A Revised Outlook For LNG: The Road To Riches Or A Waste Of Time And Money?

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This article was first published exclusively for FNArena subscribers on February 15 and is now open for general readership.

By Greg Peel

When Australia’s LNG “boom” (round two) began in earnest in 2008, the simple impetus was a forecast exponentially growing demand for energy from emerging and highly populated economies. First-movers were potentially looking at vast riches. The only real issue was that it would take a lot of time, and a lot of money, to bring such LNG production dreams to reality. It was going to be a long road.

In the ensuing period, the global picture has changed somewhat. For one, we’ve had a GFC. If nothing else, after five years Europe is still suffering from the fallout. Forecasts for ongoing Chinese growth have tempered to an extent. An earthquake off the Japanese coast has substantially changed the outlook for nuclear energy – a fossil fuel alternative. And the US has woken up to the fact it has been sitting on such a vast expanse of shale that recently developed technology has not only offered the prospect of long-coveted energy self-sufficiency, but also the prospect of a major new export industry.

All of the above has impacted on the outlook for Australia’s own LNG export aspirations. Along the way, investor patience has been sorely tested through project delays and cost blow-outs and even a lack of readily available gas. All along many energy analysts have maintained rusted-on Buy ratings for LNG stocks on the assumption the upside potential is just too substantial. Just how long do we wait?

Should we wait?
 

The Price Of Gas

We are all fairly familiar with how the price of oil has fluctuated over the past decade. If we use West Texas Intermediate crude (futures contract) as the benchmark, we entered the new century with US dollar prices per barrel pretty steady around the $20 mark, as they had been for some time. Then along came China, the emergence of which pushed oil through the $100 mark in 2008, accelerating to an explosive peak just under $150. The GFC brought a rapid tumble almost to $30, but by 2011 the price had again hit $100. At the time of writing, WTI crude is trading just under $100.
 

Over the past two years WTI has lost its global benchmark status given it is not an export crude, and as a result of oversupply flowing in from Canada. North Sea Brent crude has replaced WTI as a more accurate benchmark, and all other global export oils trade in a close range to Brent. Brent trades today at a much higher price than WTI — $21 higher at the time of writing – but Americans, and to a great extent the world, remain fixated on the longstanding WTI “price of oil”. To that end, WTI is used when comparing crude prices to natural gas prices.

The natural gas price, as represented by the US Henry Hub futures price, suffered even more extreme volatility in the lead up to the GFC than did WTI, but unlike the oil price, the natgas price has never since recovered earlier peaks. A bounce from a US dollar price per million British thermal units of a lowly $2 in 2012 up to over $3 today is not insignificant, but still minimal in the wider picture.
 

 

Given both are “fossil fuel” sources of energy, oil and gas have long been considered substitutable, such that if the price of one were to run too high then industry/households could switch to the other. Such a consideration ensured a stable ratio in the price of the two for many decades. But as noted above, the (benchmark) price of oil rather quickly rebounded after the GFC and the price of gas did not. As the following chart shows, this price divergence has proven quite substantial.
 

 

This chart takes us only to 2012, at which point the Henry Hub gas price was hitting historical lows around $2. Gas has since rebounded 50% to over $3 while the oil price has settled into a less volatile range, meaning that at the time of writing, the ratio is 30 rather than over 50 – much lower, but still substantial when compared to the ratio of 10 up to 2008.

Crude oil and its liquid products (petrol, diesel, heating oil etc) can be easily and cheaply transported, and thus export/imported, because they are liquids. Pour the stuff into a tanker and away you go. Gas, on the other hand, can only be transported and thus export/imported following the expensive construction of overland pipelines or the very expensive process of first converting to liquid natural gas (LNG) for seaborne trade. I noted earlier that WTI is not an export crude (as yet, although it will be before too long) and as such is not a good global pricing benchmark. Similarly, US natural gas to date has never left the US nor been converted into LNG for export. The Henry Hub is simply the point at which several US gas pipelines meet on the mainland and as such it provides a pricing point.

The Henry Hub natural gas price is thus irrelevant with regard to the global gas trade. Major global gas importers, such as Japan for example, have for decades purchased LNG on long term supply contracts with major exporters such as Australia. Each contract is individually negotiated and must account for non-constants among various buyers and sellers such as distance of transport. There is thus no global benchmark price for export gas, nor any single exchange-traded instrument. Instead, gas contract prices have for decades been linked to something that is heavily traded and transparent, being the “price of oil”. And why not? The two fuels are considered substitutable, as noted earlier.

