by Paula Dittrick, OGJ Senior Staff Writer, OGJ, Jun 24, 2011
Unconventional oil production from the Bakken, Eagle Ford, and Niobrara plays is expected to approach 900,000 b/d in 2015 and exceed 1.3 million b/d by 2020, a consultant forecast.
Purvin & Gertz Inc. estimates current oil production from the Bakken, Eagle Ford, and Niobrara plays at 350,000-400,000 b/d.
The Bakken formation is in North Dakota and Montana, the Eagle Ford is in South Texas, and the Niobrara is in Colorado and Wyoming.
Geoff Houlton, a vice-president with Purvin & Gertz in Houston, told OGJ that shale oil production likely will help offset US oil import volumes in coming years.
Increasing supplies of light, sweet crude from shale oil plays are expected to reduce oil imports of similar quality crude into the Gulf Coast by greater than 500,000 b/d by 2016, he said.
Purvin & Gertz released its base-case forecast in a study entitled “US Midcontinent Crude Oil Market Analysis,” which examined oil logistics and pricing. [Read more]
(Current production from the Eagle Ford is roughly 100,000 barrels per day of crude oil and condensate >> OGJ, May 6, 2011 or EPP press release May 3, 2011. Also, please see my post "BENTEK: Eagle Ford Crude Oil Production Expected to Grow Fivefold in Five Years," here. For maps of the Eagle Ford shale, please see here. For the map of North American shale plays from the U.S. Energy Information Administration/EIA, including the United States, Canada and Mexico, as of May 9, 2011, please see here. Operators increased North Dakota's Bakken production from less than 3,000 barrels per day in 2005 to over 230,000 barrels per day in 2010. The Bakken's share of total North Dakota oil production rose from about 3 percent to about 75 percent over the same period. North Dakota produced an average of 307,000 barrels of crude oil per day in 2010 and comprised about 5.6 percent of the nation's total crude production. The increase in U.S. crude oil production in 2010 was led by escalating horizontal drilling programs in U.S. shale plays---please see my post "United States: Oil Production from Shale Formations, 2005-2010 -- EIA," here. UPDATE: In its Twitter post on June 25th, Platts said, "About 50,000 b/d of Bakken crude oil not being shipped out of N. Dakota due to record flooding in Minot area: state official." -- D.R.)
Showing posts with label Prices. Show all posts
Showing posts with label Prices. Show all posts
Saturday, June 25, 2011
Friday, June 24, 2011
World Watch [IEA Oil Release]
by Vincent Lauerman, New York, EI, Jun 23, 2011
International Energy Agency (IEA) Executive Director Nobuo Tanaka announced on Thursday [June 23] that the consumer organization's 28 member countries had agreed to release 60 million barrels of oil stocks – including 30 million bbl from the US Strategic Petroleum Reserve [SPR] – in the coming month. Tanaka was following up on his implicit threat in May to unlock the reserves if Opec did not agree to increase supplies at its failed Jun. 8 meeting. The IEA has released strategic stocks twice before [please see details below -- D.R.], but this release clearly breaks with historical precedent [also, according to Peter Kemp, the IEA's release of oil stocks marks a new turn in oil market intervention---please see "World Watch," EI, Jun 24, 2011 -- D.R.]. Although the IEA framed the release in terms of the ongoing supply disruption in Libya, market sources say there is no actual shortage of physical crude. The IEA is instead making a pre-emptive move, looking ahead to “the threat of a serious market tightening” in the second half of the year, at a time when “world economies are still recovering.” Economic growth has been weakening, especially in OECD countries such as the US [...]
(In its 37-year history the IEA has collectively agreed to release strategic petroleum stocks only twice before to fill lost supplies -- in 1991 at the outbreak of the first Gulf War following Iraq's invasion of Kuwait, and in 2005 after Hurricane Katrina damaged offshore oil rigs, pipelines and oil refineries in the Gulf of Mexico. Separately, please also see Petroleum Economist (PE) commentary -- The IEA's release of crude from strategic stocks is less about Libya than about the global economy - and it should send oil prices tumbling, says the editor of PE Derek Brower. Also, please see retweets by me on Twitter dated June 23, here. The IEA has been warning since the turn of the year of rising oil burden -- "Were $100/bbl oil to become entrenched in 2011, that would risk pushing the [oil burden] figure through 5%," IEA said---please see my post "IEA Warns of Rising Oil Burden." The price of crude, if sustained at $100 a barrel or more for the rest of 2011, would cause similar demand destruction as the world experienced in 2008 that led to the global economic crisis, Nobuo Tanaka, IEA executive director, said---please see The Telegraph, Apr 20, 2011. Please compare the above-mentioned analysis to the IEA's official position -- The use of IEA strategic stocks "is not about price but rather about ensuring an adequately supplied market to protect the world economy from unnecessary damage when it is in a fragile state." [?]---please see IEA: Key Questions answered on the release of oil stocks or more precisely "IEA collective action – June 23, 2011: FAQ." The SPR crude oil stocks are stored in underground salt caverns along the Gulf of Mexico Coast. Currently, there are a historically high 726.6 million barrels of crude oil in SPR, close to its 727.0 million barrel capacity. Historically, releases from the SPR have taken one of two forms, either an exchange, where oil provided in the release is then repaid within a specified time, or sales, where oil is auctioned off in a competitive bidding process. The United States has released crude oil from the SPR a number of times since 1985, according to the U.S. Department of Energy. The most recent release was the 5.4 million barrel exchange following Hurricanes Gustav and Ike in September 2008. To date, the largest release was a 30 million barrel exchange in the fall of 2000 in response to low heating oil supplies in the Northeast region of the United States---please see chart below and U.S. Energy Information Administration/EIA, Today in Energy, Jun 24, 2011, here. -- D.R.)
[Click on chart to enlarge]
International Energy Agency (IEA) Executive Director Nobuo Tanaka announced on Thursday [June 23] that the consumer organization's 28 member countries had agreed to release 60 million barrels of oil stocks – including 30 million bbl from the US Strategic Petroleum Reserve [SPR] – in the coming month. Tanaka was following up on his implicit threat in May to unlock the reserves if Opec did not agree to increase supplies at its failed Jun. 8 meeting. The IEA has released strategic stocks twice before [please see details below -- D.R.], but this release clearly breaks with historical precedent [also, according to Peter Kemp, the IEA's release of oil stocks marks a new turn in oil market intervention---please see "World Watch," EI, Jun 24, 2011 -- D.R.]. Although the IEA framed the release in terms of the ongoing supply disruption in Libya, market sources say there is no actual shortage of physical crude. The IEA is instead making a pre-emptive move, looking ahead to “the threat of a serious market tightening” in the second half of the year, at a time when “world economies are still recovering.” Economic growth has been weakening, especially in OECD countries such as the US [...]
(In its 37-year history the IEA has collectively agreed to release strategic petroleum stocks only twice before to fill lost supplies -- in 1991 at the outbreak of the first Gulf War following Iraq's invasion of Kuwait, and in 2005 after Hurricane Katrina damaged offshore oil rigs, pipelines and oil refineries in the Gulf of Mexico. Separately, please also see Petroleum Economist (PE) commentary -- The IEA's release of crude from strategic stocks is less about Libya than about the global economy - and it should send oil prices tumbling, says the editor of PE Derek Brower. Also, please see retweets by me on Twitter dated June 23, here. The IEA has been warning since the turn of the year of rising oil burden -- "Were $100/bbl oil to become entrenched in 2011, that would risk pushing the [oil burden] figure through 5%," IEA said---please see my post "IEA Warns of Rising Oil Burden." The price of crude, if sustained at $100 a barrel or more for the rest of 2011, would cause similar demand destruction as the world experienced in 2008 that led to the global economic crisis, Nobuo Tanaka, IEA executive director, said---please see The Telegraph, Apr 20, 2011. Please compare the above-mentioned analysis to the IEA's official position -- The use of IEA strategic stocks "is not about price but rather about ensuring an adequately supplied market to protect the world economy from unnecessary damage when it is in a fragile state." [?]---please see IEA: Key Questions answered on the release of oil stocks or more precisely "IEA collective action – June 23, 2011: FAQ." The SPR crude oil stocks are stored in underground salt caverns along the Gulf of Mexico Coast. Currently, there are a historically high 726.6 million barrels of crude oil in SPR, close to its 727.0 million barrel capacity. Historically, releases from the SPR have taken one of two forms, either an exchange, where oil provided in the release is then repaid within a specified time, or sales, where oil is auctioned off in a competitive bidding process. The United States has released crude oil from the SPR a number of times since 1985, according to the U.S. Department of Energy. The most recent release was the 5.4 million barrel exchange following Hurricanes Gustav and Ike in September 2008. To date, the largest release was a 30 million barrel exchange in the fall of 2000 in response to low heating oil supplies in the Northeast region of the United States---please see chart below and U.S. Energy Information Administration/EIA, Today in Energy, Jun 24, 2011, here. -- D.R.)
[Click on chart to enlarge]
Tuesday, June 14, 2011
[...] US Ambassador [to Canada] Backs Increased Canadian Oil-Sands Imports
Petroleum Economist, June 9, 2011
The US government considers Canadian oil supplies an essential ingredient of energy security, even as competition for resources and assets ratchets up with rival China.
Speaking in Calgary, US ambassador to Canada David Jacobson described his country's need for greater imports from stable sources such as Canada to offset dependence on unstable regimes in the Middle East and North Africa. "The US sees Canada as a pillar of our energy security," he said.
It is already the largest energy-trading relationship in history, with Canada accounting for about 22% of US import demand [please see my post "U.S. Crude Oil Imports from Top 15 Countries, Dec 2010 and Full Year 2010," -- Canada supplied about 22% of total US crude oil imports in 2010, i.e., 1.97 million b/d of crude/please also see chart below, out of a total US imports of crude of 9.16 million b/d, as well as about 22% of total US crude oil and products imports in 2010, i.e., 2.532 million barrels per day---1.97 million b/d of crude oil plus 0.56 million b/d of petroleum products---out of a total US imports of crude and products of 11.753 million b/d -- D.R.). Alberta alone pumps about 1.4 million b/d to US refineries or 7% of overall US consumption [U.S. oil consumption increased by some 380,000 b/d or 2.0% to 19.148 million b/d in 2010, compared to the previous year---please see my post "Top 25 World Oil Consumers, 2009-2010." Separately, of the estimated 2.9 million b/d, sic, of crude oil produced in Canada in 2010, 1.5 million b/d of that was derived from the oil sands of Alberta---please see EIA. -- D.R.].
Canada long ago surpassed Saudi Arabia as the top supplier to the world's largest oil consumer and that relationship is poised to grow exponentially as Canadian producers increase production of oil-sands crude.
Canadian exports to the US have more than doubled since 1993 [US imports from Canada of crude oil increased from 900,000 b/d in 1993 to 1,972,000 b/d in 2010, and US imports from Canada of crude oil and petroleum products increased from 1,181,000 b/d in 1993 to 2,532,000 b/d in 2010 -- D.R.] and are set to double and quadruple over the next two decades.
According to IHS Cera, Canadian oil sands could supply 6.3 million b/d by 2035, not including any other conventional and unconventional production that would push the figure past 7 million b/d. Only Russia and Saudi Arabia would have larger output, IHC Cera added, vaulting Canada into the top tier of oil-producing nations. [...]
But that looming reality seems lost on US President Barack Obama, who has seemed to be reluctant to fully embrace the oil sands even as he has talked of the need to reduce imports from unstable and hostile regimes.
A series of nagging doubts have led some Canadian observers to question the president's energy priorities. For instance, the State Department has held up approvals for TransCanada's Keystone XL pipeline to the Gulf coast [where there are more refineries capable of handling the unusually thick crude, i.e. the heavy, high-sulphur bitumen, and please see map below -- D.R.] while it carries out environmental assessments of the carbon intensity of Canadian oil sands and heavy crude in a move seen as bowing to environmental groups. [...]
[Click on map to enlarge]
Source: PE, here.
Fearing the worst from Obama's climate-change and clean-energy initiatives, the Canadian and Alberta governments have lobbied against the adoption of clean-fuel standards and other environmental policies they claim would discriminate against Canada. [...]
