirant and the same domestic economic issues are not going to be as important in this lower population nation. Goldman Sachs believes that Canada will become a major LNG export player over time, with two Kitimat projects owned by Chevron/Apache and Shell likely to be first cabs off the rank.

On the other side of the coin, BA-Merrill Lynch notes a combination of increasing domestic demand, high depletion rates and increasingly challenged reserves has seen Indonesian LNG exports decline markedly over the last decade. Indonesian producers have recently been forced to buy in LNG at spot prices to fulfill export contract obligations, one large producer is expected to shut down in 2014 and another in 2020, and new developments are facing significant challenges. Merrills believes 2013 will see the first Indonesian LNG imports.

Australia has two advantages over other LNG export aspirants. Firstly, Australia has been exporting LNG for decades, initially from the substantial North West Shelf operation and most recently from Woodside Petroleum’s ((WPL)) new Pluto plant. Japan has been a significant buyer from the outset, with Korea and Taiwan also long term customers and China now the new burgeoning player on the demand-side. Australia has proved its LNG export credentials.

Australia’s LNG export capacity is nevertheless set to expand rapidly, with major projects underway in Western Australia, sourced from offshore natural gas, and similarly in the Northern Territory and Papua New Guinea (which counts as Australia for the purpose), and also in Queensland, sourced from coal seam gas. It was long ago perceived that the demand influence from China would provide scope for greater LNG capacity globally, and with that in mind Australia has been a first mover in expansion planned to fill the supply gap. The “gap” is made more prominent given the time it takes to construct an LNG plant and prove up gas reserves, such that anyone thinking about LNG potential now is still a long way off from reaching production.

On that basis, Australia is in the box seat. Over 2014-15, significant fresh capacity should come on line from PNG LNG, of which Oil Search ((OSH)) is a significant stakeholder and Santos ((STO)) a lesser shareholder, Gladstone LNG, of which Santos is a significant stakeholder, Asia Pacific LNG, of which Origin Energy ((ORG)) is a significant shareholder, and foreign owned Queensland Curtis LNG. Thereafter, projects such as the foreign owned Gorgon, Wheatstone and Ichthys projects, and Woodside’s partly owned Browse are also progressing.

New Australian LNG will be hitting the oceans before North America is up and running, providing the first mover advantage. Australia also enjoys a geographical advantage in terms of transport costs. Goldman Sachs recently returned from a field trip to Queensland’s three major CSG projects and has come away feeling confident. There are still some uncertainties, and room for further cost overruns, but Goldman suggests all have made good progress towards their 2014-15 start-ups. PNG LNG should be first cab off the rank.

Of course, if North America pushes ahead with its LNG aspirations then Australia’s first-mover window will not be all that wide. US politics are an issue as are the long lead times required, but either way Goldman Sachs does not believe existing Australian projects will be undermined by LNG exports from the US, and that further brownfield expansion projects in Australia and PNG will remain competitive with North American LNG.

There is still the matter of price. The first sods were turned on new and expansion projects in Australia under the assumption of ongoing oil-indexed pricing, and offtake agreements signed years ago with Asian customers suggest the buyers were also assuming no change to the pricing model. Price considerations will have played a major part in initial financial investment decisions (FID) on projects now nearing completion. But since that time, the rapid expansion of US shale gas production and the internal push to approve US LNG export capacity has prompted potential buyers into being more aggressive on pricing, as we have seen with the Kogas pull-out of Gorgon and Wheatstone deals.

Chevron has already found a buyer for the lost Wheatstone volumes but is yet to sign up another buyer at Gorgon. Local Chevron managing director Roy Krzywosinski is nevertheless unconcerned, suggesting “the closer we get to first LNG [production] the more valuable the volumes are going to be, so we’re confident we’ll be able to market those”.

The buyers can play price games, but at the end of the day Korea, for one, is yet to secure gas supplies beyond 2015. A little bit of give from the producer side may be required, but when Australian LNG is ready to go and North American LNG is yet to be seen, the buyers will not be in a position to stand firm and demand Henry Hub-based pricing.

The Demand Side

Japan has proven a significant swing-buyer of seaborne LNG since the 2011 Fukushima disaster forced the shutdown of the country’s significant nuclear energy capacity. Japan needed to quickly replace nuclear with fossil fuel energy, and aside for some marginal oil-powered generation the replacement of choice has been LNG.

US gas prices have been under pressure given the extent of shale gas production that has emerged, albeit a domestic floor in pricing has been provided by America’s own electricity generation capacity which can easily switch to gas-fired generation from coal-fired generation when gas prices fall to the right level. Macquarie notes that in the past, when the market was capped by residual fuel oil (ie the oil-indexing days), US switching levels into gas were no more than 2 billion cubic feet per day. With gas that much cheaper now, Macquarie estimates switching levels reached 12bcf per day in April-May. But outside of the influence of cheaper US gas, Japan’s previously unforeseen additional demand has ensured global LNG prices have remained supported.

