Window On LNG: Can Australia Sell Its Gas At A Decent Price?

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– International gas market dynamics remain in flux
– Australian LNG producers to enjoy window of opportunity in years ahead
– Major LNG Projects potentially facing temporary gas shortage from late 2015

 

By Greg Peel

One of the issues arising from the current geopolitical tensions in the Ukraine is that of European gas supply. Russia supplies 30% of Western Europe’s gas demand and having been built in the old Soviet Union days, the pipelines which deliver that gas cut straight through the Ukraine. This puts the relationship between the European Union and Russia on a tenuous footing – the EU has to go easy on any sanctions it imposes on Russia in response to its Crimean infiltration and Russia cannot really afford to lose the export revenues it generates.

Beyond this trade diplomacy, there is also a risk upset Ukrainians will sabotage the pipelines, as was the case in 2009 when Ukraine-Russia tensions last erupted.

Sabotage aside, analysts do not expect Moscow to give the order to cut of European gas exports. But even it does, or the pipelines are otherwise compromised, Europe and the UK have just enjoyed a very wet but relatively mild winter. In the Netherlands for example, the mildest winter since 2008 has seen gas prices fall to their lowest level in two years given reduced demand for heating. Most European hubs are carrying stored gas at levels 20% above the same time last year, and 25% in the case of the UK, National Australia Bank analysts report. Were imports to be disrupted, there would be little immediate impact.

By contrast, the US has been enduring a fierce winter which has seen low temperature records broken at many points across the country. Frigid temperatures in January led to record levels of withdrawals of gas from storage, even on a seasonally adjusted basis. The US Energy Information Agency predicts gas inventories will end the “heating season” at end-March at a six-year low.

The extraordinarily cold US winter has evoked extraordinary volatility in US gas prices. The Henry Hub benchmark price was trading below US$3.50/mmbtu in November and in the last week of January passed through US$5.00 for the first time in three years. In the first week of February the US$6.00 mark was exceeded. In mid-March, at the time of writing, the price is back at US$4.50.

The irony here is that this decade’s shale gas “explosion” in the US has so increased domestic supply that domestic prices have fallen to a level which makes additional gas drilling marginal, hence rig counts across the shale fields are at a low. At least had fallen to such a level prior to this winter. As to where the Henry Hub price will settle when the snow melts is as yet unclear.

What is clear is that the US energy industry is desperate to export its shale oil riches to foreign buyers, particularly in Asia, so as maximise the potential profits from capital deployed. The US government is less keen on such a venture, given America has for many decades been reliant on oil exports from its enemies to fuel its economy and now that energy self-sufficiency beckons (if Canadian resources are included), it seems foolish to suddenly give that energy away to the likes of China, thus providing China with the opportunity to cheaply fuel its own competing economy on imported US gas.

To that end, the US government had placed a ban on gas exports to countries with which the US has no free trade agreement (which includes China and Japan). But under intense energy industry, and thus political, lobbying, the US government has since agreed to limited exports to non-FTA destinations. Indeed, as of this month the Obama Administration has now given approval to six LNG export facilities. There are a further 17 seeking approval.

The burgeoning US LNG export industry poses a threat to the Australian LNG export industry. Australia is the major supplier of LNG to Asia and a decade ago Australia began building a suite of massive new LNG projects sourcing natural gas from off the Western Australian coast or coal seam gas in Queensland to exploit exponential gas demand growth expected from emerging Asia. These very high cost projects require the security of long term gas offtake agreements with major buyers at sufficiently high gas prices. The entry of the US into the global export race would clearly impose pressure on prices given the abundance of shale gas and low US gas prices.

Investors in Australian listed energy companies nevertheless need not fear. While it is true that the entry of the US and also Canada into the global LNG export market will undermine Australia’s advantage and pricing power, the impact will be marginal and will not be felt for some time.