Feeling snubbed by this seeming US indifference, Canada has been courting Asia, and particularly the Chinese, as an alternate buyer of its growing output.
China consumes less than half as much oil as the US [please see my posts "Top 25 World Oil Consumers, 2009-2010 -- EIA." and "Top 21 World Oil Consumers, 2007-2010 -- BP," -- D.R.], but will overtake it in a matter of decades, said Wenran Jiang of the University of Alberta's China Institute [According to the BP Energy Outlook 2030, China is the largest source of oil consumption growth, with consumption forecast to grow by 8 million b/d a day to reach 17.5 million b/d by 2030, overtaking the US to become the world's largest oil consumer -- D.R.]. And like the US, China considers Canadian energy supplies to be vital to its security and economic growth.
About 80% of China's imports must pass through the Malacca Strait and its is keen to diversify supply chains away from vulnerable shipping lanes in Southeast Asia. [Also, please see my post "What is Beijing Willing to Do to Secure Oil and Gas Supplies?" and my post "China: Taking Oil Home," -- D.R.] [...]
While the US dithers over whether to embrace "dirty oil" [please see remarks below -- D.R.] from Canada, Chinese state-owned entities have been on a shopping spree, snapping up C$20 billion ($19.8 billion [sic]) worth of assets in less than two years and forming operating partnerships with Canadian firms for both oil sands and unconventional shale gas.
There is presently no way of shipping that oil to China, but there is a growing call in Canada to do just that.
Enbridge's proposed Northern Gateway pipeline to Canada's west coast is seen as a way of opening up overseas markets and gaining higher world oil prices. [Read more]
Source: U.S. Energy Information Administration (EIA), Today in Energy, Jun 14, 2011, here.
(Canadian oil producers have been clamoring for an outlet for their oil to reach the Gulf Coast, reliving a glut that's accumulated in Cushing, Oklahoma, where several pipeline routes terminate --- the delivery point for the West Texas Intermediate benchmark. The large amount of oil stranded in Cushing has led to a deep discount in crude-oil prices in the region and on the New York Mercantile Exchange. In March, the U.S. State Department delayed approval of the 1.1-million-barrel-a-day TransCanada Corp. Keystone XL pipeline expansion that would bring Canadian oil to the Gulf of Mexico. Environmental groups have raised objections about the possibility of oil spills. Alberta Energy Minister Ron Liepert called for the U.S. State Department to quickly approve the extension of a controversial oil pipeline to the U.S., adding that Canada has other potential customers for its oil. Canada is the biggest supplier of foreign oil to the U.S. but Minister Liepert said Canada is "actively cultivating" relationships with China and other emerging markets, where energy demand is growing rapidly---please see MarketWatch, May 16, 2011. In regard to environmental concerns surrounding oil sands production, Minister Liepert states, “We have been a leader in terms of initiatives around the environment. We have made significant advancement in tailings [Tailings are a mixture of fine clay, silt, sand, water and residual bitumen produced through oil sands extraction -- D.R.] management. Tailings are associated only with the mining operations, which is less than 50 per cent of the oil sands production now and continues to decline as a percentage of production.” He continues, “We have a 15 dollar per ton carbon tax, and most of the large operations in the oil sands fall under that. The tax goes into a clean energy fund. Alberta only has a population of 3.5 million people, but has invested $2 billion—probably the largest of any jurisdiction in the world—into carbon capture and storage.”---please see Energy Digital, Jun 14, 2011. -- D.R.)
The US government considers Canadian oil supplies an essential ingredient of energy security, even as competition for resources and assets ratchets up with rival China.
Speaking in Calgary, US ambassador to Canada David Jacobson described his country's need for greater imports from stable sources such as Canada to offset dependence on unstable regimes in the Middle East and North Africa. "The US sees Canada as a pillar of our energy security," he said.
It is already the largest energy-trading relationship in history, with Canada accounting for about 22% of US import demand [please see my post "U.S. Crude Oil Imports from Top 15 Countries, Dec 2010 and Full Year 2010," -- Canada supplied about 22% of total US crude oil imports in 2010, i.e., 1.97 million b/d of crude/please also see chart below, out of a total US imports of crude of 9.16 million b/d, as well as about 22% of total US crude oil and products imports in 2010, i.e., 2.532 million barrels per day---1.97 million b/d of crude oil plus 0.56 million b/d of petroleum products---out of a total US imports of crude and products of 11.753 million b/d -- D.R.). Alberta alone pumps about 1.4 million b/d to US refineries or 7% of overall US consumption [U.S. oil consumption increased by some 380,000 b/d or 2.0% to 19.148 million b/d in 2010, compared to the previous year---please see my post "Top 25 World Oil Consumers, 2009-2010." Separately, of the estimated 2.9 million b/d, sic, of crude oil produced in Canada in 2010, 1.5 million b/d of that was derived from the oil sands of Alberta---please see EIA. -- D.R.].
Canada long ago surpassed Saudi Arabia as the top supplier to the world's largest oil consumer and that relationship is poised to grow exponentially as Canadian producers increase production of oil-sands crude.
Canadian exports to the US have more than doubled since 1993 [US imports from Canada of crude oil increased from 900,000 b/d in 1993 to 1,972,000 b/d in 2010, and US imports from Canada of crude oil and petroleum products increased from 1,181,000 b/d in 1993 to 2,532,000 b/d in 2010 -- D.R.] and are set to double and quadruple over the next two decades.
According to IHS Cera, Canadian oil sands could supply 6.3 million b/d by 2035, not including any other conventional and unconventional production that would push the figure past 7 million b/d. Only Russia and Saudi Arabia would have larger output, IHC Cera added, vaulting Canada into the top tier of oil-producing nations. [...]
But that looming reality seems lost on US President Barack Obama, who has seemed to be reluctant to fully embrace the oil sands even as he has talked of the need to reduce imports from unstable and hostile regimes.
A series of nagging doubts have led some Canadian observers to question the president's energy priorities. For instance, the State Department has held up approvals for TransCanada's Keystone XL pipeline to the Gulf coast [where there are more refineries capable of handling the unusually thick crude, i.e. the heavy, high-sulphur bitumen, and please see map below -- D.R.] while it carries out environmental assessments of the carbon intensity of Canadian oil sands and heavy crude in a move seen as bowing to environmental groups. [...]
[Click on map to enlarge]
Fearing the worst from Obama's climate-change and clean-energy initiatives, the Canadian and Alberta governments have lobbied against the adoption of clean-fuel standards and other environmental policies they claim would discriminate against Canada. [...]
Feeling snubbed by this seeming US indifference, Canada has been courting Asia, and particularly the Chinese, as an alternate buyer of its growing output.
China consumes less than half as much oil as the US [please see my posts "Top 25 World Oil Consumers, 2009-2010 -- EIA." and "Top 21 World Oil Consumers, 2007-2010 -- BP," -- D.R.], but will overtake it in a matter of decades, said Wenran Jiang of the University of Alberta's China Institute [According to the BP Energy Outlook 2030, China is the largest source of oil consumption growth, with consumption forecast to grow by 8 million b/d a day to reach 17.5 million b/d by 2030, overtaking the US to become the world's largest oil consumer -- D.R.]. And like the US, China considers Canadian energy supplies to be vital to its security and economic growth.
About 80% of China's imports must pass through the Malacca Strait and its is keen to diversify supply chains away from vulnerable shipping lanes in Southeast Asia. [Also, please see my post "What is Beijing Willing to Do to Secure Oil and Gas Supplies?" and my post "China: Taking Oil Home," -- D.R.] [...]
While the US dithers over whether to embrace "dirty oil" [please see remarks below -- D.R.] from Canada, Chinese state-owned entities have been on a shopping spree, snapping up C$20 billion ($19.8 billion [sic]) worth of assets in less than two years and forming operating partnerships with Canadian firms for both oil sands and unconventional shale gas.
There is presently no way of shipping that oil to China, but there is a growing call in Canada to do just that.
Enbridge's proposed Northern Gateway pipeline to Canada's west coast is seen as a way of opening up overseas markets and gaining higher world oil prices. [Read more]
(Canadian oil producers have been clamoring for an outlet for their oil to reach the Gulf Coast, reliving a glut that's accumulated in Cushing, Oklahoma, where several pipeline routes terminate --- the delivery point for the West Texas Intermediate benchmark. The large amount of oil stranded in Cushing has led to a deep discount in crude-oil prices in the region and on the New York Mercantile Exchange. In March, the U.S. State Department delayed approval of the 1.1-million-barrel-a-day TransCanada Corp. Keystone XL pipeline expansion that would bring Canadian oil to the Gulf of Mexico. Environmental groups have raised objections about the possibility of oil spills. Alberta Energy Minister Ron Liepert called for the U.S. State Department to quickly approve the extension of a controversial oil pipeline to the U.S., adding that Canada has other potential customers for its oil. Canada is the biggest supplier of foreign oil to the U.S. but Minister Liepert said Canada is "actively cultivating" relationships with China and other emerging markets, where energy demand is growing rapidly---please see MarketWatch, May 16, 2011. In regard to environmental concerns surrounding oil sands production, Minister Liepert states, “We have been a leader in terms of initiatives around the environment. We have made significant advancement in tailings [Tailings are a mixture of fine clay, silt, sand, water and residual bitumen produced through oil sands extraction -- D.R.] management. Tailings are associated only with the mining operations, which is less than 50 per cent of the oil sands production now and continues to decline as a percentage of production.” He continues, “We have a 15 dollar per ton carbon tax, and most of the large operations in the oil sands fall under that. The tax goes into a clean energy fund. Alberta only has a population of 3.5 million people, but has invested $2 billion—probably the largest of any jurisdiction in the world—into carbon capture and storage.”---please see Energy Digital, Jun 14, 2011. -- D.R.)
Monday, June 6, 2011
Indonesia to Fall Short of 2011 Oil Output Target - BPMigas
Platts, May 25, 2011
Indonesia's crude and condensate production this year will likely average between 933,000 b/d and 945,000 b/d, below its target of 970,000 b/d as a result of unplanned shutdowns, the chairman of upstream regulator BPMigas said Tuesday [please see remarks below -- D.R.].
"The average production this year is expected [to] reach 933,000 b/d in minimum or 945,000 b/d in maximum," R. Priyono said in a parliamentary hearing. [...]
Gas production is now expected to average 7.808 Bcf/d, exceeding its target this year of 7.769 Bcf/d, Priyono said. [...]
The country's oil and gas revenue in 2011 is now seen reaching $31.088 billion, well above the target of $26.554 billion, as crude and gas prices are expected to be higher than previously forecast. [...]
Indonesia's crude and condensate output has been steadily sliding for at least the last decade [also, please see my post "Top 8 Oil Producers in Asia & Oceania, 2006-2010," and please see remarks below -- D.R.] because of natural declines at aging fields. But the government hopes to be able to produce 1 million b/d of crude and condensate by 2013.
The country failed to achieve its 2010 crude target of 965,000 b/d, pumping only 947,000 b/d. However the country exceeded last year's gas production by 17.4% to 8.88 Bcf/d from a target of 7.56 Bcf/d [sic; target - 7.758 Bcf/d? -- D.R]. [Read full]
(According to BPMigas data, Indonesia's oil production was only 916,000 barrels per day as of the end of April 2011---please see The Jakarta Post, June 3, 2011, here. Indonesia's crude oil production has been declining since 1997, due to the maturation of the country's largest oil fields and failure to develop new, comparable resources. In 1996 it produced 1,547,486 barrels of crude oil including lease condensate per day---please see EIA's data, here. Indonesia was a member of the Organization of Petroleum Exporting Countries/OPEC from 1962 to 2008. In 2004, the country became a net oil importer and in January 2009, suspended its OPEC membership. BPMigas and the Indonesian government have introduced policies aimed at increasing investment in the country's upstream sector - in particular via investment incentives and improving the flexibility of the production sharing contracts/PSC bidding process---read more U.S. EIA, Indonesia Country Analysis Brief, May 2011, here. According to the Oil & Gas Journal's Jan 1, 2011 estimate, Indonesia's proved oil reserves stand at 3.99 billion barrels. Indonesia was the third-largest exporter of liquefied natural gas/LNG in the world in 2009, following only Qatar and Malaysia. And in 2010, it was Japan's third-largest LNG supplier, after Malaysia and Australia---please see charts, here -- D.R.)
