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Syrian Gas Triangle And Its Risk-Prone Future

Commodities / Natural Gas Aug 11, 2013 - 01:27 PM GMT

By: Andrew_McKillop


Reuters reported from Doha, Qatar, 8 August that Saudi Arabia has offered Russia economic incentives including a $15 billion arms-buying deal and a pledge not to challenge Russian gas sales in Europe, if Moscow scales back or abandons support for Syrian President Bashr al-Assad. The proposed deal was reportedly set out by Saudi intelligence chief Prince Bandar bin Sultan in a four-hour meeting with Russian President Vladimir Putin in Moscow last week.

Reuters reported a Syrian opposition spokesman as saying "Bandar sought to allay two main Russian fears: that Islamist extremists will replace Assad, and that Syria would become a conduit for Gulf, mainly Qatari gas at the expense of Russia". He added that "Bandar offered to intensify energy, military and economic cooperation with Moscow."

In the recent past, Saudi Arabia has made arms buying offers to Moscow in return for Russia diluting its support to Iran.  An arms contract signed in 2008 for 150 T-90 tanks, a now highly outdated piece of ordnance and about 100 military helicopters was never executed.

The Qatari strategy is very simple – build a gas export pipeline across Syria to tie-in to existing or proposed gas grids on the southern and southeastern rim of Europe. Qatar could then undercut prices set by Gazprom and other exporters for gas sales to Europe, presumably by not very much given the likely costs of the gas pipeline and transit fees across intervening countries. While this “gas export model” had a degree of credibility in 2008, and until 2010, its present credibility or viability is low.

Times have changed in the world of gas and will go on changing.

As recently as 2005-2007, North America was seen as threatened by major and enduring gas shortage. Prices were expected to stay as high as, or exceed present European gas import prices, typically $10 - $12 per million BTU (July 2013) for pipeline gas, and often more than that for LNG imports. Asian LNG gas import prices for certain markets, especially Japan, can presently attain more than $15 per million BTU pricing this energy at close to $35 per 1000 kWh (1 MWh).

Electricity produced from gas at this price will have a generating-fuel-only cost of around $70 per 1000 kWh. Electricity produced from coal currently imported to Europe at about $85 a ton has a fuel-only cost of far below $10 per 1000 kWh. There is no need to ship the coal through Syria, or Qatar. While Russia is a major coal exporter to Europe it in no way has a monopoly on world coal trade.

For September delivery, early August prices of US natural gas contracts traded on the Nymex are currently priced around $3.45 per million BTU. Neither Russia nor Qatar wants to live with that.

In 2005-2007 major investment was underway in the US to build terminals to import LNG, not to ship it overseas. Today, converting import terminals into export terminals, and building new LNG export terminals at typical costs ranging from $10 to $20 billion each, is the major planned or projected gas infrastructure program underway in the US and Canada. All of this aims to capture sales in high-gas-price export markets – especially Asia and Europe.

Due to the turnaround being recent, the high costs, and regulatory requirements including energy policy concerns and environment protection, the US government has to date only approved two projects for LNG exports. Debate rages in Washington over whether to allow more, with calls for no or low exports from the USA coming from consumer groups and major industrial gas and energy users, such as Dow Chemical, who say the gas should stay on the continent to ensure cheap energy for domestic manufacturing and consumers. Eurasia Group, an energy infrastructure consulting firm, estimates  energy companies could spend up to $50 billion converting existing liquid-gas import plants in the US into export plants, and an additional $60 billion to build all-new export terminals in Canada, by 2020.

Over and above the North American shale gas boom, where Western Canada's shale gas resources are estimated by the Canadian federal government at about 37 trillion cubic metres, East African and Australian “stranded gas” reserves are also very large. East African offshore “stranded gas” finds to date are vast. One single giant Mozambican field, the Rovuma Basin is currently estimated as holding about 3 trillion cubic metres – comparable with world total gas consumption in 2012 estimated by Index Mundi at 3.2 trillion cubic metres.

