Platts: OPEC Production Plunges in March
Tuesday, April 12, 2011
Platts
The 12-member Organization of the Petroleum Exporting Countries' (OPEC) crude oil production output plunged by 630,000 barrels per day (b/d) in March to average 29.17 million b/d, according to a just-released Platts survey of OPEC and oil industry officials and analysts. Higher volumes from several member states failed to cover the loss of 930,000 b/d of Libyan supply, the survey showed.
Excluding Iraq, which does not participate in OPEC output agreements, production from the 11 members bound by notional quotas (OPEC-11) fell by 580,000 b/d to 26.52 million b/d in March from 27.1 million b/d in February.
Libyan production, which had already fallen to 1.39 million b/d from 1.58 million b/d in February, was estimated to have averaged around 460,000 b/d over March.
"Even the simple counting of barrels shows how difficult it will be for the market to recover from the loss of so much Libyan crude," said John Kingston, Platts global director of news. "Beyond that, the quality of the crude coming out of Libya is one of the highest in the world, with very good yields on the transportation fuels, particularly diesel, which the world needs. So one barrel of crude from another OPEC country doesn't neatly replace one barrel of Libyan crude. The market will need to see a decline in demand to balance, and we are seeing signs of that reaction to higher prices ongoing."
OPEC kingpin Saudi Arabia pumped an average 9 million b/d, a 300,000 b/d boost from February levels. With the kingdom claiming 12.5 million b/d of capacity, this leaves Saudi Arabia with some 3.5 million b/d of spare capacity.
The United Arab Emirates (UAE) also increased production, by 100,000 b/d to an estimated 2.5 million b/d, while Kuwait boosted output by 70,000 b/d to 2.4 million b/d, the survey found.
Angolaramped up production to 1.7 million b/d from 1.65 million b/d in February.
But production fell in Nigeria, due in part to maintenance at the Bonga field, with the country's total volumes declining to 2 million b/d from 2.16 million b/d in February.
Venezuelan output fell by 20,000 b/d to 2.21 million b/d. Iraqi production fell by 50,000 b/d to 2.65 million b/d from 2.7 million b/d in February.
Iranian production was steady. However, industry sources said Iran was holding significant volumes of floating storage because of marketing difficulties. It was not clear whether this was crude only or a mix of crude, condensates and fuel oil. One industry source said 15 VLCCs (very large crude carriers) were being used.
OPEC has a notional output target of 24.845 million b/d for the 11 members bound by quotas. The latest estimates of OPEC-11 output show that, as a result of the plunge in Libyan supply, the volume of overproduction has been reduced to 1.675 million b/d.
Tuesday, April 12, 2011
Musings: Updated 2011 Hurricane Forecast Still Calls for Active Year
Musings: Updated 2011 Hurricane Forecast Still Calls for Active Year
Tuesday, April 12, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks
The latest forecast update from Professors Philip Klotzbach and William Gray of the Department of Atmospheric Science at the Colorado State University (CSU) says the upcoming hurricane season is expected to see above-average activity. The April 6th forecast is slightly lower than their December 2010 forecast largely due to uncertainty about the sea surface temperatures in both the South Pacific and South Atlantic oceans that can assist or retard the development and strengthening of tropical storms.
The forecasting team has developed a new April methodology based on a data collected from 1982-2010. There are four predictors employed in the model with two of them based on sea surface temperatures in the Atlantic and Pacific oceans. The Pacific Ocean for most of the past year has been cooler than normal, which helped contribute to the Atlantic basin’s storm activity last year mostly turning north before reaching the U.S. In general, sea surface temperatures in the eastern and central tropical Pacific Ocean have been 0.50C-1.00C below average.
Exhibit 21. Pacific Ocean Sea Surface Temperatures Low
Source: Colorado State University
On the other side of the globe, Atlantic Ocean sea surface temperatures remain at or above average levels. They have cooled recently but most likely that has been caused by a shift from a negative phase for the North Atlantic Oscillation to a positive phase. Atmospheric conditions currently are conducive for an active hurricane season as wind shear, a force that can limit the development and strengthening of tropical storms, across the basin has been well below average over the past two months.
Exhibit 22. Atlantic Ocean Temperatures Near Normal
Source: Colorado State University
With these conditions, the CSU forecasting team began looking for analog years to help fine-tune their forecast. They were looking for years generally characterized by weak to moderate La Niña conditions and above-average tropical Atlantic and far North Atlantic sea surface temperatures during February and March. They found five seasons that met these conditions. Four of them had either neutral or La Niña conditions during the hurricane season and all four of them were very active years. Those four years were 1955, 1996, 1999 and 2008.
Exhibit 23. Analog Years For Hurricane Forecast
Source: Colorado State University, PPHB
The forecasters also found 2006, which had the same February-March conditions. That year, however, experienced an unexpected El Niño, which greatly reduced hurricane activity.
The CSU team anticipates 2011 to be slightly more active than what was experienced in the average of these five analog years due to the very active season predicted by their new statistical model. It is interesting that there were only two analog years that fit the parameters for both the December 2010 and April 2011 forecasts, and those years were 1999 and 2008.
Exhibit 24. Latest Hurricane Forecast Down Slightly
Source: Colorado State University, PPHB
The CSU forecast calls for a total of 16 named storms, down one from the December 2010 forecast total. It also expects there to be nine hurricanes and five major hurricanes. The total number of storm days will be down by five, from 85 to 80, with a similar reduction for each of the other storm categories.
In terms of landfall probabilities, the forecast calls for a 72% probability of a storm hitting the entire U.S. coastline compared to the 52% average for the past century. There is a 48% chance of a landing on the East Coast including the Florida peninsula compared to the historic 31% rate. For the Gulf Coast from the Florida Panhandle to Brownsville, Texas, there is a 47% chance of a tropical storm landfall versus the historical average of 30%. Despite the higher probabilities, nature is such that it is impossible to forecast with any degree of accuracy until a storm is on its way whether it will reach land. For the offshore energy industry, it will need to be on alert this hurricane season, although if the current pace of permitting continues, there won’t be too many offshore rigs to have to worry about this fall. Is that a backhanded positive?
Download the PDF Musings041211.pdf
Tuesday, April 12, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks
The latest forecast update from Professors Philip Klotzbach and William Gray of the Department of Atmospheric Science at the Colorado State University (CSU) says the upcoming hurricane season is expected to see above-average activity. The April 6th forecast is slightly lower than their December 2010 forecast largely due to uncertainty about the sea surface temperatures in both the South Pacific and South Atlantic oceans that can assist or retard the development and strengthening of tropical storms.
The forecasting team has developed a new April methodology based on a data collected from 1982-2010. There are four predictors employed in the model with two of them based on sea surface temperatures in the Atlantic and Pacific oceans. The Pacific Ocean for most of the past year has been cooler than normal, which helped contribute to the Atlantic basin’s storm activity last year mostly turning north before reaching the U.S. In general, sea surface temperatures in the eastern and central tropical Pacific Ocean have been 0.50C-1.00C below average.
Exhibit 21. Pacific Ocean Sea Surface Temperatures Low
Source: Colorado State University
On the other side of the globe, Atlantic Ocean sea surface temperatures remain at or above average levels. They have cooled recently but most likely that has been caused by a shift from a negative phase for the North Atlantic Oscillation to a positive phase. Atmospheric conditions currently are conducive for an active hurricane season as wind shear, a force that can limit the development and strengthening of tropical storms, across the basin has been well below average over the past two months.
Exhibit 22. Atlantic Ocean Temperatures Near Normal
Source: Colorado State University
With these conditions, the CSU forecasting team began looking for analog years to help fine-tune their forecast. They were looking for years generally characterized by weak to moderate La Niña conditions and above-average tropical Atlantic and far North Atlantic sea surface temperatures during February and March. They found five seasons that met these conditions. Four of them had either neutral or La Niña conditions during the hurricane season and all four of them were very active years. Those four years were 1955, 1996, 1999 and 2008.
Exhibit 23. Analog Years For Hurricane Forecast
Source: Colorado State University, PPHB
The forecasters also found 2006, which had the same February-March conditions. That year, however, experienced an unexpected El Niño, which greatly reduced hurricane activity.
The CSU team anticipates 2011 to be slightly more active than what was experienced in the average of these five analog years due to the very active season predicted by their new statistical model. It is interesting that there were only two analog years that fit the parameters for both the December 2010 and April 2011 forecasts, and those years were 1999 and 2008.
Exhibit 24. Latest Hurricane Forecast Down Slightly
Source: Colorado State University, PPHB
The CSU forecast calls for a total of 16 named storms, down one from the December 2010 forecast total. It also expects there to be nine hurricanes and five major hurricanes. The total number of storm days will be down by five, from 85 to 80, with a similar reduction for each of the other storm categories.
In terms of landfall probabilities, the forecast calls for a 72% probability of a storm hitting the entire U.S. coastline compared to the 52% average for the past century. There is a 48% chance of a landing on the East Coast including the Florida peninsula compared to the historic 31% rate. For the Gulf Coast from the Florida Panhandle to Brownsville, Texas, there is a 47% chance of a tropical storm landfall versus the historical average of 30%. Despite the higher probabilities, nature is such that it is impossible to forecast with any degree of accuracy until a storm is on its way whether it will reach land. For the offshore energy industry, it will need to be on alert this hurricane season, although if the current pace of permitting continues, there won’t be too many offshore rigs to have to worry about this fall. Is that a backhanded positive?
Download the PDF Musings041211.pdf
SunPower Receives Loan Guarantee From The Department of Energy
SunPower Receives Loan Guarantee From The Department of Energy
SunPower Corp (NASDAQ:SPWRA) received a conditional commitment Tuesday from the U.S. Department of Energy for a $1.187 billion loan guarantee to finance its 250-megawatt solar power plant in central California, according to a Reuters report.