Indonesia's crude and condensate production this year will likely average between 933,000 b/d and 945,000 b/d, below its target of 970,000 b/d as a result of unplanned shutdowns, the chairman of upstream regulator BPMigas said Tuesday [please see remarks below -- D.R.].
"The average production this year is expected [to] reach 933,000 b/d in minimum or 945,000 b/d in maximum," R. Priyono said in a parliamentary hearing. [...]
Gas production is now expected to average 7.808 Bcf/d, exceeding its target this year of 7.769 Bcf/d, Priyono said. [...]
The country's oil and gas revenue in 2011 is now seen reaching $31.088 billion, well above the target of $26.554 billion, as crude and gas prices are expected to be higher than previously forecast. [...]
Indonesia's crude and condensate output has been steadily sliding for at least the last decade [also, please see my post "Top 8 Oil Producers in Asia & Oceania, 2006-2010," and please see remarks below -- D.R.] because of natural declines at aging fields. But the government hopes to be able to produce 1 million b/d of crude and condensate by 2013.
The country failed to achieve its 2010 crude target of 965,000 b/d, pumping only 947,000 b/d. However the country exceeded last year's gas production by 17.4% to 8.88 Bcf/d from a target of 7.56 Bcf/d [sic; target - 7.758 Bcf/d? -- D.R]. [Read full]
(According to BPMigas data, Indonesia's oil production was only 916,000 barrels per day as of the end of April 2011---please see The Jakarta Post, June 3, 2011, here. Indonesia's crude oil production has been declining since 1997, due to the maturation of the country's largest oil fields and failure to develop new, comparable resources. In 1996 it produced 1,547,486 barrels of crude oil including lease condensate per day---please see EIA's data, here. Indonesia was a member of the Organization of Petroleum Exporting Countries/OPEC from 1962 to 2008. In 2004, the country became a net oil importer and in January 2009, suspended its OPEC membership. BPMigas and the Indonesian government have introduced policies aimed at increasing investment in the country's upstream sector - in particular via investment incentives and improving the flexibility of the production sharing contracts/PSC bidding process---read more U.S. EIA, Indonesia Country Analysis Brief, May 2011, here. According to the Oil & Gas Journal's Jan 1, 2011 estimate, Indonesia's proved oil reserves stand at 3.99 billion barrels. Indonesia was the third-largest exporter of liquefied natural gas/LNG in the world in 2009, following only Qatar and Malaysia. And in 2010, it was Japan's third-largest LNG supplier, after Malaysia and Australia---please see charts, here -- D.R.)
Saturday, June 4, 2011
Shale Gas Revolution -- Shale Can Support [U.S.] LNG Exports: Chesapeake
Platts, May 26, 2011
Shale gas pioneer Chesapeake Energy is confident unconventional gas plays would support proposed US LNG export projects, and believes the US could produce more than 90 Bcf/d of gas at prices are "not that high," a company executive said Wednesday.
"We have a very strong mandate from our CEO to export (LNG from the US)," Bill Wince, vice president of transportation and business development at Chesapeake, said during a panel presentation at CWC’s Americas LNG Summit here. [...]
Chesapeake last year signed a preliminary agreement to supply as much as 500,000 Mcf/d to Cheniere Energy’s proposed LNG export project in Louisiana, which aims to start exporting in 2015. Chesapeake is also talking to the proposed LNG export project in Freeport, Texas, Wince told Platts on the sidelines of the conference, declining to comment on the relative merits of the two proposals.
Current US production stands at 64-65 Bcf/d, Wince said during his presentation. [Also, please see my post "Natural Gas Production/Consumption Retrospective 2010." -- D.R] [...]
The Marcellus play needs a price of only $2.45/Mcf to provide a 10% rate of return, according to a slide he [Wince] presented. The Haynesville play needs a $4.25/Mcf price to provide the same rate of return, while the Fayetteville play needs a price of $4.70/Mcf and the Barnett play needs a price of $5.05/Mcf, the slide showed. [...]
Current production from four major shale areas is 15 Bcf/d, he said, adding that the advent of low US gas prices in recent years coincided with shale production gains. [...]
US shale production is greatly reducing basis differentials in the US market, which historically have been caused by transportation costs between producing and consuming regions, Wince said.
"We crush the basis,” he said about Chesapeake, which ranks as the country’s second-largest gas producer [after ExxonMobil -- D.R.], producing 2.7 Bcf/d in the first quarter. [...]
A significant amount of LNG import infrastructure was built last decade before the shale boom was well understood, as industry players expected LNG to make up for projected decreases in domestic gas production.
Shale gas crowds out Yemen LNG
Yemen LNG was primarily designed to sell significant LNG volumes to the US, but "the market disappeared,” Jean-Pierre Cave, head of commercial and shipping at Yemen LNG, said at the conference. [...]
Based on last week’s ruling [May 20] by the US Department of Energy authorizing Cheniere to export US-produced LNG from Sabine Pass [please see my post "Cheniere Gets OK to Ship LNG Overseas," -- D.R.], Bill Cooper, president of the Center for LNG industry group, said he expects other proposed US export projects to get similar approval. [...] [Read full]
(According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010. In 2010, U.S. shale gas production constituted 23 percent of total U.S. natural gas production---please see here. In 2009, the U.S., with its big shale gas resources, even surpassed Russia as the world's largest natural gas producer---please see EIA's data, here. -- D.R.)
Shale gas pioneer Chesapeake Energy is confident unconventional gas plays would support proposed US LNG export projects, and believes the US could produce more than 90 Bcf/d of gas at prices are "not that high," a company executive said Wednesday.
"We have a very strong mandate from our CEO to export (LNG from the US)," Bill Wince, vice president of transportation and business development at Chesapeake, said during a panel presentation at CWC’s Americas LNG Summit here. [...]
Chesapeake last year signed a preliminary agreement to supply as much as 500,000 Mcf/d to Cheniere Energy’s proposed LNG export project in Louisiana, which aims to start exporting in 2015. Chesapeake is also talking to the proposed LNG export project in Freeport, Texas, Wince told Platts on the sidelines of the conference, declining to comment on the relative merits of the two proposals.
Current US production stands at 64-65 Bcf/d, Wince said during his presentation. [Also, please see my post "Natural Gas Production/Consumption Retrospective 2010." -- D.R] [...]
The Marcellus play needs a price of only $2.45/Mcf to provide a 10% rate of return, according to a slide he [Wince] presented. The Haynesville play needs a $4.25/Mcf price to provide the same rate of return, while the Fayetteville play needs a price of $4.70/Mcf and the Barnett play needs a price of $5.05/Mcf, the slide showed. [...]
Current production from four major shale areas is 15 Bcf/d, he said, adding that the advent of low US gas prices in recent years coincided with shale production gains. [...]
US shale production is greatly reducing basis differentials in the US market, which historically have been caused by transportation costs between producing and consuming regions, Wince said.
"We crush the basis,” he said about Chesapeake, which ranks as the country’s second-largest gas producer [after ExxonMobil -- D.R.], producing 2.7 Bcf/d in the first quarter. [...]
A significant amount of LNG import infrastructure was built last decade before the shale boom was well understood, as industry players expected LNG to make up for projected decreases in domestic gas production.
Shale gas crowds out Yemen LNG
Yemen LNG was primarily designed to sell significant LNG volumes to the US, but "the market disappeared,” Jean-Pierre Cave, head of commercial and shipping at Yemen LNG, said at the conference. [...]
Based on last week’s ruling [May 20] by the US Department of Energy authorizing Cheniere to export US-produced LNG from Sabine Pass [please see my post "Cheniere Gets OK to Ship LNG Overseas," -- D.R.], Bill Cooper, president of the Center for LNG industry group, said he expects other proposed US export projects to get similar approval. [...] [Read full]
(According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010. In 2010, U.S. shale gas production constituted 23 percent of total U.S. natural gas production---please see here. In 2009, the U.S., with its big shale gas resources, even surpassed Russia as the world's largest natural gas producer---please see EIA's data, here. -- D.R.)
Monday, May 16, 2011
Saturday, May 14, 2011
North Dakota Oil Tax Revenue Breaks $100M Mark in March as Industry Booms
by Judson Berger, Fox News, May 9, 2011
North Dakota's booming oil industry has yielded record tax revenue for the state, breaking the $100 million mark in March at a time when other states are struggling to stay afloat.
The state in just the last few years has become an oil-producing powerhouse and is looking to overtake California in total production. [...]
Much of the recent increase is due to rising crude prices, which have shot up amid concerns over unrest in the Middle East. But North Dakota's oil production is also accelerating rapidly, and state officials expect the windfall to hold steady. [...]
The 350,000 barrels a day produced in March was actually about 2,000 barrels a day lower than in February. But [state Deputy Tax Commissioner Ryan] Rauschenberger attributed the dip to the weather, and said that even if crude prices return to prior levels the state expects to take in $2 billion in oil-related tax revenue over the next two years. [...]
Amid a debate on Capitol Hill over whether the U.S. needs to do more to encourage domestic oil production, North Dakota is charging ahead with expansion. The state industry was helped in no small part by efforts over the past several years to tap into a massive oil field known as the Bakken Shale deposit, where virtually all future expansion is happening [please see remarks below -- D.R.].
Production is expected to grow "substantially," Ron Ness, president of the North Dakota Petroleum Council, said. With 5,300 wells across the state and thousands more expected to come online, Ness projected that the state could reach up to 700,000 barrels a day by 2015.
North Dakota is the fourth-largest oil producing state in the U.S. behind California, Alaska and Texas [when output from the Federal Outer Continental Shelf/OCS is excluded from the total ranking -- D.R.], and Ness said California is in their "target zone." [Read more]
(Operators increased North Dakota's Bakken production from less than 3,000 bbl/d in 2005 to over 230,000 bbl/d in 2010. The Bakken's share of total North Dakota oil production rose from about 3 percent to about 75 percent over the same period---please see my post "United States: Oil Production From Shale Formations, 2005-2010," here. North Dakota produced an average of 307,000 barrels of crude oil per day in 2010 and comprised about 5.6 percent of the nation's total crude production---please see EIA data, here. For the U.S. crude oil production, please see also my post "U.S. Crude Oil Production, 1970-2010," here. North Dakota's crude oil production increased sharply in the late 1970s and peaked in 1984 at 144,000 barrels per day. Production declined through the late 1980s and early 1990s. After a small rise in 1995-97, production slowed again. Crude production dropped to 81,000 barrels per day in 2003. But since 2004, it has grown constantly to reach the above mentioned all-time peak of 307,000 barrels per day in 2010, surpassing the previous peak of 218,000 barrels per day in 2009. Also significantly, on a monthly basis, North Dakota's crude oil production rose from 138,000 barrels per day in January 2008, to 357,000 barrels per day in November 2010, before falling slightly to 344,000 barrels per day in December 2010. Update: North Dakota passed Alaska in March 2012 to become the second-leading state in crude oil production, trailing only Texas---please see my post "North Dakota Tops Alaska in Oil Production, Trailing Only Texas." -- D.R.)
North Dakota's booming oil industry has yielded record tax revenue for the state, breaking the $100 million mark in March at a time when other states are struggling to stay afloat.
The state in just the last few years has become an oil-producing powerhouse and is looking to overtake California in total production. [...]
Much of the recent increase is due to rising crude prices, which have shot up amid concerns over unrest in the Middle East. But North Dakota's oil production is also accelerating rapidly, and state officials expect the windfall to hold steady. [...]
The 350,000 barrels a day produced in March was actually about 2,000 barrels a day lower than in February. But [state Deputy Tax Commissioner Ryan] Rauschenberger attributed the dip to the weather, and said that even if crude prices return to prior levels the state expects to take in $2 billion in oil-related tax revenue over the next two years. [...]
Amid a debate on Capitol Hill over whether the U.S. needs to do more to encourage domestic oil production, North Dakota is charging ahead with expansion. The state industry was helped in no small part by efforts over the past several years to tap into a massive oil field known as the Bakken Shale deposit, where virtually all future expansion is happening [please see remarks below -- D.R.].
