Feature Stories | Aug 30 2012
This story was first published on August 8, 2012, for subscribers only. It has now been republished for general readership.
By Greg Peel
BHP Billiton's ((BHP)) US$2.8bn write down of shale gas assets acquired from Chesapeake Energy was big news in the Australian market this week. On face value it was very bad news, particularly given the write-down represented more than half of the original February 2011 purchase price, and has called into question from some commentators the longevity of Marius Kloppers' reign as CEO. However from an analyst's perspective the news was actually more positive.
For starters, the write-down amount was not as large as some had feared, with talk of US$5-6bn (including other assets) having permeated the market. Secondly, BHP did not announce any write-down of its much larger Petrohawk Energy shale acquisition, which was purchased last August for US$15.1bn. The company blamed weak US gas prices, which it sees as short term, for the Chesapeake write-down, but declared Petrohawk's value to be unaffected by such shorter term considerations.
The US natural gas price, which is benchmarked by the Henry Hub futures price as traded on Comex, has been in the grips of unusual pricing activity ever since the GFC due to a welter of competing macro and micro, shorter term and longer term factors. The price of gas had previously traded in a reliable ratio band to the benchmark oil price, given a level of substitution between the two hydrocarbon sources, but while both prices crashed as an initial result of the GFC, oil quickly pushed back towards earlier highs while the gas price just kept falling.
There is no one “oil”, and prices of oil delivered to various locations around the globe will vary depending on oil grade, transportation costs and storage capacity and cost. Crude oil, being a liquid, nevertheless moves fairly freely around the globe. Over the past two years we have seen the vagaries of oil pricing manifested in the blow-out of the price of Brent crude above the price of the longstanding West Texas Intermediate benchmark, but the price gap is largely representative of storage limitations and lack of export opportunity for land-locked WTI. Otherwise oil's ease of global trade makes the commodity subject to macro influences, from global economic factors impacting on demand to geopolitical tensions affecting supply.
The price of natural gas is not immune to such macro factors, but gas is far more heavily impacted by domestic conditions. Gas for domestic consumption can be piped to consumers as a gas, while gas for global export has to be liquefied at significant cost in order to be transported. Given the US is yet to export gas (LNG), the “global benchmark” Henry Hub price is at the whim of domestic demand and supply and thus removed from, for example, the “price of gas” for Australian consumers.
On the macro scale, it had been assumed for a long time the US would eventually have to import LNG, but when new technology reopened the massive US shale fields, the US quickly shifted to a point of expecting to have more gas than it could use. While the price of oil has risen post-GFC, the price of US domestic gas has fallen given the shale gas “glut”.
Gas is nevertheless no different to any other commodity for which over-supply results in low prices, which then force supply cut-backs, which results in under-supply, thus pushing prices higher again…and do-si-do your partner. The same works the other way around from the demand side. What shale gas aspirants such as BHP ran into from early 2012 was a confluence of longer term and shorter term factors.
The shale gas glut itself was was rapidly filling US storage tanks when early this year America enjoyed “the winter that never was”. The unseasonably mild winter weather simply meant lower demand for the gas that was already building up due to increased supply. The US natural gas price fell to under US$2.00/mmbtu which sent veteran energy traders into shock. At the same time, the “oil price” traded over US$100/bbl.
The burgeoning US shale gas industry's (including BHP) response to such uneconomical prices was to begin reducing the number of drill rigs in operation, and to shift focus away from abundant “dry gas” to more lucrative shale “liquids” present at various sites. The lower price had the effect of reducing supply.
On the demand side, the historically low gas price was not lost on US electricity providers. It takes some time to bring a coal-fired power plant up to production levels so electricity companies are not keen to switch them on and off too regularly on the basis of demand swings. By contrast, gas-fired power plants can be switched on and off relatively easily. With summer approaching, US electricity providers began to exploit low gas pricing to meet marginal electricity demand. Excess US gas storage began to be drained.
America's mild winter has been followed by a particularly hot summer. While a mild winter reduces demand for gas and electricity, a hot summer does the opposite. As demand for gas-fired electricity surged in July, so did the gas price – all the way from under US$2 to over US$3/mmbtu at a rapid clip.