The company's California Valley Solar Ranch in San Luis Obispo County will generate enough electricity to power 100,000 homes and will be one of the largest photovoltaic solar power plants in the world.
SunPower will design and build, as well as initially operate and maintain the solar plant, which it plans to then sell to NRG Energy (NYSE:NRG).
NRG Solar, a subsidiary of NRG Energy, will assume all ownership and financing responsibilities for the project, subject to certain conditions.
Construction is expected to begin in the second half of 2011, contingent on permitting and financing, with some of the project beginning operations by the end of this year, and the rest coming on line in 2012 and 2013.
SunPower is trading down 0.73% to $16.27 per share.
SunPower Corp (NASDAQ:SPWRA) received a conditional commitment Tuesday from the U.S. Department of Energy for a $1.187 billion loan guarantee to finance its 250-megawatt solar power plant in central California, according to a Reuters report.
The company's California Valley Solar Ranch in San Luis Obispo County will generate enough electricity to power 100,000 homes and will be one of the largest photovoltaic solar power plants in the world.
SunPower will design and build, as well as initially operate and maintain the solar plant, which it plans to then sell to NRG Energy (NYSE:NRG).
NRG Solar, a subsidiary of NRG Energy, will assume all ownership and financing responsibilities for the project, subject to certain conditions.
Construction is expected to begin in the second half of 2011, contingent on permitting and financing, with some of the project beginning operations by the end of this year, and the rest coming on line in 2012 and 2013.
SunPower is trading down 0.73% to $16.27 per share.
Shell, Gazprom CEOs Discuss Joint Projects
Shell, Gazprom CEOs Discuss Joint Projects
Tuesday, April 12, 2011
Dow Jones Newswires
by Jacob Gronholt-Pederson
The heads of energy giants Shell and Gazprom met Tuesday in Moscow to discuss potential joint projects in Russia and outside Europe, the Russian company said in a statement.
Peter Voser, chief executive of Shell, and Gazprom CEO Alexei Miller discussed the "implementation of joint projects in western Siberia and in eastern Russia," Gazprom said.
In addition, they talked about possible joint processing and distribution activities in Europe and Russia, as well as Gazprom participating in Shell's exploration and production projects elsewhere, the Russian company said.
Shell and Gazprom signed a memorandum of understanding last year on a global strategic partnership.
The two companies are already partners in the Sakhalin-2 project on Russia's Pacific coast.
Tuesday, April 12, 2011
Dow Jones Newswires
by Jacob Gronholt-Pederson
The heads of energy giants Shell and Gazprom met Tuesday in Moscow to discuss potential joint projects in Russia and outside Europe, the Russian company said in a statement.
Peter Voser, chief executive of Shell, and Gazprom CEO Alexei Miller discussed the "implementation of joint projects in western Siberia and in eastern Russia," Gazprom said.
In addition, they talked about possible joint processing and distribution activities in Europe and Russia, as well as Gazprom participating in Shell's exploration and production projects elsewhere, the Russian company said.
Shell and Gazprom signed a memorandum of understanding last year on a global strategic partnership.
The two companies are already partners in the Sakhalin-2 project on Russia's Pacific coast.
Internet Registry Opens for Hydraulic Fracturing Chemicals
Internet Registry Opens for Hydraulic Fracturing Chemicals
Tuesday, April 12, 2011
Rigzone Staff
by Karen Boman
The Ground Water Protection Council and the Interstate Oil and Gas Compact Commission on Monday launched a new website that allows oil and gas companies to disclose the chemical additives used in the hydraulic fracturing process on a well-by-well basis.
Chesapeake Energy has announced its active participation in the site, which is receiving funding support from the U.S. Department of Energy. The website will cover information on wells drilled starting with 2011.
Hydraulic fracturing fluid is used in developing deep shale horizontal wells, and is comprised of a mix of water and sand with small amounts of chemical additives to enhance production from otherwise inaccessible oil and gas reserves. Water and sand generally comprise about 98 percent of hydraulic fracturing fluid volume.
Chesapeake reports that it began loading well completion data onto the registry on Feb. 15, 2011, for wells where completion reports have been filed with the appropriate state agencies. Information has been uploaded covering 94 wells in Arkansas, Louisiana, Oklahoma, Pennsylvania, Texas and Wyoming.
"Providing further information about our drilling, completing and producing operations in today's environment is more critical than ever, and we believe this new public registry provides an immediate, workable and accurate way to present information about the additives of our hydraulic fracturing operations to all of our stakeholders," said Chesapeake CEO Aubrey K. McClendon.
Twenty-four companies have registered as participants on the website, and 11 of these companies, including Chesapeake, have begun using the website to provide detailed information about the additives in their hydraulic fracturing operations.
The website, www.fracfocus.org, includes information about how hydraulic fracturing works, about the chemicals used and how fresh ground water is protected. The website may also be used by the public.
Tuesday, April 12, 2011
Rigzone Staff
by Karen Boman
The Ground Water Protection Council and the Interstate Oil and Gas Compact Commission on Monday launched a new website that allows oil and gas companies to disclose the chemical additives used in the hydraulic fracturing process on a well-by-well basis.
Chesapeake Energy has announced its active participation in the site, which is receiving funding support from the U.S. Department of Energy. The website will cover information on wells drilled starting with 2011.
Hydraulic fracturing fluid is used in developing deep shale horizontal wells, and is comprised of a mix of water and sand with small amounts of chemical additives to enhance production from otherwise inaccessible oil and gas reserves. Water and sand generally comprise about 98 percent of hydraulic fracturing fluid volume.
Chesapeake reports that it began loading well completion data onto the registry on Feb. 15, 2011, for wells where completion reports have been filed with the appropriate state agencies. Information has been uploaded covering 94 wells in Arkansas, Louisiana, Oklahoma, Pennsylvania, Texas and Wyoming.
"Providing further information about our drilling, completing and producing operations in today's environment is more critical than ever, and we believe this new public registry provides an immediate, workable and accurate way to present information about the additives of our hydraulic fracturing operations to all of our stakeholders," said Chesapeake CEO Aubrey K. McClendon.
Twenty-four companies have registered as participants on the website, and 11 of these companies, including Chesapeake, have begun using the website to provide detailed information about the additives in their hydraulic fracturing operations.
The website, www.fracfocus.org, includes information about how hydraulic fracturing works, about the chemicals used and how fresh ground water is protected. The website may also be used by the public.
Gas Prices Continue Rise, Approach $4 A Gallon
Gas Prices Continue Rise, Approach $4 A Gallon
AAA reported today that the price of gas had reached a national average of $3.79 per gallon for regular grade, a $0.29 jump over the last 2 weeks, and nearly $1 higher than the same time last year.
Former president of Shell Oil John Hofmeister predicted that American could be paying $5 per gallon by 2012.
Drivers are already altering their habits. Data from MasterCard's Spending Pulse showed fuel consumption down 3.6% in the week ending April 1st.
The average price for a gallon of gas reached a peak of $4.11 on July 17, 2008.
Oil is trading down 3.42% to $106.16 per barrel.
AAA reported today that the price of gas had reached a national average of $3.79 per gallon for regular grade, a $0.29 jump over the last 2 weeks, and nearly $1 higher than the same time last year.
Former president of Shell Oil John Hofmeister predicted that American could be paying $5 per gallon by 2012.
Drivers are already altering their habits. Data from MasterCard's Spending Pulse showed fuel consumption down 3.6% in the week ending April 1st.
The average price for a gallon of gas reached a peak of $4.11 on July 17, 2008.
Oil is trading down 3.42% to $106.16 per barrel.
American Standard Acquires Acreage in Williston Basin
American Standard Acquires Acreage in Williston Basin
Tuesday, April 12, 2011
American Standard Energy Corp.
American Standard announced the acquisition of approximately 2,780 acres located in Mountrail County of North Dakota's Williston Basin, "the Bakken". The Company paid an average of $669 per acre for a total transaction price of $1,860,858.
The acreage is located within twenty separate mostly contiguous sections of the Parshall and Stanley Fields in the Williston Basin. This location offers the potential for rapid development due to current drilling operations to the north, south and west by EOG, Hunt, Brigham, Marathon and Sinclair among others. The acquisition also expands ASEN's footprint in the historically successful Bakken play, specifically within Mountrail County.
Scott Feldhacker, CEO of American Standard Energy Corp., stated, "We are excited to announce the expansion of our Bakken holdings, specifically in Mountrail County. These acres are well situated among acres held by leading Bakken exploration companies in an area of the play that is thought to be the most prolific and developed to date. This not only expands our holdings in the Bakken but demonstrates to the market and our shareholders the continued implementation of our growth strategy."
The Company's President, Richard MacQueen, also commented, "This transaction once again demonstrates our ability to make quick and successive acquisitions of quality acreage in the Bakken. Not only have we acquired highly desirable Mountrail acreage, we have acquired it at a highly desirable price."
Upon close of this transaction, the Company's Williston Basin, Bakken holdings total approximately 18,900 acres.
Tuesday, April 12, 2011
American Standard Energy Corp.
American Standard announced the acquisition of approximately 2,780 acres located in Mountrail County of North Dakota's Williston Basin, "the Bakken". The Company paid an average of $669 per acre for a total transaction price of $1,860,858.
The acreage is located within twenty separate mostly contiguous sections of the Parshall and Stanley Fields in the Williston Basin. This location offers the potential for rapid development due to current drilling operations to the north, south and west by EOG, Hunt, Brigham, Marathon and Sinclair among others. The acquisition also expands ASEN's footprint in the historically successful Bakken play, specifically within Mountrail County.
Scott Feldhacker, CEO of American Standard Energy Corp., stated, "We are excited to announce the expansion of our Bakken holdings, specifically in Mountrail County. These acres are well situated among acres held by leading Bakken exploration companies in an area of the play that is thought to be the most prolific and developed to date. This not only expands our holdings in the Bakken but demonstrates to the market and our shareholders the continued implementation of our growth strategy."
