Having already grown by 2/3rds since 2005, global LNG production capacity is set to leap a further 50% over the next 5 years if all known projects are completed, according to a new analysis by Evaluate Energy. LNG demand in the Asia-Pacific is strong, but growing shale gas volumes in the United States – a trend unforeseen when these LNG projects were conceived and implemented – has lowered the expected demand curve thereby eating into the potential profitability of these new facilities and postponing the vision that investors originally had of the role of these giant projects.
It’s hard to know which way round this is working: to what extent is additional spot LNG availability putting a lid on gas prices in North America or, alternatively, to what extent is additional shale gas supply in the US undermining demand for LNG. But we do know that LNG spot cargoes have been offered at par with domestic gas prices in the US for some time, giving much lower netbacks for producers than they might have been hoping for when they decided to invest in these megaprojects.
Although National Oil companies such as Qatar Petroleum, Sonatrach and Petronas continue to dominate the LNG business, oil Majors such as Royal Dutch Shell (NYSE:RDS.A, LON:RDSA) and ExxonMobil (and to a lesser extent BP and Total) have substantially increased their exposure to the sector. By 2020, Shell will be the 4th largest equity holder in the global LNG business and ExxonMobil (NYSE:XOM) the 5th. This represents an estimated industry-wide capital cost of $200 billion over the next 10 years, based rising capital cost intensities of new LNG projects. That’s according to an analysis by Evaluate Energy of future projects on a company by company basis. Ultimately the security of equity share the IOCs have in these projects depends on the stability of the local NOC and its government.
“Natural gas will be the fastest-growing major fuel source…the result of two factors. One is a steep rise in demand for fuel for power generation…, particularly in Non OECD countries. The second is a shift away from coal in order to reduce CO2 emisions…”
Add to those considerations the fact that the Majors have been finding it difficult to replace reserves organically and finding it even harder to gain access to reserve-rich countries while oil prices were rising.
These considerations still apply. However, when many of the decisions were made to build these huge capital intensive, ‘lumpy’ projects, horizontal drilling and fracking for shale gas were a mere glint in a driller’s eye.
Forecasters expected the US would need substantial imports of LNG as domestic gas production and imports from Canada fell. They fell into the classic forecasting error of projecting present trends into the future and not being fully aware of a real game-changer, what Nicholas Taleb, has called a “Black Swan”.
Instead, the US now imports only small amounts of LNG from Egypt, Nigeria, Norway, Peru, Qatar, Trinidad and Tobago and the Yemen at prices that averaged just $4.81 per thousand cubic feet, according to the US Energy Information Administration. These prices are only a shade higher than the depressed Henry Hub domestic marker price.
So these huge LNG production and regasification capacity projects went ahead and have created a mismatch between demand and capacity mismatch in the United States. US regasification capacity is currently around 15 bcf/day, according to Evaluate Energy’s database of regasification facilities. – equivalent to no less than one quarter of the whole of current US natural gas consumption. Yet these facilities are being utilised at a tiny fraction of their capacity. LNG regasification volumes in the US were just 2 million cu ft a day, or a mere 13% of installed regasification capacity, in January of this year, for example.
The outlook for LNG importers into the US isn’t likely to get better anytime soon. For example, take the US Energy Information Agency’s latest Annual Energy Outlook which predicts the requirement for natural gas imports will be totally flat through 2020.So we are moving into an era in which the potential exists for LNG imports into the US but there is little demand for it.
In the words of ExxonMobil’s latest Energy Outlook:
“Globally, unconventional gas production is projected to grow fivefold from 2005 to 2030. The largest growth by far is in the United States, where unconventional production meets well over half of US gas demand by 2030.”
Indeed, several companies are moving to propose new LNG export projects out of North America, offering a release valve for surplus natural gas. This might ease prices in North America but will have a knock-on effect in Asian markets. Import terminal developer Freeport for example is proposing a $2 bln 1.4 bcf/d export facility at their existing import terminal in Texas for start-up in 2015. Cheniere Energy, who run an existing regasification plant at Sabine Pass Louisiana, are planning to make the facility bidirectional, allowing some 2.4 bcf/d of LNG exports. The Kitimat project on the west coast of British Columbia has also changed plans to export rather than import LNG into the West Coast.
With new LNG capacity coming onstream so fast, a potential overhang of spot LNG is one of the factors that may be keeping natural gas prices low in the US. And as far as the LNG project owners are concerned in the producing nations – IOC and NOC alike – it will be the pace of LNG demand growth in Asia relative to the build up in LNG production capacity that will dictate how tight or slack the LNG spot market will be over the next few years. Recent signs are that LNG demand in Asia is accelerating, leading to a outrush of optimism among LNG shipowners and builders but it is perhaps too early to say whether this is a temporary spurt or a sustainable surge. That’s an inherent problem of an industry that moves forward in large supply steps that are sometimes out of line with demand.