Why not indeed. As the graph above shows, an oil-indexed gas price would have made perfect sense for at least the three decades leading up to 2008, given very low price divergence. But why, today, would it make sense for Japan, for example, to buy gas based on the price of oil when the price of gas in the US, for example, is so, so much cheaper?

The quick answer to that question is: it doesn’t. Not all of it anyway. When Japan shut down almost all of its nuclear power plants post-Fukushima, lost power generation was replaced with gas-fired production. Gas is much cleaner than oil and particularly coal, and while coal is by far the cheapest fuel source, gas should be a lot cheaper than oil given global supply. So rather than replace nuclear with gas on expensive contract prices from Australia, for example, Japan has been buying LNG from Qatar at spot. The spot price agreed is a lot closer to Henry Hub than any oil-indexed price.

Admittedly, it suited Japan to buy spot gas rather than contract gas given the government was undecided at the time as to whether it would ever turn its nuclear reactors back on. First it was yes, then it was no, then it was yes again before that government was thrown out last year. The new government is on the yes side, but not with any haste. Either way, Japan did not want to buy long term supply contract gas to fill what might prove only a temporary power generation hole. Importantly, if you can buy cheap gas at spot, and there’s plenty of it, why go back to expensive contracts?

The Fukushima disaster rocked Japan, and rocked the global uranium market as prices fell on the back of reactor shut-downs. What many would not realise is that Fukushima has also indirectly rocked the global gas market. This is a critical consideration for Australia, in which some of the world’s largest ever LNG production facilities are edging towards completion in the hope of feeding a gas-hungry, growing world. And hoping to do so at an attractive sale price.
 

The Demand-Supply Equation

The Australian LNG industry “exploded” in 2008 when international Big Oil started moving in and acquiring, or at the least attempting to acquire, stakes in Queensland’s coal seam gas prospects. The quickfire acquisitions, at a time when the oil price was surging, focused attention not only on the country’s burgeoning CSG potential but also on the expansion underway in Western Australia’s offshore gas projects. Suddenly energy analysts were jumping over themselves to re-rate prospective LNG players. China would be demanding a lot more gas, it was realised, and Australia could be in the box seat.

LNG plants are nevertheless very costly and take years to construct, and at the same time, on the other side of the world, the tiny Gulf State of Qatar was building yet more “mega-trains” for LNG production. A sense of foreboding loomed when it was realised Qatar just might have enough gas reserves to supply the world, let alone China, for decades. Australia might find itself a little slow in the race, with the first of the major projects not set to come on line until around 2014-15.

Enter the 2011 Japanese tsunami. Tragic, yes, as was the subsequent Fukushima nuclear disaster, but of significant implication for global LNG forecasting. In short, that excess Qatari capacity so worrying for Australia only a couple of years ago has ultimately been all but absorbed by the unexpected spike in Japanese LNG demand driven by the need to balance the loss of power from idled nuclear reactors. Fukushima has provided Australia’s LNG industry with somewhat of a reprieve. But then there’s another problem, also not fully appreciated back in 2008.

Back in 2008, the US was still talking about importing LNG. That is until it was realised new technology (and a high oil price) had provided the opportunity to commercially tap vast shale fields in the Midwest. If the Australian CSG and offshore LNG “boom” seemed to occur in a very short space of time, it is nothing compared to the speed with which the US has shifted from talking about the need to import LNG to discussing the capacity to become a major global LNG exporter. The only saving grace is that Australia has had a little bit of a head start.

If Japan ever switches back on its reactors – and it is assumed it will – Qatar will lose its temporary all-consuming customer. What’s more, Qatar had earmarked the significant expansion in its LNG production capacity (tapping into an abundance of natural gas) for sale to the US, given only a few years ago it was assumed the US would become a major LNG importer. At some point therefore, Qatari gas will be looking for a home again.

By 2011, the second and third biggest LNG exporters in the world were Indonesia and Malaysia, both of whom, Citi’s analysts note, have new import terminals starting up this year. And as Citi further notes, gas discoveries have surged in the last few years, making more global supply available in the future. Perhaps most significantly, China – for the supposed benefit of whom LNG facilities are being constructed or planned across the globe – actually boasts shale gas resources “as rich as that of the US,” as BA-Merrill Lynch puts it.

If that’s the case, why is so much stake being placed in a global LNG production race to satisfy increasing demand out of China and its equally fast-growing neighbours?