Production is expected to grow "substantially," Ron Ness, president of the North Dakota Petroleum Council, said. With 5,300 wells across the state and thousands more expected to come online, Ness projected that the state could reach up to 700,000 barrels a day by 2015.
North Dakota is the fourth-largest oil producing state in the U.S. behind California, Alaska and Texas [when output from the Federal Outer Continental Shelf/OCS is excluded from the total ranking -- D.R.], and Ness said California is in their "target zone." [Read more]
(Operators increased North Dakota's Bakken production from less than 3,000 bbl/d in 2005 to over 230,000 bbl/d in 2010. The Bakken's share of total North Dakota oil production rose from about 3 percent to about 75 percent over the same period---please see my post "United States: Oil Production From Shale Formations, 2005-2010," here. North Dakota produced an average of 307,000 barrels of crude oil per day in 2010 and comprised about 5.6 percent of the nation's total crude production---please see EIA data, here. For the U.S. crude oil production, please see also my post "U.S. Crude Oil Production, 1970-2010," here. North Dakota's crude oil production increased sharply in the late 1970s and peaked in 1984 at 144,000 barrels per day. Production declined through the late 1980s and early 1990s. After a small rise in 1995-97, production slowed again. Crude production dropped to 81,000 barrels per day in 2003. But since 2004, it has grown constantly to reach the above mentioned all-time peak of 307,000 barrels per day in 2010, surpassing the previous peak of 218,000 barrels per day in 2009. Also significantly, on a monthly basis, North Dakota's crude oil production rose from 138,000 barrels per day in January 2008, to 357,000 barrels per day in November 2010, before falling slightly to 344,000 barrels per day in December 2010. Update: North Dakota passed Alaska in March 2012 to become the second-leading state in crude oil production, trailing only Texas---please see my post "North Dakota Tops Alaska in Oil Production, Trailing Only Texas." -- D.R.)
Wednesday, May 4, 2011
Saudis Consider Need to Raise Output Capacity
PIW, Apr 25, 2011
Although Saudi Arabia’s desire to keep oil markets in balance saw it cut supply by 800,000 barrels per day in March [please see remarks below -- D.R.], the kingdom’s bigger and longer-term concern is over whether it needs to increase oil production capacity to meet likely future demand. The Saudi view on oil markets has altered sharply from where it was a year ago, when a battered global economy was still limping out of recession. Riyadh thinks medium- to long-term oil demand growth may be higher than it had previously anticipated, driven by China, India and also the Middle East itself, and PIW understands that discussions are now taking place on whether the kingdom should raise oil output capacity beyond its current 12.5 million b/d (PIW Apr.11,p1). The pickup in Asian demand in the second half of 2010 surprised Saudi officials, forcing them to start increasing output in November and December to try to cool rising oil prices. A tumultuous start to 2011, which has seen political upheaval across the Arab world and an earthquake and subsequent nuclear emergency in Japan, has further complicated the picture, and helped drive oil prices to levels last seen in 2008. While Saudi Aramco cut output in March in response to weak buying interest for its sour crude [please see my post here; and refiners also started to cut production on top of planned seasonal maintenance, thus reducing intake of crude oil -- D.R], demand is expected to surge again over the summer. A significant part of that surge will come from the Mideast's power plants, which have shown a recent preference for direct crude burning to power air conditioning systems to cool their cities; in a speech last week, Saudi Oil Minister Ali Naimi lumped "the [Mideast] region's oil and gas producers" together with China and India as "the main drivers of this increase in petroleum consumption.”
Riyadh has always said that it could move to capacity of 15 million b/d if required, but such statements have typically been made at times of uncertainty, as in 2008, with officials saying privately that such capacity was unnecessary. Now, while no decisions have yet been made and while work is unlikely to start this year, expansions at Shaybah, Manifa and Khurais are back on the table (PIW Jun.30'08,p3). With little help likely from other Opec producers apart from Iraq, discussions are underway on whether to reactivate plans for a 250,000 b/d expansion at the 18 billion bbl Shaybah field to bring capacity to 1 million b/d. Aramco has already decided to bring forward the 10 billion-14 billion bbl Manifa project, and could now expand its capacity from 900,000 b/d to 1.2 million b/d (PIW Apr.18,p7) [For Manifa, please see my post here -- D.R.]. Another new field, the 27 billion bbl Khurais, could add a further 300,000 b/d [sic] to its existing 1.2 million b/d capacity (PIW Mar.7,p3) [For Khurais, please see my post here -- D.R.].
Saudi sources expect the kingdom will need to keep oil output around 9 million b/d or higher over the next few years, which helps explain the decision to accelerate development of the 900,000 b/d Manifa heavy oil project. The new timetable for Manifa will help offset natural declines at fields now being asked to produce more, as well as provide strategic crude for two new deep-conversion refineries at Jubail and Yanbu. The kingdom's newer fields have annual decline rates of 2% or less, while its older fields average around 4%, so the higher overall Saudi output climbs, the sooner Manifa will be needed. The development has also been earmarked to feed Jubail and Yanbu, which will need 800,000 b/d of Arab Heavy by 2014. Taking that amount of Saudi crude off the market could be disruptive, however, particularly if the supply-demand balance has tightened by then, industry sources tell PIW. In the context of stronger demand and higher oil prices, of course, Aramco can more easily justify the $15 billion investment needed for full Manifa development, despite the $130 billion increase in social spending announced by Riyadh this year to head off potential political unrest at home (PIW Apr.4,p1). [Full story]
(Saudi Arabia's oil minister said on Sunday/Apr 17 the kingdom had slashed output by 800,000 barrels per day in March due to oversupply. "Our production in February was 9.125 million barrels per day, in March it was 8.292 million bpd. In April we don't know yet, probably a little higher than March. The reason I gave you these numbers is to show you that the market is oversupplied," Saudi Oil Minister Ali Naimi told reporters---please see Reuters, Apr 17, 2011, here. Saudi Arabia was the world's second largest crude oil producer in 2010, behind Russia---please see Aaron and David Rachovich, "World's Top 22 Oil Producers, Full Year 2010," here. It maintains the world's largest crude oil production capacity. The kingdom's Ghawar field alone accounts for more than 40% of Saudi Arabia's total oil production capacity, and is the world’s largest oil field. It produces more than 5 million bbl/d of Arabian Light crude. Ghawar also produces more than every other country except Russia and the United States---please see U.S. EIA, Saudi Arabia Country Analysis Brief, Jan 2011, here. Also, Saudi Arabia was the sixth largest oil consumer in the world in 2010, behind the United States, China, Japan, India and Russia, according to the latest estimates, and the eighth largest oil consumer in the world in 2009---please see my post "Top 25 World Oil Consumers, 2009-2010," here. Saudi Arabia is the world's biggest holder of proved oil reserves---please see our post "World's Top 22 Proven Oil Reserves Holders, Jan 1, 2011 -- OGJ," here. And the world's fourth largest holder of natural gas proven reserves as of Jan 1, 2011, behind Russia, Iran and Qatar---please see our post "World's Top 22 Natural Gas Proven Reserve Holders," here. -- D.R.)
Although Saudi Arabia’s desire to keep oil markets in balance saw it cut supply by 800,000 barrels per day in March [please see remarks below -- D.R.], the kingdom’s bigger and longer-term concern is over whether it needs to increase oil production capacity to meet likely future demand. The Saudi view on oil markets has altered sharply from where it was a year ago, when a battered global economy was still limping out of recession. Riyadh thinks medium- to long-term oil demand growth may be higher than it had previously anticipated, driven by China, India and also the Middle East itself, and PIW understands that discussions are now taking place on whether the kingdom should raise oil output capacity beyond its current 12.5 million b/d (PIW Apr.11,p1). The pickup in Asian demand in the second half of 2010 surprised Saudi officials, forcing them to start increasing output in November and December to try to cool rising oil prices. A tumultuous start to 2011, which has seen political upheaval across the Arab world and an earthquake and subsequent nuclear emergency in Japan, has further complicated the picture, and helped drive oil prices to levels last seen in 2008. While Saudi Aramco cut output in March in response to weak buying interest for its sour crude [please see my post here; and refiners also started to cut production on top of planned seasonal maintenance, thus reducing intake of crude oil -- D.R], demand is expected to surge again over the summer. A significant part of that surge will come from the Mideast's power plants, which have shown a recent preference for direct crude burning to power air conditioning systems to cool their cities; in a speech last week, Saudi Oil Minister Ali Naimi lumped "the [Mideast] region's oil and gas producers" together with China and India as "the main drivers of this increase in petroleum consumption.”
Riyadh has always said that it could move to capacity of 15 million b/d if required, but such statements have typically been made at times of uncertainty, as in 2008, with officials saying privately that such capacity was unnecessary. Now, while no decisions have yet been made and while work is unlikely to start this year, expansions at Shaybah, Manifa and Khurais are back on the table (PIW Jun.30'08,p3). With little help likely from other Opec producers apart from Iraq, discussions are underway on whether to reactivate plans for a 250,000 b/d expansion at the 18 billion bbl Shaybah field to bring capacity to 1 million b/d. Aramco has already decided to bring forward the 10 billion-14 billion bbl Manifa project, and could now expand its capacity from 900,000 b/d to 1.2 million b/d (PIW Apr.18,p7) [For Manifa, please see my post here -- D.R.]. Another new field, the 27 billion bbl Khurais, could add a further 300,000 b/d [sic] to its existing 1.2 million b/d capacity (PIW Mar.7,p3) [For Khurais, please see my post here -- D.R.].
Saudi sources expect the kingdom will need to keep oil output around 9 million b/d or higher over the next few years, which helps explain the decision to accelerate development of the 900,000 b/d Manifa heavy oil project. The new timetable for Manifa will help offset natural declines at fields now being asked to produce more, as well as provide strategic crude for two new deep-conversion refineries at Jubail and Yanbu. The kingdom's newer fields have annual decline rates of 2% or less, while its older fields average around 4%, so the higher overall Saudi output climbs, the sooner Manifa will be needed. The development has also been earmarked to feed Jubail and Yanbu, which will need 800,000 b/d of Arab Heavy by 2014. Taking that amount of Saudi crude off the market could be disruptive, however, particularly if the supply-demand balance has tightened by then, industry sources tell PIW. In the context of stronger demand and higher oil prices, of course, Aramco can more easily justify the $15 billion investment needed for full Manifa development, despite the $130 billion increase in social spending announced by Riyadh this year to head off potential political unrest at home (PIW Apr.4,p1). [Full story]
(Saudi Arabia's oil minister said on Sunday/Apr 17 the kingdom had slashed output by 800,000 barrels per day in March due to oversupply. "Our production in February was 9.125 million barrels per day, in March it was 8.292 million bpd. In April we don't know yet, probably a little higher than March. The reason I gave you these numbers is to show you that the market is oversupplied," Saudi Oil Minister Ali Naimi told reporters---please see Reuters, Apr 17, 2011, here. Saudi Arabia was the world's second largest crude oil producer in 2010, behind Russia---please see Aaron and David Rachovich, "World's Top 22 Oil Producers, Full Year 2010," here. It maintains the world's largest crude oil production capacity. The kingdom's Ghawar field alone accounts for more than 40% of Saudi Arabia's total oil production capacity, and is the world’s largest oil field. It produces more than 5 million bbl/d of Arabian Light crude. Ghawar also produces more than every other country except Russia and the United States---please see U.S. EIA, Saudi Arabia Country Analysis Brief, Jan 2011, here. Also, Saudi Arabia was the sixth largest oil consumer in the world in 2010, behind the United States, China, Japan, India and Russia, according to the latest estimates, and the eighth largest oil consumer in the world in 2009---please see my post "Top 25 World Oil Consumers, 2009-2010," here. Saudi Arabia is the world's biggest holder of proved oil reserves---please see our post "World's Top 22 Proven Oil Reserves Holders, Jan 1, 2011 -- OGJ," here. And the world's fourth largest holder of natural gas proven reserves as of Jan 1, 2011, behind Russia, Iran and Qatar---please see our post "World's Top 22 Natural Gas Proven Reserve Holders," here. -- D.R.)
