Platts, Jerusalem, Mar 22, 2011
Gas deliveries from Egypt to Israel have reached 90% of volumes prior to the cutoff on February 5 [please see my post, including remarks, here -- D.R.] and will continue to ramp up this week, Israeli energy industry sources said Tuesday.
Supplies resumed on March 15 after the export pipeline, which was damaged by an explosion, was fixed. Shipments also resumed to Jordan.
Meanwhile, Ampal-American Israel Corp [please see remarks below -- D.R.], a partner in the East Mediterranean Gas Company -- which exports the gas from Egypt to Israel -- said in its annual report Friday [sic] that the future policy of the Egyptian government may not coincide with that of EMG.
The statement said that there is no certainty that Egypt will meet its commitments regarding the supply of natural gas to Israel in the future.
EMG supplied Israel with 2.1 billion cubic meters of gas in 2010 and its contractual commitments are to increase this to 3 Bcm in 2011. EMG has signed commitments to supply 4.8 Bcm/year of gas starting in 2013 [sic].
The Ampal statement follows remarks last week by Egypt's new oil minister Abdallah Ghorab. He said that his ministry is re-examining the gas agreement with Israel, specifically the price at which gas is sold to Israel and other countries.
Ghorab said the agreements, signed under the auspices of the previous minister Sameh Fahmi, include a mechanism that permits amending the gas supply agreements. The minister said this would not be a complicated process.
Jordan is currently paying around $3/MMBtu [please see remarks below -- D.R.] while prices to Israel were raised by nearly 50% last year to around $4.50/MMBtu when the long-term supply agreement was renegotiated.
Israeli energy industry analysts have said the price of Egyptian gas sold to Israel could go as high as $6-6.50/MMBtu. [Full story]
(Also, Egypt wants to raise price of gas to Jordan. EMG is a joint company owned by Egyptian businessman Hussein Salem, Egypt Natural Gas Company, Thailand's PTT, Israel's Merhav Group, Ampal-American Israel Corp, American businessman Sam Zell and Israeli institutional investors. Ampal holds a 16.8% interest in EMG, with 8.2% held directly and 8.6% held through the joint venture with certain Israeli institutional investors, of which Ampal owns 50% and a 4.3% interest is attributable to the institutional investors. Excluding the institutional investors, Ampal has a 12.5% interest in EMG. -- D.R.)
Showing posts with label Natural Gas. Show all posts
Showing posts with label Natural Gas. Show all posts
Wednesday, March 23, 2011
Saturday, March 19, 2011
BOEMRE Approves First FPSO Use in Gulf of Mexico
by Nick Snow, OGJ, Mar 17, 2011
The US Bureau of Ocean Energy Management, Regulation, and Enforcement [the former Minerals Management Service] approved Petrobras America Inc.’s application to use a floating production, storage, and offloading vessel to produce oil and gas from its Cascade-Chinook project in the Gulf of Mexico. This will be the first time that FPSO technology has been used in the [U.S.] gulf, the US Department of the Interior agency said on Mar. 17.
The BW Pioneer FPSO [please see image below -- D.R.] will receive production through dual flow lines, which connect it to two free-standing hybrid risers for each field, also a new technology for the gulf, Petrobras America said.
BOEMRE said it approved the project’s production safety system permit and supplemental deepwater operating plan following extensive consultations with the producer.
The FPSO will have a production capacity of 80,000 b/d of oil and 16 MMcfd of natural gas, with production expected to begin soon, it indicated.
The project is in the gulf’s Walker Ridge area in 8,200 ft of water [2,500 meters] about 165 miles [266 kilometers] off Louisiana. [Full story]
Source: Petrobras via MARINE LOG.com here
(Also, the FPSO has an oil storage capacity of 500,000 barrels. Natural gas processed by the BW Pioneer will be transported to shore by pipeline, while crude oil will be offloaded to shuttle tankers for transportation. In the event of a hurricane or tropical storm, the facility is designed to disconnect from the turret-buoy and move off location until the storm has passed. FPSOs are widely used in offshore Brazil and West Africa---e.g., please see its use in Ghana, here. The FPSO vessel to be used in the project is owned and operated by Oslo-based BW Offshore. The company already operates another FPSO ship in the Mexican side of the Gulf, among many others around the globe. -- D.R.)
The US Bureau of Ocean Energy Management, Regulation, and Enforcement [the former Minerals Management Service] approved Petrobras America Inc.’s application to use a floating production, storage, and offloading vessel to produce oil and gas from its Cascade-Chinook project in the Gulf of Mexico. This will be the first time that FPSO technology has been used in the [U.S.] gulf, the US Department of the Interior agency said on Mar. 17.
The BW Pioneer FPSO [please see image below -- D.R.] will receive production through dual flow lines, which connect it to two free-standing hybrid risers for each field, also a new technology for the gulf, Petrobras America said.
BOEMRE said it approved the project’s production safety system permit and supplemental deepwater operating plan following extensive consultations with the producer.
The FPSO will have a production capacity of 80,000 b/d of oil and 16 MMcfd of natural gas, with production expected to begin soon, it indicated.
The project is in the gulf’s Walker Ridge area in 8,200 ft of water [2,500 meters] about 165 miles [266 kilometers] off Louisiana. [Full story]
(Also, the FPSO has an oil storage capacity of 500,000 barrels. Natural gas processed by the BW Pioneer will be transported to shore by pipeline, while crude oil will be offloaded to shuttle tankers for transportation. In the event of a hurricane or tropical storm, the facility is designed to disconnect from the turret-buoy and move off location until the storm has passed. FPSOs are widely used in offshore Brazil and West Africa---e.g., please see its use in Ghana, here. The FPSO vessel to be used in the project is owned and operated by Oslo-based BW Offshore. The company already operates another FPSO ship in the Mexican side of the Gulf, among many others around the globe. -- D.R.)
Wednesday, March 16, 2011
Japan May Need 200,000 Extra Barrels of Oil Daily, IEA Says
By
Oil demand in Japan may climb by about 200,000 barrels a day if the country makes up the shortfall in nuclear power with crude-fired generation, the International Energy Agency said.
Japan shut 11 atomic reactors totaling about 9.7 gigawatts of capacity [or some 20% of Japan’s total nuclear power generation capacity] after being struck on March 11 by its largest recorded earthquake. [For Japan's nuclear crisis, please see my posts here and here. -- D.R.]. The country has enough spare oil-fired plants to make up the loss, using only 30 percent of the crude generation units in 2009, the IEA said in its monthly Oil Market Report today.
Increasing the country’s natural gas-fired generation may also replace the lost nuclear plants, the agency said. Japan’s gas plants are currently running at only 55 percent of capacity.
“If the shortfall were met entirely by oil, consumption would increase by roughly 200,000 barrels a day on an annual basis,” the report said. “The generation of an extra 60 terawatt-hours using only gas would require plants to operate at near 70 percent of capacity, implying an additional 12 billion cubic meters of liquefied natural gas a year.” [Full story]
Oil demand in Japan may climb by about 200,000 barrels a day if the country makes up the shortfall in nuclear power with crude-fired generation, the International Energy Agency said.
Japan shut 11 atomic reactors totaling about 9.7 gigawatts of capacity [or some 20% of Japan’s total nuclear power generation capacity] after being struck on March 11 by its largest recorded earthquake. [For Japan's nuclear crisis, please see my posts here and here. -- D.R.]. The country has enough spare oil-fired plants to make up the loss, using only 30 percent of the crude generation units in 2009, the IEA said in its monthly Oil Market Report today.
Increasing the country’s natural gas-fired generation may also replace the lost nuclear plants, the agency said. Japan’s gas plants are currently running at only 55 percent of capacity.
“If the shortfall were met entirely by oil, consumption would increase by roughly 200,000 barrels a day on an annual basis,” the report said. “The generation of an extra 60 terawatt-hours using only gas would require plants to operate at near 70 percent of capacity, implying an additional 12 billion cubic meters of liquefied natural gas a year.” [Full story]
Thursday, March 10, 2011
Eurogas: EU 27 Gas Consumption Rises 7.2% in 2010
by Doris Leblond, Paris, OGJ, Mar 9, 2011
Preliminary figures from Eurogas indicate that total gas consumption for the European Union 27 [...] increased by 7.2% to 522 billion cu m in 2010 vs. 2009. In 2009, the economic crisis had pulled down consumption to its lowest level since 2002.
The growth was due to a combination of severe weather conditions, which strongly pushed up demand from the residential sector, and economic recovery illustrated by the 1.8% real GDP growth and the 6.6% [sic] increase in the EU 27 average production index for 2010.
Higher electricity demand due to economic recovery combined with the switch to gas from other fuels for electric power generation, which significantly contributed to total demand growth.
Indigenous gas production fell by 4% to 176 bcm in 2010, mainly because of the decline in mature production basins. However, with a 34% share [of the total net supplies -- D.R], it is still the largest source of gas for the EU 27. Main external sources were Russia, 23%; Norway, 19%; Algeria, 10%; and Qatar, 6%; the latter two countries showed an increasing role as LNG suppliers to Europe.
The UK was the largest gas consumer in 2010 with 99.8 bcm. [Estonia] [...] was the smallest with [0.5] bcm ... of gas consumed. Other countries’ gas consumption numbers were, [in order]: Germany, 87 bcm; Italy, 81.1 bcm; France, 50.7 bcm; the Netherland, 46.8 bcm; Spain, 37 bcm; [Belgium, 19.9 bcm] and [Poland, 15.5 bcm] [...].
(Cyprus and Malta are the only two EU member states that do not consume natural gas. However, the US' Noble Energy plans to start work on an exploration well in block 12 offshore Cyprus at end-2011 in an attempt to prove the country's gas potential. Both Cyprus and Malta have been oil import-dependent countries. Among the Baltic States (in the narrower sense), Lithuania was the largest consumer of natural gas with 3 bcm in 2010, followed by Latvia, 1.7 bcm and Estonia, 0.5 bcm---please see Eurogas original report -- Natural Gas Consumption in the EU27 and Switzerland in 2010, Mar 7, 2011, here. For information on EU plans to import gas from Azerbaijan, please see my post here. -- D.R.)
Preliminary figures from Eurogas indicate that total gas consumption for the European Union 27 [...] increased by 7.2% to 522 billion cu m in 2010 vs. 2009. In 2009, the economic crisis had pulled down consumption to its lowest level since 2002.
The growth was due to a combination of severe weather conditions, which strongly pushed up demand from the residential sector, and economic recovery illustrated by the 1.8% real GDP growth and the 6.6% [sic] increase in the EU 27 average production index for 2010.
Higher electricity demand due to economic recovery combined with the switch to gas from other fuels for electric power generation, which significantly contributed to total demand growth.
Indigenous gas production fell by 4% to 176 bcm in 2010, mainly because of the decline in mature production basins. However, with a 34% share [of the total net supplies -- D.R], it is still the largest source of gas for the EU 27. Main external sources were Russia, 23%; Norway, 19%; Algeria, 10%; and Qatar, 6%; the latter two countries showed an increasing role as LNG suppliers to Europe.
The UK was the largest gas consumer in 2010 with 99.8 bcm. [Estonia] [...] was the smallest with [0.5] bcm ... of gas consumed. Other countries’ gas consumption numbers were, [in order]: Germany, 87 bcm; Italy, 81.1 bcm; France, 50.7 bcm; the Netherland, 46.8 bcm; Spain, 37 bcm; [Belgium, 19.9 bcm] and [Poland, 15.5 bcm] [...].
(Cyprus and Malta are the only two EU member states that do not consume natural gas. However, the US' Noble Energy plans to start work on an exploration well in block 12 offshore Cyprus at end-2011 in an attempt to prove the country's gas potential. Both Cyprus and Malta have been oil import-dependent countries. Among the Baltic States (in the narrower sense), Lithuania was the largest consumer of natural gas with 3 bcm in 2010, followed by Latvia, 1.7 bcm and Estonia, 0.5 bcm---please see Eurogas original report -- Natural Gas Consumption in the EU27 and Switzerland in 2010, Mar 7, 2011, here. For information on EU plans to import gas from Azerbaijan, please see my post here. -- D.R.)