The reason, Merrills points out, is that the development of a Chinese domestic shale gas industry faces far greater hurdles than has been the case in the US. China’s shale reserves are deeply buried in difficult geological structure in areas where water availability is poor (water goes in to push the gas out). US shale reserves are easily accessible and sit in areas where once the US oil industry boomed, before it sucked the land dry and shifted to the Gulf. The infrastructure is already there, the pipeline networks are already there, and the technology has been developed to facilitate easy commercial extraction. China has neither the infrastructure, nor the technology, nor even a decent pipeline network.

This has not stopped the Chinese government fast-tracking its domestic shale aspirations. Beijing is aware it will take time, and that demand will exceed domestic supply for some time, but a breakdown in negotiations with neighbouring Russia as a gas supplier has steeled Beijing’s will. China is already importing gas via a pipeline from Turkmenistan, and new pipelines are being constructed from Burma, but one of the big stumbling blocks with regard to Russia is price – Russia is insisting on oil-indexed pricing. Indeed, Russia’s energy giant Gazprom is desperately, and to some extent vainly, attempting to hang onto oil-indexed pricing in a world moving rapidly towards spot.

One of the effects of Russia’s stubbornness has been a fall in gas demand in Europe. Europe has in the past imported piped gas from Russia and LNG from the likes of Qatar, but the current dire state of the European economy has forced a switch, for the purposes of power generation, back to the cheapest fuel alternative – coal. Even as Europe forces a greater shift towards cheaper spot pricing for gas imports instead of expensive oil-indexed pricing, gas demand in the region is falling.

Interestingly, Europe, too, boasts its own shale gas reserves, as does the UK. Of particular interest to Australians is that environmental concerns surrounding the fracking process involved in shale gas extraction has led to bans or partial bans across the continent. Bulgaria, Romania and the Netherlands suspended hydraulic fracking in 2012, notes Deutsche Bank, while the cost of environmental compliance in Austria renders Austrian gas uncommercial. Both France and Germany have bans or partial bans in place. The availability of water is itself also an issue.

By contrast, and faced with decreasing domestic gas supplies, the UK has moved to lift its ban. In Europe, numerous studies are underway, notes Deutsche Bank, to help establish proper safety measures and drilling procedures to minimise the risks of shale gas extraction.

As all of the above attests, the global gas demand-supply balance into the future is not a simple equation. It is certainly nowhere near as simple as “China grows, China need gas”. China nevertheless remains on top of the list in terms of expected demand growth in the nearer term, along with South East Asia, India, South America and even the Middle East (it is commercially more beneficial for MidEast oil giants to export expensive oil and import cheap gas). Racing to satisfy this demand are the likes of Australia, Qatar, Russia, East Africa, Canada and, most recently, the US (Citi notes a recent US Department of Energy report was highly supportive of LNG export, paving the way for a rapid ramp-up beginning in 2015) And let’s not forget contributions from Malaysia, Indonesia, Algeria, Egypt and Yemen.

As we speak, global LNG supply growth has actually hit a rare lull. Citi points out that 2012 is the first year in three decades in which LNG supply (year-on-year) has declined. Angola will provide the only new supply in 2013. And even that’s after a one-year delay.

Such statistics only go to underscore the immense undertaking that is LNG production. As noted often enough, it takes years and vast sums of financing to take an LNG project from planning to production. In Australia, delays, cost blowouts and even a lack of available gas reserves have proven stumbling blocks in the race to be a leading global LNG exporter, further pushing out ramp-up timing and further highlighting the tenuous commercial risk of such ventures. Economies cycle in shorter timeframes than that of LNG train construction. Demand for LNG fluctuates within that timeframe. And prices can fluctuate wildly. Today’s golden egg could be tomorrow’s omelette.

And just to add insult to injury, the pace of demand growth in China, for example, is not quite that of earlier forecasting. Firstly, there is the macroeconomic element. We’ve seen how the European Crisis has impacted on European gas demand growth and we acknowledge that while China appears to have avoided a much feared “hard landing”, the pace of its economic growth from here will be a little less frenetic than last decade. Secondly, energy efficiency has become of prime importance in China and other fast emerging economies. Improved efficiency, while laudable, acts as a dampener on energy demand growth. Thirdly, and perhaps most significantly, China, India and others are simply not ready.