The Company's President, Richard MacQueen, also commented, "This transaction once again demonstrates our ability to make quick and successive acquisitions of quality acreage in the Bakken. Not only have we acquired highly desirable Mountrail acreage, we have acquired it at a highly desirable price."
Upon close of this transaction, the Company's Williston Basin, Bakken holdings total approximately 18,900 acres.
BNK Petroleum Subsidiary Scoops Up Spanish Concession
BNK Petroleum Subsidiary Scoops Up Spanish Concession
Tuesday, April 12, 2011
BNK Petroleum Inc.
BNK Petroleum announced that its wholly owned subsidiary Trofagas Hidrocarburos, S.L., has been awarded an oil and gas concession in the Autonomous Community of Cantabria, Spain totaling approximately 61,470 acres. This concession brings the Company's total acreage in Europe to about 3.6 million net acres in 5 separate basins.
This new concession located in the Cantabrian basin of Spain was acquired for a shale gas target. The Concession contains certain minimum requirements, which must be fulfilled by BNK to retain its interest. Some of the more significant minimum requirements consist of conducting geological work in the first year, drilling one vertical well each in years two, four, five and six.
Wolf E. Regener, BNK's President and CEO commented, "We are very pleased that we have been granted our first concession in Spain and are encouraged by the data we have gathered over the last two years. The shale gas data collected in Spain looks very promising. We look forward to developing shale gas in Spain both for our shareholders and the country of Spain."
Poland
The Company also announced that the Lebork S1 well on the Slupsk Concession is currently drilling at 3,517 meters, with over 220 meters of core taken. The core will be analyzed over the coming weeks. The Company anticipates that it will complete drilling and logging in the next week, at which time it will release an update with the available data. The majority of the analysis of the sidewall cores from the Wytowno #1 well are expected back from the subcontractor in May. The 1st well on the Starogard concession is expected to begin drilling sometime in June.
Tuesday, April 12, 2011
BNK Petroleum Inc.
BNK Petroleum announced that its wholly owned subsidiary Trofagas Hidrocarburos, S.L., has been awarded an oil and gas concession in the Autonomous Community of Cantabria, Spain totaling approximately 61,470 acres. This concession brings the Company's total acreage in Europe to about 3.6 million net acres in 5 separate basins.
This new concession located in the Cantabrian basin of Spain was acquired for a shale gas target. The Concession contains certain minimum requirements, which must be fulfilled by BNK to retain its interest. Some of the more significant minimum requirements consist of conducting geological work in the first year, drilling one vertical well each in years two, four, five and six.
Wolf E. Regener, BNK's President and CEO commented, "We are very pleased that we have been granted our first concession in Spain and are encouraged by the data we have gathered over the last two years. The shale gas data collected in Spain looks very promising. We look forward to developing shale gas in Spain both for our shareholders and the country of Spain."
Poland
The Company also announced that the Lebork S1 well on the Slupsk Concession is currently drilling at 3,517 meters, with over 220 meters of core taken. The core will be analyzed over the coming weeks. The Company anticipates that it will complete drilling and logging in the next week, at which time it will release an update with the available data. The majority of the analysis of the sidewall cores from the Wytowno #1 well are expected back from the subcontractor in May. The 1st well on the Starogard concession is expected to begin drilling sometime in June.
IOGA Calls Cuomo Admin. to Remain Committed to Expedited Nat. Gas Permits
IOGA Calls Cuomo Admin. to Remain Committed to Expedited Nat. Gas Permits
Tuesday, April 12, 2011
Independent O&G Association of New York
The Independent Oil & Gas Association of New York (IOGA of NY) wrote Governor Andrew Cuomo and all members of the New York State Legislature requesting an expedited review of permits that will enhance natural gas production in New York.
IOGA of NY, which represents nearly 400 members employing more than 4,500 people in the state, asked the governor to direct the Department of Environmental Conservation (DEC) to complete its revised Supplemental Generic Environmental Impact Statement (SGEIS) by July 1.
"Nearly three years has gone by since the state essentially halted the permitting of natural gas drilling in the Southern Tier," wrote Brad Gill, IOGA of NY executive director, in his letter to the governor. "During that time we have watched people, jobs, businesses and opportunity flee our state for Pennsylvania, Ohio and West Virginia, where those economies are rebounding strongly as a result of increased natural gas development."
The industry association also asked lawmakers to allow the DEC to complete the SGEIS, and reject all forms of obstructive legislation that would further delay responsible and well-regulated natural gas development.
"New York cannot afford to allow protests rooted in misinformation to halt the tremendous economic development opportunity that awaits our state," Gill wrote in his letter to each member of the Legislature. "I write to ask you to continue to apply reason, common sense and fact-based analysis as you consider the future of natural gas development in New York."
The letters were accompanied by two newly released informational sheets that point out the economic success that other states are experiencing from Marcellus Shale drilling activity.
"Our industry is asking the state to provide an economic opportunity that is balanced by environmental protection," Gill wrote. We are "asking that policymakers work right now to embrace the economic opportunity that is balanced by environmental protection, and allow science, reason and our existing rigorous SGEIS process to trump emotion as New York works to derive the benefits of natural gas."
Tuesday, April 12, 2011
Independent O&G Association of New York
The Independent Oil & Gas Association of New York (IOGA of NY) wrote Governor Andrew Cuomo and all members of the New York State Legislature requesting an expedited review of permits that will enhance natural gas production in New York.
IOGA of NY, which represents nearly 400 members employing more than 4,500 people in the state, asked the governor to direct the Department of Environmental Conservation (DEC) to complete its revised Supplemental Generic Environmental Impact Statement (SGEIS) by July 1.
"Nearly three years has gone by since the state essentially halted the permitting of natural gas drilling in the Southern Tier," wrote Brad Gill, IOGA of NY executive director, in his letter to the governor. "During that time we have watched people, jobs, businesses and opportunity flee our state for Pennsylvania, Ohio and West Virginia, where those economies are rebounding strongly as a result of increased natural gas development."
The industry association also asked lawmakers to allow the DEC to complete the SGEIS, and reject all forms of obstructive legislation that would further delay responsible and well-regulated natural gas development.
"New York cannot afford to allow protests rooted in misinformation to halt the tremendous economic development opportunity that awaits our state," Gill wrote in his letter to each member of the Legislature. "I write to ask you to continue to apply reason, common sense and fact-based analysis as you consider the future of natural gas development in New York."
The letters were accompanied by two newly released informational sheets that point out the economic success that other states are experiencing from Marcellus Shale drilling activity.
"Our industry is asking the state to provide an economic opportunity that is balanced by environmental protection," Gill wrote. We are "asking that policymakers work right now to embrace the economic opportunity that is balanced by environmental protection, and allow science, reason and our existing rigorous SGEIS process to trump emotion as New York works to derive the benefits of natural gas."
Statoil Submits Fast-Track Plan for Vigdis
Statoil Submits Fast-Track Plan for Vigdis
Tuesday, April 12, 2011
Statoil
by SubseaIQ
Statoil has submitted a plan for development and operation (PDO) for the Vigdis North-East development in the North Sea to the Norwegian Ministry of Petroleum and Energy. Production start is scheduled for December 2012.
This is the second fast-track development plan submitted to the Norwegian Ministry of Petroleum and Energy this year. The Visund South fast-track development plan was handed over to the ministry earlier this year.
"We envisage the first five fast-track developments coming on stream at the turn of the year 2012/13," said Øystein Michelsen, Statoil's executive vice president for Development and Production Norway. "The two plans we have submitted so far this year prove that we are on the right track regarding this part of our portfolio."
Vigdis North-East is planned as a subsea development located 1.6 kilometers from the existing subsea installation on the Vigdis field.
The development will comprise a standard template with four wells – three producers and one water injector. Vigdis North-East will be tied back to the Snorre A field, which is located approximately seven kilometers away, via the existing infrastructure.
Produced oil and gas will be transported in a new pipeline to the existing Vigdis B template and then piped to Snorre A.
Recoverable reserves are estimated at around 33 million barrels of oil equivalent, with investments calculated at NOK 4.2 billion (current price).
Infrastructure-led discoveries help extend the life of the installations and are an important contributor to optimizing potential on the Norwegian continental shelf. Snorre is one of the areas with an established infrastructure and spare processing capacity.
"We have extensive experience and expertise in the area in addition to available processing and transport capacity," said Halfdan Knudsen, head of the fast-track portfolio. "Therefore Vigdis North-East is suited for a fast-track development with standard solutions. It will also increase the volumes sent to Snorre A."
Vigdis North-East is one of the projects of the fast-track portfolio, which was launched in 2010. The goal is to make smaller finds profitable by halving the time from discovery to production through the utilisation of standard solutions.
Tuesday, April 12, 2011
Statoil
by SubseaIQ
Statoil has submitted a plan for development and operation (PDO) for the Vigdis North-East development in the North Sea to the Norwegian Ministry of Petroleum and Energy. Production start is scheduled for December 2012.
This is the second fast-track development plan submitted to the Norwegian Ministry of Petroleum and Energy this year. The Visund South fast-track development plan was handed over to the ministry earlier this year.
"We envisage the first five fast-track developments coming on stream at the turn of the year 2012/13," said Øystein Michelsen, Statoil's executive vice president for Development and Production Norway. "The two plans we have submitted so far this year prove that we are on the right track regarding this part of our portfolio."
Vigdis North-East is planned as a subsea development located 1.6 kilometers from the existing subsea installation on the Vigdis field.
The development will comprise a standard template with four wells – three producers and one water injector. Vigdis North-East will be tied back to the Snorre A field, which is located approximately seven kilometers away, via the existing infrastructure.
Produced oil and gas will be transported in a new pipeline to the existing Vigdis B template and then piped to Snorre A.