Tuesday, March 8, 2011
Petrobras Announces Third LNG Terminal
by OGJ editors, OGJ, Mar 2, 2011
Petroleo Brasileiro SA (Petrobras) reported it will install a third offshore LNG terminal.
The Bahia regasification terminal (TRBA), with capacity to regasify 14 million cu m/day (cmd), will supply natural gas to the state of Bahia, the heaviest consumer of gas among the northeastern Brazilian states.
TRBA will be installed in the Bay of All Saints and interconnect with a pipeline network at two sites: one in the Bahia network, at Candeias, and the other at kilometer 910 on the Cacimbas-Catu pipeline, a section of the Southeast-Northeast Gas Pipeline started up in March 2010.
As part of Brazil’s Growth Acceleration Program, Petrobras said, work will begin in March 2012 with completion scheduled for August 2013 under an investment of nearly $425 million.
Currently, Brazil has LNG terminals at Pecem (State of Ceara) with a regasification capacity of 7 million cmd, and in the Guanabara Bay (State of Rio de Janeiro) with capacity of 14 million cmd. When the TRBA terminal comes online in September 2013, Brazil’s total regasification capacity will reach 35 million cmd, overtaking the gas imports via pipeline from Bolivia (31 million cmd).
At the Pecem and Guanabara Bay terminals, tankers moor at a two-berth pier and LNG is transferred over cryogenic arms from supply vessel to regasification vessel. At the TRBA terminal, LNG will be transferred directly between vessels using side-by-side docking, which means that the regasification vessel will dock at a single-berth, island-type pier, said the company.
With direct connection to the supply vessel, LNG will be transferred over short hoses or loading arms to the regasification vessel, which will convert LNG back into a vapor [i.e., gaseous state].
Gas will then be injected into the pipeline network through a 28-in. pipeline that is 49 km long including a 15-km subsea section.
Petrobras noted that currently only two [sic] other LNG terminals in the world use this configuration [i.e., side-by-side -- D.R.]: Bahia Blanca in Argentina and the UAE’s Dubai terminal. [Full story]
(Brazil imported 298 Bcf of natural gas in 2009, a 24 percent drop from 2008. The decline in Brazilian overall natural gas demand, coupled with policy choices aimed at reducing imports, led to this decline. The country currently receives imports by pipeline from Bolivia and liquefied natural gas (LNG) imports from Trinidad and Tobago and Nigeria. Import growth in the future is expected to be met more with LNG than with conventional pipeline imports. Brazil imports natural gas from Bolivia via the Gasbol pipeline, which links Santa Cruz, Bolivia to Porto Alegre, Brazil, via Sao Paulo. The 2,000-mile Gasbol has a maximum capacity of 1.1 Bcf per day (Bcf/d). In early 2009, Brazil announced that it would reduce imports from Bolivia from 1.1 Bcf/d to 0.7 Bcf/d. According to ANP, Brazilian imports of Bolivian gas have since declined by 27 percent. However, Bolivia still accounted for 96 percent of Brazil’s total natural gas imports. The Pecem---please see image below---received its first LNG cargo from Trinidad and Tobago in July 2008, while the Guanabara Bay terminal came online in May 2009. According to ANP, Brazil received 15 Bcf of natural gas in the form of LNG in 2009, mostly from Trinidad and Tobago---please see U.S. EIA, Brazil Country Analysis Brief, Jan 2011, here. For the Petrobras's standing in the company rankings---PIW's and others---please see my blog stand-alone page "Companies" > Petrobras, here. -- D.R.)
Source: LNGpedia.com here Description: The Floating Storage and Regasification Unit---FSRU---vessel, the Golar Spirit, is reportedly the world's first methane vessel to have been converted to perform LNG regasification on board. The regasification capacity of the Golar Spirit is seven million cubic meters (cbm) per day, and its storage capacity is 129,000 cbm of LNG, equivalent to 77 million cbm of natural gas.
Petroleo Brasileiro SA (Petrobras) reported it will install a third offshore LNG terminal.
The Bahia regasification terminal (TRBA), with capacity to regasify 14 million cu m/day (cmd), will supply natural gas to the state of Bahia, the heaviest consumer of gas among the northeastern Brazilian states.
TRBA will be installed in the Bay of All Saints and interconnect with a pipeline network at two sites: one in the Bahia network, at Candeias, and the other at kilometer 910 on the Cacimbas-Catu pipeline, a section of the Southeast-Northeast Gas Pipeline started up in March 2010.
As part of Brazil’s Growth Acceleration Program, Petrobras said, work will begin in March 2012 with completion scheduled for August 2013 under an investment of nearly $425 million.
Currently, Brazil has LNG terminals at Pecem (State of Ceara) with a regasification capacity of 7 million cmd, and in the Guanabara Bay (State of Rio de Janeiro) with capacity of 14 million cmd. When the TRBA terminal comes online in September 2013, Brazil’s total regasification capacity will reach 35 million cmd, overtaking the gas imports via pipeline from Bolivia (31 million cmd).
At the Pecem and Guanabara Bay terminals, tankers moor at a two-berth pier and LNG is transferred over cryogenic arms from supply vessel to regasification vessel. At the TRBA terminal, LNG will be transferred directly between vessels using side-by-side docking, which means that the regasification vessel will dock at a single-berth, island-type pier, said the company.
With direct connection to the supply vessel, LNG will be transferred over short hoses or loading arms to the regasification vessel, which will convert LNG back into a vapor [i.e., gaseous state].
Gas will then be injected into the pipeline network through a 28-in. pipeline that is 49 km long including a 15-km subsea section.
Petrobras noted that currently only two [sic] other LNG terminals in the world use this configuration [i.e., side-by-side -- D.R.]: Bahia Blanca in Argentina and the UAE’s Dubai terminal. [Full story]
(Brazil imported 298 Bcf of natural gas in 2009, a 24 percent drop from 2008. The decline in Brazilian overall natural gas demand, coupled with policy choices aimed at reducing imports, led to this decline. The country currently receives imports by pipeline from Bolivia and liquefied natural gas (LNG) imports from Trinidad and Tobago and Nigeria. Import growth in the future is expected to be met more with LNG than with conventional pipeline imports. Brazil imports natural gas from Bolivia via the Gasbol pipeline, which links Santa Cruz, Bolivia to Porto Alegre, Brazil, via Sao Paulo. The 2,000-mile Gasbol has a maximum capacity of 1.1 Bcf per day (Bcf/d). In early 2009, Brazil announced that it would reduce imports from Bolivia from 1.1 Bcf/d to 0.7 Bcf/d. According to ANP, Brazilian imports of Bolivian gas have since declined by 27 percent. However, Bolivia still accounted for 96 percent of Brazil’s total natural gas imports. The Pecem---please see image below---received its first LNG cargo from Trinidad and Tobago in July 2008, while the Guanabara Bay terminal came online in May 2009. According to ANP, Brazil received 15 Bcf of natural gas in the form of LNG in 2009, mostly from Trinidad and Tobago---please see U.S. EIA, Brazil Country Analysis Brief, Jan 2011, here. For the Petrobras's standing in the company rankings---PIW's and others---please see my blog stand-alone page "Companies" > Petrobras, here. -- D.R.)
Monday, March 7, 2011
Azerbaijan to Double Gas Output to 54 Bcm/Year by 2020: Official
Platts, Feb 15, 2011
Azerbaijan plans to double its natural gas output to some 54 billion cubic meters/year by 2020, a senior energy ministry official said Tuesday, with Europe expected to benefit most from the increased volumes.
Azerbaijan's deputy [industry and] energy minister Natig Abbasov told the Azerbaijan Press Agency following a session of an Azerbaijan-EU working group the country has confirmed gas reserves of 2.2 trillion cubic meters, [mostly in Shah Deniz II and the Umid fields.]
"In 2006 Azerbaijan produced 9 Bcm of gas and already in 2010 produced 27 Bcm," Abbasov said.
"By 2020 the volume of gas produced in Azerbaijan will double," he said.
In January, Azerbaijan agreed to supply enough gas to the EU to open up the so-called "Southern Gas Corridor."
Securing supplies from Azerbaijan has been seen as key to Europe's plans to diversify its gas imports away from Russia and other traditional suppliers.
Competition for Azerbaijan's future gas has been fierce, with Russia and Iran also interested in increasing supplies.
The January declaration was the first time Azerbaijan had agreed in writing to export large volumes of gas to Europe, though it has said verbally in the past it was prepared to supply countries in Europe.
Abbasov said that as recently as 2006, Azerbaijan had to import gas, but it now exports gas to Russia, Iran, Turkey and Georgia [please see my remarks below -- D.R.].
Abbasov said Azerbaijan plans to supply 2 Bcm of gas to Russia in 2011.
The main sources of Baku's gas production growth will come from the second phase of the Shah Deniz gas field and the Umid field, Abbasov said.
Umid's recoverable reserves are estimated at 200 Bcm, and Azerbaijan also has a number of other high-profile gas fields in the exploration phase, including the Total-led Absheron project, where drilling has just started.
EU PIPELINE PROJECTS
Although Russia has publicly said it could buy all of Azerbaijan's export gas, the EU is expected to receive large volumes of Azeri gas in the future.
There are currently three gas pipeline projects competing for new gas from Azerbaijan, with a decision on which is to be favored by Baku due soon.
The projected 31 Bcm/year Nabucco and the planned 11 Bcm/year ITGI lines are competing with a third project, the proposed 20 Bcm/year Trans-Adriatic Pipeline between Greece, Albania and Italy, for the role of principal carrier of Azeri gas to Europe.
Azerbaijan has also pledged gas to the Azerbaijan-Georgia-Romania Interconnector (AGRI) venture.
The energy ministers of the three countries, plus Hungary, signed a declaration on the project in the Romanian capital Bucharest Monday.
The AGRI project, created last September, envisions 7 Bcm/year of Azeri gas transported from the Sangachal terminal via existing pipelines to the port of Kulevi, Georgia.
There it would be converted to LNG in a newly built terminal and shipped to the port of Constanta, Romania, across the Black Sea, and on to Hungary via pipeline.
Hungary, which already took part in last September's AGRI talks as an observer, will be represented in the project company by state-owned power holding MVM.
The four partner companies -- Romgaz (Romania), Socar (Azerbaijan), GOGC (Georgia) and MVM -- will each control 25% of the AGRI project company.
The four parties hope to complete a feasibility study of the project by April 1, 2012.
Hungary's participation in the project is made possible by a recently opened Hungary-Romania gas interconnector.
Hungary is heavily dependent on Russian gas imports transported via Ukraine, and is also part of the Nabucco project.
"AGRI, too, could be a realistic solution for easing Hungary's one-sided gas import dependence, both in terms of gas sources and supply routes," Hungary's energy minister [Minister of National Development] Tamas Fellegi was quoted as saying. "We believe AGRI is a feasible project." [Full story]
(Azerbaijan became a net exporter of natural gas in 2007 with the startup of the Shah Deniz natural gas and condensate field in late 2006; in prior years it had been importing natural gas from Russia. Prior to 2007, the Kazi Magomed-Mozdok pipeline used to transport natural gas from Russia to Azerbaijan, but the agreement allowed for the pipeline flow to be reversed, making Azerbaijan an exporter of natural gas to Russia. The Shah Deniz field was discovered in 1999. It is one of the world's largest gas-condensate fields, with over 30 trillion cubic feet---1 trillion cubic meters---of gas in place. It lies in water depths between 50 meters and 600 meters, i.e. 1969 ft, some 70 kilometers, i.e. 43 mi, southeast of Baku---please see map below. BP operates Shah Deniz on behalf of its parners in the Shah Deniz Production Sharing Agreement. The country is also a significant oil producer. Azerbaijan produced some 51 million tons of oil, i.e., about 1 million barrels of oil per day, in 2010. -- D.R.)
Source: Rigzone, here (Azerbaijan's northern land border with Russia is missing -- D.R.)