It doesn’t matter whether you want natural gas, there’s not much you can do about it if you’re simply not in a position to receive it. It is an enormous undertaking to build liquefaction and export facilities at one end, and it’s also necessary to build “re-gas” facilities at the other end. LNG tankers need to tie up in purpose built ports to be emptied, the LNG then re-gassed on site, and the resultant gas piped to where it is needed. If those facilities are not in place in sufficient capacity, it’s a simple case of “no gas for you”.

China is, of course rushing to build pipelines and facilities, and there has been a rush of orders globally for floating storage and regasification units (FSRU), the first of which has started up in Argentina. FSRUs can be parked at appropriate locations and deliver gas into pipelines, just as fledgling floating LNG technology has the capacity to place LNG trains and transfer-to-tanker facilities right on top of offshore gas deposits. But it is probably timely that global LNG production is in a lull right now, because global LNG demand is quite simply under constraint.

What happens next?
 

The Real Price Of Gas

An oil-indexed contract pricing system made sense for decades because price divergence was minimal, and an important factor driving this low divergence was true substitutability. In factories, either fuel oil or gas could be burned for power. In the home, either heating oil or gas could be used for heating. But in 2013, the focus is on electricity generation and its rapid capacity growth in emerging economies. Coal provides a cheap fuel for power generation, far cheaper than diesel. Gas can be quickly substituted for coal in power generation but if the price of that gas is indexed to the oil price, it, too, is too expensive. If the gas is priced at spot however, gas is much more viable as a coal substitute.

In the US, which boasts its own coal and its own, abundant, gas supplies, electricity producers have quickly become swing players, buying which ever fuel is cheaper at the time. Switching from one to the other is not difficult. This is only the case because those companies can buy US gas off a pipeline at the Henry Hub spot price. Were they forced to pay an oil-indexed price, substitution would not be viable.

As Canada and the US move towards LNG export, North America is looking ahead to becoming a regional swing supplier to the world on a seasonal basis. From Canada in the north to the Gulf in the south and an ocean either side, North America could equivalently supply LNG to Europe, Asia and South America and do so on a seasonal rota (energy demand rises in winter), as the Citi analysts note. And while the price at the delivery point will take into account LNG conversion and freight costs to varying locations, the “base” cost of the gas will be spot (Henry Hub), not oil-indexed. North America will be very competitive.

In the meantime, Europe will not now buy gas at oil-indexed pricing from Russia or anyone else given its economic problems, and is either buying at spot or switching to cheaper coal while redirecting excess contracted imports to Asia. Japan has a big hole to fill with its reactors turned off, but will only pay spot for gas. Qatar is happy to oblige.

Taking all the above into account, the reader will now be assuming oil-indexed LNG pricing will soon be consigned to the history books. But it’s not quite that simple.

Energy is arguably the most vital input to any economy. Energy security considerations are enough to start wars (some might say the only reason in the past century) and economies with no domestic source of energy inputs, such as Japan, are vulnerable. It is almost inconceivable to think that US reliance on foreign (enemy) oil imports for so long could soon switch completely around to America not only being energy self-sufficient, but an exporter. It therefore stands to reason that energy (in this case gas) importers are willing to sign long-term supply contracts rather than risk their economies to the vagaries of a spot market.

On the other side of the fence, gas exporters face an uncertain future themselves if forced to deal only on the basis of spot pricing. At the risk of sounding like a broken record, pipelines are expensive and take time to build and LNG facilities are very expensive and take a long time to build. LNG projects are not ultimately sanctioned by their investors until the projected risk/reward balance is deemed commercially viable. Such projects are rarely sanctioned without the pre-signing of long-term offtake deals with importers. Exporters basically need to “sell forward” their gas to some extent otherwise the risk of spending all that time and money for nothing is too large.

It may thus be commercially viable for existing producers to sell marginal gas production (that not already under contract) to customers with marginal demand (such as Japan) on a spot basis. Or to sell marginal production to a customer otherwise lost (such as Europe) on a spot basis. But if spot pricing was all an LNG producer had to look forward to, with growing competition threatening revenues from one day to the next, no new LNG facility would ever be built. The risk would quite simply be beyond reason.

Thus on the one hand we have nations looking to confirm long-term gas supply for energy security reasons, and nations looking to confirm long term customers for commercial viability reasons. Thus it follows that the extremes of gas pricing cannot be oil-indexing at the high end and spot at the low end, but rather a “cap and floor” range somewhere in between.

A “floor price” will establish itself as the price below which investment in new supply facilities is uncommercial. No new supply coming on to feed growing demand will ensure customers will appreciate this floor. A “cap price” will establish itself as the price above which gas is no longer economical vis a vis other forms of energy, and oil in particular. Coal will always be the cheapest source, but also the dirtiest source.