Recoverable reserves are estimated at around 33 million barrels of oil equivalent, with investments calculated at NOK 4.2 billion (current price).
Infrastructure-led discoveries help extend the life of the installations and are an important contributor to optimizing potential on the Norwegian continental shelf. Snorre is one of the areas with an established infrastructure and spare processing capacity.
"We have extensive experience and expertise in the area in addition to available processing and transport capacity," said Halfdan Knudsen, head of the fast-track portfolio. "Therefore Vigdis North-East is suited for a fast-track development with standard solutions. It will also increase the volumes sent to Snorre A."
Vigdis North-East is one of the projects of the fast-track portfolio, which was launched in 2010. The goal is to make smaller finds profitable by halving the time from discovery to production through the utilisation of standard solutions.
Calvalley Delivers First Oil into MEPS
Calvalley Delivers First Oil into MEPS
Tuesday, April 12, 2011
Calvalley Petroleum Inc.
Calvalley has commenced delivery of Block 9 production of crude oil into the Masila Export Pipeline System ("MEPS") through the Company's Truck Offloading Facilities ("TOF") located at Block 51. Current deliveries utilize existing space in the Block 51 metering system. This temporary arrangement will be in place until early May when the Company's own metering system will be fully functional.
With the initiation of operations at the TOF, Calvalley is a now able to begin production of the first commercial oil from the Ras Nowmah and Al Roidhat fields, into the MEPS.
As well, and despite the unsettled security environment in Yemen, Calvalley continues its activities, as close to normal as possible, with two drilling rigs and one service rig in operation.
Completion of the TOF is a major milestone in Calvalley's program of increasing production, by bringing significant volumes of shut-in production on line, takes advantage of higher oil prices and market accessibility provided by the MEPS. As a result, all of Calvalley's blended crude oil will receive the Masila Blend price which is benchmarked to Brent Crude pricing.
Tuesday, April 12, 2011
Calvalley Petroleum Inc.
Calvalley has commenced delivery of Block 9 production of crude oil into the Masila Export Pipeline System ("MEPS") through the Company's Truck Offloading Facilities ("TOF") located at Block 51. Current deliveries utilize existing space in the Block 51 metering system. This temporary arrangement will be in place until early May when the Company's own metering system will be fully functional.
With the initiation of operations at the TOF, Calvalley is a now able to begin production of the first commercial oil from the Ras Nowmah and Al Roidhat fields, into the MEPS.
As well, and despite the unsettled security environment in Yemen, Calvalley continues its activities, as close to normal as possible, with two drilling rigs and one service rig in operation.
Completion of the TOF is a major milestone in Calvalley's program of increasing production, by bringing significant volumes of shut-in production on line, takes advantage of higher oil prices and market accessibility provided by the MEPS. As a result, all of Calvalley's blended crude oil will receive the Masila Blend price which is benchmarked to Brent Crude pricing.
Oil Companies Have Plan for Lake Spill Equipment
Oil Companies Have Plan for Lake Spill Equipment
Tuesday, April 12, 2011
The Bismarck Tribune, Bismarck, North Dakota
by Lauren Donovan, The Bismarck Tribune, N.D.
North Dakota's first oil and saltwater spill into Lake Sakakawea caught the industry unprepared for a lake cleanup, but that could soon change.
A group of oil well and pipeline owners was already making plans to spend $1 million on boats, booms, skimmers and ice-borne pumps for fast response to a lake accident when the first spill into the lake was reported April 2.
Petro-Hunt LLC says five barrels of oil and 100 barrels of saltwater escaped a pipeline rupture at well north of Keene, near the lake on the south side.
A committee of 12 well owners and three pipeline companies with wells and pipelines near the lake started talking after last summer's BP Deepwater well blowout in the Gulf.
Committee chairman Jack Braun, of Whiting Petroleum, one of the largest oil producers in the oil patch, said the recent spill into Lake Sakakawea could put plans on the fast track.
"My reaction (to the lake spill) was, 'Oh, no.' I was really disappointed. This is a black eye for the entire industry. It might encourage the committee to work faster," Braun said.
Most of the oil was recovered, but all the saltwater reached the lake, though diluted by running snow-melt.
Rep. Kenton Onstad, D-Parshall, said he's asked state oil regulators about the lack of a statewide plan in the event of a lake spill.
"What's the plan when a tanker driver from Texas slides around the curve (at New Town) and goes off the bridge? What's the plan for that?" he said.
He said oil wells could be sited a safe distance from the water and reach oil with long horizontal legs.
"Why play with disaster?" Onstad said. "So many wells are near water. There should be better precautions so that any major spill doesn't hit the lake."
The Dakota Resource Council, an environmental group, said the first lake spill is among eight reported spills in a year, and troubling because lake water is used for community drinking water and agriculture.
Braun said the companies recognize the weakness in the overall spill response plan and are voluntarily moving to make it stronger.
"Our goal is create a cooperative to maintain spill response equipment that's big enough to operate on the lake, or get oil under the ice," he said. "We recognize the potential danger and we want to voluntarily do what's right," Braun said.
Braun said the committee members identified more than 100 of their own wells and a "handful" of pipelines close to the lake, or on tributaries. "These have the potential to either spill directly into the lake, or into drainage to the lake," he said.
One oil pipeline is attached to the underside of the 4 Bears bridge at New Town, which spans the lake.
He said a lake accident is more likely to involve hundreds, not thousands of barrels. A possible scenario is loss of well control causing oil or mist to shoot out from the well, or a pipeline break, which could potentially be worse, he said.
Braun said the committee is looking into how to jointly own the equipment, where to store it and training. The committee will meet Thursday to review draft agreements, he said. Part of the discussion will be about sharing equipment with companies that aren't in on the purchase.
If it goes well, Braun said it's possible the equipment could be purchased within months.
He said spill prevention is engineered into well equipment, into the strength of pipes and valves, and maintained through inspections for corrosion and other problems.
By law, oil companies are required to have spill response plans. There are about 20 response trailers in the oil patch with personal protection, booms, absorbent pads, fencing, and the like for a land spill. None of that gets to oil out on the lake, and that presented a troublesome gap in the overall response plan, Braun said.
When an SM Energy oil well near Arnegard caught fire last month, specialized well control equipment was trucked from Texas and arrived four days later.
Braun said having lake response equipment in the oil patch means it could be on the water within hours. He said committee plans to purchase a couple of larger boats, capable of pulling up to 5,000 feet of oil-trapping boom, a couple of smaller work boats, two oil skimmers and possibly an air boat for working close to shore. An ice response would involve equipment to drill holes or trenches on the ice to accommodate pumps.
Onstad said he thinks state regulators need to give more thought to wells sited near the lake before there is a major spill.
"A double dike (around wells) is not good enough," he said.
Tuesday, April 12, 2011
The Bismarck Tribune, Bismarck, North Dakota
by Lauren Donovan, The Bismarck Tribune, N.D.
North Dakota's first oil and saltwater spill into Lake Sakakawea caught the industry unprepared for a lake cleanup, but that could soon change.
A group of oil well and pipeline owners was already making plans to spend $1 million on boats, booms, skimmers and ice-borne pumps for fast response to a lake accident when the first spill into the lake was reported April 2.
Petro-Hunt LLC says five barrels of oil and 100 barrels of saltwater escaped a pipeline rupture at well north of Keene, near the lake on the south side.
A committee of 12 well owners and three pipeline companies with wells and pipelines near the lake started talking after last summer's BP Deepwater well blowout in the Gulf.
Committee chairman Jack Braun, of Whiting Petroleum, one of the largest oil producers in the oil patch, said the recent spill into Lake Sakakawea could put plans on the fast track.
"My reaction (to the lake spill) was, 'Oh, no.' I was really disappointed. This is a black eye for the entire industry. It might encourage the committee to work faster," Braun said.
Most of the oil was recovered, but all the saltwater reached the lake, though diluted by running snow-melt.
Rep. Kenton Onstad, D-Parshall, said he's asked state oil regulators about the lack of a statewide plan in the event of a lake spill.
"What's the plan when a tanker driver from Texas slides around the curve (at New Town) and goes off the bridge? What's the plan for that?" he said.
He said oil wells could be sited a safe distance from the water and reach oil with long horizontal legs.
"Why play with disaster?" Onstad said. "So many wells are near water. There should be better precautions so that any major spill doesn't hit the lake."
The Dakota Resource Council, an environmental group, said the first lake spill is among eight reported spills in a year, and troubling because lake water is used for community drinking water and agriculture.
Braun said the companies recognize the weakness in the overall spill response plan and are voluntarily moving to make it stronger.
"Our goal is create a cooperative to maintain spill response equipment that's big enough to operate on the lake, or get oil under the ice," he said. "We recognize the potential danger and we want to voluntarily do what's right," Braun said.
Braun said the committee members identified more than 100 of their own wells and a "handful" of pipelines close to the lake, or on tributaries. "These have the potential to either spill directly into the lake, or into drainage to the lake," he said.
One oil pipeline is attached to the underside of the 4 Bears bridge at New Town, which spans the lake.
He said a lake accident is more likely to involve hundreds, not thousands of barrels. A possible scenario is loss of well control causing oil or mist to shoot out from the well, or a pipeline break, which could potentially be worse, he said.
Braun said the committee is looking into how to jointly own the equipment, where to store it and training. The committee will meet Thursday to review draft agreements, he said. Part of the discussion will be about sharing equipment with companies that aren't in on the purchase.
If it goes well, Braun said it's possible the equipment could be purchased within months.
He said spill prevention is engineered into well equipment, into the strength of pipes and valves, and maintained through inspections for corrosion and other problems.
By law, oil companies are required to have spill response plans. There are about 20 response trailers in the oil patch with personal protection, booms, absorbent pads, fencing, and the like for a land spill. None of that gets to oil out on the lake, and that presented a troublesome gap in the overall response plan, Braun said.