Azerbaijan plans to double its natural gas output to some 54 billion cubic meters/year by 2020, a senior energy ministry official said Tuesday, with Europe expected to benefit most from the increased volumes.
Azerbaijan's deputy [industry and] energy minister Natig Abbasov told the Azerbaijan Press Agency following a session of an Azerbaijan-EU working group the country has confirmed gas reserves of 2.2 trillion cubic meters, [mostly in Shah Deniz II and the Umid fields.]
"In 2006 Azerbaijan produced 9 Bcm of gas and already in 2010 produced 27 Bcm," Abbasov said.
"By 2020 the volume of gas produced in Azerbaijan will double," he said.
In January, Azerbaijan agreed to supply enough gas to the EU to open up the so-called "Southern Gas Corridor."
Securing supplies from Azerbaijan has been seen as key to Europe's plans to diversify its gas imports away from Russia and other traditional suppliers.
Competition for Azerbaijan's future gas has been fierce, with Russia and Iran also interested in increasing supplies.
The January declaration was the first time Azerbaijan had agreed in writing to export large volumes of gas to Europe, though it has said verbally in the past it was prepared to supply countries in Europe.
Abbasov said that as recently as 2006, Azerbaijan had to import gas, but it now exports gas to Russia, Iran, Turkey and Georgia [please see my remarks below -- D.R.].
Abbasov said Azerbaijan plans to supply 2 Bcm of gas to Russia in 2011.
The main sources of Baku's gas production growth will come from the second phase of the Shah Deniz gas field and the Umid field, Abbasov said.
Umid's recoverable reserves are estimated at 200 Bcm, and Azerbaijan also has a number of other high-profile gas fields in the exploration phase, including the Total-led Absheron project, where drilling has just started.
EU PIPELINE PROJECTS
Although Russia has publicly said it could buy all of Azerbaijan's export gas, the EU is expected to receive large volumes of Azeri gas in the future.
There are currently three gas pipeline projects competing for new gas from Azerbaijan, with a decision on which is to be favored by Baku due soon.
The projected 31 Bcm/year Nabucco and the planned 11 Bcm/year ITGI lines are competing with a third project, the proposed 20 Bcm/year Trans-Adriatic Pipeline between Greece, Albania and Italy, for the role of principal carrier of Azeri gas to Europe.
Azerbaijan has also pledged gas to the Azerbaijan-Georgia-Romania Interconnector (AGRI) venture.
The energy ministers of the three countries, plus Hungary, signed a declaration on the project in the Romanian capital Bucharest Monday.
The AGRI project, created last September, envisions 7 Bcm/year of Azeri gas transported from the Sangachal terminal via existing pipelines to the port of Kulevi, Georgia.
There it would be converted to LNG in a newly built terminal and shipped to the port of Constanta, Romania, across the Black Sea, and on to Hungary via pipeline.
Hungary, which already took part in last September's AGRI talks as an observer, will be represented in the project company by state-owned power holding MVM.
The four partner companies -- Romgaz (Romania), Socar (Azerbaijan), GOGC (Georgia) and MVM -- will each control 25% of the AGRI project company.
The four parties hope to complete a feasibility study of the project by April 1, 2012.
Hungary's participation in the project is made possible by a recently opened Hungary-Romania gas interconnector.
Hungary is heavily dependent on Russian gas imports transported via Ukraine, and is also part of the Nabucco project.
"AGRI, too, could be a realistic solution for easing Hungary's one-sided gas import dependence, both in terms of gas sources and supply routes," Hungary's energy minister [Minister of National Development] Tamas Fellegi was quoted as saying. "We believe AGRI is a feasible project." [Full story]
(Azerbaijan became a net exporter of natural gas in 2007 with the startup of the Shah Deniz natural gas and condensate field in late 2006; in prior years it had been importing natural gas from Russia. Prior to 2007, the Kazi Magomed-Mozdok pipeline used to transport natural gas from Russia to Azerbaijan, but the agreement allowed for the pipeline flow to be reversed, making Azerbaijan an exporter of natural gas to Russia. The Shah Deniz field was discovered in 1999. It is one of the world's largest gas-condensate fields, with over 30 trillion cubic feet---1 trillion cubic meters---of gas in place. It lies in water depths between 50 meters and 600 meters, i.e. 1969 ft, some 70 kilometers, i.e. 43 mi, southeast of Baku---please see map below. BP operates Shah Deniz on behalf of its parners in the Shah Deniz Production Sharing Agreement. The country is also a significant oil producer. Azerbaijan produced some 51 million tons of oil, i.e., about 1 million barrels of oil per day, in 2010. -- D.R.)
Sunday, March 6, 2011
Fitch: Long Production Cut Biggest MENA Threat
By OGJ editors, OGJ, Mar 3, 2011
Long interruption of production represents the largest threat from political turmoil to the financial stability of oil and gas companies with operations in the Middle East and North Africa (MENA) but remains unlikely, an international credit-reporting agency says.
A secondary risk, nationalization of assets by successor regimes in countries now experiencing unrest, is a “remote scenario,” although contract renegotiations by successor regimes remains possible, according to Fitch Ratings, New York and London.
A recent Fitch report covering North American companies with operations in the MENA region said credit pressures from unrest in Egypt, Libya, and other countries of concern are manageable.
Credit ratings are most sensitive to “widespread and long-lasting production” upsets, which Fitch doesn’t expect “due to the importance of oil revenues to the region’s economies.”
Most North American producers in the MENA region are large, integrated companies for which production in countries experiencing unrest is small in relation to total. Oil price increases mitigate the elevated risks of production losses and contract renegotiation.
Company exposures
Apache Corp. has the highest exposure among North American producers to any single country experiencing turmoil, Fitch said. Apache’s 163,300 boe/d of output in Egypt is 24% of Fitch’s assessment of the company’s recent total production.
Exposure levels in Libya include Marathon, 12% of total production; Suncor Energy Inc., 8%; Hess Corp., 5%; ConocoPhillips, 3%, and Occidental Petroleum Corp., 1%.
Fitch called Algeria “the other North African country that could present the largest concerns for North American-based upstream companies.” There, sizable exposure levels include Anadarko Petroleum Corp., 7% of total production, and Hess, 3%. ConocoPhillips produced 14,000 boe/d in Algeria in the third quarter last year, less than 1% of total production, according to Fitch estimates.
North American companies with production in restive Yemen include Nexen Inc., 11% of estimated total production, and Oxy, 6%.
Among European oil and gas companies tracked by Fitch, four have production in Libya or Egypt, the firm said in a separate report.
Eni, OMV, and Repsol have production exposure of 9-14% in Libya, “with Eni as the most exposed,” Fitch said. About one fourth of BG Energy Holdings Ltd.’s total oil and gas output is in Egypt.
“There could be a more pronounced impact on European oil and gas companies’ operations and financials if the political unrest spreads across Africa and/or the Middle East,” Fitch said, adding it “does not currently view this scenario as very likely.” [Full story]
Friday, March 4, 2011
Tuesday, March 1, 2011
Asian LNG Outlook: The Evolution of a New Asian LNG Market
By Hong Chou Hui, Platts, Singapore, Feb 23, 2011
Asia's LNG market is set to come of age in 2011 as the volatility of the last few years has shaken up the region and increased players' appetite for a more sophisticated approach.
Demand in Asia bounced back in 2010 on the back of extreme cold and hot temperatures coupled with economic recovery across the region, after the global financial crisis at the end of 2008 curtailed LNG cargoes purchased in 2009.
Requirements for 2011 are expected to remain robust among traditional buyers, while a series of new players are also entering the fray.
The region continues to be the dominant force in LNG. Growing shale gas production in the US has reduced the need for imports there to virtually nil.
Europe's gas demand remains largely focused on pipeline imports, while the growth in LNG imports into the northwest of the continent has been offset by a decline in imports into the southwest.
While the final figures for 2010 have yet to be collated, the previous year saw Asia take 62.8% [please see table below -- D.R.], or 1.09 billion barrels of oil equivalent of the world's total imported LNG, according to data from independent LNG consultant Andy Flower. And the initial data for last year give every indication of repeating that pattern.
Japan's LNG imports in 2010 were up 8.6% year on year at 70.01 million mt, reaching a new record for annual volumes and surpassing the pre-financial crisis level seen in 2008 of 69.26 million mt, customs data from the Ministry of Finance show.
The figure looks all the more impressive when compared with 2009's dramatic drop in imports to 64.49 million mt. [Please see table below -- D.R.]
Similarly, South Korea's 2010 LNG imports were up 26.26% year on year at 32.6 million mt, from 25.82 million mt in 2009, according to the country's customs data compiled by Platts over the year.
Across the board, all [sic, please see bar chart below -- D.R.] Asian buyers imported more LNG in 2010 compared to the previous year.
[Click on bar chart to enlarge]
Meanwhile, though the traditional buyers in Japan and South Korea, which currently have almost 180 million mt/year and 40 million mt/year of LNG import capacity respectively, will likely continue to remain the dominant force in the market, Asia's largest countries are beginning to make their presence felt.
China and India are building a further 20 million mt/year and 10 million mt/year of regasification capacity respectively.
Two Chinese LNG terminals, both being built by state-owned PetroChina, will startup this year -- the 3.5 million mt/year Rudong facility in April and the 3 million mt/year Dalian terminal in June -- bringing China's total import capacity to 18.8 million mt/year.
And a further three terminals are due for completion in the following few years. (See related chart: Asian terminal capacities (million mt/year)).
[Click on bar chart to enlarge]
Meanwhile India has two terminals under construction, building on its existing import capacity of 13.6 million mt/year. And, like China, there are plans for a host of further regasification facilities in India in the years ahead.
China and India's GDPs are projected to grow by around 10% this year and in 2012 [sic, please see chart below -- D.R.], outperforming both Japan and Korea at 2% and 5% respectively over the same period, according to the IMF World Economic Outlook. Coupled with state support for gas use, there is significant potential for increased LNG imports into the two countries.
[Click on chart to enlarge]
But despite their muscular economies and large populations, China and India have both faced constraints on their LNG imports in the last year or so, with the former's ability to bring in shipments curtailed by a small number of import terminals and limited storage facilities, while India is limited by the capacity of its downstream gas pipelines.
And any forecasts are further clouded by the potential for domestic production of unconventional gas -- coalbed methane and shale gas -- in both countries, which could limit the need for LNG purchases in the future. [Full story]
(Japan is the world's largest importer of liquefied natural gas---LNG---followed by South Korea and Spain, according to the 2008, 2009 and 2010 data. For information on Japan's, South Korea's and China's LNG imports in 2010, please see also my post "East Asian LNG Imports in 2010," including remarks, here. For major LNG exporters to Japan in 2010, please see bar chart here. Sustained oil prices over $100 a barrel, as a result of instability in the Middle East & North Africa, could also have a negative effect on economy of Asia. -- D.R.)
Asia's LNG market is set to come of age in 2011 as the volatility of the last few years has shaken up the region and increased players' appetite for a more sophisticated approach.
Demand in Asia bounced back in 2010 on the back of extreme cold and hot temperatures coupled with economic recovery across the region, after the global financial crisis at the end of 2008 curtailed LNG cargoes purchased in 2009.
Requirements for 2011 are expected to remain robust among traditional buyers, while a series of new players are also entering the fray.
The region continues to be the dominant force in LNG. Growing shale gas production in the US has reduced the need for imports there to virtually nil.
Europe's gas demand remains largely focused on pipeline imports, while the growth in LNG imports into the northwest of the continent has been offset by a decline in imports into the southwest.
While the final figures for 2010 have yet to be collated, the previous year saw Asia take 62.8% [please see table below -- D.R.], or 1.09 billion barrels of oil equivalent of the world's total imported LNG, according to data from independent LNG consultant Andy Flower. And the initial data for last year give every indication of repeating that pattern.
Japan's LNG imports in 2010 were up 8.6% year on year at 70.01 million mt, reaching a new record for annual volumes and surpassing the pre-financial crisis level seen in 2008 of 69.26 million mt, customs data from the Ministry of Finance show.
The figure looks all the more impressive when compared with 2009's dramatic drop in imports to 64.49 million mt. [Please see table below -- D.R.]
