Surging gas demand in the Middle East will see at least three GCC states become LNG importers in the next five years. Rising production costs in the region is also likely to lead to more fundamental pricing reforms.
The peak summer demand season in the Middle East has drawn to a close for 2010. However, the region is expected to see a flurry of LNG-related activity over the next couple of months, with both Dubai and Bahrain each seeking to fast-track LNG import plans as part of a strategy to plug a growing gas supply shortfall.
The Dubai Supply Authority (DUSUP) is understood to have already made its debut as an LNG importer, having received its first commissioning cargo at the 3 million tonne per annum (mtpa) floating regasification terminal at the Jebel Ali port earlier this month (see GLM 8 October 2010).
The commissioning process on the 126,000m3 Golar Freeze, the converted floating storage and regasification unit (FSRU), is expected to complete by December or January. This could provide DUSUP with the option to tap the spot market over the winter if needed, and it certainly leaves the state company ontrack ahead of May 2011 when it is expected to start receiving regular term LNG from the Qatargas 4 project.
In the meantime, Bahrain is also hoping to join neighbouring Kuwait and Dubai as an LNG importer and is looking to formalise an engineering, procurement and construction (EPC) tender for its planned 400 million cubic feet/day (4.13 billion cubic metres (Gm3)/year) terminal in the next week or two, with an award expected early next year.
Bahrain's National Oil and Gas Authority (NOGA) still has to finalise a number of technical aspects for the planed terminal, such as whether to opt for a floating or onshore option. But the overriding aim is to commission the terminal by the final quarter of 2014 in order to avert a growing gas crunch in the Kingdom.
The requirement of three of the Gulf Cooperation Council (GCC) states - comprising Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates - to have to fast-track LNG import plans may at first glance appear to be illogical as the GCC holds around 42.57 trillion cubic metres of proved gas reserves or 22.7% of the world's total reserves, according to BP's 2010 Statistical Review.
However, this figure masks the fact that a decade-long, region-wide boom of government-sponsored programmes to develop large gas-intensive industries, premised on access to cheap feedstock, has led to gas demand in the GCC outpacing virtually every other region in world.
From 1998 through 2008, GCC economies grew at a rate of around 7.6%/year, with demand for gas and power in the region growing at an average of 5.5% and 6.1% respectively.
The 2008-2009 global economic recession may have slowed these growth rates - as well as resulting in the mothballing of a number of petrochemical and gas-fired power projects - but consumption is still climbing strongly.
A study on GCC gas consumption by management consultancy Booz & Co, released this summer, warned that the regional gas shortage is will become more pronounced by 2015 as demand continues to outpace the region's current production capabilities.
The regional gas shortage is expected to reach around 20-21Gm3 this year. If economic growth rates in the region return to pre-recession levels by 2012, as the International Monetary Fund (IMF) predicts, the region could face shortages of around 50Gm3 by 2015, Booz & Co said.
Even in its most conservative scenario - which assumes that the threat of a global double-dip recession materialises, driving oil prices down back to early 2009 levels leading to the postponement of more gas-dependent infrastructure projects - Booz forecasts that the GCC will face shortages of 31bn m3 by 2015.
The biggest challenge for the region is that gas has traditionally been seen as a subsidised by-product of oil. As a result, the regulated domestic sales price ranges from $0.75/MMBtu in Saudi Arabia to around $2.00/MMBtu in parts of the UAE, with a regional average of around $1.50/MMBtu.
The utilization of such cheap associated gas has been central to GCC efforts to diversify the economy and build vast petrochemical complexes, aluminium, water desalination and power plants. But this strategy has begun to buckle under the strain of supply shortages, and an energy intensity level that is second to none.
Moreover, the historical view that access to cheap gas is part of the social contract between the state and the people, has also been a major psychological barrier that GCC governments have been reluctant to tackle, fearing the short-term social and inflationary impact of such measures.