If we now combine the above-discussed demand-supply situation with our pricing discussion, we can start to get a handle on what gas prices might be in the short, medium and longer terms. This is a vitally important consideration not just for gas exporters and importers, but also for industry and households who also buy energy. And investors in LNG stocks and any stock with an energy bill.
 

Mind The Gap

Some China-related statistics from BA-Merrill Lynch: China’s energy consumption is 6% above the rest of the world average; coal consumption is 290% above the average against domestic coal reserves 36% lower than the rest of the world average; crude consumption is 50% below against reserves 96% below; natural gas (as distinct from shale gas) consumption is 85% below against reserves 94% below; hydro power consumption is 12% above against water resources 72% below.

China, Merrills notes, is attempting to improve its air quality. The air pollution situation in the big cities is clearly now quite dire, as recent television pictures exhibited. On the numbers above, China needs to reduce its coal consumption and increase its hydro and gas consumption (gas is not “clean” but a lot cleaner than coal or oil), while also stepping up developments in nuclear and alternative sources. Hydro is not much of an option though, given a shortage of water. China has a world-leading nuclear plant construction schedule underway but reactors take up to a decade to come on line. Alternative sources (eg solar, wind) are simply not base-load viable. Shale gas, as discussed earlier, is an option but a long way from commercial development. Natural gas is set to come in via pipeline but being held up by a breakdown in negotiations with Russia.

China’s capacity to import LNG is as yet constrained, as noted earlier, but so too is global supply at this time. Angola will provide the only new export source in 2013 after a decline in global supply growth in 2012. Australia is not the only LNG export aspirant running into cost blow-out and delay issues, all of which is providing China and others with the time to speed up their import capacity. The aforementioned FSRUs are set to accelerate the LNG receiving process.

The bottom line is that China’s demand for gas will do nothing but grow from here, as will that of Other Asia, the Middle East and South America, at a time when supply is constrained. India is having major problems with its domestic gas supply and Japan, for now, needs to buy a lot of gas to fill a big energy hole. The opportunity exists for what we might call the “first next to market” players. Australia’s North West Shelf was among the first developments ever to export LNG, some decades ago. Then there was a lull, and then the need for more LNG was recognised as China and others “emerged”. Australia’s major sanctioned LNG players will lead this first next to market brigade, assuming no disasters, from next year. That’s how long it has taken to move from recognition of opportunity to actual production (when and if it happens). Then the race will really be on, especially with the US hot on Australia’s trail.

Japan’s sudden need for excess LNG has realistically been all that has stopped the price of gas from falling further, given the now appreciated abundance of shale gas in the US and other discoveries being made elsewhere. This has more than compensated for Europe’s declining demand. If the European economy ever gets back on its feet, presumably European gas demand (pipe/LNG) will rise again. If Japan ever switches back on its reactors, which most assume it will, Japan’s excess LNG demand will wane. To some extent, these factors might cancel each other out.

In the meantime, global LNG demand will exceed supply at least until supply catches up to provide the balance. Energy analysts largely agree that a window of opportunity exists – “the gap” – for windfall profits up until about 2020. Counterbalancing profit potential is the shift towards spot pricing, or at least a “cap and floor” pricing system which better reflects spot as a base rather than oil-indexation as a base. At present, the ball is in the court of the upcoming suppliers as far as contract pricing goes. Yet still they are struggling to secure deals given the buyers have a different ball in their own court, that of downward pressure on the pricing mechanism.

If all of Australia’s currently sanctioned LNG projects reach production, LNG has the capacity to jump from a low-ish base to match iron ore exports as a contributor to Australia’s GDP. Benefits should flow for the likes of Woodside Petroleum ((WPL)), Santos ((STO)), Oil Search ((OSH)) and Origin Energy ((ORG)). It will depend on further delays and cost blow-outs being contained, and on being realistic about the potential for additional trains.

Beyond 2020 it may be a different matter, nevertheless.

“Our global gas model, even using fairly bullish assumptions about demand and oil-substitution, and risk-adjusting LNG supplies to reflect the industry’s potential to run behind schedule, still indicates an oversupplied market later in the decade,” the Citi analysts warn. “The surge in LNG supplies expected out of Australia, with other increases from the US, East Africa and Russia, all combine to more than sate still rising demand”.