Similarly, South Korea's 2010 LNG imports were up 26.26% year on year at 32.6 million mt, from 25.82 million mt in 2009, according to the country's customs data compiled by Platts over the year.
Across the board, all [sic, please see bar chart below -- D.R.] Asian buyers imported more LNG in 2010 compared to the previous year.
[Click on bar chart to enlarge]
Meanwhile, though the traditional buyers in Japan and South Korea, which currently have almost 180 million mt/year and 40 million mt/year of LNG import capacity respectively, will likely continue to remain the dominant force in the market, Asia's largest countries are beginning to make their presence felt.
China and India are building a further 20 million mt/year and 10 million mt/year of regasification capacity respectively.
Two Chinese LNG terminals, both being built by state-owned PetroChina, will startup this year -- the 3.5 million mt/year Rudong facility in April and the 3 million mt/year Dalian terminal in June -- bringing China's total import capacity to 18.8 million mt/year.
And a further three terminals are due for completion in the following few years. (See related chart: Asian terminal capacities (million mt/year)).
[Click on bar chart to enlarge]
Meanwhile India has two terminals under construction, building on its existing import capacity of 13.6 million mt/year. And, like China, there are plans for a host of further regasification facilities in India in the years ahead.
China and India's GDPs are projected to grow by around 10% this year and in 2012 [sic, please see chart below -- D.R.], outperforming both Japan and Korea at 2% and 5% respectively over the same period, according to the IMF World Economic Outlook. Coupled with state support for gas use, there is significant potential for increased LNG imports into the two countries.
[Click on chart to enlarge]
But despite their muscular economies and large populations, China and India have both faced constraints on their LNG imports in the last year or so, with the former's ability to bring in shipments curtailed by a small number of import terminals and limited storage facilities, while India is limited by the capacity of its downstream gas pipelines.
And any forecasts are further clouded by the potential for domestic production of unconventional gas -- coalbed methane and shale gas -- in both countries, which could limit the need for LNG purchases in the future. [Full story]
(Japan is the world's largest importer of liquefied natural gas---LNG---followed by South Korea and Spain, according to the 2008, 2009 and 2010 data. For information on Japan's, South Korea's and China's LNG imports in 2010, please see also my post "East Asian LNG Imports in 2010," including remarks, here. For major LNG exporters to Japan in 2010, please see bar chart here. Sustained oil prices over $100 a barrel, as a result of instability in the Middle East & North Africa, could also have a negative effect on economy of Asia. -- D.R.)
Monday, February 28, 2011
Gazprom Ups Italian Gas Supplies 30% Due to Libya Unrest: Source
Platts, Moscow, Feb 28, 2011
Gazprom has increased its daily Russian gas deliveries to Italy by around 30% after unrest in Libya led to the shutdown of the 11 billion cubic meter/year Greenstream pipeline [please see map below -- D.R.] last week, a source close to Gazprom said Monday.
The source told Platts it was unclear how long the gas supplies would remain at an elevated level.
Gazprom's deliveries reached 81.1 million cu m/day on Thursday, up from a daily average of 63 million-65 million cu m on weekdays and 54 million-55 million cu m at weekends, Russian news agency Interfax reported Friday, citing Italy's gas grid operator Snam Rete Gas.
Snam Rete Gas was not available for comment.
Last Tuesday Eni, Italy's main gas supplier and the parent of Snam Rete Gas, announced it had shut down Greenstream.
Greenstream, which is a joint venture between Eni and the National Oil Corporation of Libya, exported around 9.4 billion cu m of gas to Italy in 2010.
It runs from Mellitah in Libya to Gela in Sicily, Italy.
According to the European Commission, 30% of Italy's gas supplies come from Russia, with Libya typically supplying around 11%. Thirty-three percent of the country's gas imports come from Algeria and 9% from Norway.
The increase in Russian supplies to Italy is likely to be temporary, according to a research note by investment company Alfa Bank.
"There could be other positive implications for Russia, as the incident is likely to underscore the country's reputation as a reliable gas supplier and could ease concern over Russia's large share of European gas markets," the note said.
Within Europe, Libya only delivers gas to Italy and Spain [to Spain in the form of LNG -- D.R.]. Libyan gas represents 1.5% of Spanish [gas] imports. [Full story]
(The c. 520-kilometer---323-mile---Greenstream submarine pipeline came online in 2004. For information on Libya's oil and gas profile, please see my post here.)
Source: ENI, here
Gazprom has increased its daily Russian gas deliveries to Italy by around 30% after unrest in Libya led to the shutdown of the 11 billion cubic meter/year Greenstream pipeline [please see map below -- D.R.] last week, a source close to Gazprom said Monday.
The source told Platts it was unclear how long the gas supplies would remain at an elevated level.
Gazprom's deliveries reached 81.1 million cu m/day on Thursday, up from a daily average of 63 million-65 million cu m on weekdays and 54 million-55 million cu m at weekends, Russian news agency Interfax reported Friday, citing Italy's gas grid operator Snam Rete Gas.
Snam Rete Gas was not available for comment.
Last Tuesday Eni, Italy's main gas supplier and the parent of Snam Rete Gas, announced it had shut down Greenstream.
Greenstream, which is a joint venture between Eni and the National Oil Corporation of Libya, exported around 9.4 billion cu m of gas to Italy in 2010.
It runs from Mellitah in Libya to Gela in Sicily, Italy.
According to the European Commission, 30% of Italy's gas supplies come from Russia, with Libya typically supplying around 11%. Thirty-three percent of the country's gas imports come from Algeria and 9% from Norway.
The increase in Russian supplies to Italy is likely to be temporary, according to a research note by investment company Alfa Bank.
"There could be other positive implications for Russia, as the incident is likely to underscore the country's reputation as a reliable gas supplier and could ease concern over Russia's large share of European gas markets," the note said.
Within Europe, Libya only delivers gas to Italy and Spain [to Spain in the form of LNG -- D.R.]. Libyan gas represents 1.5% of Spanish [gas] imports. [Full story]
(The c. 520-kilometer---323-mile---Greenstream submarine pipeline came online in 2004. For information on Libya's oil and gas profile, please see my post here.)
Saturday, February 26, 2011
Friday, February 25, 2011
China: Taking Oil Home
by Song Yen Ling and Jason Fargo, Energy Compass, Feb 11, 2011
As China pushes deeper into the global upstream industry, it's widely assumed that the expanding portfolio is being used to funnel oil supplies back home -- feeding the country's insatiable appetite for energy. Yet the reality is not so simple: The strategy of energy security is more complex, faces competing pressures from other policy goals, and can bump into infrastructural and commercial constraints, Energy Compass analysis shows.
What's not in doubt is that Chinese companies have spent tens of billions of dollars acquiring large volumes of production overseas. Foreign equity oil and gas output averaged 1.4 million barrels of oil equivalent per day in 2010, an increase of 40% on the previous year, according to a new report by state China National Petroleum Corp. (CNPC). Oil accounted for the lion's share, at 1.2 million barrels per day.
Energy security was the original driver of overseas expansion, with Beijing instructing companies to amass sources of supply. But in recent years this has become intertwined with a parallel objective of turning state oil giants into global, commercially driven entities capable of competing with Western oil companies. Beijing has also become preoccupied with its rising energy import bill, as oil prices and Chinese demand growth feed off each other. The government now sees overseas investments as important in bolstering global oil production to meet the growing needs of its economy, while acting as a hedge against higher prices.
CNOOC [China National Offshore Oil Corp.] Chairman Fu Chengyu recently spelt out these overlapping goals, telling local media that his company's overseas drive was designed to increase world oil supply and fulfill the needs of the host market, rather than to ship crude oil back to China. "Our expansion strategy overseas is based on grabbing good opportunities. But more importantly, commercial value must be realized," he said. The strategy not only helps China's economy, Fu said, but also contributes to the global economy.
The government increasingly recognizes that China's large upstream footprint does not necessarily translate into supply security, says one Chinese oil insider. Chinese companies tend to operate in politically unstable parts of the world, increasing the risk of nationalization or domestic controls, and may be limited by fiscal regimes.
Cash-for-oil deals -- where Beijing extends huge loans to oil-producing governments in exchange for a fixed volume of oil supply -- are viewed as a stronger bet in this regard, and have been embraced in the past couple of years. Such deals are now in place with Venezuela, Brazil, Kazakhstan, Russia [please see remarks below -- D.R.] and Ecuador, and account for some 1.1 million b/d, according to Energy Intelligence calculations (EC Jul.9,p5). With equity oil and domestic production, China now effectively controls some 6.4 million b/d of global oil production.
Tacit Understanding
Industry sources say there still is an understanding that, in a crisis, national interests will trump all commercial or other objectives. In the event that Mideast crude supply to China is interrupted, for example, state companies would be expected to send as much oil home as possible. This has already played out in other markets: Beijing put pressure on CNPC to increase natural gas supply this winter, which the company did at a loss. Similarly, refiners were compelled to suspend diesel exports during recent domestic shortages (EC Dec.3,p7).
In a global oil crisis, China's new strategic stockpile would be the first line of defense; this already has capacity of almost 250 million bbl and is due to hit 500 million-600 million bbl by 2020. There would also be limits on how much crude could easily be shipped back to China. Older refineries were built to run local [relatively] light, sweet grades Daqing [...], and only 30% of the country's [...] capacity can process sour grades. And companies may be constrained by contractual obligations to existing customers or the politics of the situation, Chatham House's John Mitchell wrote in a recent report (EC Jan.14,p10). Indeed, if the host country is involved in the crisis, equity oil investments could become "hostages" that limit the importer's foreign policy options "in exactly the way that energy security policy is supposed to avoid," Mitchell wrote.
Sudan, for one, provides large volumes of equity oil for the Chinese market, but also offers some of the highest risks of disruption, especially after the south's vote for independence (EC Jan.21,p6). CNPC has equity stakes of 40%-95% in the country's three largest production ventures, equivalent to about 205,000 b/d of Sudan's 475,000 b/d production. With marketing options limited by crude quality and US sanctions, some 253,000 b/d of Sudan's oil was exported to China last year. CNPC has built a special 200,000 b/d refinery at Qinzhou to process Dar and Nile Blend crudes.
At the other end of the spectrum is Ecuador, where China has again built a dominant position in export trade -- but takes hardly any oil back home. Andes Petroleum and PetroOriental, both partnerships of CNPC and Sinopec, produce a total of about 50,000 b/d. In addition, China is entitled to lift 96,000 b/d of state Petroecuador's crude under a two-year, $1 billion loan signed in mid-2009 (EC Aug.21'09,p5). Yet Chinese crude imports from Ecuador averaged just 16,300 barrels per day in 2010, down 55% on the previous year. Transportation costs are high, and Chinese refineries are not optimized for Ecuadorean grades.
Instead, the value of China's Ecuador presence has lain elsewhere, in providing a springboard for expansion in Latin America's oil industry and an avenue for PetroChina to develop an active global trading role, as the CNPC affiliate recreates itself as an international integrated company (EC Jan.14,p3). Virtually all of China's crude entitlement from Ecuador is sold on the open market, mainly to refineries in California, with PetroChina now the country's main lifter. PetroChina also swaps some supplies for crude more suited to China's refineries -- a twist demonstrating the increasing complexity and sophistication of China's energy security strategy.
Other overseas equity oil that doesn't make its way to China includes CNOOC's interests in Argentina and offshore Nigeria. [Read full]
(China agreed to loan Russian companies, Rosneft and Transneft $25 billlion to finance the East Siberia Pacific Ocean---ESPO---oil pipeline in exchange for 300,000 bbl/d of oil shipments---please see my post here. China is the world's second-largest consumer of oil behind the United States, and for the first time the second-largest net importer of oil in 2009---please see my post, including remarks, here. -- D.R.)
As China pushes deeper into the global upstream industry, it's widely assumed that the expanding portfolio is being used to funnel oil supplies back home -- feeding the country's insatiable appetite for energy. Yet the reality is not so simple: The strategy of energy security is more complex, faces competing pressures from other policy goals, and can bump into infrastructural and commercial constraints, Energy Compass analysis shows.
