News
Intra-Gulf gas pricing to witness 10-fold increase
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Galloping regional demand for gas will ensure that intra-Gulf supply deals will henceforth be struck at significantly higher prices, signaling the end of the price-capped cheap gas era, a US-based strategy advisory firm in global energy has said.
The Dolphin Energy pipeline supplying the UAE and Oman with two billion cubic feet per day (bcf/d) from Qatar's North Field at $1.35/MMBtu "is a deal of the past, and almost certainly will not be replicated, even as a political gesture of goodwill", Washington, DC-based PFC Energy said.
"There has never been a single pricing point in the GCC," said PFC Energy analyst Raja Kiwan in an e-mail interview.
"In fact, there still is no single price marker internationally either. LNG fetches different prices in different basins. Regionally, the Dolphin deal was priced on a cost-plus basis. As an anchor point, however, the natural gas futures contract traded in the US priced off Henry Hub in Louisiana has climbed from $2/MMBtu in 1991 to over $8/MMBtu currently. In Asia, LNG prices can go as high as $20/MMBtu."
Abu Dhabi-owned Dolphin currently derives its profit from sales of 90mb/d and 30mb/d of condensate and liquefied petroleum gas, or LPG, rather than the gas sold into the price-capped domestic markets.
"A new agreement to fill the pipeline's 3.5bcf/d potential will not be achieved without a significant increase in the price paid for the gas, of probably 10-fold or more," PFC said.
Kiwan said: "As more expensive indigenous gas sources and imports (whether LNG or pipeline) becomes a bigger part of the total energy mix, there will be economic implications for governments as long as heavy subsidies for grid-gas and power exist.
"The region's natural cost advantage is being slowly eroded and subsidy regimes have to be revised to achieve sustainability."
Less than 10 years ago, Dubai rejected as too expensive an offer of gas from Iran's Sirri Field at 80¢/MMBtu.
A reported 65¢/MMBtu price negotiated in 2000 all but derailed Sharjah's plans to import 500mcf/d from Iran. Delivery is now four years overdue in spite of construction of the necessary facilities and pipeline having been completed.
"With LNG [liquefied natural gas] achieving Asian prices of up to $20/MMBtu, any new pipeline deals would have to provide Qatar – the region's de facto central bank for gas – with a corresponding netback price.
"This might not necessarily be as high as global average LNG prices given the lower capital investments, but certainly above the $5-$6/MMBtu figures often mentioned by senior officials," PFC said.
Higher prices have the potential to kickstart increased investment in exploration in the region. "Given the higher costs of any new import deals, the value proposition for developing domestic sources of supply increases," Kiwan said.
"If you've got to pay $10-$11/MMBtu for LNG, then it would now make sense to develop more problematic gas sources, even if the cost were, say, $4-$5/MMbtu. So yes, the higher gas price environment does offer upside to future exploration."
More than 70 per cent of Qatar's LNG exports are tied to long-term contracts with fixed destinations.
Most of the rest has been contracted but with destination flexibility.
"A pipeline serving a specific customer with a fixed volume would remove the trade and arbitrage opportunities offered by an LNG project. With this reality in mind and the dimming prospects for future pipeline deals, it is no surprise that Dubai – where gas forms 75 per cent of its energy needs – has signed a deal with Shell to provide 650,000 tonnes per year of LNG imports from a floating vessel at a price of $11/MMBtu, while Kuwait is also following suit with Excelerate.
"Despite this acceptance of a drastically new price paradigm, there still seems to be a reluctance to accept similar prices for pipeline gas: a fact reflected by the absence of any operational projects (Dolphin aside) regionally and in other emerging markets," PFC said.
POLICY PRESSURES
The rapidly increasing Gulf demand for gas due to accelerated economic growth has also created a new set of pressures and challenges at the policy level, according to the think-tank.
Qatar, which intends to produce 16bcf/d of gas, has asserted in the past that future monetisation of gas will favour domestic requirements. This "paints a less than rosy picture" for those waiting in line to access Qatar's gas.
"If and when the moratorium on new gas projects is lifted, though this looks increasingly unlikely, Qatar's neighbours will come further down the priority list, behind domestic industrialisation and petrochemicals," PFC said.
"On the upside, a rapprochement between Qatar and its neighbours over the past two years does provide a degree of political will to strengthen ties through a pipeline deal, although government policy aimed at maintaining gas production for two to three generations means that any future decisions will be deeply scrutinised," the note said.
According to PFC, the case for Iran is more severe given the 70-million strong population, hefty industrial sector dependent on gas and re-injection volumes for oilfield pressure maintenance.
