The gas revolution

Capital considerations

All this activity has been generated in a little over five years since Heritage Oil (HOIL) and Tullow Oil (TLW) alerted the industry to the promise of the region through a successful exploration programme in Uganda's Lake Albert. The subsequent rate of change has been so rapid, that a significant portion of the estimated $169bn in capital expenditure earmarked for global LNG projects through to 2017 could be diverted to East Africa. It's certainly possible given the region is long on reserves; and short on production. But would that be in the immediate interests of the likes of Shell and BG Group (BG.), which have been pouring billions into the development of the Australian LNG industry?

Within the next five years, it's expected that Australia's annual liquefaction capacity will substantially outstrip that of Qatar's - currently around 78m metric tons - but some of the biggest players in the industry have been reviewing their commitments down under in light of the strength of the Australian dollar, combined with fast-rising cost inflation. BG, Chevron and local energy company Santos all faced cost overruns during 2012. And during the next few months, Shell - as part of a consortium led by Australia's Woodside Petroleum - will decide on the preferred monetisation option for the $40bn Browse LNG project off Western Australia. Cost considerations were partly responsible for a number of equity changes to the Browse project last year, but the backing provided by a number of heavy-duty Asian investors provided reassurance for the market. Japan's MIMI (Mitsubishi Corp and Mitsui) forked out $2bn for a 14.7 per cent stake, while BHP Billiton (BLT) sold its 10 per cent holding to PetroChina for $1.63bn. BP (BP.) has also taken a minority position. Shell became the second-largest holder in the consortium when it took over an interest held by Chevron, and the Anglo-Dutch giant may well push its partners towards an unconventional solution.

Less than 5 per cent of China's electricity is produced through natural gas, but that could change rapidly on completion of new LNG facilities.

The future's offshore

One of the options being considered for taking Browse forward is through the use of a floating liquefied natural gas (FLNG) terminal. Shell, in particular, has been investing heavily in the development of this technology. The group is already building the world's first FLNG facility at Australia's Prelude offshore LNG project, which is expected to start by 2017, with a processing capacity of 3.6m tons. The group's commitment to this fledgling technology was underlined by a heads of agreement it signed with Asia's Technip Samsung Consortium covering the design, engineering, procurement, construction, and installation of future FLNG facilities.

It's not difficult to appreciate the commercial incentives. FLNG technology will allow energy companies to unlock previously inaccessible offshore gas fields that hitherto would have been too difficult or costly to develop. By utilising FLNG platforms, energy companies won't need to lay expensive underwater pipelines, nor develop coastal infrastructure - the potential cost benefits from this technology could transform the industry.

Oz costs prompt a rethink

As mentioned, although Australia will outstrip Qatar in terms of LNG output in fairly short order, it certainly won't in terms of unit profitability for the industry. That was always likely to be the case, given that the Gulf State's production costs are kept relatively low by a geology that renders the bulk of its reserves easily accessible. However, the marginal difference has been magnified by the currency/inflationary problems besetting Australia. The successful development of FLNG technology would eventually bring more of Australia's offshore gas deposits into play, and substantially reduce cost pressures. Estimates vary, but offshore LNG deposits could be up to 40 per cent cheaper to access.

After a problematic year for the industry in Australia, any positive news on the offshore developments would be welcomed by investors. However, it's conceivable that if the roll-out of FLNG technology was to gather momentum, then the East African discoveries could be commercialised far more rapidly (and with less capital) than currently anticipated. Another incentive is provided by the proximity of India, a ready and expanding marketplace, where the growth of the economy is being stifled by a perpetual energy deficit.

Obviously, the relentless upward pressure on costs in Australia has spooked some investors, but the moves by PetroChina and MIMI indicate that certain investment decisions are being undertaken primarily from a strategic angle, rather than simply from a narrow focus on profitability. This raises the fundamental issue of whether the huge capital outlay by the industry is justified by the current increase in global demand, particularly in light of the slowdown in the world economy.

Shell has been investing heavily in the development of floating liquefied natural gas (FLNG) technology.