What's not in doubt is that Chinese companies have spent tens of billions of dollars acquiring large volumes of production overseas. Foreign equity oil and gas output averaged 1.4 million barrels of oil equivalent per day in 2010, an increase of 40% on the previous year, according to a new report by state China National Petroleum Corp. (CNPC). Oil accounted for the lion's share, at 1.2 million barrels per day.
Energy security was the original driver of overseas expansion, with Beijing instructing companies to amass sources of supply. But in recent years this has become intertwined with a parallel objective of turning state oil giants into global, commercially driven entities capable of competing with Western oil companies. Beijing has also become preoccupied with its rising energy import bill, as oil prices and Chinese demand growth feed off each other. The government now sees overseas investments as important in bolstering global oil production to meet the growing needs of its economy, while acting as a hedge against higher prices.
CNOOC [China National Offshore Oil Corp.] Chairman Fu Chengyu recently spelt out these overlapping goals, telling local media that his company's overseas drive was designed to increase world oil supply and fulfill the needs of the host market, rather than to ship crude oil back to China. "Our expansion strategy overseas is based on grabbing good opportunities. But more importantly, commercial value must be realized," he said. The strategy not only helps China's economy, Fu said, but also contributes to the global economy.
The government increasingly recognizes that China's large upstream footprint does not necessarily translate into supply security, says one Chinese oil insider. Chinese companies tend to operate in politically unstable parts of the world, increasing the risk of nationalization or domestic controls, and may be limited by fiscal regimes.
Cash-for-oil deals -- where Beijing extends huge loans to oil-producing governments in exchange for a fixed volume of oil supply -- are viewed as a stronger bet in this regard, and have been embraced in the past couple of years. Such deals are now in place with Venezuela, Brazil, Kazakhstan, Russia [please see remarks below -- D.R.] and Ecuador, and account for some 1.1 million b/d, according to Energy Intelligence calculations (EC Jul.9,p5). With equity oil and domestic production, China now effectively controls some 6.4 million b/d of global oil production.
Tacit Understanding
Industry sources say there still is an understanding that, in a crisis, national interests will trump all commercial or other objectives. In the event that Mideast crude supply to China is interrupted, for example, state companies would be expected to send as much oil home as possible. This has already played out in other markets: Beijing put pressure on CNPC to increase natural gas supply this winter, which the company did at a loss. Similarly, refiners were compelled to suspend diesel exports during recent domestic shortages (EC Dec.3,p7).
In a global oil crisis, China's new strategic stockpile would be the first line of defense; this already has capacity of almost 250 million bbl and is due to hit 500 million-600 million bbl by 2020. There would also be limits on how much crude could easily be shipped back to China. Older refineries were built to run local [relatively] light, sweet grades Daqing [...], and only 30% of the country's [...] capacity can process sour grades. And companies may be constrained by contractual obligations to existing customers or the politics of the situation, Chatham House's John Mitchell wrote in a recent report (EC Jan.14,p10). Indeed, if the host country is involved in the crisis, equity oil investments could become "hostages" that limit the importer's foreign policy options "in exactly the way that energy security policy is supposed to avoid," Mitchell wrote.
Sudan, for one, provides large volumes of equity oil for the Chinese market, but also offers some of the highest risks of disruption, especially after the south's vote for independence (EC Jan.21,p6). CNPC has equity stakes of 40%-95% in the country's three largest production ventures, equivalent to about 205,000 b/d of Sudan's 475,000 b/d production. With marketing options limited by crude quality and US sanctions, some 253,000 b/d of Sudan's oil was exported to China last year. CNPC has built a special 200,000 b/d refinery at Qinzhou to process Dar and Nile Blend crudes.
At the other end of the spectrum is Ecuador, where China has again built a dominant position in export trade -- but takes hardly any oil back home. Andes Petroleum and PetroOriental, both partnerships of CNPC and Sinopec, produce a total of about 50,000 b/d. In addition, China is entitled to lift 96,000 b/d of state Petroecuador's crude under a two-year, $1 billion loan signed in mid-2009 (EC Aug.21'09,p5). Yet Chinese crude imports from Ecuador averaged just 16,300 barrels per day in 2010, down 55% on the previous year. Transportation costs are high, and Chinese refineries are not optimized for Ecuadorean grades.
Instead, the value of China's Ecuador presence has lain elsewhere, in providing a springboard for expansion in Latin America's oil industry and an avenue for PetroChina to develop an active global trading role, as the CNPC affiliate recreates itself as an international integrated company (EC Jan.14,p3). Virtually all of China's crude entitlement from Ecuador is sold on the open market, mainly to refineries in California, with PetroChina now the country's main lifter. PetroChina also swaps some supplies for crude more suited to China's refineries -- a twist demonstrating the increasing complexity and sophistication of China's energy security strategy.
Other overseas equity oil that doesn't make its way to China includes CNOOC's interests in Argentina and offshore Nigeria. [Read full]
(China agreed to loan Russian companies, Rosneft and Transneft $25 billlion to finance the East Siberia Pacific Ocean---ESPO---oil pipeline in exchange for 300,000 bbl/d of oil shipments---please see my post here. China is the world's second-largest consumer of oil behind the United States, and for the first time the second-largest net importer of oil in 2009---please see my post, including remarks, here. -- D.R.)
Thursday, February 24, 2011
EC Сoncerned over Economic Impact If Oil Stays over $100/b
Platts, Brussels, Feb 24, 2011
The European Union is not worried about the loss of Libyan oil supplies as it is importing alternative crude from producers such as Saudi Arabia, the European Commission's energy spokeswoman Marlene Holzner said Thursday.
"The EU imports 10% of its oil from Libya. Production has been stopped but the EU is receiving extra supplies from alternative suppliers, such as Saudi Arabia," Holzner told reporters in Brussels.
The head of Italian oil major Eni's Paolo Scaroni said Thursday he believes Libyan oil production has fallen by about 75% or 1.2 million b/d due to ongoing upheaval in recent days in the North African country.
Libya normally produces some 1.6 million b/d of oil and exports about 1.4 million b/d of the total, according to the International Energy Agency.
Brent oil prices jumped to almost $120/barrel early Thursday, hitting a 30-month high, as ongoing Libya instability stoked supply jitters across the Middle East and North Africa.
On the oil price, Holzner said the EU would only be concerned about negative economic impacts if higher oil prices if it remains [sic] over $100/b "for several months," or if it is particularly volatile over several months.
"We are concerned about rising oil prices because of what is happening in North Africa," [EC] Economic and Monetary Affairs spokesman Amadeu Altafaj Tardio said. "When we look at the inflation figures, we see that inflation has been rising and mainly due to the effects of increasing energy prices. The other components are quite stable, [but there is] no doubt that rising energy prices can have an adverse impact on inflation."
"The EC will present its interim economic forecast on March 1, so there will be more comments then and there is a press conference with [economic and monetary affairs] commissioner Rehn on Tuesday," Altafaj Tardio added.
European Union president Herman Van Rompuy early Thursday renewed his call for Libyan authorities to immediately "end the use of force" against protesters. [Full story]
(The International Energy Agency warned last month that sustained oil prices of US$100 a barrel pose a real risk to the world economy. "Were $100/bbl oil to become entrenched in 2011, that would risk pushing the [oil burden] figure through 5%," IEA said in its monthly Oil Market Report (OMR), released on January 18---please read about the oil burden, here. Please see Libya's oil and gas profile, here. -- D.R.)
The European Union is not worried about the loss of Libyan oil supplies as it is importing alternative crude from producers such as Saudi Arabia, the European Commission's energy spokeswoman Marlene Holzner said Thursday.
"The EU imports 10% of its oil from Libya. Production has been stopped but the EU is receiving extra supplies from alternative suppliers, such as Saudi Arabia," Holzner told reporters in Brussels.
The head of Italian oil major Eni's Paolo Scaroni said Thursday he believes Libyan oil production has fallen by about 75% or 1.2 million b/d due to ongoing upheaval in recent days in the North African country.
Libya normally produces some 1.6 million b/d of oil and exports about 1.4 million b/d of the total, according to the International Energy Agency.
Brent oil prices jumped to almost $120/barrel early Thursday, hitting a 30-month high, as ongoing Libya instability stoked supply jitters across the Middle East and North Africa.
On the oil price, Holzner said the EU would only be concerned about negative economic impacts if higher oil prices if it remains [sic] over $100/b "for several months," or if it is particularly volatile over several months.
"We are concerned about rising oil prices because of what is happening in North Africa," [EC] Economic and Monetary Affairs spokesman Amadeu Altafaj Tardio said. "When we look at the inflation figures, we see that inflation has been rising and mainly due to the effects of increasing energy prices. The other components are quite stable, [but there is] no doubt that rising energy prices can have an adverse impact on inflation."
"The EC will present its interim economic forecast on March 1, so there will be more comments then and there is a press conference with [economic and monetary affairs] commissioner Rehn on Tuesday," Altafaj Tardio added.
European Union president Herman Van Rompuy early Thursday renewed his call for Libyan authorities to immediately "end the use of force" against protesters. [Full story]
(The International Energy Agency warned last month that sustained oil prices of US$100 a barrel pose a real risk to the world economy. "Were $100/bbl oil to become entrenched in 2011, that would risk pushing the [oil burden] figure through 5%," IEA said in its monthly Oil Market Report (OMR), released on January 18---please read about the oil burden, here. Please see Libya's oil and gas profile, here. -- D.R.)
Saudi Arabia's Longest Well Drilled in Manifa
OffshoreEnergyToday.com Feb 23, 2011
The Manifa Drilling Team set a new record in December when it finished drilling the longest well in Saudi Arabia to a total depth of 32,136 ft (± 9.8 km) and completed a horizontal power water injector across the Lower Ratawi reservoir.
A [Canada's] Precision Drilling rig did the work on the Manifa well, [...]. The same drilling team set an earlier record while working on the 30,850 ft (+9.4 km) Manifa well.
Discovered in 1957, Manifa field is in shallow waters southeast of Tanajib, about 200 km northwest of Dhahran [please see map of oil and gas fields in Saudi Arabia, here -- D.R].
The [Saudi Aramco's] development strategy of Manifa is based on optimum use of onshore drilling. Instead of developing Manifa completely from offshore platforms, it is developed from 27 drilling islands connected by a 47-km long causeway, in addition to 16 onshore drill sites and 13 [offfshore] platforms. [Please see image below -- D.R.]
Source: OffshoreEnergyToday.com
Extended-reach wells, such as the two mentioned above are required for optimum field coverage. Read more
(During the May 2010 Offshore Technology Conference, Zuhair Al-Hussain, Aramco vice-president, drilling and workovers, said production from Manifa will start in mid-2013 but will not ramp up quickly to the original target of 900,000 b/d of Arab heavy oil (OGJ, May 10, 2010, p. 19). Also, please see my updated post on Manifa -- "Manifa to Yield 500,000 b/d by 2013 and 900,000 b/d by 2014 -- Aramco," here. Houston-based Parker Drilling, operator of the Yastreb Rig for Exxon Neftegas Limited, set world record for extended-reach drilling: Sakhalin's Odoptu OP-11 well reached a total measured depth of 40,502 feet (12,345 meters or 7.67 miles)---please see my post here. -- D.R.)
The Manifa Drilling Team set a new record in December when it finished drilling the longest well in Saudi Arabia to a total depth of 32,136 ft (± 9.8 km) and completed a horizontal power water injector across the Lower Ratawi reservoir.
A [Canada's] Precision Drilling rig did the work on the Manifa well, [...]. The same drilling team set an earlier record while working on the 30,850 ft (+9.4 km) Manifa well.
Discovered in 1957, Manifa field is in shallow waters southeast of Tanajib, about 200 km northwest of Dhahran [please see map of oil and gas fields in Saudi Arabia, here -- D.R].
The [Saudi Aramco's] development strategy of Manifa is based on optimum use of onshore drilling. Instead of developing Manifa completely from offshore platforms, it is developed from 27 drilling islands connected by a 47-km long causeway, in addition to 16 onshore drill sites and 13 [offfshore] platforms. [Please see image below -- D.R.]