"Facing increasingly tight oil product balances, Iran has also been driving policies aimed at substituting gasoline and diesel with gas in industry as well as transport. Tehran's resource mis-management in the past means that it is simply over-extending itself in trying to do everything."
Despite the pressures, talks between Gulf states and Iran have recently fired up again, PFC notes. "Both Dubai and Bahrain are said to be pursuing buyback deals to import 1bcf/d, while Oman is also manoeuvring to import similar volumes. "
Having publicly acknowledged the region's gas dilemma, the UAE and Bahrain are introducing more energy-efficient building requirements while the pursuit of alternative fuels – including nuclear and solar power – has moved into a higher gear, PFC said.
The UAE is also developing sour gas reserves, considered less than 10 years ago by many to be far too expensive to monetise.
Dubai a magnet for energy giants
Since Dubai oil production peaked in 1991, the central question concerning energy matters has not been about production, but how much it needs to fuel its robust economy, says The Report: Dubai 2007 published by United Kingdom-based Oxford Business Group (OBG).
Most of the major energy sector companies already have, or are in the process of, moving to Dubai, as the emirate consolidates its role as the region's leading business hub.
Halliburton, the US oil industry services company, has relocated its headquarters to Dubai.
Upstream majors such as BP and Shell are also heavily involved in the emirate.
PSI Energy Holding, formerly based in Bahrain, recently announced its decision to move most of its corporate operations to Dubai in an effort to better access projects in the region.
Both the Dubai Mercantile Exchange and the Dubai Multi Commodities Centre have established energy futures contracts for fuel oil and Oman crude, which use Dubai's physical marketplace as a basis.
At the same time, Dubai remains a profitable market for regional energy producers in terms of its potential to purchase petrol, natural gas and electricity as its economy goes from strength to strength.
The ever adaptive emirate is shaping up to be a new financial and corporate centre for the energy industry worldwide, and is increasing its importance as a place to trade energy, perhaps due to, rather than despite, its declining status as a producer, says The Report.
Dave Lesar, Chairman, President and CEO of Halliburton, who has moved to Dubai with his corporate headquarters office to lead the company's efforts in growing business in the eastern hemisphere, said: "This is already a strong market for us and we are excited to position the company in this key business area. This is an excellent place to live and a perfect environment from which to forge a working climate that is germane to the progression of international business."
The Dolphin Energy pipeline supplying the UAE and Oman with two billion cubic feet per day (bcf/d) from Qatar's North Field at $1.35/MMBtu "is a deal of the past, and almost certainly will not be replicated, even as a political gesture of goodwill", Washington, DC-based PFC Energy said.
"There has never been a single pricing point in the GCC," said PFC Energy analyst Raja Kiwan in an e-mail interview.
"In fact, there still is no single price marker internationally either. LNG fetches different prices in different basins. Regionally, the Dolphin deal was priced on a cost-plus basis. As an anchor point, however, the natural gas futures contract traded in the US priced off Henry Hub in Louisiana has climbed from $2/MMBtu in 1991 to over $8/MMBtu currently. In Asia, LNG prices can go as high as $20/MMBtu."
Abu Dhabi-owned Dolphin currently derives its profit from sales of 90mb/d and 30mb/d of condensate and liquefied petroleum gas, or LPG, rather than the gas sold into the price-capped domestic markets.
"A new agreement to fill the pipeline's 3.5bcf/d potential will not be achieved without a significant increase in the price paid for the gas, of probably 10-fold or more," PFC said.
Kiwan said: "As more expensive indigenous gas sources and imports (whether LNG or pipeline) becomes a bigger part of the total energy mix, there will be economic implications for governments as long as heavy subsidies for grid-gas and power exist.
"The region's natural cost advantage is being slowly eroded and subsidy regimes have to be revised to achieve sustainability."
Less than 10 years ago, Dubai rejected as too expensive an offer of gas from Iran's Sirri Field at 80¢/MMBtu.
A reported 65¢/MMBtu price negotiated in 2000 all but derailed Sharjah's plans to import 500mcf/d from Iran. Delivery is now four years overdue in spite of construction of the necessary facilities and pipeline having been completed.
"With LNG [liquefied natural gas] achieving Asian prices of up to $20/MMBtu, any new pipeline deals would have to provide Qatar – the region's de facto central bank for gas – with a corresponding netback price.
"This might not necessarily be as high as global average LNG prices given the lower capital investments, but certainly above the $5-$6/MMBtu figures often mentioned by senior officials," PFC said.