So we are faced with the irony of BHP announcing a significant shale asset write-down just as US gas prices have rallied some 40%. Energy analysts admit, nevertheless, they have been taken aback with both the rapid drop in the shale drill rig count and with the level and speed of “coal displacement” (electricity companies quickly switching to gas-fired generation from coal-fired generation). These are shorter term influences to consider for future forecasting. On the weather front, August is expected to be warm in the US but not as hot as July, while gas players must now look ahead to the expected energy demand cycle of the next winter, assuming a return to “normal” temperatures.
Across the globe, investment in natural gas production – from shale gas to supply the US domestic market to Australian LNG projects preparing for supply to Asia – is a long term consideration. Weather is a short term consideration, but the historically low US gas prices of early 2012 and their impact show that the short term cannot be ignored. Accepting that weather will always be unpredictable but should follow typical cycles on average, let us now consider the macro and longer term vagaries of global gas supply and demand.
Unsurprisingly, demand for energy is currently weak in recession-hit Europe. The bulk of gas consumed in Europe is piped in from Russia, but with Russia prone to limit exports if domestic demand requires, Europe also imports LNG. Russia has not reduced supply to Europe this year, so Russian gas is flooding in despite weaker demand. LNG has also been arriving from the likes of Qatar and Nigeria given those producers have hit a drop in demand from Asia.
When Japan suffered its tsunami and subsequent nuclear disaster last year, resulting in the shutting down of the country's nuclear power generation (30% of electricity supply), it was immediately assumed gas would be the “winner” from the tragedy. Japan would need to import LNG for gas-fired electricity production and the Japanese government feared rolling black-outs by the summer. Japanese utilities sprung into action, and by May had imported some 80-90% of expected summer requirements. So far Japan has experienced a relatively mild summer.
One might assume Korea feared the price impact from the elevated LNG demand of its neighbour and reacted accordingly, given Korea's May natural gas inventories were more than double that of the previous May.
In the meantime, China has also been suffering an economic slowdown. Chinese electricity generation was down 5.6% year on year in June, which should imply reduced demand for imported LNG for gas-fired power stations. However, as National Australia Bank analysts note, China's LNG imports increased by 33% year on year in June. That's a lower rate than was the case in May, but nevertheless indicates China's LNG import program remains “massive”.
How long can China maintain such levels of LNG import growth as its economy slows? It is a well known fact that Beijing does not like to be beholden to volatile global price variations in commodities China does not produce in sufficient amounts domestically, having been caught out in past decades. China's state-owned enterprises are thus prone to stockpile particular commodities beyond that which otherwise might be expected, taking advantage of cyclically weak pricing. When prices recover, China backs off and starts consuming those cheaper stockpiles.
Reports suggest, notes NAB, that Chinese activity in the spot LNG market has been “very quiet” in recent weeks.
With Japan, Korea and potentially China all now holding gas inventories in excess of immediate demand, LNG prices in the Asia Pacific region have recently drifted lower. From an average of US$18.00/mmbtu in June, reports now have spot prices trading around US$13.50/mmbtu. Note that the difference between the Henry Hub natural gas price and LNG prices reflects the cost of converting gas to LNG, transporting it, and converting it back to gas again. It is weaker Asian demand which, as previously noted, has pushed Qatar and Nigeria to divert some of their LNG exports to Europe, which itself is suffering weaker demand in the face of more than sufficient supply.
Meanwhile, since the US domestic gas priced bottomed at US$1.80/mmbtu and surged to over US$3.00, US electricity providers have pulled back on their coal displacement. It's all about price. The result is a recent drift-back in pricing to around US$2.90/mmbtu. August is so far not as hot in the US as was the case in July, and as the fall approaches seasonal demand will drop back until cycling into the winter cold, assuming normal conditions.
On that basis, more than one analyst is expecting Henry Hub prices to continue to drift lower in the September quarter before turning around once more in the December quarter. No one is expecting to see US$1.80/mmbtu again. The basis for this argument is not the weather, but the longer term picture.
The US low-price episode has forced rationalisation (and write-downs) in what some had earlier described as the US shale gas production “bubble”. Data in the meantime have also suggested initial well life assumptions may have been overly optimistic. But another factor is at play for the bigger picture of US gas prices.
Last week, US company Freeport LNG announced it had signed a 20-year liquefaction tolling agreement with the two largest utilities in Japan, Osaka Gas and Chubu Electric, for the supply of 100% of the capacity of the first LNG train at the proposed facility at Freeport, Texas. The first train represents a third of the total capacity of what is a proposed three-train operation, and the two utilities are in “exclusive negotiation” for off-take agreements for the other two trains.