Extended-reach wells, such as the two mentioned above are required for optimum field coverage. Read more
(During the May 2010 Offshore Technology Conference, Zuhair Al-Hussain, Aramco vice-president, drilling and workovers, said production from Manifa will start in mid-2013 but will not ramp up quickly to the original target of 900,000 b/d of Arab heavy oil (OGJ, May 10, 2010, p. 19). Also, please see my updated post on Manifa -- "Manifa to Yield 500,000 b/d by 2013 and 900,000 b/d by 2014 -- Aramco," here. Houston-based Parker Drilling, operator of the Yastreb Rig for Exxon Neftegas Limited, set world record for extended-reach drilling: Sakhalin's Odoptu OP-11 well reached a total measured depth of 40,502 feet (12,345 meters or 7.67 miles)---please see my post here. -- D.R.)
Tuesday, February 22, 2011
IEA Facts in Brief: Libya
IEA website, Feb 21, 2011
A look at the supply of oil and gas from the North African nation.
Libya is a net exporter of oil, having sent abroad some 1.49 million barrels per day (mb/d) in January 2011. Europe receives more than 85 percent of Libya’s crude exports, while about 13 percent heads east of Suez. Libya also produces some 15 bcm/y of gas, a third of which is domestically consumed. Roughly 45% of domestic electricity is generated by natural gas. In 2010, Libya exported 1.2 mb/d of crude oil to IEA countries, of which 376,000 b/d or more than 30% went to Italy. France, Germany and Spain are also significant buyers.
Click here to see the Facts on Libya: oil and gas
(Libya's proven oil reserves of 46.4 billion barrels, the biggest in Africa, are the ninth largest in the world, as of Jan 1, 2011---please see my post "World's Top 22 Oil Reserves Holders, Jan 1, 2011," here. However, with its proven natural gas reserves of 54.68 trillion cubic feet (tcf), Libya ranks only 22nd---using OGJ data---among the world's largest proven gas reserves holders, as of Jan 1, 2011---please see my post "World's Top 22 Natural Gas Proven Reserve Holders, Jan 1, 2011," here. For information on Libya's oil and gas, please see also Economist Intelligence Unit---EIU---"Libya Economy: Oil Trouble," Feb 22, 2011, here. -- D.R.)
A look at the supply of oil and gas from the North African nation.
Libya is a net exporter of oil, having sent abroad some 1.49 million barrels per day (mb/d) in January 2011. Europe receives more than 85 percent of Libya’s crude exports, while about 13 percent heads east of Suez. Libya also produces some 15 bcm/y of gas, a third of which is domestically consumed. Roughly 45% of domestic electricity is generated by natural gas. In 2010, Libya exported 1.2 mb/d of crude oil to IEA countries, of which 376,000 b/d or more than 30% went to Italy. France, Germany and Spain are also significant buyers.
Click here to see the Facts on Libya: oil and gas
(Libya's proven oil reserves of 46.4 billion barrels, the biggest in Africa, are the ninth largest in the world, as of Jan 1, 2011---please see my post "World's Top 22 Oil Reserves Holders, Jan 1, 2011," here. However, with its proven natural gas reserves of 54.68 trillion cubic feet (tcf), Libya ranks only 22nd---using OGJ data---among the world's largest proven gas reserves holders, as of Jan 1, 2011---please see my post "World's Top 22 Natural Gas Proven Reserve Holders, Jan 1, 2011," here. For information on Libya's oil and gas, please see also Economist Intelligence Unit---EIU---"Libya Economy: Oil Trouble," Feb 22, 2011, here. -- D.R.)
Monday, February 21, 2011
BP and Reliance Industries Announce Transformational Partnership in India
BP website, Feb 21, 2011
BP to take a 30 per cent stake in 23 oil and gas blocks.
Reliance Industries Limited and BP today announced a historic partnership between the two companies. Mr. Mukesh Ambani, Chairman and Managing Director of Reliance Industries Limited, and Mr. Robert Dudley, BP Group Chief Executive, signed the relationship framework and transactional agreements in London.
The partnership across the full value chain comprises BP taking a 30 per cent stake in 23 oil and gas production sharing contracts that Reliance operates in India, including the producing KG D6 block [see map below -- D.R.], and the formation of a 50:50 joint venture between the two companies for the sourcing and marketing of gas in India. The joint venture will also endeavor to accelerate the creation of infrastructure for receiving, transporting and marketing of natural gas in India.
Map of BP and Reliance Industries Deal Interests
Source: BP
The partnership will combine BP’s world-class deepwater exploration and development capabilities with Reliance’s project management and operations expertise.
Mukesh Ambani said: “We are delighted to partner with BP, one of the largest energy majors and one of the finest deep water exploration companies in the world. This partnership combines the skills of both companies and will be focused on finding more hydrocarbons in the deep water blocks of India and significantly contribute to India’s energy security.”
For BP, Reliance is a natural partner in India, given its strong position in the Indian market.
“This partnership meets BP’s strategy of forming alliances with strong national partners, taking material positions in significant hydrocarbon basins and increasing our exposure to growing energy markets,” said Mr. Carl-Henric Svanberg, Chairman of BP.
BP will pay Reliance Industries Limited an aggregate consideration of US$7.2 billion, and completion adjustments, for the interests to be acquired in the 23 production sharing contracts. Future performance payments of up to US$1.8 billion could be paid based on exploration success that results in development of commercial discoveries. These payments and combined investment could amount to US$20 billion.
BP’s confidence in India is evident from the fact that the transaction constitutes one of the largest foreign direct investments into India.
The 23 oil and gas blocks together cover approximately 270,000 square kilometers. This will make the partnership India’s largest private sector holder of exploration acreage.
So that the joint venture can capitalize on Reliance’s outstanding project management track record and operations expertise, Reliance will continue to be the operator under the production sharing contracts, whose blocks lie in water depths ranging from 400 to over 3,000 meters. These currently produce about 1.8 billion cubic feet of gas per day (bcf/d), over 30 per cent of India’s total consumption, and over 40 per cent of India’s total production.
“India is one of the fastest growing economies in the world. By allying ourselves with Reliance, we will access the most prolific gas basin in India and secure a place in the fast growing Indian gas markets, creating a genuinely distinctive BP position,” said Bob Dudley. “BP looks forward to a long and successful working partnership with Reliance.”
Completion of the transactions is subject to Indian regulatory approvals and other customary conditions. [Full story]
(BP has been working with Reliance since December 2008 on the D-17 deepwater block in the Krishna Godavari (KG) basin on the east coast of India---see map above. BP, with a 50 per cent interest, operates the block and Reliance holds the remaining interest. BP has a strong presence in India in addition to its interest in block D-17. Castrol India Limited is a market leader in the retail automotive lubricant business, including car engine oils, premium 4-stroke motorcycle oils and multi-grade diesel engine oils. Castrol India also operates in the industrial and marine lubricants markets. Tata BP Solar, a joint venture between BP Solar and the Tata Group, has been operating in India since 1989. It is a leader in the Indian solar energy market, manufacturing solar cells, solar PV modules and systems. Reliance Industries Limited (RIL) is India’s largest private sector company on all major financial parameters. RIL runs the world's largest refining complex at Jamnagar with two plants of combined capacity of 1.24 million barrels per day---please see my post "World's Largest Refineries," including notes, here. It has also been buying up shale gas assets in the United States and has interests in petrochemicals and retail, and is now looking at diversifying. According to BP’s Energy Outlook 2030, energy consumption in India has grown by 190% over the past 20 years and is likely to grow by 115% over the next 20 years, a rate of over 4% per annum. Gas is expected to be the fastest growing fossil fuel, with demand growing at a rate of nearly 5% a year between 2010 and 2030. India’s gas consumption was 5.0 bcf/d in 2009 and is estimated to have been 6.1 bcf/d in 2010 (comprising 4.9 bcf/d production plus 1.2 bcf/d LNG imports). Total Indian gas consumption is projected to grow to 12.5 bcf/d in 2025, and exceed 15 bcf/d in 2030. The Indian deal marks the second major deal under BP's new chief executive Bob Dudley. Last month, on January 14, BP and Rosneft announced a major strategic partnership that would include a share swap and the joint exploration of three blocks in the Russian Arctic---please see my post here. -- D.R.)
BP to take a 30 per cent stake in 23 oil and gas blocks.
Reliance Industries Limited and BP today announced a historic partnership between the two companies. Mr. Mukesh Ambani, Chairman and Managing Director of Reliance Industries Limited, and Mr. Robert Dudley, BP Group Chief Executive, signed the relationship framework and transactional agreements in London.
The partnership across the full value chain comprises BP taking a 30 per cent stake in 23 oil and gas production sharing contracts that Reliance operates in India, including the producing KG D6 block [see map below -- D.R.], and the formation of a 50:50 joint venture between the two companies for the sourcing and marketing of gas in India. The joint venture will also endeavor to accelerate the creation of infrastructure for receiving, transporting and marketing of natural gas in India.
Map of BP and Reliance Industries Deal Interests
The partnership will combine BP’s world-class deepwater exploration and development capabilities with Reliance’s project management and operations expertise.
Mukesh Ambani said: “We are delighted to partner with BP, one of the largest energy majors and one of the finest deep water exploration companies in the world. This partnership combines the skills of both companies and will be focused on finding more hydrocarbons in the deep water blocks of India and significantly contribute to India’s energy security.”
For BP, Reliance is a natural partner in India, given its strong position in the Indian market.
“This partnership meets BP’s strategy of forming alliances with strong national partners, taking material positions in significant hydrocarbon basins and increasing our exposure to growing energy markets,” said Mr. Carl-Henric Svanberg, Chairman of BP.
BP will pay Reliance Industries Limited an aggregate consideration of US$7.2 billion, and completion adjustments, for the interests to be acquired in the 23 production sharing contracts. Future performance payments of up to US$1.8 billion could be paid based on exploration success that results in development of commercial discoveries. These payments and combined investment could amount to US$20 billion.
BP’s confidence in India is evident from the fact that the transaction constitutes one of the largest foreign direct investments into India.
The 23 oil and gas blocks together cover approximately 270,000 square kilometers. This will make the partnership India’s largest private sector holder of exploration acreage.
So that the joint venture can capitalize on Reliance’s outstanding project management track record and operations expertise, Reliance will continue to be the operator under the production sharing contracts, whose blocks lie in water depths ranging from 400 to over 3,000 meters. These currently produce about 1.8 billion cubic feet of gas per day (bcf/d), over 30 per cent of India’s total consumption, and over 40 per cent of India’s total production.
“India is one of the fastest growing economies in the world. By allying ourselves with Reliance, we will access the most prolific gas basin in India and secure a place in the fast growing Indian gas markets, creating a genuinely distinctive BP position,” said Bob Dudley. “BP looks forward to a long and successful working partnership with Reliance.”
Completion of the transactions is subject to Indian regulatory approvals and other customary conditions. [Full story]
(BP has been working with Reliance since December 2008 on the D-17 deepwater block in the Krishna Godavari (KG) basin on the east coast of India---see map above. BP, with a 50 per cent interest, operates the block and Reliance holds the remaining interest. BP has a strong presence in India in addition to its interest in block D-17. Castrol India Limited is a market leader in the retail automotive lubricant business, including car engine oils, premium 4-stroke motorcycle oils and multi-grade diesel engine oils. Castrol India also operates in the industrial and marine lubricants markets. Tata BP Solar, a joint venture between BP Solar and the Tata Group, has been operating in India since 1989. It is a leader in the Indian solar energy market, manufacturing solar cells, solar PV modules and systems. Reliance Industries Limited (RIL) is India’s largest private sector company on all major financial parameters. RIL runs the world's largest refining complex at Jamnagar with two plants of combined capacity of 1.24 million barrels per day---please see my post "World's Largest Refineries," including notes, here. It has also been buying up shale gas assets in the United States and has interests in petrochemicals and retail, and is now looking at diversifying. According to BP’s Energy Outlook 2030, energy consumption in India has grown by 190% over the past 20 years and is likely to grow by 115% over the next 20 years, a rate of over 4% per annum. Gas is expected to be the fastest growing fossil fuel, with demand growing at a rate of nearly 5% a year between 2010 and 2030. India’s gas consumption was 5.0 bcf/d in 2009 and is estimated to have been 6.1 bcf/d in 2010 (comprising 4.9 bcf/d production plus 1.2 bcf/d LNG imports). Total Indian gas consumption is projected to grow to 12.5 bcf/d in 2025, and exceed 15 bcf/d in 2030. The Indian deal marks the second major deal under BP's new chief executive Bob Dudley. Last month, on January 14, BP and Rosneft announced a major strategic partnership that would include a share swap and the joint exploration of three blocks in the Russian Arctic---please see my post here. -- D.R.)