Higher prices have the potential to kickstart increased investment in exploration in the region. "Given the higher costs of any new import deals, the value proposition for developing domestic sources of supply increases," Kiwan said.
"If you've got to pay $10-$11/MMBtu for LNG, then it would now make sense to develop more problematic gas sources, even if the cost were, say, $4-$5/MMbtu. So yes, the higher gas price environment does offer upside to future exploration."
More than 70 per cent of Qatar's LNG exports are tied to long-term contracts with fixed destinations.
Most of the rest has been contracted but with destination flexibility.
"A pipeline serving a specific customer with a fixed volume would remove the trade and arbitrage opportunities offered by an LNG project. With this reality in mind and the dimming prospects for future pipeline deals, it is no surprise that Dubai – where gas forms 75 per cent of its energy needs – has signed a deal with Shell to provide 650,000 tonnes per year of LNG imports from a floating vessel at a price of $11/MMBtu, while Kuwait is also following suit with Excelerate.
"Despite this acceptance of a drastically new price paradigm, there still seems to be a reluctance to accept similar prices for pipeline gas: a fact reflected by the absence of any operational projects (Dolphin aside) regionally and in other emerging markets," PFC said.
POLICY PRESSURES
The rapidly increasing Gulf demand for gas due to accelerated economic growth has also created a new set of pressures and challenges at the policy level, according to the think-tank.
Qatar, which intends to produce 16bcf/d of gas, has asserted in the past that future monetisation of gas will favour domestic requirements. This "paints a less than rosy picture" for those waiting in line to access Qatar's gas.
"If and when the moratorium on new gas projects is lifted, though this looks increasingly unlikely, Qatar's neighbours will come further down the priority list, behind domestic industrialisation and petrochemicals," PFC said.
"On the upside, a rapprochement between Qatar and its neighbours over the past two years does provide a degree of political will to strengthen ties through a pipeline deal, although government policy aimed at maintaining gas production for two to three generations means that any future decisions will be deeply scrutinised," the note said.
According to PFC, the case for Iran is more severe given the 70-million strong population, hefty industrial sector dependent on gas and re-injection volumes for oilfield pressure maintenance.
"Facing increasingly tight oil product balances, Iran has also been driving policies aimed at substituting gasoline and diesel with gas in industry as well as transport. Tehran's resource mis-management in the past means that it is simply over-extending itself in trying to do everything."
Despite the pressures, talks between Gulf states and Iran have recently fired up again, PFC notes. "Both Dubai and Bahrain are said to be pursuing buyback deals to import 1bcf/d, while Oman is also manoeuvring to import similar volumes. "
Having publicly acknowledged the region's gas dilemma, the UAE and Bahrain are introducing more energy-efficient building requirements while the pursuit of alternative fuels – including nuclear and solar power – has moved into a higher gear, PFC said.
The UAE is also developing sour gas reserves, considered less than 10 years ago by many to be far too expensive to monetise.
Dubai a magnet for energy giants
Since Dubai oil production peaked in 1991, the central question concerning energy matters has not been about production, but how much it needs to fuel its robust economy, says The Report: Dubai 2007 published by United Kingdom-based Oxford Business Group (OBG).
Most of the major energy sector companies already have, or are in the process of, moving to Dubai, as the emirate consolidates its role as the region's leading business hub.
Halliburton, the US oil industry services company, has relocated its headquarters to Dubai.
Upstream majors such as BP and Shell are also heavily involved in the emirate.
PSI Energy Holding, formerly based in Bahrain, recently announced its decision to move most of its corporate operations to Dubai in an effort to better access projects in the region.
Both the Dubai Mercantile Exchange and the Dubai Multi Commodities Centre have established energy futures contracts for fuel oil and Oman crude, which use Dubai's physical marketplace as a basis.
At the same time, Dubai remains a profitable market for regional energy producers in terms of its potential to purchase petrol, natural gas and electricity as its economy goes from strength to strength.
The ever adaptive emirate is shaping up to be a new financial and corporate centre for the energy industry worldwide, and is increasing its importance as a place to trade energy, perhaps due to, rather than despite, its declining status as a producer, says The Report.
Dave Lesar, Chairman, President and CEO of Halliburton, who has moved to Dubai with his corporate headquarters office to lead the company's efforts in growing business in the eastern hemisphere, said: "This is already a strong market for us and we are excited to position the company in this key business area. This is an excellent place to live and a perfect environment from which to forge a working climate that is germane to the progression of international business."