As LNG supply tightens, uncertainty mounts
Forecasts for the growth of LNG – ranging from a bullish 7% a year to a stratospheric 10% – look increasingly unrealistic in a supply-constrained world, writes Alex Forbes
OFFSHORE Teesside in northeastern England there is an innovative new liquefied natural gas (LNG) importation facility – Excelerate's GasPort project. It was commissioned in February, but, after receiving an initial cargo that was used to get the facility up and running (5% of a carrier's-worth from Trinidad) it has lain idle.
Southwards, in the Thames estuary, the operators of the Isle of Grain regasification project could, until last month, have been forgiven for having forgotten what an LNG carrier looked like. The cargo that unloaded in the middle of October was the first to arrive since July and only the 11th to arrive this year.
Moving westwards into south Wales, two large regasification facilities are under construction at Milford Haven. Dragon is due on stream before the end of the year and the South Hook terminal should be commissioned by the middle of next year – but no-one is sure how much LNG they will regasify. What seems highly likely is that neither will work at anything like capacity in the first year of operation and probably for much longer.
So why is it – after so much hullabaloo about the future role of LNG in the now import-dependent UK market – that these expensive new projects appear to be so little needed? And what are the implications for the wider LNG industry?
Of the various factors at work, some are specific to the UK market. Others relate to wider issues of how the LNG industry is developing in the context of global natural gas – and indeed energy – markets. The bullishness of 2004 and 2005 has been tempered in 2006 and 2007 by concerns that LNG growth will be constrained by supply. This is not just affecting forecasts of LNG production growth to 2020, but also causing developers of proposed regasification terminals to reconsider their positions.
The situation in the UK is the result of a surprisingly sudden realisation in the early years of this decade that a country that used to be a net gas exporter was becoming a net importer because of declining indigenous production.
Such was the level of concern about gas supply that even regulators battle-hardened by the fight to liberalise markets readily offered derogations from third-party access requirements for most new import-infrastructure projects. What followed was a rush to construct new gas-importation capacity in the form of both pipelines and LNG regasification facilities.
Today, the UK market is flooded by new import capacity. The 3.3m tonnes a year (t/y) Isle of Grain LNG facility, which came on stream in July 2005, was quickly followed in the autumn of that year by the 15bn cubic metres a year (cm/y) Balgzand Bacton Line from the Netherlands. In October 2006, the first phase of the 20bn cm/y Langeled pipeline from Norway began operation. The GasPort LNG facility in Teesside, which came on stream in February of this year, has been followed this autumn by the second phase of Langeled and the little-known, but significant, 10bn cm/y Tampen Link pipeline connecting the Norwegian and UK offshore networks.
For now, at least, the pipelines appear to have the upper hand. This is partly because pipeline supply still tends to be less costly than LNG. But, in a globalising gas world, other factors are coming into play: tightening LNG supply; high oil prices; changing weather patterns; and acts of god, such as the earthquake in Japan earlier this year that led to the emergency shut-down of Tokyo Electric Power's 8 gigawatt nuclear power plant at Kashiwazaki-Kariwa– an important driver in spot/short-term LNG trading for much of 2007.
Of these factors, the one driving perceptions of LNG development more than any other is the tightening of supply – in the long, medium and even short term. At the start of 2006, expectations were high that the year would see a series of final investment decisions (FIDs) on greenfield and expansion liquefaction projects. By the end of the year, it was being widely reported that not one of these projects had reached FID. This was not strictly correct – Peru LNG reached FID in late December – but the general trend was clear.
Three new projects in two years
So far in 2007, with the year coming to a close, Australia's Pluto LNG has reached FID, while Sonatrach has finally awarded the engineering, procurement and construction (EPC) contract for the new train that will replace those destroyed in an explosion at the Skikda complex in 2004 (a project generally referred to as the Skikda re-build). That makes just three new liquefaction projects sanctioned in almost two years.
The scarcity of liquefaction projects reaching FID over the past two years has raised concerns about how burgeoning demand for LNG will be met from 2010 onwards, given that it is taking around four years to bring liquefaction projects on stream from the award of EPC contracts.
Looking further out, doubts are growing about how quickly projects expected to come on stream in the post-2010 time-frame will materialise. Several LNG projects proposed in Russia now have big question marks hanging over them; it is hard to see what will follow the Sakhalin Energy project, which looks likely to come on stream next year.
Of the numerous LNG projects proposed in Iran – some more speculative than others – not one has yet reached FID or awarded an EPC contract. Pars LNG, the project generally regarded as the most advanced, appears to be going nowhere fast.
In Algeria, the Skikda re-build is not expected on stream until 2011, two years behind the original target of 2009, while the Gassi Touil project, for which the original target was also 2009, has run into the sand. In September, Sonatrach kicked out its Spanish partners, Repsol YPF and Gas Natural, because of delays and cost over-runs. The Algerian state-owned company is now adamant that it will complete the project on its own (PE 10/07 p37). The earliest feasible start date now looks to be 2012.
Progress in Nigeria, Australia
Progress is being made in two other nations with major liquefaction construction ambitions – Nigeria and Australia – but not nearly as quickly as was envisaged even a year ago.
The result of all this doubt is that industry consultancies such as Wood Mackenzie and Gas Strategies have been revising downwards their projections for the build-up of global liquefaction capacity out to 2020. The forecasts made for LNG growth over the past 18 months have ranged from the bullish to the stratospheric, but they have tended to assume that supply would not be a constraint.
At the World Gas Conference in Amsterdam, in June 2006, for example, Royal Dutch Shell's chief executive, Jeroen van der Veer, said LNG would grow at a rate of 10% a year through to 2020 (with Shell's own production growing by 14% a year).
