BO – 19 Novembre 2013

Gas mUS exports of LNG may be able to open up and integrate global gas markets, but only if there is enough gas – and if it gets to the market in time, writes Matteo Mazzoni of Italian research company NE Nomisma Energia. If not, it will find the window of opportunity closed by new pipelines and geopolitical arrangements. A look ahead at how world gas markets may develop.
Until recently, most market watchers were expecting that growing, flexible LNG supplies from various parts of the world would link the world’s three major regional gas markets – North America, Europe and Asia – ever more closely together. Regional price differentials and oil-indexed gas prices were expected to be on their way out.

As most readers will know, the global gas market is characterized by strong regional differences both in terms of prices and flows. In the US, Henry Hub prices reached a low of $2/MMBtu by mid-2012 and have recently stabilized at $4/MMBtu. In the European market prices have been flat around $10/MMBtu. In North East Asia, Japanese prices peaked above $18/MMBtu early this year, later slipping down to $15/MMBtu after demand started to fall.

The price differentials remain so marked because we have three markets experiencing opposite dynamics: an abundance of natural gas in the US, generated as a consequence of the shale boom; a switch from gas to coal in European power generation, which has resulted in lower LNG imports; and a skyrocketing Asian demand, mainly coming from Japan, which desperately needs to replace almost 30% of its power generation, after the stop imposed on all its nuclear power plants.

The growth in LNG supplies has not yet been able to overcome these fundamental differences. Indeed, the LNG market has recently met with unexpectedly heavy weather. During the past decade natural gas consumption grew by an average 2.8% per year. A trend which was seen as the beginning of a new era, the “Golden Age of Gas” as the International Energy Agency called it just 2 years ago. But that age seems to be taking longer than expected based on the latest figures. In 2012, in fact, natural gas consumption grew by a thinner 2%, showing the first signs of an unexpected slowdown. And the major victim of this slowdown seems to be the LNG market, still the most expensive market for natural gas.

First setback for LNG
After 30 years of continuous growth, in fact, 2012 was the first year in which LNG trade recorded a setback, with global trade contracting by 1.9% compared to 2011, from 241 MT (million tons) to 236 MT. A figure that looks more like the beginning of a new trend rather than a one-off case, as proved by the decline registered in the first half of 2013, with international LNG trade down 4% compared to the same period of 2012. So, what is exactly going on?

At the root of this downtrend, which many analysts believe will be short-lived, lie four main causes: i) an unexpected fall in supply due to a mix of project delays, outages and scheduled maintenances; ii) reduced demand in Europe; iii) a skyrocketing bill paid by Japanese utilities that is restraining the country’s demand for natural gas; iv) lower imports by the US following the shale gas revolution.

-Loss of Capacity
Of these four factors, the major one that caused the fall in LNG trade was the loss of available capacity recorded in the last 18 months. This was connected with scheduled shutdowns and unexpected supply disruptions.
Although global LNG capacity increased, with the Australian Pluto terminal coming online in April 2012, a combination of higher domestic energy demand, lagging development of gas fields and declining overall gas production strongly restrained the activity of LNG terminals in Egypt, Algeria and the United Arab Emirates (UAE). Furthermore, significant losses were recorded in Indonesia and Malaysia. Add to this the pipeline bombings in Yemen, which caused a 23% drop in production, it becomes clear why the LNG market is highly supply-constrained, and why neither the ramp-up in production in Qatar, nor the rise in Russian LNG production have been able to entirely offset the loss of short-term capacity.

-EU’s Falling Demand
In Europe demand for natural gas has slowed down significantly over the past three years. Much of that is due to the recession that has hit most Member States, with a big contribution also coming from the switch towards cheaper coal in power generation. As is well-known, the spark spread has been negative for the past two years across all the main European power markets, forcing European utilities to mothball part of their gas-fired fleet. This trend is expected to continue in the coming 2 to 3 years, favored by a combination of abundant and cheap coal and low carbon prices.

-The Japanese bill
After the 2011 Fukushima disaster, and the following closure of great part of the Japanese nuclear fleet for safety inspections, Japan has heavily turned to the LNG market, causing massive shifts of LNG cargos towards its coasts. A move that has been justified with the need to keep the lights on. However, the rise in LNG imports (+24% in 2012 compared to 2010), coupled with a parallel depreciation of the Japanese yen, has resulted in a stunning jump of the energy bill paid by the country, with Japan disbursing JPY 6.2 trillion in the fiscal year 2012 (around $ 62.3 bn, or 1.5% of the country’s GDP) for energy imports, a massive 75% increase from the fiscal year 2010. This has prompted the country towards a major diversification effort, including a shift to long-term LNG, easing the pressure on shorter term maturities contracts, massive investments in renewables and the construction of two new coal plants that will be completed by December 2013. This will lead to 2% lower import of physical gas compared to the first half of 2012.

-The new role of the US
The shale breakthrough in the US has been felt mainly on the oil market as it has been able to cap the price of oil below a certain level ($ 120 per barrel) amidst several geopolitical tensions that could have spurred prices much higher. The impact on the gas market was rather focused on the LNG market. Since natural gas still is a multi-regional market, the main consequence of the spike in US natural gas production has been the diversion of cargo routes. In less than three years, in fact, US demand for LNG dropped by 9 MTPA (million tons per annum) to 3 MTPA, with all Atlantic cargoes forced to shift to other markets, mainly Asia or South America.