Wednesday, April 27, 2011
[United States:] Natural Gas Production/Consumption Retrospective 2010
EIA, Today in Energy, Apr 25, 2011
In 2010, the natural gas industry saw an abundance of production and strong consumption. On an average annual basis, marketed production of natural gas grew to 61.8 billion cubic feet (Bcf) per day, an increase of about 4% from 2009, despite relatively low prices. Natural gas consumption in 2010 rose to a record level of 66.1 Bcf per day, up from 62.6 Bcf per day in 2009.
In 2010, the average annual spot natural gas price at the Henry Hub increased 12% to $4.37 per million British thermal units, but remained significantly lower than average annual prices at Henry Hub for any year between 2003 and 2008.
Overall, 2010 may turn out to be an important bellwether for the industry. It represents the natural gas industry's first year without major economic upheaval since shale gas rose to prominence. Key points:
Production:
Consumption:
In 2010, the natural gas industry saw an abundance of production and strong consumption. On an average annual basis, marketed production of natural gas grew to 61.8 billion cubic feet (Bcf) per day, an increase of about 4% from 2009, despite relatively low prices. Natural gas consumption in 2010 rose to a record level of 66.1 Bcf per day, up from 62.6 Bcf per day in 2009.
In 2010, the average annual spot natural gas price at the Henry Hub increased 12% to $4.37 per million British thermal units, but remained significantly lower than average annual prices at Henry Hub for any year between 2003 and 2008.
Overall, 2010 may turn out to be an important bellwether for the industry. It represents the natural gas industry's first year without major economic upheaval since shale gas rose to prominence. Key points:
Production:
- Marketed production of natural gas grew about 4% to 61.8 billion cubic feet (Bcf) per day, and reached its highest recorded level in the lower 48 States. The production gains in the lower 48 States more than offset declines in the Gulf of Mexico, where production continued a long-term decline.
- Net imports of natural gas to the United States in 2010 were at the lowest level since 1994. This was a result of decreases in deliveries of liquefied natural gas from a variety of countries and increases in exports from the United States. Net imports of natural gas represented nearly 11% of total U.S. consumption, the lowest proportion since 1991.
Consumption:
- Consumption of natural gas for electric power generation accounted for about 31% of the total annual natural gas consumed. Natural gas-fired power generation continues to displace coal-fired generation in some regions, when delivered spot prices for natural gas approach those for Appalachian coal (after accounting for the differences in gas and coal plant efficiencies).
- Industrial use of natural gas increased 7% to 18.1 Bcf per day in 2010. Relatively low prices and an improving economy led to increase in production by gas-using industries. [Full text but please see the interactive bar chart of natural gas production, consumption and net imports -- D.R.]
Sunday, April 10, 2011
CERAWeek: Unconventional Gas Lifts US Petrochemicals
by Bob Tippee, OGJ Editor, OGJ, Mar 9, 2011
Rapid growth in gas supply from shales and other unconventional reservoirs inverts expectations for North American petrochemicals and underscores the importance of feedstock flexibility in an integrated business strategy, says the leader a major US petrochemical manufacturer.
The brightened business outlook shows the importance of integrating petrochemicals not only with refining but also with upstream operations, according to Stephen Pryor, president of ExxonMobil Chemical Co. and vice-president of ExxonMobil Corp.
A 20% surge in gas supply from unconventional resources during the past 5 years [please see remarks below -- D.R.] has boosted ethane production by 25% and lowered the cost of an important feedstock, Pryor told an IHS-CERA Week conference session [please see remarks below -- D.R.].
“We see ethane reemerging as an advantage feedstock in North America, reflecting the growing production of unconventional natural gas and the increasing importance of gas in the world energy mix,” he said.
In the US last year, the growing supply of relatively low-cost ethane strengthened margins for ethylene and derivatives, lightened the feed slate, and increased US exports.
“The current strength of the US petrochemical market contrasts with conventional wisdom of just a few years ago when it was believed that US petrochemical production would decline, feed slates would get heavier, and the US by 2010 would flip into a net import position,” Pryor said. “Actually, exports grew by about 28% last year.”
Capacity gains?
The ExxonMobil Chemical chief doubts that the improved outlook for North American petrochemicals will lead to an early surge in grassroots construction of ethane crackers.
At least in the near term, he said, capacity growth will be incremental, resulting from debottlenecking of existing light-feed capacity and limited conversion of heavy-feed crackers.
Capacity investment will depend on the pace and pattern of North American ethane supply growth, which in turn will depend on the location and rate of unconventional gas development, liquids content across geologic plays, and construction of equipment able to strip, transport, and store NGLs.
“Just as in refining, incremental investment in feed flexibility and capacity creep are the most efficient ways to meeting growing demand in a mature market like North America, major investments at full grassroots costs would be subject to significant risks relative to long-term oil and gas prices, export economics, and gas developments around the world that could provide feedstocks for competitors overseas,” Pryor said.
Integration strategy
Feedstock flexibility is central to what Pryor described as the “site-wide optimization” ExxonMobil Chemical applies in its integration strategy.
It involves “having the flexibility to process a wide variety of feedstocks and selecting the feed slate that generates the highest value for the integrated complex,” he said. “It entails adjusting the process conditions and product slates in real time so that you extract maximum value from every molecule processed.”
Integration is “more than simply collocating refineries with petrochemical plants,” Pryor said.
It involves optimization not only of feedstocks but also of products, costs, capital, and people. Pryor said 90% of his company’s petrochemical capacity is integrated with refining or gas processing capacity.
The process is continuous and oriented to long-term outcomes. Managing through the “turbulence” of modern markets requires a “disciplined, long-term approach that does not change with short-term changes in commodity prices and profits,” he said. [Full story]
(According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010---please see my post > remarks > EIA data, here. In 2005, U.S. shale gas production stood at just over 0.5 tcf. After methane, ethane is the second-largest component of natural gas. The new natural gas/i.e., shale gas can provide ethane feedstock that can be converted into ethylene, a key plastic feedstock used to make commodity resins polyethylene and PVC and several specialty materials as well. For years, North American makers of plastics and petrochemicals had been looking for a way to remain competitive on the global market. Use of low-priced natural gas as a feedstock has allowed the North American market to use less ethylene based on higher-priced naphtha feedstock, which comes from price-volatile crude oil. Naturally, as the price of crude oil rises, so does the price of plastic. The Barnett shale basin in Texas, with 12,000 natural gas wells as of 2009, “is huge,” Alan Armstrong, CEO of Williams Cos. Inc., said. But the Marcellus shale basin---covering a large portion of Pennsylvania and parts of Ohio, New York and West Virginia, etc.---is expected to be many times larger---please see Plastics News, Apr 5, 2011, here. -- D.R.)
Rapid growth in gas supply from shales and other unconventional reservoirs inverts expectations for North American petrochemicals and underscores the importance of feedstock flexibility in an integrated business strategy, says the leader a major US petrochemical manufacturer.
The brightened business outlook shows the importance of integrating petrochemicals not only with refining but also with upstream operations, according to Stephen Pryor, president of ExxonMobil Chemical Co. and vice-president of ExxonMobil Corp.
A 20% surge in gas supply from unconventional resources during the past 5 years [please see remarks below -- D.R.] has boosted ethane production by 25% and lowered the cost of an important feedstock, Pryor told an IHS-CERA Week conference session [please see remarks below -- D.R.].
“We see ethane reemerging as an advantage feedstock in North America, reflecting the growing production of unconventional natural gas and the increasing importance of gas in the world energy mix,” he said.
In the US last year, the growing supply of relatively low-cost ethane strengthened margins for ethylene and derivatives, lightened the feed slate, and increased US exports.
“The current strength of the US petrochemical market contrasts with conventional wisdom of just a few years ago when it was believed that US petrochemical production would decline, feed slates would get heavier, and the US by 2010 would flip into a net import position,” Pryor said. “Actually, exports grew by about 28% last year.”
Capacity gains?
The ExxonMobil Chemical chief doubts that the improved outlook for North American petrochemicals will lead to an early surge in grassroots construction of ethane crackers.
At least in the near term, he said, capacity growth will be incremental, resulting from debottlenecking of existing light-feed capacity and limited conversion of heavy-feed crackers.
Capacity investment will depend on the pace and pattern of North American ethane supply growth, which in turn will depend on the location and rate of unconventional gas development, liquids content across geologic plays, and construction of equipment able to strip, transport, and store NGLs.
“Just as in refining, incremental investment in feed flexibility and capacity creep are the most efficient ways to meeting growing demand in a mature market like North America, major investments at full grassroots costs would be subject to significant risks relative to long-term oil and gas prices, export economics, and gas developments around the world that could provide feedstocks for competitors overseas,” Pryor said.
Integration strategy
Feedstock flexibility is central to what Pryor described as the “site-wide optimization” ExxonMobil Chemical applies in its integration strategy.
It involves “having the flexibility to process a wide variety of feedstocks and selecting the feed slate that generates the highest value for the integrated complex,” he said. “It entails adjusting the process conditions and product slates in real time so that you extract maximum value from every molecule processed.”
Integration is “more than simply collocating refineries with petrochemical plants,” Pryor said.
It involves optimization not only of feedstocks but also of products, costs, capital, and people. Pryor said 90% of his company’s petrochemical capacity is integrated with refining or gas processing capacity.
The process is continuous and oriented to long-term outcomes. Managing through the “turbulence” of modern markets requires a “disciplined, long-term approach that does not change with short-term changes in commodity prices and profits,” he said. [Full story]
(According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010---please see my post > remarks > EIA data, here. In 2005, U.S. shale gas production stood at just over 0.5 tcf. After methane, ethane is the second-largest component of natural gas. The new natural gas/i.e., shale gas can provide ethane feedstock that can be converted into ethylene, a key plastic feedstock used to make commodity resins polyethylene and PVC and several specialty materials as well. For years, North American makers of plastics and petrochemicals had been looking for a way to remain competitive on the global market. Use of low-priced natural gas as a feedstock has allowed the North American market to use less ethylene based on higher-priced naphtha feedstock, which comes from price-volatile crude oil. Naturally, as the price of crude oil rises, so does the price of plastic. The Barnett shale basin in Texas, with 12,000 natural gas wells as of 2009, “is huge,” Alan Armstrong, CEO of Williams Cos. Inc., said. But the Marcellus shale basin---covering a large portion of Pennsylvania and parts of Ohio, New York and West Virginia, etc.---is expected to be many times larger---please see Plastics News, Apr 5, 2011, here. -- D.R.)
Friday, April 8, 2011
Mixed Drilling Trends off NW Europe, Deloitte Finds
Offshore Magazine, Aberdeen UK, Apr 8, 2011
Exploration and drilling has tailed off slightly on the UK continental shelf, but held steady or has risen elsewhere in northwest Europe according to the latest survey by Deloitte.
During the first quarter of 2011, Deloitte identified nine exploration and appraisal well spuds [more specifically, five exploration + four appraisal wells -- D.R.] on the UKCS, a decrease of 25% compared with the previous quarter. Of the nine wells spud this year, five were in the central North Sea, two in the southern gas basin, one in the northern North Sea, and one on the Faroe-Shetland escarpment.
Despite the dip, Deloitte says the outlook was more positive until the government imposed its surprise tax increase on the sector in March [please see remarks below -- D.R.]. Various companies have since stated their intention to put appraisal and development projects on hold, although it is not clear how much this will impact drilling levels over the coming months.
During 1Q 2011, 10 UKCS exploration and appraisal wells were completed, four by EnCore and its partners in central block 28/9 to find or appraise the Varadero, Catcher North, and Burgman discoveries. Another of the completed wells was Maersk’s Culzean gas/condensate find in the same sector.
UK farm-in activity has risen, Deloitte says, with 13 farm-in deals announced in the first quarter of this year compared with eight in the previous quarter. The rising oil price could be an incentive for companies to increase their equities in reserves, or it could herald a return to corporate strategies that were in place pre-recession.
Offshore Norway, one appraisal and 12 exploration and appraisal wells spudded during the first quarter, the same as during the corresponding quarter in 2010. Eight of the 13 wells were in the North Sea, three in the Norwegian Sea, and two in the Barents Sea.
The outlook for the Norwegian shelf remains positive, Deloitte says. New production licenses were awarded in January under the latest pre-defined areas (APA) round. These, combined with the oil price, should sustain high drilling activity over the remainder of this year.