Long-term trends still positive

Not all the portents are favourable. For example, China still imports far more gas via overland pipelines, as opposed to the world's sea lanes. This is reflected in a recent assessment provided by shipping specialist DVB Bank SE, which points to over-capacity in seaborne LNG transportation for this year and next. Shipyards are set to build LNG carriers that will increase seaborne export capacity by around 16 per cent by 2015, but liquefaction facilities that produce seaborne cargoes will increase capacity by just 9.7 per cent over the same period, effectively lowering vessel usage. Fleet utilisation stood at 90.1 per cent last year, but will fall to 89.5 per cent and 87.7 per cent respectively over 2013-14.

Energy analysts have certainly become more downbeat in their assessment of the global LNG industry because of the extent of cost escalation in Australia, coupled with anxieties over China's economic performance. Nevertheless, long-term prospects remain strong. For a start, there are already signs that cost pressures in Australia are beginning to dissipate, particularly on the labour front. It's also worth noting that China's new administration - headed by President Xi Jinping - has clearly indicated that it will prioritise the use of cleaner fuel sources, wherever applicable, as part of policy to improve air quality in China's urban areas. Beijing has dragged its feet on environmental issues, and widespread corruption and a lack of accountability has meant that even meaningful reforms have floundered. Yet the administration is finding it harder to ignore evidence that the long-term cost in public health terms may yet outweigh the economic benefits accrued from its existing laissez-faire energy policy. The country is home to three-quarters of the world's 20 most polluted cities; the unfortunate legacy of three decades of unfettered economic growth.

Although Beijing is now offering subsidies to coal-fuelled power plants that reduce their nitrogen-oxide emissions, the future emphasis in China will increasingly be on electricity generated through renewable and nuclear sources, in addition to natural gas. When used to make electricity, gas-fired turbines emit less than half the CO2 emissions of those powered by coal. At present, less than 5 per cent of China's electricity is produced through natural gas, but that could change rapidly on completion of new LNG facilities, and the eventual development of a domestic shale gas industry. New supply will certainly be needed. According to the Paris-based International Energy Agency (IEA), China's annual gas consumption will double in the five years to 2017, and other nations in the Asia-Pacific region are following suit. The immense scale of BG's investment in Australia has been predicated on the view that by 2025, the four biggest consumers of LNG will be Japan, China, India and South Korea, while Indonesia, Singapore, Vietnam and Thailand intend to develop LNG import terminals. And the experience of the US demonstrates that the transition to gas-fired electricity can occur rapidly; last year, natural gas fuelled just under a third of US domestic power requirements (coal provides 39 per cent), against just 12 per cent five years earlier.

But at what cost?

Of course, the experience of the US, particularly through the expansion of its shale gas industry, raises the contentious issue of gas pricing. Industry watchers sounded a cautionary note in the wake of the collapse of wholesale prices in the US. Last April, prices hit a decade low as the market was forced to absorb a glut from domestic producers. As a consequence, heavyweight investors in the sector - such as BHP, Chesapeake Energy, Shell and ExxonMobil - were forced to book substantial write-downs on their US shale gas assets, although they may subsequently turn out to be excessive. US prices, though volatile, have recovered in the intervening period, but the fact that relative wholesale prices declined to less than a third of those in Europe underlines the piecemeal nature of global pricing.

Europe's gas imports are generally pegged to petroleum prices; a somewhat spurious system that nonetheless tends to underpin producer prices. There are around a dozen LNG import facilities in the US, and there are proposals afoot to convert at least some of these into liquefaction export plants in response to world demand. There are legislative barriers in the US to prevent the export of gas, so Federal authorities need to rubber stamp any export licences. Nevertheless, the transition of the US to a net exporter of LNG is likely given the price premium available in global markets.

Some opponents of US LNG exports think that they could push up consumer prices, and imperil a recovery in US industry. However, a report published by Deloitte - covering the probable impact of US LNG exports - maintains that a managed transition could result in a move away from oil-priced indexation of gas supply contracts. North American households and industry would still purchase their gas based on the 'Henry Hub' price, but exporters would be free to negotiate contracts on global markets. After all, a supply-side glut in the US invariably decreases investment incentives, so it makes sense to allow local producers to cash in on a global price anomaly. Such a scenario is also is potentially good news for European consumers, although rather less so for Gazprom.