When an SM Energy oil well near Arnegard caught fire last month, specialized well control equipment was trucked from Texas and arrived four days later.
Braun said having lake response equipment in the oil patch means it could be on the water within hours. He said committee plans to purchase a couple of larger boats, capable of pulling up to 5,000 feet of oil-trapping boom, a couple of smaller work boats, two oil skimmers and possibly an air boat for working close to shore. An ice response would involve equipment to drill holes or trenches on the ice to accommodate pumps.
Onstad said he thinks state regulators need to give more thought to wells sited near the lake before there is a major spill.
"A double dike (around wells) is not good enough," he said.
IMF Projects 2011 U.S. Deficit As Largest Among Developed Nation
IMF Projects 2011 U.S. Deficit As Largest Among Developed Nation
The U.S. fiscal deficit is set to be the largest among major developed economies this year, beating out Japan and the U.K., with a shortfall representing 10.8% of GDP, the IMF said in a report released today.
President Barack Obama will unveil long-term proposals for reducing the deficit to sustainable levels and getting the national debt under control on Wednesday. He will have to cut the deficit by at least 5% of GDP to attain his pledge of halving the deficit by the end of his four-year term.
The IMF wrote in its Fiscal Monitor report, "Market concerns about sustainability remain subdued in the U.S., but a further delay of action could be fiscally costly, with deficit increases exacerbated by rising yields,"
The IMF said most advanced economies are taking steps to reign in budget shortfalls, while two of the world's three largest economies, Japan and the United States, have delayed such measures.
The IMF expressed concern that upcoming elections in Japan and the United States, as well as France, could complicate policy efforts needed to reduce deficit spending.
The U.S. fiscal deficit is set to be the largest among major developed economies this year, beating out Japan and the U.K., with a shortfall representing 10.8% of GDP, the IMF said in a report released today.
President Barack Obama will unveil long-term proposals for reducing the deficit to sustainable levels and getting the national debt under control on Wednesday. He will have to cut the deficit by at least 5% of GDP to attain his pledge of halving the deficit by the end of his four-year term.
The IMF wrote in its Fiscal Monitor report, "Market concerns about sustainability remain subdued in the U.S., but a further delay of action could be fiscally costly, with deficit increases exacerbated by rising yields,"
The IMF said most advanced economies are taking steps to reign in budget shortfalls, while two of the world's three largest economies, Japan and the United States, have delayed such measures.
The IMF expressed concern that upcoming elections in Japan and the United States, as well as France, could complicate policy efforts needed to reduce deficit spending.
General Motors Invests $100 Million to Add 30 Jobs in Rochester, N.Y.
General Motors Invests $100 Million to Add 30 Jobs in Rochester, N.Y.
General Motors (GM) announced Tuesday that it will invest $100 million towards more jobs and automotive components. The auto giant said it plans to add 30 jobs and purchase tooling and equipment for its GM Components Holdings Rochester Operation.
This would enable the facility to produce a new generation of fuel-efficient small block car and truck engines. The new jobs will be added to an existing workforce of 826 hourly and salaried employees at the Rochester facility.
GM's total investment in its new small block engine is now approximately $1.1 billion, creating or retaining more than 2,400 jobs. As far as where GM is sitting in the market, shares are up 0.19% to $30.83.
General Motors (GM) announced Tuesday that it will invest $100 million towards more jobs and automotive components. The auto giant said it plans to add 30 jobs and purchase tooling and equipment for its GM Components Holdings Rochester Operation.
This would enable the facility to produce a new generation of fuel-efficient small block car and truck engines. The new jobs will be added to an existing workforce of 826 hourly and salaried employees at the Rochester facility.
GM's total investment in its new small block engine is now approximately $1.1 billion, creating or retaining more than 2,400 jobs. As far as where GM is sitting in the market, shares are up 0.19% to $30.83.
Statoil ADRs Off 3%; Company Looking to Sell Gassled Stake to Free Up Capital
Statoil ADRs Off 3%; Company Looking to Sell Gassled Stake to Free Up Capital
ADRs of Statoil ASA (STO) are down as Bloomberg reports that the oil producer--the largest in Norway--is looking at selling a portion of its 28.5% stake in Norwegian gas-pipeline network Gassled to free up capital.
Already, Exxon Mobil (XOM) agreed last year to sell its 9.43% stake in the network to Njord Gas Infrastructure.
Statoil ADRs are down 3.1%, or $0.90, to $27.96.
ADRs of Statoil ASA (STO) are down as Bloomberg reports that the oil producer--the largest in Norway--is looking at selling a portion of its 28.5% stake in Norwegian gas-pipeline network Gassled to free up capital.
Already, Exxon Mobil (XOM) agreed last year to sell its 9.43% stake in the network to Njord Gas Infrastructure.
Statoil ADRs are down 3.1%, or $0.90, to $27.96.
Statoil, Partners Sign $1.5B EPC Contract with Petrofac
Statoil, Partners Sign $1.5B EPC Contract with Petrofac
Tuesday, April 12, 2011
Statoil
Statoil, BP and Sonatrach have signed a USD 1.15 billion engineering, procurement and construction (EPC) contract with Petrofac International (UAE) LLC in Algiers for the execution of the In Salah Southern Fields development project.
The EPC contract is part of the phase two development of the In Salah license. For Development and Production International the project marks an important step towards maturing barrels for profitable production.
The three gas fields – Krechba, Teg and Reg – located in the northern part of the license, were initially developed in phase one, with the objective of delivering a production profile of nine billion cubic meters of gas annually. This phase started in late 2001, and first commercial gas was delivered in July 2004.
Based on the expected decline of gas production from these three fields, phase two of the development has now implemented to maintain the production plateau and sustain long-term gas sales commitments. It consists of four gas fields – Garet El Bifna, Gour Mahmoud, In Salah and Hassi Moumene – in the southern part of the license.
Under the EPC contract Petrofac will build a number of facilities – including well pads, manifolds, flowlines, and a new central processing facility (CPF) with a gas processing capacity of 17 million cubic meters per day. The CPF will be constructed north of In Salah town and tied back to the existing producing facilities located in Reg for further transport of the gas to Krechba CPF for carbon dioxide removal and gas export.
In his speech, Victor Sneberg, Statoil's country president in Algeria, stated his expectation to Petrofac to deliver on time, cost and schedule.
First gas from the Southern Fields development project is expected for the first half of 2014. Gas produced from In Salah is marketed by joint marketing company "In Salah Gas Limited" – an association between Sonatrach, BP and Statoil. The three partners in the In Salah license have investment shares of 35% (Sonatrach), 33.15% (BP) and 31.85% (Statoil), respectively.
Tuesday, April 12, 2011
Statoil
Statoil, BP and Sonatrach have signed a USD 1.15 billion engineering, procurement and construction (EPC) contract with Petrofac International (UAE) LLC in Algiers for the execution of the In Salah Southern Fields development project.
The EPC contract is part of the phase two development of the In Salah license. For Development and Production International the project marks an important step towards maturing barrels for profitable production.
The three gas fields – Krechba, Teg and Reg – located in the northern part of the license, were initially developed in phase one, with the objective of delivering a production profile of nine billion cubic meters of gas annually. This phase started in late 2001, and first commercial gas was delivered in July 2004.
Based on the expected decline of gas production from these three fields, phase two of the development has now implemented to maintain the production plateau and sustain long-term gas sales commitments. It consists of four gas fields – Garet El Bifna, Gour Mahmoud, In Salah and Hassi Moumene – in the southern part of the license.
Under the EPC contract Petrofac will build a number of facilities – including well pads, manifolds, flowlines, and a new central processing facility (CPF) with a gas processing capacity of 17 million cubic meters per day. The CPF will be constructed north of In Salah town and tied back to the existing producing facilities located in Reg for further transport of the gas to Krechba CPF for carbon dioxide removal and gas export.
In his speech, Victor Sneberg, Statoil's country president in Algeria, stated his expectation to Petrofac to deliver on time, cost and schedule.
First gas from the Southern Fields development project is expected for the first half of 2014. Gas produced from In Salah is marketed by joint marketing company "In Salah Gas Limited" – an association between Sonatrach, BP and Statoil. The three partners in the In Salah license have investment shares of 35% (Sonatrach), 33.15% (BP) and 31.85% (Statoil), respectively.
UBS Raises Its Target Price For Teco Energy, Reiterates Buy Rating
UBS Raises Its Target Price For Teco Energy, Reiterates Buy Rating
UBS bumped its target price for Teco Energy (NYSE:TE) to $20.50 from $20.00 and reiterated its buy rating on the company.
The bank cited the fact that its global research team has again raised its metallurgical coal price estimates for 2011, 2012, and 2013.
TECO Energy has a potential upside of 0.7% based on a current price of $18.71 and an average consensus analyst price target of $18.84.
UBS bumped its target price for Teco Energy (NYSE:TE) to $20.50 from $20.00 and reiterated its buy rating on the company.
The bank cited the fact that its global research team has again raised its metallurgical coal price estimates for 2011, 2012, and 2013.
TECO Energy has a potential upside of 0.7% based on a current price of $18.71 and an average consensus analyst price target of $18.84.
Blackstone, Alta Invest up to $1B to Jointly Develop N. America Assets
Blackstone, Alta Invest up to $1B to Jointly Develop N. America Assets
Tuesday, April 12, 2011
The Blackstone Group
Alta and Blackstone announced the formation of Alta Energy Partners, and a concurrent commitment to invest up to $1 billion via this entity to acquire and develop unconventional oil and gas assets in North America.
Founded in 1999 by Joseph G. Greenberg, its President and CEO, Alta Resources has been a leader in the development of shale gas assets from the Fayetteville shale basin in Arkansas to the Marcellus shale field in Pennsylvania. George P. Mitchell, a partner in Alta Resources, is widely regarded as the father of shale gas for his pioneering role in developing the Barnett shale in Texas.