Critically depending on gas prices, and therefore gas demand, gas collection of the world's currently flared 150 billion cubic metres-a-year also offers new gas supply prospects. See eg. (Scroll to see major 24/7 gas flaring in the North Sea, Algeria, Libya, Middle Eastern producers, and Russia). World coalbed methane resources are also large, and may be extreme, that is potentially equivalent to over 500 years of world current gas consumption. According to US EIA and the US Geological Survey, world presently-known shale gas reserves exceed 180 years of world current gas consumption.

Potential oversupply of global LNG supply, and fast-rising cost for LNG infrastructures, including terminals and ocean cryogenic tankers are already taking their toll on what, in June 2011 prompted the IEA to publish a special report titled: “Are We Entering A Golden Age Of Gas?”.

According to BG Group and at end-2012, LNG covered about 10%, or 320 billion cubic metres a year of global natural gas consumption, with 18 exporting and 26 importing countries, and around 365 tanker ships for transportation. The global share of LNG according to BG Group and the IEA, can easily double by 2022 but costs and gas demand are the key determinants.

The ex-shipyard price for a smaller-sized 160 000 cubic metre LNG tanker is typically around $210 million with a rental cost (freight rate) of $70 000-per-day, at present, but this market is highly volatile, with a possible crash of new tanker prices, but a rise of freight rates. Concerning new tanker building capacity, the impending restructuring of China's shipyard capacity is the main question mark.  The national "ship industry restructuring and revitalization plan" submitted in 2011, stated that China accounted for over 35% of world total shipbuilding capacity, and this should be reduced by a third. In the restructuring period however, the potential for China's LNG tanker building yards seeking customers at any prices, by price cutting, is high.

Onshore and offshore gas field costs including exploration and development costs, and costs for LNG cryogenic compression and export “trains” have in some cases dramatically increased. One specific example of radically increasing costs is Australia. By mid-year 2012, typical comment on Australia's formerly booming LNG sector was as follows: “We’ve gone through a period when Australia was the blue-eyed boy of LNG,” said Frank Harris, head of LNG at energy consultancy Wood Mackenzie. “Now buyers have a lot more choice”. Supply-wise, East Africa is the new El Dorado.

The potential rate of LNG supply expansion – and domestic national shale gas production for global gas markets that are in no way booming, but show low growth – result in gas production and transport capacity that is quickly shifting to a buyers' market. When the UK-based BG Group attempted to divest its stake in a big Australian LNG project, starting in March 2012, many expected a quick sale especially due to strong interest from Asian buyers keen on acquiring a part of LNG projects to guarantee or hedge supply. Japanese utilities were highly active as the country moves away from nuclear power in the aftermath of the Fukushima disaster and Japan's gas import demand increases. In fact however BG's attempt at offloading up to 20 per cent of its Queensland Curtis LNG project was already hampered by its rivals also seeking the sale of their participations, both in local offshore gas projects, and local onshore coalbed methane projects, for export as LNG.

Rather than gas resource shortage, therefore, major challenges with world gas include pricing and transport in a context where any major return to global recession as in 2008-2009 will firstly cut the world's relatively slow-growing gas demand, and secondly create massive financial problems in the now highly leveraged, debt-dependent, capital intensive gas and LNG industry. Gas is moving rapidly to the status of a buyers' market – due to oversupply.

In total, according to a 'Wall Street Journal' report, August 5, energy major companies “are proposing half a trillion dollars in projects to export vast new finds of North American natural gas”. Western Canada and the US Gulf Coast are competing for the lion's share of investment.  The first major announced project, in Prince Edward, British Columbia, by Malaysia's Petronas projects the spending of $20 billion on a LNG terminal, feeder pipelines and other infrastructures, creating 3 500 construction jobs and 200 to 300 permanent jobs. .

This can be called the Asian export market strategy, and Canada's federal government is broadly favourable to the strategy. The main advantage of Canada-Asia rather than US Gulf Coast-Asia LNG exporting is shorter sailing times, about 5 days against 10 days (LNG tankers losing about 1% of their cargo each day, from boil-off). Deprived of the even-more-captive gas market of Asian consumers, Qatar, a major LNG exporter, will be forced to become a lot less arrogant on pricing. Russia has moved slowly to capture Asian gas markets, by either LNG or pipeline, forcing it to “put its eggs in one basket”, what it thinks or hopes are European captive markets.