Aside from playing havoc with domestic natural gas pricing, the US shale boom has allowed the US to swing from expected LNG importer to planned LNG exporter. As the above deal suggests, the US should not have too much difficulty finding customers. The Freeport facility is expected to reach a final investment decision for the full project by the latter half of 2013, and operation is not expected until around 2017-18.
The Americans are looking to exploit the widely assumed acceleration of Asian energy demand into the future, particularly from China. Australian LNG aspirants are chasing the same market. Energy analysts have for some years warned that America's LNG plans will potentially undermine the expected riches to be generated by Australia's LNG push. There is nevertheless a matter of timing.
Energy analysts have also warned that not everyone with LNG aspirations, including in Australia, will successfully coexist. Asian gas demand growth is not expected to be limitless and the bulk of supply is traded in long term offtake agreements of twenty years average, with the major consumers (utilities) already taking equity stakes in LNG projects. On that basis, “first to market” is of significant importance. Analysts expect those LNG projects already sanctioned in Australia to enjoy the spoils (assuming costs can be managed and enough gas can be sourced) but others to miss out.
If all goes to plan, the step-jump in Australian LNG production will commence from around 2014 – a few years ahead of the Freeport timeline. Moreover, the US Department of Energy has to date only approved one application for the export of US domestic gas, JP Morgan notes, and the current Administration is awaiting the results of a DOE study into the effects of exports on domestic gas prices before any further applications are approved. Earlier assumptions had first US LNG being ready for export from around 2015 but this timing is no longer so clear.
One presumes a change of Administration in the US would bring a change of attitude, but either way there have been plenty of assumptions made already about what effect a jump in LNG exports from the US would have on Australian domestic gas prices. With lucrative Asian offtake contracts on offer, Australian gas for domestic consumption will be priced in accordance with prices achievable through LNG production and sale. In other words, Australian gas prices are expected to rise dramatically.
The same is expected in the US, assuming no impediments are placed on a US LNG industry. We do, of course, have to take in population differences and assumptions about just how much gas reserves there are in the US compared to Australia and so forth, but aside from expected Asian demand growth being the primary driver, US gas consumption is also expected to rise.
US electricity producers may have been exploiting low prices by switching to gas-fired from coal-fired earlier this year, but “cleaner” gas-fired is set to replace retiring coal-fired plants over time as US environmental regulations come into force. A demand-side response will still be needed, and JP Morgan suggests that will need to come from industrial consumers including the transport industry. Trying to predict producer behaviour at different pricing levels is at this stage very difficult, the analysts admit.
JP Morgan notes that the gas price forward curve has split distinctly into three segments – 2012 pricing, 2013-14 pricing, and pricing for 2015 and beyond. At the short end we have the immediate influences discussed in this article, in the mid-section we hit the lull between growing global LNG demand and the supply-side catch-up timetable, and from 2015 and beyond we see visions of the future. It is within the latter timeframe that most of the supportive narratives will manifest, JP Morgan suggests.
“The historically wide spread between crude oil and natural gas pricing is driving long-term decision-making regarding infrastructure and transportation development,” the analysts note, “and the decisions being made now should begin to impact the actual balance right around the time when [US] LNG exports become a reality”.
And so we return to BHP and its shale asset write-down. While the US$2.8bn write-down of the Chesapeake asset proved less than some had feared, a concern remains BHP will be forced to make further write-downs, including to the Petrohawk assets unaltered on the books. While conceding the low US gas price (in face of rising production costs) forced last week's write-down, BHP has remained stoic on the longer term value of the Petrohawk acquisitions.
One presumes BHP's stance reflects a generally accepted expectation for gas prices to rise over time. The experiences of 2012 nevertheless serve to emphasise that the road is never a smooth one. The global economy was not previously expected to slow as much as it has in 2012, the US winter was meant to be cold and the summer no more than typically warm, gas prices were certainly not expected to fall as low as they did and cost increases in the resource sector are still taking producers by surprise.
Meanwhile in Australia, LNG news continues to fluctuate. Gas supply is an issue off the west coast but Woodside Petroleum's ((WPL)) sell-down of equity stakes and progress on Pluto LNG, for example, has offered greater hope. Gas supply is also proving an issue on the east coast but newly sanctioned LNG trains are also keeping hopes very much alive. On both side of the continent, costs remain an issue. Political polarisation over the impact of CSG extraction on farming land is the latest fly in the ointment.
For the stock investor, it remains a bumpy road.
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