While not enduring quite the winter the US has had this year, Asia has nonetheless seen a cold one. Strong gas demand from Japan and Korea pushed the landed price of gas to a record high above US$20.00 in mid-February. NAB analysts note that for Australian LNG projects to provide sufficient returns they will need to achieve landed pricing of US$14.00-15.00 so there’s no need for too much concern, but if we assume a US Henry Hub price of US$5.50 (a dollar above where it is now and two dollars above the November price) then the US should be able to sell LNG to Asia at a landed price of US$11.50.

Now that is a concern.

There are, however, several factors to consider.

Firstly, Woodside Petroleum’s ((WPL)) Pluto facility became the first of the new generation Australian LNG projects to begin exporting gas in 2012 (see table below). PNG LNG, owned in part by Oil Search ((OSH)) and Santos ((STO)), should begin exporting around the middle of this year and QCLNG, owned mostly by Britain’s BG Group, will provide the first Queensland CSM LNG to hit the oceans later this year if it remains on schedule. Santos’ GLNG and Origin Energy’s ((ORG)) APLNG are set to follow in 2015. Gorgon, Wheatstone, Ichthys and Prelude (all foreign owned) are scheduled to begin export in 2015-17.

Realistically the US will not become an LNG export contender until around 2020. Hence Australian projects will enjoy a reasonable window of first mover advantage. Canada is behind the US. The US has only recently begun to build LNG export facilities and Canada is still just talking about it. Before the advent of the new technology which opened up the massive US shale fields for the first time, the US was expecting to be an LNG importer, not an exporter. Therefore the first LNG export facilities expected to be up and running in the US will actually be converted import, or regasification, facilities.

Which brings us to the second point. Having started slowly, it would appear the US government has now sped up its approval of LNG facilities for export to non-FTA countries. But JP Morgan points out all of the six projects now approved involve conversion of regasification facilities (brownfield) and the analysts suggest any projects looking to start from scratch (greenfield) would likely face “a much sterner test” from the regulator. Of the 17 projects still seeking approval, three are brownfield and the remainder are greenfield. Greenfield projects would require a much higher realised LNG price in order to be viable, given the extensive time and costs involved, hence it is unlikely the US government would find it “in the US interest” to grant these projects export approval.

Thus not only will it take some time before US LNG exports hit the market, volumes will still be limited.

Which brings us to the third point. Longstanding LNG importers such as Japan and Korea have always put security of long term supply ahead of any fiddling around the edges of pricing. As demand for imports in Asia and other emerging economies heats up, such security becomes even more important. LNG customers will not want to risk playing around in less certain spot markets and missing out on deliveries. Thus even if North American exporters can one day offer a cheaper price, the track records of Australian long term offtake agreements will continue to attract premium pricing.

Demand is a fourth and critical point. Chinese LNG imports rose to a new record of 2.65m tonnes in January, beating the previous record of 2.43m tonnes set in December. Notwithstanding the cold Chinese winter, December saw the start-up of the Tangshan LNG import (regasification) plant and the first cargoes were received at the Tianjin floating LNG import plant in January. China’s state-owned energy company CNOOC is aiming to double its LNG import capacity by 2015 by adding five new terminals. NAB analysts report that will only take China’s ratio of natural gas in its energy mix to 8% from 5%. There remains plenty of upside.

While North America spends the time becoming export ready, global demand growth will potentially push pricing above today’s current levels before additional supply can rebalance the equation. And into that demand equation we can add the US itself. The cold US winter has proven domestic demand spikes can impact very significantly on local pricing. Moreover, the US will need time to shift energy consumption focus from imported crude oil to domestic natural gas, but presumably in five years the balance will already look a lot different.

A fifth point is that Australia, too, boasts enormous “unconventional” (shale) reserves so the US cannot expect to monopolise that market at the end of the day. For that matter, so does China. The exploitation of these reserves is nevertheless a long time off.