Alta Resources and Blackstone have worked together recently to evaluate joint investments in unconventional oil & gas assets and have identified a number of potentially attractive investment opportunities to lease or acquire acreage in emerging and developed shale basins in North America.
Mr. Greenberg said, "I am delighted that Blackstone has chosen to partner with Alta Resources. Millions of acres are currently leased for North American shale oil and gas, requiring extraordinary amounts of capital to develop. We believe the combination of Alta's experienced shale gas technical team with Blackstone's strong capital base, network, and industry knowledge will allow Alta Energy Partners to stand apart as the partner of choice for companies seeking joint ventures or exits for their shale oil and gas assets."
David I. Foley, a Senior Managing Director at Blackstone and head of Blackstone's private equity investment activities in the energy and natural resources sector, commented, "Identifying and partnering with exceptional management talent is a fundamental element of Blackstone's investment philosophy and we are very pleased to have the opportunity to back Joe Greenberg and his team in this investment. This management team has worked together successfully for a number of years, has very strong geological and technical skills and a track record of generating outstanding returns for their investors."
Tuesday, April 12, 2011
The Blackstone Group
Alta and Blackstone announced the formation of Alta Energy Partners, and a concurrent commitment to invest up to $1 billion via this entity to acquire and develop unconventional oil and gas assets in North America.
Founded in 1999 by Joseph G. Greenberg, its President and CEO, Alta Resources has been a leader in the development of shale gas assets from the Fayetteville shale basin in Arkansas to the Marcellus shale field in Pennsylvania. George P. Mitchell, a partner in Alta Resources, is widely regarded as the father of shale gas for his pioneering role in developing the Barnett shale in Texas.
Alta Resources and Blackstone have worked together recently to evaluate joint investments in unconventional oil & gas assets and have identified a number of potentially attractive investment opportunities to lease or acquire acreage in emerging and developed shale basins in North America.
Mr. Greenberg said, "I am delighted that Blackstone has chosen to partner with Alta Resources. Millions of acres are currently leased for North American shale oil and gas, requiring extraordinary amounts of capital to develop. We believe the combination of Alta's experienced shale gas technical team with Blackstone's strong capital base, network, and industry knowledge will allow Alta Energy Partners to stand apart as the partner of choice for companies seeking joint ventures or exits for their shale oil and gas assets."
David I. Foley, a Senior Managing Director at Blackstone and head of Blackstone's private equity investment activities in the energy and natural resources sector, commented, "Identifying and partnering with exceptional management talent is a fundamental element of Blackstone's investment philosophy and we are very pleased to have the opportunity to back Joe Greenberg and his team in this investment. This management team has worked together successfully for a number of years, has very strong geological and technical skills and a track record of generating outstanding returns for their investors."
BPZ Concludes Seismic Work at Peru Blocks
BPZ Concludes Seismic Work at Peru Blocks
Tuesday, April 12, 2011
BPZ Resources Inc.
BPZ Resources provided an update to its operations in northwest Peru.
Production
For the first quarter ended March 31, 2011, total production was approximately 381,000 barrels of oil (4,233 barrels of oil per day, "bopd") from the offshore Corvina and Albacora fields in Block Z-1. This compares to total production of 414,000 barrels of oil (4,500 bopd) in the fourth quarter of 2010. The lower production in first quarter was due to shutting in well A-14XD in the Albacora field on January 24, 2011.
Albacora and Corvina Permits
Authorization for interference testing along with associated gas flaring covering a four month period beginning June 1, 2011, has been received from the Ministry of Energy and Mining of Peru for Albacora. The permits are for the Company's A-14XD, A-9G, and A-13E oil wells, with the latter two having been drilled by a previous operator, which are all currently shut-in at the Albacora platform. As a result, workovers will first be conducted on the A-9G and A-13E wells, with an estimated start in May 2011. Each well is expected to be opened at various intervals, both on an individual basis and simultaneously, during the four-month period to test reservoir connectivity of the sands that were producing at the A-14XD well. Upon completion of the interference testing, the Company plans to open previously untested zones in each of the three wells. However, in order to produce from those new zones, we must request authorization to flare associated gas until the injection equipment is installed at the Albacora platform which is currently scheduled for year-end 2011.
At Corvina, the permanent production facilities including the compressor are operating at expected efficiency levels. The Company has received approval to maintain the wells open while the compressor undergoes scheduled maintenance during the current calendar year. As a result of obtaining the authorization for interference testing at Albacora, the snubbing unit will not be moved to the Corvina platform as originally planned as it will first be used to complete the Albacora workovers.
The additional production from the interference testing at Albacora is expected to offset the anticipated lower than forecasted production from Corvina due to the delay in performing workovers on certain Corvina wells. As such, the Company maintains the previously provided total production guidance of approximately 4,000 bopd for the year 2011.
Seismic Surveys
Block XXIII
The 3-D seismic survey covering approximately 370 square kilometers in the northern section of onshore Block XXIII was completed in January 2011. The 3-D seismic survey was conducted to better delineate the Mancora gas play and the potential oil prospectivity in the Heath formation. To further delineate the oil potential of Block XXIII, in October 2010 we completed a 2-D seismic covering 312 kilometers in the southern section where we are following the trend of the adjacent Talara basin oil fields. Processing is expected to be completed by mid-year 2011.
Block XXII
In March 2011, a 258 kilometer, 2-D seismic survey was completed that covered several oil leads following the trend of nearby oil fields in adjacent blocks. Processing is also expected to be completed by mid-year 2011.
Block Z-1
The Company is continuing the process aimed at securing the permit to acquire the offshore 3-D seismic survey in Block Z-1. The public audiences were completed in January, 2011 and the governmental agencies are finalizing their review. We remain optimistic about obtaining the required seismic permit by the end of the second quarter.
Block XIX - Pampa la Gallina
We have been granted a 45-day deferral on drilling the Pampa la Gallina (PLG) onshore well due to contractor delays in completing the rig refurbishment. This defers the commitment deadline to drill and log the PLG well to mid July 2011. The Company may also request an extension of up to six months beyond the July deadline.
Standby Costs and Other Income
As previously disclosed, the Petrex-09 rig formerly utilized at the Corvina field is being refurbished and upgraded at no cost to the Company in order to enhance its capability in preparation for drilling an exploration well in the onshore PLG prospect in Block XIX. Reduced standby rates for the rig are being charged to the Company during the refurbishment and will continue until the rig is utilized.
Also as previously disclosed, the Petrex-18 rig, formerly utilized at the Albacora field, is under lease to another operator through November 15, 2011. The Company plans to resume drilling at Albacora after the 3-D seismic survey on offshore Block Z-1 is completed and the data is processed and interpreted.
Accordingly, standby costs for calendar year 2011 are expected to range between $10 million and $12 million. However, the Company intends to continue to pursue opportunities to further reduce these standby costs such as subleasing the Petrex-09 rig to another operator while not being utilized by the Company.
In addition, we have reached an agreement to charter to that same operator our BPZ-02 barge that supports the Petrex 18 drilling rig, as well as the Don Fernando construction barge, and are working on the possibility of chartering the Company's floating production, storage and offloading (FPSO) barge, the Namoku, as well. Rental income from these vessels is expected to offset related costs.
President and CEO, Manolo Zuniga commented, "We are very pleased that the seismic work on Blocks XXII and XXIII was completed as planned. This work will allow us to better map the oil and gas leads in these blocks." Mr. Zuniga continued, "The progress we are making on all our growth initiatives has been made possible by our close working relationship with the Peruvian authorities. We are appreciative of the spirit of cooperation that has been established and we look forward to continuing to partner together. Indeed, strong partnerships contribute greatly to the goals we have set for our Company."
Tuesday, April 12, 2011
BPZ Resources Inc.
BPZ Resources provided an update to its operations in northwest Peru.
Production
For the first quarter ended March 31, 2011, total production was approximately 381,000 barrels of oil (4,233 barrels of oil per day, "bopd") from the offshore Corvina and Albacora fields in Block Z-1. This compares to total production of 414,000 barrels of oil (4,500 bopd) in the fourth quarter of 2010. The lower production in first quarter was due to shutting in well A-14XD in the Albacora field on January 24, 2011.
Albacora and Corvina Permits
Authorization for interference testing along with associated gas flaring covering a four month period beginning June 1, 2011, has been received from the Ministry of Energy and Mining of Peru for Albacora. The permits are for the Company's A-14XD, A-9G, and A-13E oil wells, with the latter two having been drilled by a previous operator, which are all currently shut-in at the Albacora platform. As a result, workovers will first be conducted on the A-9G and A-13E wells, with an estimated start in May 2011. Each well is expected to be opened at various intervals, both on an individual basis and simultaneously, during the four-month period to test reservoir connectivity of the sands that were producing at the A-14XD well. Upon completion of the interference testing, the Company plans to open previously untested zones in each of the three wells. However, in order to produce from those new zones, we must request authorization to flare associated gas until the injection equipment is installed at the Albacora platform which is currently scheduled for year-end 2011.
At Corvina, the permanent production facilities including the compressor are operating at expected efficiency levels. The Company has received approval to maintain the wells open while the compressor undergoes scheduled maintenance during the current calendar year. As a result of obtaining the authorization for interference testing at Albacora, the snubbing unit will not be moved to the Corvina platform as originally planned as it will first be used to complete the Albacora workovers.
The additional production from the interference testing at Albacora is expected to offset the anticipated lower than forecasted production from Corvina due to the delay in performing workovers on certain Corvina wells. As such, the Company maintains the previously provided total production guidance of approximately 4,000 bopd for the year 2011.
Seismic Surveys
Block XXIII
The 3-D seismic survey covering approximately 370 square kilometers in the northern section of onshore Block XXIII was completed in January 2011. The 3-D seismic survey was conducted to better delineate the Mancora gas play and the potential oil prospectivity in the Heath formation. To further delineate the oil potential of Block XXIII, in October 2010 we completed a 2-D seismic covering 312 kilometers in the southern section where we are following the trend of the adjacent Talara basin oil fields. Processing is expected to be completed by mid-year 2011.