Sunday, February 13, 2011
World Watch [East African Oil & Gas]
by Peter Kemp, EI
East Africa is a hot frontier and a top investment story for 2011. The talk is of big gas finds offshore Mozambique and Tanzania, which is launching a new deepwater licensing round. BG Group is angling for blocks off Kenya, and explorers are excited by the first signs of elusive oil offshore as well. But landlocked Uganda, where the first oil in East Africa was discovered barely five years ago, is rattling investors. With reserve estimates at 2.5 billion barrels [please see below] and counting, the country's potential is huge. Yet exploration has stalled. Disputes have arisen over taxes, seized licenses and conflicting views on the pace and shape of development. ... The government [recently] outlined plans for a domestic refinery that it considers to be a higher priority and more profitable than crude oil exports. Unsurprisingly, incumbent explorers are dismayed that their export plans may not get the green light. As Tullow Oil's sunny optimism fades amid the endless discussions, the patience of the prospective incomers, Total and China's CNOOC, is also being put to the test.
(So far, one billion barrels of oil reserves have been confirmed in a quarter of the Albertine Graben of Uganda, a figure that is projected to reach 2.5 billion. Uganda is included in the OGJ's latest annual survey of world oil & gas reserves---see OGJ, Dec 6, 2010---for the first time with 1 billion bbl of proved oil reserves and 500 bcf of gas reserves. Britain's Tullow Oil PLC reports another 1.5 billion bbl in prospective resources in the East African nation in addition to these totals. Uganda does not yet have any oil or gas production. In contrast, new oil province in West African Ghana, being developed by Tullow and its partners, has already begun to bear fruit. 15 December 2010 celebrated the delivery of First Oil from the offshore Jubilee field---please see my post here. -- D.R.)
East Africa is a hot frontier and a top investment story for 2011. The talk is of big gas finds offshore Mozambique and Tanzania, which is launching a new deepwater licensing round. BG Group is angling for blocks off Kenya, and explorers are excited by the first signs of elusive oil offshore as well. But landlocked Uganda, where the first oil in East Africa was discovered barely five years ago, is rattling investors. With reserve estimates at 2.5 billion barrels [please see below] and counting, the country's potential is huge. Yet exploration has stalled. Disputes have arisen over taxes, seized licenses and conflicting views on the pace and shape of development. ... The government [recently] outlined plans for a domestic refinery that it considers to be a higher priority and more profitable than crude oil exports. Unsurprisingly, incumbent explorers are dismayed that their export plans may not get the green light. As Tullow Oil's sunny optimism fades amid the endless discussions, the patience of the prospective incomers, Total and China's CNOOC, is also being put to the test.
(So far, one billion barrels of oil reserves have been confirmed in a quarter of the Albertine Graben of Uganda, a figure that is projected to reach 2.5 billion. Uganda is included in the OGJ's latest annual survey of world oil & gas reserves---see OGJ, Dec 6, 2010---for the first time with 1 billion bbl of proved oil reserves and 500 bcf of gas reserves. Britain's Tullow Oil PLC reports another 1.5 billion bbl in prospective resources in the East African nation in addition to these totals. Uganda does not yet have any oil or gas production. In contrast, new oil province in West African Ghana, being developed by Tullow and its partners, has already begun to bear fruit. 15 December 2010 celebrated the delivery of First Oil from the offshore Jubilee field---please see my post here. -- D.R.)
Friday, February 11, 2011
Problems Slow Statoil's 2010-11 Production
by Paula Dittrick, OGJ, Feb 9, 2011
Statoil expects its 2011 production to be about the same as its 2010 level or slightly lower, which it attributed to production problems at several fields, including safety concerns at Gullfaks oil and gas field in the North Sea where Statoil has shut in 50 of the field’s 140 wells.
During 2010, Statoil’s total equity production was 1.8 million boe/d compared with 1.9 million boe/d for 2009. Fourth-quarter 2010 equity production was 1.9 million boe/d compared with about 2 million boe/d for the same period the previous year.
On Feb. 1, Statoil said it’s unclear when the 50 shut-in Gullfaks wells might be reopened. Statoil halted drilling last year in Gullfaks field to enable an additional review of drilling operations. Statoil said the review stemmed from a May 19, 2010, incident while drilling Well C-06 on the Gullfaks C platform.
Statoil later provided the Petroleum Safety Authority of Norway a report on its internal investigation after the incident (OGJ Online, Nov. 5, 2010).
On Dec. 12, Statoil shut down Kristin platform in the Norwegian Sea because workers detected higher-than-acceptable temperature outside an exhaust duct on a gas turbine during a routine inspection.
Kristin platform, a hub on the southwestern part of Halten Bank, produces gas, oil, and condensate from Kristin and Tyrihans fields (OGJ Online, Dec. 16, 2010).
Statoil reported fourth quarter 2010 net profit of 9.7 billion kroner, or 2.99 kroner/share, compared with 7.1 billion kroner, or 2.25 kroner/share, for the same period a year earlier. Higher earnings were attributed in part to higher oil and gas prices and higher volumes of gas sold.
"Production volumes were below our expectations in the second part of the year due to high maintenance, specific operational issues, and reduced production permits," Helge Lund, Statoil chief executive, said during a Feb. 9 earnings presentation in London.
Lund said Statoil expects a stable production outlook toward 2020 on the Norwegian Continental Shelf. “The NCS still has a large resource base with significant yet-to-find volumes,” he said.
Statoil is developing 13 fields expected to come on stream by 2012, and it expects companywide production to grow an average 3%/year through 2012.
Meanwhile, Statoil continues expanding its international exploration and production efforts. Statoil Canada Ltd. started bitumen production at Leismer steam-assisted gravity drainage demonstration project in the Athabasca oil sands region of northeast Alberta this year (OGJ Online, Jan. 27, 2011).
Statoil expects to start Peregrino heavy oil field off Brazil towards the end of first quarter. Peregrino is in 100 m of water. China’s Sinochem Group acquired a 40% interest in Peregrino in the Campos basin from Statoil for $3.07 billion (OGJ Online, May 21, 2010). Statoil owned 100% before the transaction. [Full story]
(See more about Statoil's operations in Brazil, here. With a holding of 67% the Norwegian state is the main shareholder in Statoil. Statoil has been ranked 27th in Platts 2010 top 250 global energy companies ranking---please see here. Also, it was ranked 19th in the recent PFC Energy top-50 ranking during 2010---please see here. Separately, Norway ranks 22nd among the world's top 22 proven oil reserves holders, as of Jan 1, 2011---please see the list here. -- D.R.)
Statoil expects its 2011 production to be about the same as its 2010 level or slightly lower, which it attributed to production problems at several fields, including safety concerns at Gullfaks oil and gas field in the North Sea where Statoil has shut in 50 of the field’s 140 wells.
During 2010, Statoil’s total equity production was 1.8 million boe/d compared with 1.9 million boe/d for 2009. Fourth-quarter 2010 equity production was 1.9 million boe/d compared with about 2 million boe/d for the same period the previous year.
On Feb. 1, Statoil said it’s unclear when the 50 shut-in Gullfaks wells might be reopened. Statoil halted drilling last year in Gullfaks field to enable an additional review of drilling operations. Statoil said the review stemmed from a May 19, 2010, incident while drilling Well C-06 on the Gullfaks C platform.
Statoil later provided the Petroleum Safety Authority of Norway a report on its internal investigation after the incident (OGJ Online, Nov. 5, 2010).
On Dec. 12, Statoil shut down Kristin platform in the Norwegian Sea because workers detected higher-than-acceptable temperature outside an exhaust duct on a gas turbine during a routine inspection.
Kristin platform, a hub on the southwestern part of Halten Bank, produces gas, oil, and condensate from Kristin and Tyrihans fields (OGJ Online, Dec. 16, 2010).
Statoil reported fourth quarter 2010 net profit of 9.7 billion kroner, or 2.99 kroner/share, compared with 7.1 billion kroner, or 2.25 kroner/share, for the same period a year earlier. Higher earnings were attributed in part to higher oil and gas prices and higher volumes of gas sold.
"Production volumes were below our expectations in the second part of the year due to high maintenance, specific operational issues, and reduced production permits," Helge Lund, Statoil chief executive, said during a Feb. 9 earnings presentation in London.
Lund said Statoil expects a stable production outlook toward 2020 on the Norwegian Continental Shelf. “The NCS still has a large resource base with significant yet-to-find volumes,” he said.
Statoil is developing 13 fields expected to come on stream by 2012, and it expects companywide production to grow an average 3%/year through 2012.
Meanwhile, Statoil continues expanding its international exploration and production efforts. Statoil Canada Ltd. started bitumen production at Leismer steam-assisted gravity drainage demonstration project in the Athabasca oil sands region of northeast Alberta this year (OGJ Online, Jan. 27, 2011).
Statoil expects to start Peregrino heavy oil field off Brazil towards the end of first quarter. Peregrino is in 100 m of water. China’s Sinochem Group acquired a 40% interest in Peregrino in the Campos basin from Statoil for $3.07 billion (OGJ Online, May 21, 2010). Statoil owned 100% before the transaction. [Full story]
(See more about Statoil's operations in Brazil, here. With a holding of 67% the Norwegian state is the main shareholder in Statoil. Statoil has been ranked 27th in Platts 2010 top 250 global energy companies ranking---please see here. Also, it was ranked 19th in the recent PFC Energy top-50 ranking during 2010---please see here. Separately, Norway ranks 22nd among the world's top 22 proven oil reserves holders, as of Jan 1, 2011---please see the list here. -- D.R.)
Sunday, February 6, 2011
Egypt Pipeline Explosion Cuts Gas Supply to Israel
by Christopher Helman, Forbes (blog), Feb 5, 2011
An explosion today [Feb 5] on the Arab Gas Pipeline [AGP] forced Egypt to shut off natural gas supplies to Israel and Jordan. [...] [Egyptian] Oil Minister Sameh Fahmy reportedly said it could take up to two weeks to repair the damage.
The pipeline is the third most strategically important piece of energy infrastructure in Egypt after the Suez Canal and the Sumed Pipeline. But it [its El Arish-Ashkelon branch] is the most important one to Israel, delivering 40% of Israeli natural gas supplies. [Total gas consumption in Israel stood at around 5.2 bcm in 2010, of which 2.1 bcm were imported from Egypt -- D.R.]. The Israeli government said this afternoon that it did not expect any interruption of electricity supplies as the country has gas in storage and can also switch to other fuels like [fuel] oil and diesel. Israel started receiving gas from the [El Arish-Ashkelon submarine] pipeline in 2008. [...]