A long way to closer integration
These trends are likely to continue to exert a certain pressure on the LNG market over the following months. After years of continuous growth, the LNG market is starting to face several challenges that may hinder the announced rapid expansion, or at least force analysts and operators to take a further look at the numerous business plans ready to get the final go ahead. It is a bit strange of course that we are witnessing a fall in LNG consumption just when the number of countries joining the LNG market rises. But we’re living in strange times.
For the next two-to-three years the additional liquefaction capacity coming online should be limited. With the Australian Pluto already running at full capacity, and after the entering in operation of the Angolan LNG plant and the completion of the new Skidda liquefaction plant in Algeria early this year, we won’t see many new additions in the near future.
Things will get interesting by 2015 onwards, when many projects now under construction, may come on-stream. There are 26 liquefaction plants now under construction, 14 in Australia, 3 in Malaysia and 2 in Australia and Papua New Guinea, They represent a massive growth that is expected to levy global liquefaction capacity up to 336 MTPA by 2017, an increase of 20%.
However, this figure has to be taken with a pinch of salt: many of the projects now under construction, in fact, are facing a series of unplanned troubles connected with logistical problems and cost overruns, making most of them now no longer economically viable. Rising costs, lower margins and increasing competition will have a major impact on numerous projects. Both Chevron’s Gorgon project in Australia, which has already blown-out by $37bn to $52bn, and Exxon’s LNG project in Papua New Guinea, which has recently seen a 20% jump in the cost of construction, are setting a scary precedent for many investors.
The LNG projects are also faced with a divergence between on the one hand higher construction costs for many plants, which require solid long-term off-take agreements, and on the other hand greater flexibility demanded by more price sensitive buyers. It is in the breach created by these two trends that US exporters may be able to step. US exporters have the advantage of lower development costs and lower gas prices; two factors which combined offer interesting margins for US LNG companies.
The boom in shale gas production grants the US a huge potential in terms of LNG export, with as much as 190 MTPA of additional capacity at a proposal stage, something like two-thirds of the current global LNG capacity. At the moment, just four (Sabine Pass, Freeport, Lake Charles and Dominion Cove Point) out of the 21 projects which have requested a non-FTA export approval – permission to export gas outside of the North American Free Trade Area – have been authorized by the US Department of Energy. In addition, eight more projects are now close to a final investment decision in Canada, which would raise North America’s additional liquefaction capacity to nearly 240 MTPA. It is clear how this development may change the overall market dramatically, both in terms of routes and in terms of pricing.

Emerging doubts
The question is, however, whether the US LNG fleet will develop as expected. Currently market conditions favor the construction of new liquefaction terminals. Henry Hub prices are markedly lower than other world prices, and the fact that many liquefaction facilities can be built at locations that had originally been destined for regasification terminals offers a clear advantage in terms of licensing and operating costs. Even with an estimated cost of $ 3/MBtu for liquefaction and of $ 3/MBtu for shipping to Asia, US companies will still have a $ 4/MBtu margin.
But the future success of US LNG cannot be taken for granted. First, doubts have emerged about the real amount of shale gas the US will be able to produce, with many geologists and analysts claiming that the average productivity of American wells is declining rapidly, making it a lot more expensive to extract gas.
Furthermore, all business plans are based on current prices, and it is quite unrealistic to expect Henry Hub prices to remain at these levels for long, especially after part of the national gas production will be diverted outside US borders. Paradoxically, US LNG exporters need low domestic gas prices, but their own activities will drive up prices.
At the same time, the rest of the world is not standing still. Russia is expanding its pipeline capacity to both Europe (South Stream) and China (Altai). The Caspian region will also enter into the equation, with pipelines panned to Europe (TAP) and China (AGP). In 2012, pipelines accounted for 70% of the global gas trade, still representing the bulk of the natural gas market, linking suppliers and consumers in different areas on a long-term basis.
Who will win this contest will for a large part be determined by the success or failure of a flexible LNG market with routes that can be adjusted over time according to changing demand patterns.
Despite the fact that the LNG market is currently supply-constrained, the global gas market remains a buyer’s market, with buyers looking for more flexibility rather than for security of supply, whereas suppliers are desperate to lock in long- term off-take agreements that guarantee the feasibility of their investments. The surge in cargo reloads in 2012, along with the renegotiation of TOP (Take or Pay) contracts between several European utilities and major (Russian and Algerian) gas companies represent strong evidences of a changing paradigm.
This situation could provide an important edge for US LNG exporters that will be able to exploit their competitive advantages (quicker and cheaper construction processes and lower gas prices). In this sense, it’s noteworthy that some US LNG projects have already signed long-term contracts indexed on Henry Hub prices and not on oil prices anymore. This is a first hint that US companies have already partially spotted these opportunities.
Nonetheless, timing remains the crucial factor for the US exporters. Delays in building the needed infrastructures and in bringing the LNG supplies to the world market may provide their competitors on the world stage with the opportunity to corner the market first.


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