At it most basic, due to gas resource shortage being off the menu for at least 50 years, decisions are founded on current gas market prices. Current gas prices are below $4 per million BTU in North America, about $12 in Europe but up to $16 per million BTU in Asia. Conversely, LNG will always be more expensive than locally produced gas due to LNG conversion and transport costs. How much more expensive is the key question. Hopes are unsurprisingly very high, shown by British Columbia's Premier, Christy Clark comparing BC's coming LNG exports with Alberta's oilsands, saying that he is contemplating a $100 billion "windfall gain fund" from expected LNG tax revenues.

Many LNG and gas infrastructure companies and experts are dubious about the Canada-Asia export strategy, due to high, or very high construction costs in often-difficult, environmentally-sensitive terrain not compensated by shorter sailing times for LNG tankers. As a result, current strategies by major players are to “back both horses”, with investments in LNG facilities both in Canada and USA. Current government-approved export projects in Canada  total 3, with 4 pending.

Majority opinion among analysts is that world gas, as well as world LNG are both risk-prone and uncertain. Factors weighing on the trend of events are wide-ranging, for example existing European “anti-gas” policies extending from national bans of shale gas fracking, to energy policies seeking a reduction in the downstream use of natural gas, considered a climate changing fossil fuel with unsure supply lifetimes ahead of it. In theory, world gas demand should be growing rapidly, but it is not.

Gas demand is highly sensitive to economic growth trends, and can decrease as well as increase. Becoming radically more capital intensive, especially due to LNG development, the sector is also exposed to financial deleveraging and investor retreat. Conversely, supply growth for global gas has “gone viral” and is unrelated, for the moment, to demand trends.

As recently as the early 2000s, soaring US gas prices had triggered plans to build dozens of LNG import terminals in the US by 2015. In 2008, Cheniere Energy opened its first such facility in Louisiana, but even at that date the project's financial future was highly doubtful. As we know, the US shale gas revolution in drilling and extraction was unlocking vast new domestic reserves of gas.

The breakdown in gas import outlooks for the US forced Cheniere to lay off much of its staff, and to sell the first LNG tanker it had purchased, at a distressed “fire sale” price. Today, LNG exporting is treated as “the coming thing” and Cheniere's Louisiana import terminal is one of the first to be converted, at a cost estimated at about $12 billion, for LNG exporting.

Project risk most certainly remains high. Among the most important are potential declines in global gas demand, and accelerated local and domestic gas exploration and development – featuring shale gas and coalbed methane, as well as stranded gas – in expected LNG importer countries. Other major risks also concern the price of gas. While onshore gas reservoirs linked by pipelines can accept a major reduction in gas tariffs and remain viable – as Gazprom knows full well -  LNG projects are much more sensitive to falling prices. The main gauge for likely trends in the gas sector including LNG, today, will be the maintenance, or not, of financial flows to the sector.

By Andrew McKillop


Former chief policy analyst, Division A Policy, DG XVII Energy, European Commission. Andrew McKillop Biographic Highlights

Co-author 'The Doomsday Machine', Palgrave Macmillan USA, 2012

Andrew McKillop has more than 30 years experience in the energy, economic and finance domains. Trained at London UK’s University College, he has had specially long experience of energy policy, project administration and the development and financing of alternate energy. This included his role of in-house Expert on Policy and Programming at the DG XVII-Energy of the European Commission, Director of Information of the OAPEC technology transfer subsidiary, AREC and researcher for UN agencies including the ILO.

© 2013 Copyright Andrew McKillop - All Rights Reserved Disclaimer: The above is a matter of opinion provided for general information purposes only and is not intended as investment advice. Information and analysis above are derived from sources and utilising methods believed to be reliable, but we cannot accept responsibility for any losses you may incur as a result of this analysis. Individuals should consult with their personal financial advisor.

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