Of the 11 E&A wells completed on the shelf in the quarter, three were successful. Appraisal well 15/6-11 A intersected an oil column for Statoil on the Dagny/Ermintrude discovery, and well 24/9-10 S and its side track 24/9-10 A encountered oil at Caterpillar.
Off the Netherlands, three E&A wells were spudded during the quarter, compared with one in the corresponding quarter last year.
So far in 2011, four wells have been completed, of which two were drilled by GDF Suez in the K quadrant to target the Darcy prospect. Both resulted in technical failure after heavy mud losses were experienced while drilling though a fractured chalk horizon.
The Minister of Economic Affairs is inviting applications for an exploration license for Dutch North Sea block E/5, with bids due by June 7. One unnamed operator has so far applied. [Full story]
(UK Chancellor of the Exchequer George Osborne announced plans on March 23 to raise GBP2 billion a year from the sector to pay for a fuel duty freeze by adding an extra 12% to taxes on profits made from oil and natural gas in the UK North Sea while crude oil prices remain above $75/b---please see Platts, London, Apr 8, 2011, here. -- D.R.)
Exploration and drilling has tailed off slightly on the UK continental shelf, but held steady or has risen elsewhere in northwest Europe according to the latest survey by Deloitte.
During the first quarter of 2011, Deloitte identified nine exploration and appraisal well spuds [more specifically, five exploration + four appraisal wells -- D.R.] on the UKCS, a decrease of 25% compared with the previous quarter. Of the nine wells spud this year, five were in the central North Sea, two in the southern gas basin, one in the northern North Sea, and one on the Faroe-Shetland escarpment.
Despite the dip, Deloitte says the outlook was more positive until the government imposed its surprise tax increase on the sector in March [please see remarks below -- D.R.]. Various companies have since stated their intention to put appraisal and development projects on hold, although it is not clear how much this will impact drilling levels over the coming months.
During 1Q 2011, 10 UKCS exploration and appraisal wells were completed, four by EnCore and its partners in central block 28/9 to find or appraise the Varadero, Catcher North, and Burgman discoveries. Another of the completed wells was Maersk’s Culzean gas/condensate find in the same sector.
UK farm-in activity has risen, Deloitte says, with 13 farm-in deals announced in the first quarter of this year compared with eight in the previous quarter. The rising oil price could be an incentive for companies to increase their equities in reserves, or it could herald a return to corporate strategies that were in place pre-recession.
Offshore Norway, one appraisal and 12 exploration and appraisal wells spudded during the first quarter, the same as during the corresponding quarter in 2010. Eight of the 13 wells were in the North Sea, three in the Norwegian Sea, and two in the Barents Sea.
The outlook for the Norwegian shelf remains positive, Deloitte says. New production licenses were awarded in January under the latest pre-defined areas (APA) round. These, combined with the oil price, should sustain high drilling activity over the remainder of this year.
Of the 11 E&A wells completed on the shelf in the quarter, three were successful. Appraisal well 15/6-11 A intersected an oil column for Statoil on the Dagny/Ermintrude discovery, and well 24/9-10 S and its side track 24/9-10 A encountered oil at Caterpillar.
Off the Netherlands, three E&A wells were spudded during the quarter, compared with one in the corresponding quarter last year.
So far in 2011, four wells have been completed, of which two were drilled by GDF Suez in the K quadrant to target the Darcy prospect. Both resulted in technical failure after heavy mud losses were experienced while drilling though a fractured chalk horizon.
The Minister of Economic Affairs is inviting applications for an exploration license for Dutch North Sea block E/5, with bids due by June 7. One unnamed operator has so far applied. [Full story]
(UK Chancellor of the Exchequer George Osborne announced plans on March 23 to raise GBP2 billion a year from the sector to pay for a fuel duty freeze by adding an extra 12% to taxes on profits made from oil and natural gas in the UK North Sea while crude oil prices remain above $75/b---please see Platts, London, Apr 8, 2011, here. -- D.R.)
Saturday, April 2, 2011
Iraq Says to Produce 6.5 mil b/d by 2014; Disputes IMF Figures
Platts, Dubai, Mar 30, 2011
The Iraqi Oil Ministry Wednesday insisted that it was on track to achieve a crude oil production target of 6.5 million b/d by 2014, and disputed a recent IMF report suggesting a lower output rise because of infrastructure challenges.
Oil Ministry spokesman Assem Jihad said in a statement that Iraq expected its oil production, currently at around 2.7 million b/d, to rise to 3.3 million b/d in 2012, 4.5 million b/d in 2013 and 6.5 million b/d the following year.
Iraq is targeting close to 13 million b/d of production capacity by 2017 after awarding long term service contracts to foreign oil companies for development and further development of some of its biggest oil fields [output is projected to increase considerably, following the two bid rounds in June and December of 2009, that resulted in 11 Technical Service Contracts---TSCs---with most of the world's top oil companies, please see David Rachovich, Iraq's Oil Sector: Present, Past and Future -- D.R.].
The latest oil ministry figures obtained by Platts show that Iraq produced 2.63 million b/d in February, down slightly from a post-war record of 2.652 million b/d in January [also, please see my post "OPEC's Top Crude Oil Producers, 2010-Jan. 2011," here -- D.R.]
Jihad said the targets were in line with plans established in coordination with the foreign oil companies.
Oil Minister Abdul Karim Luaibi had not seen the figures contained in the IMF report but they appeared based on "inaccurate data and reports," he added.
The IMF said in a country report issued March 28 that while Iraqi oil production was projected to increase considerably over the medium- to long-term, to 12.2 million b/d over the next seven years in a best case scenario, there were infrastructural risks that could hamper the developments.
"While these production goals could be feasible in the longer term, the main risks in the coming years will be bottlenecks in the export infrastructure that will need to be addressed," the IMF said.
Noting that the government had plans to expand the country's oil, pipeline and export infrastructure, it said execution would take time, in which case production would rise to 5.35 million b/d by 2017 if a more conservative scenario was adopted.
"In addition, large investments in supporting activities are also underway and planned, including the construction of desalination plants to produce water for injection in the fields, and storage facilities. These investments will require time to implement, and suggest a more gradual increase in Iraq's oil production," the IMF said. "Based on more conservative assumptions for the time it will take to expand Iraq's export capacity, oil production could still increase to over 5 million b/d by 2017."
Jihad, referring to the report, said that the ministry had put port and storage expansion projects on a fast track.
These plans include building 24 new storage tanks with capacity of over 300,000 b/d as well as floating platforms with capacity of 900,000 b/d each to absorb the anticipated higher exports [sic]. The plans also include two single point moorings to link the storage tanks to southern export terminals [sic].
The project, which Jihad said would normally take 4-5 years to complete, will raise export capacity by 1.8 million b/d and be completed by the end of this year. The second phase will be finished by the end of next year, he said.
Current export capacity from the south is estimated at 1.6 million b/d [sic, Basra - 1.6 million b/d, Khor al-Amaya - 0.7 million b/d, but their efffecive capacity is less -- D.R.] and the lack of storage facilities has hampered a more rapid rise in oil production from southern oil fields, where output has risen by more than 300,000 b/d since the start of the year.
The additional crude has come as the leaders of three foreign consortia awarded contracts to develop the giant Rumaila, Zubair and West Qurna 1 oil fields have reported reaching the 10% initial output hike from the three fields. However, latest figures from the oil ministry show that output has fallen slightly, apparently because of restricted export and storage capacity. [...]
The IMF said that oil export revenues in 2010 exceeded budgetary projections as higher oil prices offset lower export volumes. It said exports last year averaged 1.85 million b/d, well below Baghdad's 2.1 million b/d target.
"The shortfall reflected periods of bad weather and attacks on pipelines, as well as the lack of an agreement with the Kurdish region to secure additional exports," it said.
"Export prices were substantially higher, however, averaging just over $74/barrel during the year, compared to a budgeted price of $62.50/barrel," it said, adding that total oil export revenues reached $50 billion in 2010 compared with a budget forecast of $48 billion and up from $39 billion in 2009.
But this was still well below the peak of $63 billion in 2008, when oil prices [WTI] rose to a record above $147/b [the price of Kirkuk crude oil reached an all-time high of $134/b in July 2008 -- D.R.] before shedding more than $100/b by the end of that year.
The resumption of Kurdish oil exports in early February pushed up Iraqi oil exports to 2.2 million b/d, the highest since March 2003 [and the highest figure in 22 years, please see David Rachovich, Iraq's Oil Sector: Present, Past and Future, Table 1 -- D.R.]. Iraq has targeted exports of 2.25 million b/d in 2011, including 100,000 b/d [sic] from the Kurdish province.
It based its 2011 budget on an oil price assumption of $76.50/b, below current global oil prices. [Read more]
(Please see the International Monetary Fund/IMF's report, published on Mar 28, 2011, especially Box 1, here. Iraq was the sixth largest supplier of crude oil to the United States in 2010, after Canada, Mexico, Saudi Arabia, Nigeria and Venezuela---please see my post "U.S. Crude Oil Imports from Top 15 Countries," here. For Rumaila, West Qurna-1 and Zubair, please read my Dec 2010 - Jan 2011 blog posts under the category/label "Iraq." -- D.R.)
The Iraqi Oil Ministry Wednesday insisted that it was on track to achieve a crude oil production target of 6.5 million b/d by 2014, and disputed a recent IMF report suggesting a lower output rise because of infrastructure challenges.
Oil Ministry spokesman Assem Jihad said in a statement that Iraq expected its oil production, currently at around 2.7 million b/d, to rise to 3.3 million b/d in 2012, 4.5 million b/d in 2013 and 6.5 million b/d the following year.
Iraq is targeting close to 13 million b/d of production capacity by 2017 after awarding long term service contracts to foreign oil companies for development and further development of some of its biggest oil fields [output is projected to increase considerably, following the two bid rounds in June and December of 2009, that resulted in 11 Technical Service Contracts---TSCs---with most of the world's top oil companies, please see David Rachovich, Iraq's Oil Sector: Present, Past and Future -- D.R.].
The latest oil ministry figures obtained by Platts show that Iraq produced 2.63 million b/d in February, down slightly from a post-war record of 2.652 million b/d in January [also, please see my post "OPEC's Top Crude Oil Producers, 2010-Jan. 2011," here -- D.R.]
Jihad said the targets were in line with plans established in coordination with the foreign oil companies.
Oil Minister Abdul Karim Luaibi had not seen the figures contained in the IMF report but they appeared based on "inaccurate data and reports," he added.
The IMF said in a country report issued March 28 that while Iraqi oil production was projected to increase considerably over the medium- to long-term, to 12.2 million b/d over the next seven years in a best case scenario, there were infrastructural risks that could hamper the developments.
"While these production goals could be feasible in the longer term, the main risks in the coming years will be bottlenecks in the export infrastructure that will need to be addressed," the IMF said.
Noting that the government had plans to expand the country's oil, pipeline and export infrastructure, it said execution would take time, in which case production would rise to 5.35 million b/d by 2017 if a more conservative scenario was adopted.
"In addition, large investments in supporting activities are also underway and planned, including the construction of desalination plants to produce water for injection in the fields, and storage facilities. These investments will require time to implement, and suggest a more gradual increase in Iraq's oil production," the IMF said. "Based on more conservative assumptions for the time it will take to expand Iraq's export capacity, oil production could still increase to over 5 million b/d by 2017."
Jihad, referring to the report, said that the ministry had put port and storage expansion projects on a fast track.
These plans include building 24 new storage tanks with capacity of over 300,000 b/d as well as floating platforms with capacity of 900,000 b/d each to absorb the anticipated higher exports [sic]. The plans also include two single point moorings to link the storage tanks to southern export terminals [sic].
The project, which Jihad said would normally take 4-5 years to complete, will raise export capacity by 1.8 million b/d and be completed by the end of this year. The second phase will be finished by the end of next year, he said.
Current export capacity from the south is estimated at 1.6 million b/d [sic, Basra - 1.6 million b/d, Khor al-Amaya - 0.7 million b/d, but their efffecive capacity is less -- D.R.] and the lack of storage facilities has hampered a more rapid rise in oil production from southern oil fields, where output has risen by more than 300,000 b/d since the start of the year.
