Middle East gas shortages grow
The Mideast Gulf is one of the world's most gas-rich areas, yet many of the states are suffering from shortages. The situation is worsening, and is being driven by subsidies. Miles Lang reports
THE TRINITY Arrow liquefied natural gas (LNG) tanker docked in Kuwait on 10 May. The shipment, which came from Zeebrugge, was the first part of a four-year deal with trader Vitol to supply Kuwait Petroleum with LNG during the summer months.
Kuwait, like other Gulf states, has been struggling to find enough gas to feed its growing electricity demand – in June, the country's grid reached 99% of its 11 gigawatt generating capacity, resulting in fires in transformers and widespread blackouts. The consequence is this seemingly absurd reality: LNG tankers leaving Abu Dhabi with cargoes for Japan and South Korea, passing tankers redirected from Europe for delivery to Kuwait.
Of the six Gulf Cooperation Council (GCC) countries, Qatar is the only net gas exporter. But Kuwait, which is separated from Qatar by the Saudi Arabian coastline and waters, cannot pipe gas in from Qatar. Saudi Arabia would not allow an extension of the Dolphin pipeline through its territory.
Gulf demand on the rise
The GCC member countries – Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates (UAE) – together hold around 23% of global gas reserves, but, apart from Qatar, are facing increasing gas shortages. Although the global economic crisis has reduced the need for gas in some regions of the world, GCC gas demand has outstripped the region's production. GCC economies are growing at a rate of around 7% a year, and demand for both gas and electricity is keeping pace with GDP growth and economic diversification.
The United Arab Emirates (UAE) is a case in point. Abu Dhabi is the richest of the seven emirates in terms of hydrocarbons reserves, providing 90% of the UAE's gas production. The emirate produces 6bn cubic feet a day (cf/d), of which: 2bn cf/d is reinjected into oilfields to maintain pressure; 0.6bn-0. 7bn cf/d is exported as LNG to the Asia-Pacific region under long-term contracts; and the rest is distributed as sales gas. At the same time, however, the emirate imports 2bn cf/d from Qatar through the Dolphin pipeline and has a gas-supply deficit of 2bn cf/d during the summer season.
Qatar exports gas through the Dolphin pipeline to the UAE and Oman, but the prices at which it does so are low. Gulf states are willing to pay rates of only up to $5/m British thermal units (Btu), and recent contracts featured prices of around $1.5/m Btu. Qatar can secure $10/m Btu for its LNG in the Asia-Pacific market, so, understandably, is reluctant to sell more gas than it already does to its neighbours.
In the UAE, gas is sold to customers at highly subsidised prices. Production costs of deep and mildly sour gas projects in the Gulf are between $5-6/m Btu, but domestic sales prices range from $0.75-2.00/m Btu. As a result of these subsidies and the already big demand for gas from electricity and water-producing companies, gas use is inefficient, and demand is high and rising.
Sharjah, the emirate east of Dubai, saw a rise in gas consumption of more than 30% between 2008 and 2009. As well as rising industrial use, this increase represents 25,000 new gas connections in a single year. It is estimated that the UAE will need a further 5bn cf/d for extra power-generating capacity by 2019.
In Kuwait, the residential market for electricity accounts for around 60% of generating capacity and, after subsidy, the government charges households $0.07 a kilowatt hour. Added to that, many households do not pay their bills and are rarely penalised – increasing the cost to the government.
In the short-term, Kuwait has a deal with Vitol to import around 0.5m cf/d of LNG to feed its power stations. In the longer term, the country is hoping to step up its own non-associated gas production and has targeted levels of 13m cf/d, up from the present level of 3m cf/d from its northern gasfields. But the reservoirs are complex and the government signed a $0.7bn deal with Shell in February that will bring in the expertise needed to handle the tricky development programme.
The strain of subsidies
In the longer-term, low prices resulting from subsidies will constrain upstream investment. And with demand growing as it is, something must give. John Roberts, global energy-security analyst at Platts, says of the GCC countries: "They aren't fools. They know they've been profligate, but they're not going to rein the profligacy anything but slowly – they're more likely to just cap how fast it grows, and slow demand growth."
The countries know that they must do something about gas subsidies. As Roberts puts it: "Any society that continues with subsidies on products it imports is almost literally burning money."
The effect of subsidies on potential new production is worrying. In April, ConocoPhillips withdrew from its 40% holding in Abu Dhabi's Shah sour-gas development. Apart from the high cost of sweetening the gas from the Shah field, perhaps the biggest barrier to development is the cost curve. Development costs range from $4/m Btu to $5/m Btu. Taking into account the subsidised domestic price of around $1/m Btu, it is not hard to see why an investor would be nervous of committing. The emirate is yet to find another partner for the $10bn project, which plans to process 1bn cf/d of ultra-sour gas into 0.54bn cf/d of feed gas for UAE industrial, commercial and domestic consumption.
Another GCC gas project that has just lost a foreign investor is Oman's Abu Butabul tight-gas project, which has around 2 trillion cf in place. BG Group dropped the project in June, saying it was uneconomical. Oman had hoped that the project would come on stream in 2012 and help alleviate its gas shortage. According to Cedigaz, Oman produced 0.875 trillion cf of gas, consumed 0.520 trillion cf and exported 377bn cf in 2009, leaving a shortage of 22bn cf. With Omani gas demand expected to rise by 7% a year, this deficit will cost more each year unless new production is brought on stream.
Worse still, BG's move is a negative indicator of investor sentiment and Oman needs investment to maintain its oil and gas output. Oman Oil is in talks with the oil ministry with a view to possibly taking over at Abu Butabul, but it will take a partnership with a company with tight-gas experience to get the project flowing.