It is not thus surprising that Japan has been arguably most vocal in the push for the end of oil-indexed pricing, arguing instead for an Asian hub to replicate the Henry Hub and going as far as to suggest an LNG futures market. But while Japan will continue to import large amounts of LNG as it has always done, additional imports to replace lost nuclear power may soon no longer be required.

Prime Minster Abe has pledged to restart Japan’s nuclear reactors, despite political resistance from those who would rather have nothing to do with nuclear energy. Citi suggests the first two to three reactors could be restarted in time for the Japanese winter. As reactors restart, Japan’s marginal demand for LNG will decline. Some areas have been forced to import more expensive oil for power generation and these imports will no doubt be first to be ceased. Depending on where Japan’s reactors are situated vis a vis oil and/or gas-fired generators, gas imports will also begin to be reduced. Which again brings us back to the pricing issue.

If Japan’s reactors were not to restart but Japan was able to secure future LNG imports from US exporters at Henry Hub-based pricing, Citi calculates Japan could reduce annual energy spending by US$5-7bn. If LNG is imported from the US and reactors are restarted, Citi suggests the savings could be as much as US$24bn per year (off a current US$74bn). Such a reduction could help cut Japan’s current account deficit, Citi notes.

At the very least, Citi believes a restart of Japan’s reactors, thus removing the current global demand swing-factor, will provide leverage to all LNG importers negotiating prices with exporters.

Such a scenario does not bode well for expensive Australian LNG. However, JP Morgan points out that a collapse in seaborne LNG pricing due to the entry of the US is still not likely.

China, for example, is leading the world in developing alternative energy sources in order to cap carbon emissions. It’s not that the Chinese authorities have suddenly become rampant tree-huggers, but rather Beijing has become increasingly concerned over levels of pollution in China’s major cities. China can thus appear to be a good global citizen while tackling this domestic problem, and while coal-fired generators are still being built in China at a rapid pace, gas-fired generators are now preferred. Coal and gas are both fossil fuels but gas burns a lot cleaner.

The point here is that while coal may be cheaper, LNG is the preference. And China is only one emerging market with growing energy demands. For most developing nations, seaborne LNG remains prohibitively expensive. It will continue to be prohibitively expensive under an oil-index pricing model, but if the price were more competitive, the story could be different.

Citi cites India as being a good example. India’s engagement with LNG to date has been minimal in relation to its growing energy demand, but were LNG available at a cheaper price such an engagement could well spark up. In other words, Citi suggests that a midpoint will be found in pricing that will reflect cheap North American supply on the one hand and fresh emerging market demand on the other.

The demand side will play a significant role after 2020 because assuming all global LNG aspirations are fulfilled, the world will be in LNG oversupply. China will not be growing fast enough to make up the difference. It is notable that not only is Japan campaigning for lower seaborne LNG pricing, the European Union is in there pitching as well. EU gas supply is largely beholden to Russian pipeline exports and Russia has no qualms turning off the pipes when greater domestic supply is needed. Europe imports LNG from Qatar but it is in Qatar’s interest not to give way on pricing. Indeed Qatar limits its own LNG production, a la OPEC, in order to maintain consistent prices.

It is expected Europe will take a long time to recover from its economic malaise, and greater access to cheaper (and cleaner) energy will be needed in order to compete on exports with those enjoying lesser energy costs.

Conclusion

The bottom line for Australia’s LNG aspirants is that it is not necessary to panic. The global LNG picture has many moving parts, from US domestic energy policy to Japanese nuclear policy, long lead times, high costs, first mover advantages, growing emerging market demand, carbon reduction targets, and on and on. Assuming all goes to plan, PNG LNG will soon join Pluto in LNG production, the Queensland CSG projects will come on line soon after, and new Western Australian projects will not be far behind. The US remains well behind in the race.

Immediate demand from Asia will ensure prices paid for Australian LNG will not collapse to Henry Hub-based pricing, although it is clear the anachronistic oil-indexed pricing model may well need to be reassessed. Somewhere in between will be common ground. The losers, in Australia and globally, will be those planned LNG projects that are non-commercial at less than oil-indexed pricing.

Australian stock analysts are still placing great faith in PNG and Queensland CSG LNG, expecting the share prices of Australia’s gas majors to quickly re-rate once investors are confident that LNG exports can become a reality. US LNG is not seen as a game-breaker.

And on a final note, the US does not, by any means, have a monopoly on shale. This week the US Department of Energy released a report suggesting there are enough shale oil/gas reserves globally to meet demand for several years. The DoE believes Australia alone may boast up to ten times the country’s currently known reserves of shale.

China, too, has shale reserves. As to how long it takes to develop US-scale shale industries in Australia, China or anywhere is else is a consideration for the future.

Find out why FNArena subscribers like the service so much: "Your Feedback (Thank You)" – Warning this story contains unashamedly positive feedback on the service provided.

Click to view our Glossary of Financial Terms