But the regional turn to LNG imports as a means to alleviate peak summer gas shortages, and the willingness of Dubai, Bahrain and Kuwait, to pay a higher price for gas, has been one driver in challenging fundamental price assumptions in the region, argues Justin Dargin, research fellow of GCC energy relations at the Dubai Initiative, Harvard University.
"There is an increasing realisation among GCC states that they will have to examine the current structure of domestic gas pricing," said Dargin. "External pressure has come with an increasing exposure to the global LNG market as well as from Qatar and Iran, the two main regional producers with the capacity to export gas, who have made it clear that they will not accept anything below $5.00/MMBtu for exports."
Rising Production Costs
The domestic price structure is also coming under internal pressure from the higher development costs that are required to bring new gas production on stream to meet growing demand. According to Dargin, the average production cost of new unconventional and deepwater reserves across the region is around $5.00/MMBtu.
Saudi Aramco, for example, is fast-tracking the development of three large offshore fields - Karan, Hasbah, and Arabiyah - with the aim of bringing on a total of around 44Gm3/year of supply by 2015. This would go some way to easing the Kingdom's supply shortage and may bring about a reversal of a moratorium on new gas-fired power plants.
But these reserves will cost Aramco $3.50-5.00/MMBtu to develop, compared with the regulated sales price of $0.75/MMBtu, according to US Energy Information Agency. The potential impact on the state company's budget has prompted Aramco to call for an upward revision - albeit a gentle revision - of the regulated price.
A major national oil company, with high technical capabilities such as Saudi Aramco, may be able to absorb the impact of the higher development costs and bring the new fields on stream on time and on budget.
However, this may not be the case elsewhere in the region, and two international oil companies this year have withdrawn from higher-cost upstream projects earmarked to supply the domestic market.
In April, ConocoPhillips walked away from its 40% interest in the Shah sour gas field in Abu Dhabi. The project, which had been slated to bring on stream 1bcf/day of sour gas for the domestic UAE consumers, had been projected to cost $4.00-5.00/MMBtu to develop.
State oil company ADNOC has pledged to continue with the $10bn project and stick to the 2014 timetable, although its failure to find another partner has thrown this timetable into doubt.
Two months later, BG withdrew from the Abu Butabul tight-gas project in Oman, which in one swoop dealt a blow to the country's ambitions to meet rising domestic demand for power generation and industry while maintaining LNG export levels. Officially, the UK company said that its decision was "based on a desire to refocus our strategy", although Omani officials said that while BG had found 2 trillion cubic feet (tcf) it had discovered very little condensate, which was not enough to justify the investment needed to prove up and develop commercial quantities from the tight gas reserve.
Mind the gap
Kuwait, and to a lesser degree Bahrain, have viewed LNG as a stop-gap measure, giving the two states the necessary breathing space to develop their own higher priced unconventional reserves.
Bahrain, which produced about 15.4Gm3 of gas last year, is pinning its hopes on bringing on stream an additional 5.16Gm3/year of production from its deep pre-Khuff gas reservoirs by 2015. But the technical complexity of the project, which is being developed solely by NOGA have raised questions about the costs and timing.
The Kuwait Petroleum Company's (KPC) decision to spurn a long-term supply contract and opt instead for a series of medium term supply deals with Shell and Vitol underlined its commitment to its domestic gas programme.
Under this programme, Kuwait hopes to increase current production at its complex deep northern gas fields from its present level of 1.45Gm3/year, to 10.33Gm3/year by 2015. For its part, KPC signed a technical services agreement in May with Shell who will provide advice on the development of the deep reserves.
But the complexity of the programme, divisions in the Kuwaiti parliament which hitherto has scuppered any progress on formalising a coherent long-term energy strategy, and the challenge in ushering in price reforms to rationalise demand growth is such that it may not be feasible to expect the supply/demand balance to be closed over a five-year period.
"LNG may be seen by Kuwait as a stop-gap measure, giving it the time it needs to bring its deep gas formations in the north of the country on stream, but far from being an interim measure, it is likely to mutate into long-term dependence," said Dargin.