According to Cedigaz, LNG trade in 2006 amounted to 211bn cm (or 159m tonnes). Taking that as a starting figure, a 10% annual growth rate would see LNG trade rising to around 0.5 trillion cm (370m tonnes) in 2015 and to 0.8 trillion cm (0.6bn tonnes) in 2020. The view of Cedigaz' secretary-general, Marie Françoise-Chabrelie, is that LNG is likely to grow by 6.5-7.5% a year. The mid-point, 7% a year, would take LNG trade to 390bn cm (290m tonnes) in 2015, and to 0.54 trillion cm (410m tonnes) in 2020.
In a review of natural gas markets published earlier this year, the International Energy Agency projected that LNG production capacity would rise to 0.5-0.6 trillion cm/y by 2015, equivalent to annual average growth rates of 7.5-9.0%.
If, as seems increasingly likely, production growth is more like 4% a year because of supply constraints, volumes in 2015 would reach 300bn cm (230m tonnes), rising to 370bn cm (280m tonnes) by 2020. Figure 1 illustrates what this would mean.
The factors likely to limit the growth of LNG after 2010 – likely to lead to delay or even cancellation of proposed projects that have not yet begun construction – were explored in detail earlier this year at LNG15 in Barcelona, the triennial conference that is the industry's largest gathering.
What emerged in Barcelona is that the industry faces four main challenges: access to gas reserves; the spiralling costs of raw materials, such as steel and nickel, and contractors; the availability of contractors able to handle large EPC projects; and the availability of skilled operating staff, in the case of onshore projects, or qualified seafarers, in the case of shipping.
There are signs that these problems are already affecting the industry: in recent months, concern has begun to grow that the six mega-trains under construction in Qatar, which together will account for a very large slice of new supply, may prove more difficult to bring on stream within the original timetable than everyone had been assuming.
Qatargas-2's Train 1, for example, which at one time was expected to start up around now, is not likely to come on stream much before the middle of next year. That leaves Qatargas facing the problem of what to do with the project's ships, which are already being delivered.
To date, Qatar's record of completing LNG trains on time has been exemplary, but while EPC contracts were awarded some time ago for all its new trains, the country is finding that it is not immune to the cost over-runs, supply bottlenecks and staff shortages that are besetting the entire energy-project construction industry.
An additional source of uncertainty for Qatar is that the liquefaction technology being used in all six trains is new and has yet to be tested in an operational project. An example of the problems that can occur when new technology is employed for gas liquefaction is Norway's Snøhvit project in the Barents Sea, which has been struggling for weeks to produce sufficient LNG for its inaugural cargo.
All this means that even in the medium term, meaning between now and 2010, there are signs that supply will be tighter than many previously expected. An insight into what tightening supply could mean for LNG buyers can be gleaned from what has been happening in the spot/short-term LNG markets over recent months.
Paying the price
Following the earthquake that shut down the nuclear plant in Japan, and with an eye on securing cargoes for the coming winter, Japanese LNG buyers have been happily paying $12.50/m Btu for any spare or flexible cargoes they could lay their hands on. Japan is entirely dependent on LNG for its natural gas supply, unlike markets in the Atlantic basin, which mostly depend on pipeline gas, with LNG playing a marginal role.
This goes a long way towards explaining why regasification terminals dependent on liquid, traded markets for gas demand have found it difficult to attract cargoes for much of this year. That should change as winter approaches, although much will depend on how cold it becomes.
Quite how the dynamics of the LNG market will play out is hard to forecast, depending as they do on so many factors that are themselves beset with uncertainty. As the uncertainties grow, LNG is starting to look a much riskier business.
No particular place to go
WITH the liquefied natural gas (LNG) industry undergoing a metamorphosis in the way it operates commercially, the deal reached earlier this year by Algeria and the European Commission over how gas-supply contracts are drafted has provided welcome clarity.
Until relatively recently, the complexity and cost of LNG technology meant that it was a niche fuel, competitive only under particular sets of circumstances and in particular markets. The complexity of the hardware was matched by the complexity of the commercial arrangements put in place to ensure that billion-dollar investments would earn an appropriate return.
These arrangements were underpinned by contracts with terms of 25-30 years, to match the expected life of the producing assets. So rigid were the terms of these contracts – particularly in specifying the destination of LNG cargoes – that LNG projects were sometimes described as virtual pipelines.
It is these so-called destination clauses that were at the centre of the agreement between Algeria and the Commission. The agreement also covered so-called profit-sharing mechanisms (PSMs), which have become increasingly popular as a way of sharing profits when seller and buyer mutually agree to divert an LNG cargo to a higher-priced market.
The Commission has long regarded destination restriction clauses as anti-competitive. In 2003, it reached agreement with Russia to remove such clauses in pipeline supply contracts. Negotiations with Algeria have taken much longer, partly because the country's national oil company, Sonatrach, is a large supplier of both pipeline gas and LNG, which, with its inherent destination flexibility, raises more complex issues.
The EU Commissioner for Competition, Neelie Kroes, said the agreement "eliminates an important obstacle for the creation of a single EU-wide market in gas". This is what Kroes and the Algerian energy minister, Chakib Khelil, have agreed under their common understanding:
- Territorial restrictions will be deleted from all existing contracts and will not appear in future contracts;
- PSMs will only be applied in LNG contracts under which the title of the gas remains with the seller until the ship is unloaded, terms generally known as delivery ex-ship (DES). Consequently, Sonatrach is aiming to transform its remaining free on-board (Fob) and carriage, insurance, freight (Cif) LNG contracts to sales under DES terms;
- There will be no PSMs in future LNG contracts under which the title of the gas passes to the purchaser at the port of loading (in practice, for sales under Fob and Cif terms); and
- There will be no PSMs in existing or future pipeline gas supply contracts.