These are five among other reasons why the ultimate price of the first North American LNG exports is likely to be higher than today’s Henry Hub domestic US price might suggest, notwithstanding Australian producers will enjoy a window of valuable pricing opportunity ahead of that date. But there are also reasons why, on the other side of the coin, export prices may also come under downward pressure, other than through the introduction of North American supply.

Japan is currently paying a record price for its LNG because it is importing a lot more of it for electricity generation as a result of the country’s 48 nuclear reactors (operational or planned) still being shut down (or halted) three years after Fukushima. Korea is having to pay the same price not only because of elevated Japanese demand, but because four of the country’s 23 reactors also remain offline for the same reason. But the outlook is changing.

The Japanese government is expected to release a new energy policy late this month which will reinforce Japan’s reliance on nuclear energy in the mix. While the policy will likely be more motherhood than specific, analysts anticipate the release will be a precursor to up to ten of the country’s idled reactors being restarted by year-end. It is the Korean government’s aim to not only restart Korea’s idled reactors but to lift the country’s nuclear energy mix from the current 26% that 23 rectors represents to 29% by 2035.

Once Japan’s nuclear power supply starts ramping up again, its excess LNG import demand will begin to ease.

And while China might be rapidly building LNG import facilities, the country will not only be relying on seaborne LNG to satisfy its growing gas demand. Pipelines are currently being built from Russia, Central Asia and South Asia to supplement Chinese gas supply.

Finally, and irrespective of all of the above, Australian producers cannot afford to be too smug about their pricing power either currently or in the next few years lest their Asian customers become annoyed. The Japanese and Canadian prime ministers have already, for example, held discussions about future LNG trading potential. Longstanding Asian customers, while still beholden to Australian supply, have not let the big gap between current Asian landed gas prices and domestic US gas prices go unnoted. As NAB notes, Woodside went very close to having one of its long term contracts, worth $1.5bn, terminated by a Japanese customer earlier this year.

If we add all of this up, we might arrive at a reasonable conclusion that by the time the US is exporting LNG, global pricing will have converged to a level below record prices currently being paid and above low prices currently suggested by the US Henry Hub price. This middle ground should, nevertheless, prove sufficient to ensure viable returns for those Australian LNG projects now nearing completion, if not for other projects yet to get anywhere close.

But we are missing one small factor.

It’s all very well for Australian and foreign energy companies to build massive, competing LNG export facilities in Australia, but those facilities still have to find sufficient reserves of natural or coal seam gas to feed them. Woodside had originally planned a second and possibly even a third LNG train at Pluto, but a succession of dry exploration wells has seen the company settle at just the one. Citi is now suggesting the Queensland CSM LNG projects are likely to run into the same problem.

Having built well-by-well models to define likely gas production for the GLNG, APLNG and QCLNG projects, and having assumed delays in upstream facilities of 3-6 months for all projects, Citi believes the trio will be net short gas for 12 months from the December quarter of 2015, at which point six LNG trains are expected to be operational in total. The shortage will limit the ramp-up of respective additional trains.

Of the three, QCLNG boasts the greatest reserves, to the point APLNG is already set to buy in source gas from its competitor. APLNG is expected to be sitting on excess gas while it ramps up, while GLNG has suffered from setbacks and may have to look to a deal with QCLNG as well. On Citi’s modelling, QCLNG will actually have less gas it can afford to pass on to APLNG and APLNG won’t have any excess gas during ramp-up at all. GLNG would then have to look to third party sources elsewhere.

Indeed, while Citi believes gas supply tightness will only occur during 12 months of the protracted ramp-up phase, it is in the interests of the owners to “de-risk” their projects by jumping on any third party gas deals that become available on a long term basis rather than relying on the more expensive and uncertain process of developing one’s own reserves.

In other words, the honeymoon Australian producers are expected to enjoy in their “window of opportunity” before North America ramp-up may not be quite as enjoyable as Mum described it after all. And that’s before we talk about the potential for any further ramp-up delays, which some analysts are prepared to suggest are more probable than possible.

 

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