As well as the simple rising supply meets rising demand story, the rise of distribution “gas hubs” in Europe, Singapore and North America for example will ensure the shift towards “hub-based” (more spot-based) pricing and away from oil-indexed pricing, offering less margin to the supplier. LNG prices will already be under pressure once new supply comes on line from Australia and elsewhere. “If the full suite of currently proposed projects materialises,” warns Citi, “that pressure could be severe”.

Macquarie has also based forecasts on “the gap”. “A key market window is opening from 2014-19 which is being actively targeted by producers,” the analysts suggest.

Macquarie does not believe producers are overly concerned by the expected longer term drift down to lower LNG pricing and away from oil-indexation, noting that prices will still be higher than today’s prices. In the medium term, gas prices are expected to trade well above marginal cost of production and thus have “significant earnings and valuation implications,” the analysts suggest, “for the local players exposed”, albeit “the highest prices may only last a few years”.

Macquarie has Buy (Outperform) ratings on each of Santos, Origin and Beach Energy ((BPT)).

Higher quality projects have the upper hand. Merrills sees a third LNG train at PNG LNG (Santos/Oil Search) and a fourth at foreign-owned Gorgon as likely to progress. Expansion plans at other sanctioned projects are not as likely to make the cut while the economics of other Australian projects yet to be fully sanctioned are “thin at best,” says Merrills. These include Browse, Arrow, Equus, Scarborough and Sunrise. In the big cap names, Merrills preference is for Oil Search.

2012 was not a happy year for patient energy investors, with the ASX energy sector index falling 7% in an otherwise (net) rising market. No less than five LNG cost/schedule blow-outs were announced in the year. The FNArena database nevertheless shows a Buy/Hold/Sell rating ratio among the maximum eight covering brokers therein of 6/2/0 for Oil Search. Santos currently boasts a perfect score of 8/0/0. Origin is afforded 5/2/0 and Woodside 3/5/0.

No one is keen to sell the LNG majors.

In the small cap energy space, Merrills prefers Roc Oil ((ROC)), Horizon Oil ((HZN)) and Karoon Gas ((KAR)). Beach Energy offers local shale gas potential but only in the uncertain future and Merrills has a Sell on the stock, making up a 1/1/3 database ratio. Roc (3/1/0), Horizon (3/1/0) and Karoon (6/0/0) are widely preferred.
 

The Impact At Home

You don’t need me to tell you that over the past five years your gas bill has risen by two-three times. Funny, isn’t it, that all you have read to this point underlines the abundance of gas in Australia and the potential for this country to be a major LNG super power, and yet we are paying through the nose for what is under our own soil.

Quite simply, Australia’s is a free market economy, and this means that gas producers are free to sell their gas to whomever they like, whether they are from Wooloomooloo, Ghangzhou or Mars. And if an energy-hungry emerging world is prepared to pay far more for gas than us handful of locals, that price becomes the benchmark for all. But did you know that Australia is the only country in the world that allows international oil companies to access and export natural gas without prioritising local supply? The government won’t budge for fear of scaring off development and thus supply. And as Citi notes, the state of Western Australia implemented a local supply-first policy in 2006, yet WA gas prices have still trebled.

Thus we all have to face the fact that our gas bills over the next few years may yet have higher to run as the LNG export boom period begins. Adding to the irony is the fact it has become increasing apparent the east coast of Australia is fairly bursting with CSG. Energy companies are ready to drop a test well into any farm or probably back garden and start fracking immediately. On that basis, local gas should be a lot cheaper one presumes, especially when “the gap” ultimately closes. There remains only the small matter of obvious farmer/landowner and environmental opposition, and subsequent political resistance.

Electricity bills, too, have risen exponentially. Aside from the so-called “gold plated poles and wires” debate, bear in mind that Australian gas-fired electricity production is rising as an offset to coal-fired. In other words, double whammy.

It is not just households suffering energy bill angst. Energy-consuming industry is also a victim of the sudden explosion in utility costs. This is no trivial matter, given Citi suggests a two or threefold increase in the cost of domestic gas and the inability to secure supply beyond 2014 (when it will all go offshore) are likely to impact on basic industrial stocks by compressing margins, pressuring companies to rationalise excess capacity and rendering some prospective projects uneconomic.

Investors in favoured stocks may be inclined to asses just how energy intensive those companies’ activities are, notwithstanding allowances for those companies sourcing self-owned power. If LNG aspirants do not satisfy the risk/reward preferences of the longer term investor as an investment, they may actually be an attractive consideration as a hedge. At least towards 2020.
 

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