Block XXII
In March 2011, a 258 kilometer, 2-D seismic survey was completed that covered several oil leads following the trend of nearby oil fields in adjacent blocks. Processing is also expected to be completed by mid-year 2011.
Block Z-1
The Company is continuing the process aimed at securing the permit to acquire the offshore 3-D seismic survey in Block Z-1. The public audiences were completed in January, 2011 and the governmental agencies are finalizing their review. We remain optimistic about obtaining the required seismic permit by the end of the second quarter.
Block XIX - Pampa la Gallina
We have been granted a 45-day deferral on drilling the Pampa la Gallina (PLG) onshore well due to contractor delays in completing the rig refurbishment. This defers the commitment deadline to drill and log the PLG well to mid July 2011. The Company may also request an extension of up to six months beyond the July deadline.
Standby Costs and Other Income
As previously disclosed, the Petrex-09 rig formerly utilized at the Corvina field is being refurbished and upgraded at no cost to the Company in order to enhance its capability in preparation for drilling an exploration well in the onshore PLG prospect in Block XIX. Reduced standby rates for the rig are being charged to the Company during the refurbishment and will continue until the rig is utilized.
Also as previously disclosed, the Petrex-18 rig, formerly utilized at the Albacora field, is under lease to another operator through November 15, 2011. The Company plans to resume drilling at Albacora after the 3-D seismic survey on offshore Block Z-1 is completed and the data is processed and interpreted.
Accordingly, standby costs for calendar year 2011 are expected to range between $10 million and $12 million. However, the Company intends to continue to pursue opportunities to further reduce these standby costs such as subleasing the Petrex-09 rig to another operator while not being utilized by the Company.
In addition, we have reached an agreement to charter to that same operator our BPZ-02 barge that supports the Petrex 18 drilling rig, as well as the Don Fernando construction barge, and are working on the possibility of chartering the Company's floating production, storage and offloading (FPSO) barge, the Namoku, as well. Rental income from these vessels is expected to offset related costs.
President and CEO, Manolo Zuniga commented, "We are very pleased that the seismic work on Blocks XXII and XXIII was completed as planned. This work will allow us to better map the oil and gas leads in these blocks." Mr. Zuniga continued, "The progress we are making on all our growth initiatives has been made possible by our close working relationship with the Peruvian authorities. We are appreciative of the spirit of cooperation that has been established and we look forward to continuing to partner together. Indeed, strong partnerships contribute greatly to the goals we have set for our Company."
Keppel Secures Offshore, Marine Jobs Globally
Keppel Secures Offshore, Marine Jobs Globally
Tuesday, April 12, 2011
Keppel Corp. Ltd.
Keppel has clinched new contracts totaling S$240 million from international customers.
These entail building a new multi-purpose dive support construction vessel for SBM Offshore as well as modifying and upgrading a Floating Production Storage and Offloading (FPSO) vessel for Petrofac.
Mr. Nelson Yeo, Managing Director (Marine) of Keppel O&M, said, "These new contracts reflect the confidence of our customers in the capabilities of the Keppel O&M group. We are proud of the solid partnerships built with faithful customers who turn to our yards worldwide for their fleet expansion and upgrading needs.
"Looking ahead, I am confident that we will continue to strengthen the mutual trust and partnership with SBM Offshore and Petrofac with Keppel's commitment to quality and reliability."
Keppel Singmarine will build for SBM Offshore a prototype multi-purpose dive support construction vessel (DSCV) scheduled for delivery in 2Q 2013. This cutting-edge vessel combines capabilities of diving support, subsea construction and anchor handling, and features a DP III (Dynamically Positioned) system.
The DSCV will be equipped with a fully integrated 12-men saturation diving system that enables divers to work safely up to a depth of 300m, and a 250-tonne crane to support subsea oilfield development. It will also feature a 200-tonne double drum winch, four chain lockers and a stern roller for anchor handling functions.
Since 2000, sister company Keppel Shipyard has completed 13 FPSO and FSO projects for SBM Offshore with another four FPSO conversion projects currently underway.
Keppel Shipyard has also secured a fast-track project for the upgrading of a FPSO vessel from Petrofac International (UAE), a subsidiary of Petrofac. The upgrading of the ex-FPSO East Fortune includes refurbishment and life extension works, engineering, fabricating, installing and integrating new topside process modules, upgrading of spread mooring and auxiliary support systems.
Work has commenced in 1Q 2011. Designated for an oil and gas field offshore Peninsular Malaysia, this FPSO facility will be able to handle both oil and gas production.
The above contracts are not expected to have material impact on the net tangible assets and earnings per share of Keppel Corporation Limited for the current financial year.
Tuesday, April 12, 2011
Keppel Corp. Ltd.
Keppel has clinched new contracts totaling S$240 million from international customers.
These entail building a new multi-purpose dive support construction vessel for SBM Offshore as well as modifying and upgrading a Floating Production Storage and Offloading (FPSO) vessel for Petrofac.
Mr. Nelson Yeo, Managing Director (Marine) of Keppel O&M, said, "These new contracts reflect the confidence of our customers in the capabilities of the Keppel O&M group. We are proud of the solid partnerships built with faithful customers who turn to our yards worldwide for their fleet expansion and upgrading needs.
"Looking ahead, I am confident that we will continue to strengthen the mutual trust and partnership with SBM Offshore and Petrofac with Keppel's commitment to quality and reliability."
Keppel Singmarine will build for SBM Offshore a prototype multi-purpose dive support construction vessel (DSCV) scheduled for delivery in 2Q 2013. This cutting-edge vessel combines capabilities of diving support, subsea construction and anchor handling, and features a DP III (Dynamically Positioned) system.
The DSCV will be equipped with a fully integrated 12-men saturation diving system that enables divers to work safely up to a depth of 300m, and a 250-tonne crane to support subsea oilfield development. It will also feature a 200-tonne double drum winch, four chain lockers and a stern roller for anchor handling functions.
Since 2000, sister company Keppel Shipyard has completed 13 FPSO and FSO projects for SBM Offshore with another four FPSO conversion projects currently underway.
Keppel Shipyard has also secured a fast-track project for the upgrading of a FPSO vessel from Petrofac International (UAE), a subsidiary of Petrofac. The upgrading of the ex-FPSO East Fortune includes refurbishment and life extension works, engineering, fabricating, installing and integrating new topside process modules, upgrading of spread mooring and auxiliary support systems.
Work has commenced in 1Q 2011. Designated for an oil and gas field offshore Peninsular Malaysia, this FPSO facility will be able to handle both oil and gas production.
The above contracts are not expected to have material impact on the net tangible assets and earnings per share of Keppel Corporation Limited for the current financial year.
Import Prices U.S. Up 2.7% In March
Import Prices U.S. Up 2.7% In March
Prices for imports to the U.S. jumped 2.7% in March, the largest monthly increase in almost two years, and fuel costs have now risen 36.6% over the past six months.
Excluding fuel, import prices rose 0.6% in March, driven by the largest increase in food, feed and beverage costs in 17 years.
Import prices have climbed 9.7% over the past year, nearly identical to the 9.5% increase in export prices over that time frame. For the month of March, export prices rose 1.5%.
Non-fuel import prices have risen 4.2% over the last 12 months, the largest year-over-year increase since October of 2008.
Economists had expected import prices to increase 2% for the month.
The cost of imports of one of several main inflation gauges, and the report may fuel growing concerns about the recent uptick in inflation.
Prices for imports to the U.S. jumped 2.7% in March, the largest monthly increase in almost two years, and fuel costs have now risen 36.6% over the past six months.
Excluding fuel, import prices rose 0.6% in March, driven by the largest increase in food, feed and beverage costs in 17 years.
Import prices have climbed 9.7% over the past year, nearly identical to the 9.5% increase in export prices over that time frame. For the month of March, export prices rose 1.5%.
Non-fuel import prices have risen 4.2% over the last 12 months, the largest year-over-year increase since October of 2008.
Economists had expected import prices to increase 2% for the month.
The cost of imports of one of several main inflation gauges, and the report may fuel growing concerns about the recent uptick in inflation.
EnCore Repeats Success with Additional Cladhan Pay
EnCore Repeats Success with Additional Cladhan Pay
Tuesday, April 12, 2011
EnCore Oil plc
EnCore provided an update on the Cladhan appraisal well 210/30a-4 located in UK North Sea Block 210/30a.
The appraisal well was drilled as a deviated well to a Total Measured Depth of 12,252 feet and encountered oil bearing Upper Jurassic sandstones in two separate reservoir intervals. No Oil Water Contact was observed. The Upper reservoir sequence had a gross True Vertical Thickness (TVT) of 18 feet and a net sand of 13 feet TVT. The sand has an average porosity of 16 percent. and hydrocarbon saturation of 82 percent. Pressures suggest that this reservoir is in a separate pressure regime from the Lower reservoir. In the Lower reservoir sequence, the main reservoir in previous Cladhan wells, the well encountered a gross TVT of 256 feet and a net sand of 21 feet TVT. The sand has an average porosity of 16 percent. and hydrocarbon saturation of 75 percent. Initial pressure data indicates that the lower sand is in pressure communication with, and is part of the original Cladhan discovery. The well has proven an Oil Down To of 10,447 feet True Vertical Depth Sub Sea (TVDSS), giving a minimum hydrocarbon column of over 1,200 feet.
Upon completion of operations at well 210/30a-4, the Transocean Prospect semi-submersible rig will commence the first planned side-track, 210/30a-4z to evaluate the Upper Jurassic sandstones significantly down dip from the 210/30a-4 well in an attempt to define oil water contacts for both the upper and lower reservoir units, as well as investigating the potential for thickening of the upper unit. It is expected that this side-track will take approximately 20 - 25 days subject to weather or operational delays.