The additional crude has come as the leaders of three foreign consortia awarded contracts to develop the giant Rumaila, Zubair and West Qurna 1 oil fields have reported reaching the 10% initial output hike from the three fields. However, latest figures from the oil ministry show that output has fallen slightly, apparently because of restricted export and storage capacity. [...]
The IMF said that oil export revenues in 2010 exceeded budgetary projections as higher oil prices offset lower export volumes. It said exports last year averaged 1.85 million b/d, well below Baghdad's 2.1 million b/d target.
"The shortfall reflected periods of bad weather and attacks on pipelines, as well as the lack of an agreement with the Kurdish region to secure additional exports," it said.
"Export prices were substantially higher, however, averaging just over $74/barrel during the year, compared to a budgeted price of $62.50/barrel," it said, adding that total oil export revenues reached $50 billion in 2010 compared with a budget forecast of $48 billion and up from $39 billion in 2009.
But this was still well below the peak of $63 billion in 2008, when oil prices [WTI] rose to a record above $147/b [the price of Kirkuk crude oil reached an all-time high of $134/b in July 2008 -- D.R.] before shedding more than $100/b by the end of that year.
The resumption of Kurdish oil exports in early February pushed up Iraqi oil exports to 2.2 million b/d, the highest since March 2003 [and the highest figure in 22 years, please see David Rachovich, Iraq's Oil Sector: Present, Past and Future, Table 1 -- D.R.]. Iraq has targeted exports of 2.25 million b/d in 2011, including 100,000 b/d [sic] from the Kurdish province.
It based its 2011 budget on an oil price assumption of $76.50/b, below current global oil prices. [Read more]
(Please see the International Monetary Fund/IMF's report, published on Mar 28, 2011, especially Box 1, here. Iraq was the sixth largest supplier of crude oil to the United States in 2010, after Canada, Mexico, Saudi Arabia, Nigeria and Venezuela---please see my post "U.S. Crude Oil Imports from Top 15 Countries," here. For Rumaila, West Qurna-1 and Zubair, please read my Dec 2010 - Jan 2011 blog posts under the category/label "Iraq." -- D.R.)
Sunday, March 27, 2011
World Watch [Brazil as a Role Model]
by Jim Washer, London, EI
Petrobras Chief Executive José Sergio Gabrielli de Azevedo has been named by Energy Intelligence as its 2011 Petroleum Executive of the Year. The award reflects Gabrielli’s stewardship of the state-controlled Brazilian firm through a period of unprecedented growth, encompassing the discovery of huge [deep water] subsalt oil and gas reserves [in the South Atlantic]. Gabrielli’s triumph comes at an intriguing time. Political unrest in North Africa and the Middle East has left the world contemplating an oil price shock reminiscent of those of the 1970s. The price spikes of that decade prompted a radical energy policy response from some consuming countries, most notably Brazil. The government sought to protect the country from future price shocks by promoting the extensive use of sugar cane-derived ethanol in transport fuels and by making Petrobras a pioneer in deepwater exploration. If the disruption to Libyan oil and gas exports spreads to other producers in the region, the impact on energy prices may encourage other oil and gas importing nations to follow the Brazilian example.
(Under Gabrielli’s leadership, Petrobras made discoveries expected to more than double its oil reserves and production in the years to come. The company has established itself as a leader in deepwater exploration and production technology with among the highest safety and efficiency standards in the business. He also raised huge amounts of capital to fund these upstream developments and allow the state company to remain very much the dominant force in the development of Brazil’s oil industry. The Petroleum Executive of the Year selection process begins with Energy Intelligence eliciting nominations from the heads of the 100 largest oil companies determined by The Energy Intelligence Top 100: Ranking The World’s Oil Companies, an EI publication. These nominations are then voted on by a committee of previous award winners and former senior oil executives. Past winners of the Petroleum Executive of the Year Award include Andrew Gould of Schlumberger (2010), Christophe de Margerie of Total (2009), Paolo Scaroni of Eni (2008), Abdulla al-Attiyah of Qatar (2007), Dr. Shokri Ghanem of Libya (2006), Abdallah Jum'ah of Saudi Aramco (2005), David O'Reilly of Chevron (2004), Lee Raymond of ExxonMobil (2003), James J. Mulva of ConocoPhillips (2002), Sir Mark Moody-Stuart of Royal Dutch Shell (2001), Thierry Desmarest of Total (2000), Lucio A. Noto of ExxonMobil (1999), Luis Giusti of PDVSA (1998) and Lord John Browne of BP (1997)---please see EON: Enhanced Online News, here. Brazil has become a net oil exporter in the last decade. Petrobras has been ranked fourth in the Platts Top 250 Global Energy Companies Rankings 2010, behind ExxonMobil, BP and Gazprom Oao---please see my post, here. Petrobras with a market capitalization of $229 billion, ranked at No. 3 in the PFC Energy 50 Ranking of World's Top Energy Companies, Jan 2011 reflecting 2010 Rank, after ExxonMobil and PetroChina---please see my post here. Also, Petrobras retained its spot as the No. 15, in the 2011 Petroleum Intelligence Weekly's/PIW's ranking for 2009---please see my blog stand-alone page "Companies" > Petrobras. -- D.R.)
Petrobras Chief Executive José Sergio Gabrielli de Azevedo has been named by Energy Intelligence as its 2011 Petroleum Executive of the Year. The award reflects Gabrielli’s stewardship of the state-controlled Brazilian firm through a period of unprecedented growth, encompassing the discovery of huge [deep water] subsalt oil and gas reserves [in the South Atlantic]. Gabrielli’s triumph comes at an intriguing time. Political unrest in North Africa and the Middle East has left the world contemplating an oil price shock reminiscent of those of the 1970s. The price spikes of that decade prompted a radical energy policy response from some consuming countries, most notably Brazil. The government sought to protect the country from future price shocks by promoting the extensive use of sugar cane-derived ethanol in transport fuels and by making Petrobras a pioneer in deepwater exploration. If the disruption to Libyan oil and gas exports spreads to other producers in the region, the impact on energy prices may encourage other oil and gas importing nations to follow the Brazilian example.
(Under Gabrielli’s leadership, Petrobras made discoveries expected to more than double its oil reserves and production in the years to come. The company has established itself as a leader in deepwater exploration and production technology with among the highest safety and efficiency standards in the business. He also raised huge amounts of capital to fund these upstream developments and allow the state company to remain very much the dominant force in the development of Brazil’s oil industry. The Petroleum Executive of the Year selection process begins with Energy Intelligence eliciting nominations from the heads of the 100 largest oil companies determined by The Energy Intelligence Top 100: Ranking The World’s Oil Companies, an EI publication. These nominations are then voted on by a committee of previous award winners and former senior oil executives. Past winners of the Petroleum Executive of the Year Award include Andrew Gould of Schlumberger (2010), Christophe de Margerie of Total (2009), Paolo Scaroni of Eni (2008), Abdulla al-Attiyah of Qatar (2007), Dr. Shokri Ghanem of Libya (2006), Abdallah Jum'ah of Saudi Aramco (2005), David O'Reilly of Chevron (2004), Lee Raymond of ExxonMobil (2003), James J. Mulva of ConocoPhillips (2002), Sir Mark Moody-Stuart of Royal Dutch Shell (2001), Thierry Desmarest of Total (2000), Lucio A. Noto of ExxonMobil (1999), Luis Giusti of PDVSA (1998) and Lord John Browne of BP (1997)---please see EON: Enhanced Online News, here. Brazil has become a net oil exporter in the last decade. Petrobras has been ranked fourth in the Platts Top 250 Global Energy Companies Rankings 2010, behind ExxonMobil, BP and Gazprom Oao---please see my post, here. Petrobras with a market capitalization of $229 billion, ranked at No. 3 in the PFC Energy 50 Ranking of World's Top Energy Companies, Jan 2011 reflecting 2010 Rank, after ExxonMobil and PetroChina---please see my post here. Also, Petrobras retained its spot as the No. 15, in the 2011 Petroleum Intelligence Weekly's/PIW's ranking for 2009---please see my blog stand-alone page "Companies" > Petrobras. -- D.R.)
Thursday, March 24, 2011
World Watch [Oil Markets]
by Matt Piotrowski, Washington, EI
Oil markets took a breather [sic] Wednesday [Mar 23], with little movement on either of the major benchmarks. It appears that Brent has settled down around the $115 per barrel level, while WTI looks comfortable in the $100-$105 range. The markets have already priced in an extended outage in Libya, but traders are having difficulty factoring in other pockets of instability in the Arab world. Unrest in Yemen, Syria and Bahrain this week is underpinning prices, and will likely do so for some time. There are some dangers on the downside, such as a fragile global economic recovery and a possible short-term decline in Japanese demand, but the risk to the upside appears greater. Societe Generale said this week that if another medium-sized oil producer similar to Libya were to lose output, Brent would rise to $125-$150. And if the turmoil spreads to Saudi Arabia, the world could be looking at $200 oil, the SocGen analysts said.
(U.S. crude ended at a 2-1/2 year high on Wednesday as Palestinian rocket strikes on Israel escalated Middle East geopolitical risks and U.S. gasoline inventories posted the biggest seasonal decline on record, amid ongoing unrest in MENA countries---Reuters. Light, sweet crude---benchmark WTI---for May delivery settled 78 cents higher at $105.75 a barrel on the New York Mercantile Exchange, the highest settlement since September 2008. In London, Brent May crude futures settled down 15 cents at $115.55 a barrel. -- D.R.)
Oil markets took a breather [sic] Wednesday [Mar 23], with little movement on either of the major benchmarks. It appears that Brent has settled down around the $115 per barrel level, while WTI looks comfortable in the $100-$105 range. The markets have already priced in an extended outage in Libya, but traders are having difficulty factoring in other pockets of instability in the Arab world. Unrest in Yemen, Syria and Bahrain this week is underpinning prices, and will likely do so for some time. There are some dangers on the downside, such as a fragile global economic recovery and a possible short-term decline in Japanese demand, but the risk to the upside appears greater. Societe Generale said this week that if another medium-sized oil producer similar to Libya were to lose output, Brent would rise to $125-$150. And if the turmoil spreads to Saudi Arabia, the world could be looking at $200 oil, the SocGen analysts said.
(U.S. crude ended at a 2-1/2 year high on Wednesday as Palestinian rocket strikes on Israel escalated Middle East geopolitical risks and U.S. gasoline inventories posted the biggest seasonal decline on record, amid ongoing unrest in MENA countries---Reuters. Light, sweet crude---benchmark WTI---for May delivery settled 78 cents higher at $105.75 a barrel on the New York Mercantile Exchange, the highest settlement since September 2008. In London, Brent May crude futures settled down 15 cents at $115.55 a barrel. -- D.R.)
Wednesday, March 23, 2011
Egyptian Gas Supply to Israel Almost Back to Normal: Sources
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.)
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.)
Monday, March 21, 2011
Continental: Bakken's Giant Scope Underappreciated
by OGJ editors, OGJ, Feb 16, 2011
The Bakken play [please see map below -- D.R.] in the Williston basin could become the world’s largest discovery in the last 30-40 years, a senior manager at Continental Resources Inc. said Feb. 16.
Ultimate recovery from the overall play is now estimated at 24 billion bbl of oil, compared with US reserves of nearly 20 billion bbl, he told the NAPE Expo in Houston.
The 24 billion bbl figure is five times the US Geological Survey’s 2008 estimate and compares with the 151 million bbl the survey put forth as recently as the mid-1990s, said Jack Stark, Continental senior vice-president, exploration (OGJ, Apr. 21, 2008, p. 37).
Close to 2 billion bbl of the 24 billion will come from the underlying Three Forks [region], which Continental helped prove to be a separate reservoir, Stark noted (OGJ Online, July 10, 2008).
The increases resulted as technology evolved over a 20-year span from marginal or uneconomic vertical wells to open hole stimulations in single, dual, and trilaterals to liners with staged fracs that are resulting in 50% rates of return today, Stark said. Industry also began drilling into the Middle Bakken dolomite, which is more porous and permeable than the upper and lower Bakken shale source rocks.
Production exceeds 400,000 b/d including Montana and North Dakota, Stark estimated, and smaller volumes are being produced in Canada. So recovery of that volume of oil will take years.