One thing is for sure. Faced with insecure gas supplies from Egypt, Israel must now move with haste to develop the massive reserves of natural gas recently discovered offshore. You can read about them here (Leviathan Oil Field Could Supply Israel For Decades) and here (Israel Confirms Leviathan Gas Find). [Please read also my post here]. Read more
(The branch of the pipeline that carries natural gas into Israel wasn’t directly damaged in the incident, as the Sinai incident occurred on a part of the natural-gas network before it divides into branches serving Jordan, Syria and Lebanon, via Jordan, and Israel, via El Arish-Ashkelon branch. The blast occurred at around 7 a.m. (0500 GMT) on Saturday at a gas terminal, three km from the El Arish airport, North Sinai governor Abdel Wahab Mabrouk told reporters. He said the fire was brought under control by mid-morning, after valves allowing the flow of gas from the terminal into pipelines were shut off. Actually a fire and explosion at a gas metering station forced Egypt's gas transport company/Egyptian Natural Gas Company---GASCO---to cut off supplies to the Arab Gas Pipeline/AGP linking Egypt to Jordan, Syria, etc., as well as the pipeline supplying Egyptian gas to Israel. Egypt is an important gas producer of 64 bcm/y, of which some 45 bcm/y is consumed domestically and some 19 bcm/y is exported, mostly as LNG, according to the International Energy Agency. Gas demand has been increasing very fast over the past decade at 8%/year. Due to this growth, gas exports have been limited to one third of the reserve base. Liquefaction capacity stands at 16 bcm and exports averaged 14 bcm over 2007-09. The LNG produced in Egypt is going to Spain (4.3), U.S. (4.5), UK (0.5), South Korea (1.9) and France (1.4). Some 5 bcm/y is exported by pipeline, mostly to Jordan, Israel and Syria. Both Jordan and Israel’s power sectors are dependent on gas. See also my remarks here. Furthermore, Israel's Yam Thetis field---a major supplier of gas to Israel---off coastal Ashkelon was prepared to help compensate for the loss of Egyptian gas. The halt in Egyptian supplies also triggered a request for faster development of a floating LNG import terminal project. The planned location for the LNG import facility/floating platform/offshore LNG buoy is just off Israel's central Mediterranean coast at Hadera. For Egypt's East Mediterranean Gas Supply Corp, i.e. EMG, the gas exporting company via the 100-kilometer (62-mile) El Arish-Ashkelon submarine pipeline, please read my blog posts under the category/label "Israel." UPDATE: For the resumption of Egyptian gas supply to Israel, please see my post here. -- D.R.)
An explosion today [Feb 5] on the Arab Gas Pipeline [AGP] forced Egypt to shut off natural gas supplies to Israel and Jordan. [...] [Egyptian] Oil Minister Sameh Fahmy reportedly said it could take up to two weeks to repair the damage.
The pipeline is the third most strategically important piece of energy infrastructure in Egypt after the Suez Canal and the Sumed Pipeline. But it [its El Arish-Ashkelon branch] is the most important one to Israel, delivering 40% of Israeli natural gas supplies. [Total gas consumption in Israel stood at around 5.2 bcm in 2010, of which 2.1 bcm were imported from Egypt -- D.R.]. The Israeli government said this afternoon that it did not expect any interruption of electricity supplies as the country has gas in storage and can also switch to other fuels like [fuel] oil and diesel. Israel started receiving gas from the [El Arish-Ashkelon submarine] pipeline in 2008. [...]
One thing is for sure. Faced with insecure gas supplies from Egypt, Israel must now move with haste to develop the massive reserves of natural gas recently discovered offshore. You can read about them here (Leviathan Oil Field Could Supply Israel For Decades) and here (Israel Confirms Leviathan Gas Find). [Please read also my post here]. Read more
(The branch of the pipeline that carries natural gas into Israel wasn’t directly damaged in the incident, as the Sinai incident occurred on a part of the natural-gas network before it divides into branches serving Jordan, Syria and Lebanon, via Jordan, and Israel, via El Arish-Ashkelon branch. The blast occurred at around 7 a.m. (0500 GMT) on Saturday at a gas terminal, three km from the El Arish airport, North Sinai governor Abdel Wahab Mabrouk told reporters. He said the fire was brought under control by mid-morning, after valves allowing the flow of gas from the terminal into pipelines were shut off. Actually a fire and explosion at a gas metering station forced Egypt's gas transport company/Egyptian Natural Gas Company---GASCO---to cut off supplies to the Arab Gas Pipeline/AGP linking Egypt to Jordan, Syria, etc., as well as the pipeline supplying Egyptian gas to Israel. Egypt is an important gas producer of 64 bcm/y, of which some 45 bcm/y is consumed domestically and some 19 bcm/y is exported, mostly as LNG, according to the International Energy Agency. Gas demand has been increasing very fast over the past decade at 8%/year. Due to this growth, gas exports have been limited to one third of the reserve base. Liquefaction capacity stands at 16 bcm and exports averaged 14 bcm over 2007-09. The LNG produced in Egypt is going to Spain (4.3), U.S. (4.5), UK (0.5), South Korea (1.9) and France (1.4). Some 5 bcm/y is exported by pipeline, mostly to Jordan, Israel and Syria. Both Jordan and Israel’s power sectors are dependent on gas. See also my remarks here. Furthermore, Israel's Yam Thetis field---a major supplier of gas to Israel---off coastal Ashkelon was prepared to help compensate for the loss of Egyptian gas. The halt in Egyptian supplies also triggered a request for faster development of a floating LNG import terminal project. The planned location for the LNG import facility/floating platform/offshore LNG buoy is just off Israel's central Mediterranean coast at Hadera. For Egypt's East Mediterranean Gas Supply Corp, i.e. EMG, the gas exporting company via the 100-kilometer (62-mile) El Arish-Ashkelon submarine pipeline, please read my blog posts under the category/label "Israel." UPDATE: For the resumption of Egyptian gas supply to Israel, please see my post here. -- D.R.)
Friday, February 4, 2011
World Watch [PFC Energy 50 Ranking of World's Top Energy Companies, Jan 2011]
by Tom Haywood, Houston, EI
Exxon Mobil, with a market capitalization of $368.7 billion, is back at the top of the heap in the 2010 ranking of the world's largest publicly traded energy companies. But it's cold comfort for anyone hoping that the Western IOCs may be staging a comeback. The real story behind the annual survey by Washington-based consulting firm PFC Energy is that the Western majors are continuing to lose ground to non-Western rivals. China's PetroChina (no. 2) and Brazil's Petrobras (no. 3) have market capitalizations of $303 billion and $229 billion, respectively, and rounding out the non-Western top 10 are Russia's Gazprom (no. 6 at $149 billion) and China's CNOOC (no. 10 at $106 billion). The PFC top-10 includes the usual Western suspects -- Royal Dutch Shell [no. 4 at $207.9 billion], Chevron [no. 5 at $183.6 billion], BP [no. 7 at $136.4 billion], Total [no. 8 at $124.5 billion] and Schlumberger [no. 9 at $113.9 billion]. However, there is no getting around the fact that the Western majors owned 85% of the world's energy reserves in the late 1960s and own 15% today. [Full story]
(The PFC Energy 50 is the definitive ranking of the world's leading publicly traded energy companies by market capitalization. The listing includes companies from nine sectors: International Oil Companies; National Oil Companies; Exploration & Production; North America-Focused E&P, Refining & Marketing; Gas/Utilities; Oilfield & Drilling Services; Equipment, Engineering & Construction; and Alternative Energy. The full report is available at https://workspaces.acrobat.com/?d=4sFQLTPinFv*dy6goC6pRw. ExxonMobil, with market capitalization of $368.7 billion, regained the top position it has held on the PFC Energy 50 list in every year but 2007 and 2009. The XTO merger---see also my remarks here---and 7% share price growth combined to increase the company’s market capitalization by 14%. The 2009 leader PetroChina, a subsidiary of CNPC, closed the year 18% behind ExxonMobil, following a 14% decline in its market value. Petrobras, this year no. 3 at $228.9 billion, was no. 27 on the first PFC Energy 50 list in 1999; its market cap has grown from $13.5 billion – a 27% compound annual rate. The effect of the 23% 2010 share price decline was more than offset by a ~$67 billion new offering. North America is home to no fewer than 20 of the top 50 firms in the world: 14 U.S. firms and six Canadian firms. U.S. companies on the list include No.1 ExxonMobil; No. 5 Chevron; No. 9 Schlumberger; No. 12 ConocoPhillips; No. 16 Occidental; No. 27 Apache; No. 30 Anadarko; No. 32 Halliburton; No. 36 Devon; No. 42 Natl Oilwell Varco; No. 44 Marathon; No. 45 Hess; No. 47 Baker Hughes and No. 49 EOG Resources. Canada's companies on the list include No. 23 Suncor; No. 25 Canadian Natural; No. 34 Imperial Oil; No. 46 Cenovus; No. 48 Husky amd No. 50 Talisman. Oilfield service companies averaged the greatest value gains (+44%). Schlumberger (no. 9) achieved its highest rank since 2001. All three service companies on the list, Schlumberger, Halliburton and Baker Hughes benefitted from the robust U.S. market for hydraulic fracturing---see the PFC report. Also, please read the press release from PFC Energy, here. Update: Please see my post "PFC Energy 50 Ranking of World’s Top Energy Companies: SuperMajors, led by Chevron, Top 2011 Value Growth Performance." -- D.R.)
Exxon Mobil, with a market capitalization of $368.7 billion, is back at the top of the heap in the 2010 ranking of the world's largest publicly traded energy companies. But it's cold comfort for anyone hoping that the Western IOCs may be staging a comeback. The real story behind the annual survey by Washington-based consulting firm PFC Energy is that the Western majors are continuing to lose ground to non-Western rivals. China's PetroChina (no. 2) and Brazil's Petrobras (no. 3) have market capitalizations of $303 billion and $229 billion, respectively, and rounding out the non-Western top 10 are Russia's Gazprom (no. 6 at $149 billion) and China's CNOOC (no. 10 at $106 billion). The PFC top-10 includes the usual Western suspects -- Royal Dutch Shell [no. 4 at $207.9 billion], Chevron [no. 5 at $183.6 billion], BP [no. 7 at $136.4 billion], Total [no. 8 at $124.5 billion] and Schlumberger [no. 9 at $113.9 billion]. However, there is no getting around the fact that the Western majors owned 85% of the world's energy reserves in the late 1960s and own 15% today. [Full story]
(The PFC Energy 50 is the definitive ranking of the world's leading publicly traded energy companies by market capitalization. The listing includes companies from nine sectors: International Oil Companies; National Oil Companies; Exploration & Production; North America-Focused E&P, Refining & Marketing; Gas/Utilities; Oilfield & Drilling Services; Equipment, Engineering & Construction; and Alternative Energy. The full report is available at https://workspaces.acrobat.com/?d=4sFQLTPinFv*dy6goC6pRw. ExxonMobil, with market capitalization of $368.7 billion, regained the top position it has held on the PFC Energy 50 list in every year but 2007 and 2009. The XTO merger---see also my remarks here---and 7% share price growth combined to increase the company’s market capitalization by 14%. The 2009 leader PetroChina, a subsidiary of CNPC, closed the year 18% behind ExxonMobil, following a 14% decline in its market value. Petrobras, this year no. 3 at $228.9 billion, was no. 27 on the first PFC Energy 50 list in 1999; its market cap has grown from $13.5 billion – a 27% compound annual rate. The effect of the 23% 2010 share price decline was more than offset by a ~$67 billion new offering. North America is home to no fewer than 20 of the top 50 firms in the world: 14 U.S. firms and six Canadian firms. U.S. companies on the list include No.1 ExxonMobil; No. 5 Chevron; No. 9 Schlumberger; No. 12 ConocoPhillips; No. 16 Occidental; No. 27 Apache; No. 30 Anadarko; No. 32 Halliburton; No. 36 Devon; No. 42 Natl Oilwell Varco; No. 44 Marathon; No. 45 Hess; No. 47 Baker Hughes and No. 49 EOG Resources. Canada's companies on the list include No. 23 Suncor; No. 25 Canadian Natural; No. 34 Imperial Oil; No. 46 Cenovus; No. 48 Husky amd No. 50 Talisman. Oilfield service companies averaged the greatest value gains (+44%). Schlumberger (no. 9) achieved its highest rank since 2001. All three service companies on the list, Schlumberger, Halliburton and Baker Hughes benefitted from the robust U.S. market for hydraulic fracturing---see the PFC report. Also, please read the press release from PFC Energy, here. Update: Please see my post "PFC Energy 50 Ranking of World’s Top Energy Companies: SuperMajors, led by Chevron, Top 2011 Value Growth Performance." -- D.R.)
Subscribe to:
Posts (Atom)