Industry has completed 2,750 horizontal wells since 2000. It is running 165 rigs that likely will drill 1,800 more wells in 2011, and production could reach as much as 1 million b/d within a few years, Stark said. The Bakken is continuous under nearly 15,000 sq miles.
The play’s numerous operators are drilling 18,000-21,000-ft wellbores that include 9,500-ft laterals and applying 18-30 frac stages/well, said Stark.
In general, higher initial potential producing rates indicate higher estimated ultimate recoveries, but the correlation isn’t 1:1 “due to overriding geological factors,” he said. Operators seem to reach a point of diminishing returns between 18 and 24 frac stages and are still seeking the ideal number of stages, he said. [Full story]
(The Bakken formation was discovered in 1953 and as early as 1974, it was postulated that vast amounts of petroleum were contained in the formation itself but it was not economically viable as the oil was trapped in shale, i.e., fine sedimentary rocks. With the development of new drilling techniques, it became possible to horizontally drill right into the flat shaped deposits and collapse the oil rich rocks by fracking---i.e., pumping sand/proppant and liquids at high pressure into the well bore---in order to allow the oil to flow back up. Applying new drilling techniques alongside higher oil prices made it economically viable to exploit the oil trapped in the Bakken shale as well as other formations such as the Cardium in Alberta and the Viking in Saskatchewan. Armed with the same proven technology, the industry has now set its eyes on the Southern Alberta Basin. With its similarities to the Williston Basin, the companies are excited about the potential of this new emerging light oil play dubbed: The Alberta Bakken, stretching from Southern Alberta into Montana---please see BeatingTheIndex.com blog here. Wood Mackenzie's Upstream M&A Service report "2010 in Review and the Outlook for 2011" shows that US shale gas in particular had an exceptional year in 2010 - continuing a steady increase in deal activity over the last five years - with acquisition spend amounting to US$39 billion, equivalent to 21% of all global merger and acquisition---M&A---activity. Also, "2010 ended with a flurry of shale oil transactions, centered on the Bakken play where we anticipate further activity in the coming year. In the last two months of 2010, there were four US$1 billion plus Bakken deals announced, pushing cumulative M&A spend in North American tight oil beyond US$15 billion," said Luke Parker, manager of WoodMac's M&A research---please see my post here. -- D.R.)
Map of the Bakken Formation Oil and Gas Play
Source: Geology.com here. Description: The Bakken is below parts of northwestern North Dakota, northeastern Montana, southern Saskatchewan and southwestern Manitoba.
The Bakken play [please see map below -- D.R.] in the Williston basin could become the world’s largest discovery in the last 30-40 years, a senior manager at Continental Resources Inc. said Feb. 16.
Ultimate recovery from the overall play is now estimated at 24 billion bbl of oil, compared with US reserves of nearly 20 billion bbl, he told the NAPE Expo in Houston.
The 24 billion bbl figure is five times the US Geological Survey’s 2008 estimate and compares with the 151 million bbl the survey put forth as recently as the mid-1990s, said Jack Stark, Continental senior vice-president, exploration (OGJ, Apr. 21, 2008, p. 37).
Close to 2 billion bbl of the 24 billion will come from the underlying Three Forks [region], which Continental helped prove to be a separate reservoir, Stark noted (OGJ Online, July 10, 2008).
The increases resulted as technology evolved over a 20-year span from marginal or uneconomic vertical wells to open hole stimulations in single, dual, and trilaterals to liners with staged fracs that are resulting in 50% rates of return today, Stark said. Industry also began drilling into the Middle Bakken dolomite, which is more porous and permeable than the upper and lower Bakken shale source rocks.
Production exceeds 400,000 b/d including Montana and North Dakota, Stark estimated, and smaller volumes are being produced in Canada. So recovery of that volume of oil will take years.
Industry has completed 2,750 horizontal wells since 2000. It is running 165 rigs that likely will drill 1,800 more wells in 2011, and production could reach as much as 1 million b/d within a few years, Stark said. The Bakken is continuous under nearly 15,000 sq miles.
The play’s numerous operators are drilling 18,000-21,000-ft wellbores that include 9,500-ft laterals and applying 18-30 frac stages/well, said Stark.
In general, higher initial potential producing rates indicate higher estimated ultimate recoveries, but the correlation isn’t 1:1 “due to overriding geological factors,” he said. Operators seem to reach a point of diminishing returns between 18 and 24 frac stages and are still seeking the ideal number of stages, he said. [Full story]
(The Bakken formation was discovered in 1953 and as early as 1974, it was postulated that vast amounts of petroleum were contained in the formation itself but it was not economically viable as the oil was trapped in shale, i.e., fine sedimentary rocks. With the development of new drilling techniques, it became possible to horizontally drill right into the flat shaped deposits and collapse the oil rich rocks by fracking---i.e., pumping sand/proppant and liquids at high pressure into the well bore---in order to allow the oil to flow back up. Applying new drilling techniques alongside higher oil prices made it economically viable to exploit the oil trapped in the Bakken shale as well as other formations such as the Cardium in Alberta and the Viking in Saskatchewan. Armed with the same proven technology, the industry has now set its eyes on the Southern Alberta Basin. With its similarities to the Williston Basin, the companies are excited about the potential of this new emerging light oil play dubbed: The Alberta Bakken, stretching from Southern Alberta into Montana---please see BeatingTheIndex.com blog here. Wood Mackenzie's Upstream M&A Service report "2010 in Review and the Outlook for 2011" shows that US shale gas in particular had an exceptional year in 2010 - continuing a steady increase in deal activity over the last five years - with acquisition spend amounting to US$39 billion, equivalent to 21% of all global merger and acquisition---M&A---activity. Also, "2010 ended with a flurry of shale oil transactions, centered on the Bakken play where we anticipate further activity in the coming year. In the last two months of 2010, there were four US$1 billion plus Bakken deals announced, pushing cumulative M&A spend in North American tight oil beyond US$15 billion," said Luke Parker, manager of WoodMac's M&A research---please see my post here. -- D.R.)
Map of the Bakken Formation Oil and Gas Play
Sunday, March 20, 2011
Kogas to Send Up to 500,000 Tonnes of LNG to Japan
LNG World News, Mar 18, 2011
South Korea said on Friday Korea Gas Corp (KOGAS), the world’s top corporate buyer of liquefied natural gas (LNG), would supply 400,000-500,000 tonnes of LNG to quake-hit Japan, as requested by Japanese utilities.
South Korea’s economy ministry said in a statement that the state-run entity’s gas supply on a swap basis would be made from late March through April, following a government announcement on the supply plan on Sunday.
Global LNG prices jumped about 10 percent this week after Friday’s earthquake shut nuclear power plants in the world’s third-largest economy [after the U.S. and China], prompting increased demand for LNG.
Analysts reckon the world’s top LNG buyer may import about an extra 1 billion cubic feet per day to make up for the 9 gigawatts of nuclear power lost.
“We will continue to discuss with Japan possible further supplies if needed, while we maintain sufficient inventory levels,” said a government source with direct knowledge of the matter, who declined to be identified. [...]
South Korea’s current LNG inventory stands at 1.5 million tonnes, adding that supply to Japan would come from incoming shipments, not current inventory, the source said.
The ministry also noted South Korea’s emergency oil product and boron supply to Japan, referring to about 4.5 million barrels of shipments by four Korean refiners, as Japanese refiners grapple with the loss of about a third of their 4.5 million barrel-per-day refining capacity [sic].
Japan’s worst quake on record, which sparked a nuclear crisis, has caused the loss of around 9,700 megawatts (MW) of nuclear and 10,831 MW of thermal power generation.
To help stop fission nuclear reactions, South Korea said on Wednesday it would send some of its reserve boron to Japan after a request from Tokyo for the metalloid, which is being mixed with seawater to limit damage to Japan’s crippled nuclear reactors. [Read full]
(Japan is the third largest oil consumer in the world behind the United States and China and the third-largest net importer of crude oil. It is the world's largest importer of both LNG and coal---please see Japan Energy Profile, prepared by the U.S. EIA, here. For information on Japan's nuclear crisis and its impact, please see also my posts under the category/label "Japan." South Korea is the world's second largest importer of LNG. For Asian LNG market, please see my posts here and here. -- D.R.)
South Korea said on Friday Korea Gas Corp (KOGAS), the world’s top corporate buyer of liquefied natural gas (LNG), would supply 400,000-500,000 tonnes of LNG to quake-hit Japan, as requested by Japanese utilities.
South Korea’s economy ministry said in a statement that the state-run entity’s gas supply on a swap basis would be made from late March through April, following a government announcement on the supply plan on Sunday.
Global LNG prices jumped about 10 percent this week after Friday’s earthquake shut nuclear power plants in the world’s third-largest economy [after the U.S. and China], prompting increased demand for LNG.
Analysts reckon the world’s top LNG buyer may import about an extra 1 billion cubic feet per day to make up for the 9 gigawatts of nuclear power lost.
“We will continue to discuss with Japan possible further supplies if needed, while we maintain sufficient inventory levels,” said a government source with direct knowledge of the matter, who declined to be identified. [...]
South Korea’s current LNG inventory stands at 1.5 million tonnes, adding that supply to Japan would come from incoming shipments, not current inventory, the source said.
The ministry also noted South Korea’s emergency oil product and boron supply to Japan, referring to about 4.5 million barrels of shipments by four Korean refiners, as Japanese refiners grapple with the loss of about a third of their 4.5 million barrel-per-day refining capacity [sic].
Japan’s worst quake on record, which sparked a nuclear crisis, has caused the loss of around 9,700 megawatts (MW) of nuclear and 10,831 MW of thermal power generation.
To help stop fission nuclear reactions, South Korea said on Wednesday it would send some of its reserve boron to Japan after a request from Tokyo for the metalloid, which is being mixed with seawater to limit damage to Japan’s crippled nuclear reactors. [Read full]
(Japan is the third largest oil consumer in the world behind the United States and China and the third-largest net importer of crude oil. It is the world's largest importer of both LNG and coal---please see Japan Energy Profile, prepared by the U.S. EIA, here. For information on Japan's nuclear crisis and its impact, please see also my posts under the category/label "Japan." South Korea is the world's second largest importer of LNG. For Asian LNG market, please see my posts here and here. -- D.R.)
Monday, March 7, 2011
World Watch -- Comment & Interpretation on Today's News [Oil Prices]
by Peter Kemp, London, EI
The ebb and flow of protests across North Africa and the Middle East is being mirrored in oil markets, with WTI following Brent north of $100 per barrel this past week. A mix of geopolitical risks and technical explanations is driving price forecasts even higher as predictions of a bumpy ride towards $200/bbl gain credibility. Financial analysts are driving these frothy predictions, while market fundamentalists fret that the oil balances still show sluggish demand outside of Asia, ample supply and enough spare capacity for almost any eventuality. But with Libya offline and jumpiness about potential disruptions elsewhere, a period of higher prices is inevitable. This makes Saudi Arabia’s effort to calm the market with extra barrels for which there was no obvious demand all the more understandable. A runaway rise in oil prices is an immediate threat to the fragile global recovery from recession, and an even bigger threat to long-term demand for oil.
(Please see also my recent blog posts under the categories/labels "Libya," "Saudi Arabia" and "Oil Fundamentals." -- D.R.)
The ebb and flow of protests across North Africa and the Middle East is being mirrored in oil markets, with WTI following Brent north of $100 per barrel this past week. A mix of geopolitical risks and technical explanations is driving price forecasts even higher as predictions of a bumpy ride towards $200/bbl gain credibility. Financial analysts are driving these frothy predictions, while market fundamentalists fret that the oil balances still show sluggish demand outside of Asia, ample supply and enough spare capacity for almost any eventuality. But with Libya offline and jumpiness about potential disruptions elsewhere, a period of higher prices is inevitable. This makes Saudi Arabia’s effort to calm the market with extra barrels for which there was no obvious demand all the more understandable. A runaway rise in oil prices is an immediate threat to the fragile global recovery from recession, and an even bigger threat to long-term demand for oil.
(Please see also my recent blog posts under the categories/labels "Libya," "Saudi Arabia" and "Oil Fundamentals." -- 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
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