Commenting on the latest well result, Graham Doré, EnCore's Exploration Director said, "This is an important result for Cladhan. The well has confirmed both the presence of a large oil column in the main Cladhan reservoir as well as a new hydrocarbon bearing reservoir sequence, and has yet to find an Oil Water Contact. The next side-track to the east will evaluate the fan structure some 1,000 feet deeper, and has the potential to encounter improved net to gross as well as establishing Oil Water Contacts for both reservoir sequences. This will be followed by a side-track to the south which is designed to confirm the presence of oil in the Central channel."
The equity in the Cladhan joint venture partnership is as follows: EnCore Oil plc (16.6 percent.), Sterling Resources Ltd (39.9 percent., Operator), Wintershall (UK North Sea) Limited (33.5 percent.) and Dyas (10 percent.).
Graham Doré B.Sc. (Hons.) in Geology and M.Sc. in Petroleum Geology and EnCore's Exploration Director, who has over 25 years' experience in the oil exploration and production industry, has reviewed and approved the technical information contained in this announcement.
Tuesday, April 12, 2011
EnCore Oil plc
EnCore provided an update on the Cladhan appraisal well 210/30a-4 located in UK North Sea Block 210/30a.
The appraisal well was drilled as a deviated well to a Total Measured Depth of 12,252 feet and encountered oil bearing Upper Jurassic sandstones in two separate reservoir intervals. No Oil Water Contact was observed. The Upper reservoir sequence had a gross True Vertical Thickness (TVT) of 18 feet and a net sand of 13 feet TVT. The sand has an average porosity of 16 percent. and hydrocarbon saturation of 82 percent. Pressures suggest that this reservoir is in a separate pressure regime from the Lower reservoir. In the Lower reservoir sequence, the main reservoir in previous Cladhan wells, the well encountered a gross TVT of 256 feet and a net sand of 21 feet TVT. The sand has an average porosity of 16 percent. and hydrocarbon saturation of 75 percent. Initial pressure data indicates that the lower sand is in pressure communication with, and is part of the original Cladhan discovery. The well has proven an Oil Down To of 10,447 feet True Vertical Depth Sub Sea (TVDSS), giving a minimum hydrocarbon column of over 1,200 feet.
Upon completion of operations at well 210/30a-4, the Transocean Prospect semi-submersible rig will commence the first planned side-track, 210/30a-4z to evaluate the Upper Jurassic sandstones significantly down dip from the 210/30a-4 well in an attempt to define oil water contacts for both the upper and lower reservoir units, as well as investigating the potential for thickening of the upper unit. It is expected that this side-track will take approximately 20 - 25 days subject to weather or operational delays.
Commenting on the latest well result, Graham Doré, EnCore's Exploration Director said, "This is an important result for Cladhan. The well has confirmed both the presence of a large oil column in the main Cladhan reservoir as well as a new hydrocarbon bearing reservoir sequence, and has yet to find an Oil Water Contact. The next side-track to the east will evaluate the fan structure some 1,000 feet deeper, and has the potential to encounter improved net to gross as well as establishing Oil Water Contacts for both reservoir sequences. This will be followed by a side-track to the south which is designed to confirm the presence of oil in the Central channel."
The equity in the Cladhan joint venture partnership is as follows: EnCore Oil plc (16.6 percent.), Sterling Resources Ltd (39.9 percent., Operator), Wintershall (UK North Sea) Limited (33.5 percent.) and Dyas (10 percent.).
Graham Doré B.Sc. (Hons.) in Geology and M.Sc. in Petroleum Geology and EnCore's Exploration Director, who has over 25 years' experience in the oil exploration and production industry, has reviewed and approved the technical information contained in this announcement.
Amerisur to Farm-Out Fenix Contract
Amerisur to Farm-Out Fenix Contract
Tuesday, April 12, 2011
Amerisur Resources plc
Amerisur has entered into a Commercial Agreement with Reto Petroleum Limited Colombian Branch (Reto) under which Reto has the right to acquire a working interest in the Fenix Exploration and Production contract (100% owned and operated by Amerisur) in exchange for completing certain work programs and investments.
Phase 1 of the agreement contemplates the drilling of 10 wells to appraise and develop the Isabel structure. These wells will be funded 100% by Reto. Once this work program is completed to Amerisur's satisfaction, the Company will cede a 20% undivided working interest in the Fenix contract to Reto, subject to regulatory approvals.
The drilling operations associated with Phase 1 must be completed within 18 months of the effective date of the agreement.
Phase 2 of the Commercial Agreement gives Reto the right, subject to satisfactory completion of Phase 1, to earn an additional 10% undivided working interest in the Fenix block in exchange for the funding (100%) of the acquisition and processing of a seismic program of at least 75 line kilometers within the Fenix contract area. In the event that Reto does not exercise this right, they will fund 20% of this seismic program.
Amerisur Exploracion Colombia, the Company branch established in Colombia will remain the operator of the contract. The effective date of the agreement is April 6, 2011.
John Wardle, CEO, said, "I am very pleased to welcome Reto, whose principals have enjoyed great success in the Colombian E&P sector in the past and who bring a wealth of experience and background understanding to the Fenix contract. Your board believes this is a strong win-win deal for both parties, which will expose us to significant activity in the Fenix block without impacting upon progress or taking our focus away from our principal challenge this year, the development of the Platanillo asset. The terms of the agreement may also cover off our exploration commitments in the Fenix contract for the next two phases, which begin on April 22. Naturally this agreement also demonstrates the level of industry interest in Fenix, which we continue to believe has very significant potential. These work programs will go a long way to defining and accessing that potential."
Tuesday, April 12, 2011
Amerisur Resources plc
Amerisur has entered into a Commercial Agreement with Reto Petroleum Limited Colombian Branch (Reto) under which Reto has the right to acquire a working interest in the Fenix Exploration and Production contract (100% owned and operated by Amerisur) in exchange for completing certain work programs and investments.
Phase 1 of the agreement contemplates the drilling of 10 wells to appraise and develop the Isabel structure. These wells will be funded 100% by Reto. Once this work program is completed to Amerisur's satisfaction, the Company will cede a 20% undivided working interest in the Fenix contract to Reto, subject to regulatory approvals.
The drilling operations associated with Phase 1 must be completed within 18 months of the effective date of the agreement.
Phase 2 of the Commercial Agreement gives Reto the right, subject to satisfactory completion of Phase 1, to earn an additional 10% undivided working interest in the Fenix block in exchange for the funding (100%) of the acquisition and processing of a seismic program of at least 75 line kilometers within the Fenix contract area. In the event that Reto does not exercise this right, they will fund 20% of this seismic program.
Amerisur Exploracion Colombia, the Company branch established in Colombia will remain the operator of the contract. The effective date of the agreement is April 6, 2011.
John Wardle, CEO, said, "I am very pleased to welcome Reto, whose principals have enjoyed great success in the Colombian E&P sector in the past and who bring a wealth of experience and background understanding to the Fenix contract. Your board believes this is a strong win-win deal for both parties, which will expose us to significant activity in the Fenix block without impacting upon progress or taking our focus away from our principal challenge this year, the development of the Platanillo asset. The terms of the agreement may also cover off our exploration commitments in the Fenix contract for the next two phases, which begin on April 22. Naturally this agreement also demonstrates the level of industry interest in Fenix, which we continue to believe has very significant potential. These work programs will go a long way to defining and accessing that potential."
Aminex Inks Development License for Kiliwani North Gas Field
Aminex Inks Development License for Kiliwani North Gas Field
Tuesday, April 12, 2011
Aminex plc
Aminex announced that The Minister for Energy & Minerals of Tanzania, the Hon. William Ngeleja, has signed a Development License with the Company's Tanzanian subsidiary, Ndovu Resources Ltd., ('Ndovu') for the Kiliwani North Gas Field in Tanzania. This is a major step in bringing the Kiliwani North Field on to production.
The Development License represents an area carved out of the Nyuni East Songo-Songo Production Sharing Agreement ('Nyuni PSA') which includes the mapped area of the Kiliwani North gas field. The Kiliwani North-1 well flowed gas at a rate of 40 million cubic feet per day (equivalent to 6,700 barrels of oil per day) under full production test conditions. Ndovu manages the Nyuni PSA and the Kiliwani North gas field as operating partner for a four-company consortium.
East Africa has become the subject of high industry interest recently, following successful drilling by large companies operating in deep water, both in Tanzania and in neighboring northern Mozambique. The Kiliwani North Development License is the first new Development License granted in Tanzania as a consequence of exploration drilling carried out in recent times and is a significant milestone in the commercialization of Tanzanian gas.
Kiliwani North has been independently estimated to contain 45 billion cubic feet ('BCF') gas in place on a Pmean Contingent Resources basis, equivalent to 7.5 million barrels of oil. Gas from Kiliwani North will be available to assist in countering current energy shortages in Tanzania.
Another prospect which lies within the development area, known as Fanjove North, but which has yet to be drilled, has been independently estimated to contain in excess of 200 BCF gas in place, equivalent to approximately 30 million barrels of oil, on a Pmean Prospective Resources basis and, subject to the outcome of a planned transition zone seismic survey, may be drilled in due course.
The Kiliwani North wellhead is situated on the southern tip of Songo-Songo island off the coast of Tanzania and is less than 3 kilometers from the nearest access point to the process facilities (being upgraded) at the input end of the Songas common-user pipeline which delivers gas from the neighboring Songo-Songo field to the city of Dar es Salaam. Ndovu has already negotiated a memorandum of understanding for the future sale of gas to industrial users in the Dar es Salaam area and expects to be able to deliver first gas within 12 months.
Partners in the Development License are:
* Ndovu (Aminex) 65%
* RAK Gas Commission 25%
* Key Petroleum 5%
* Bounty Oil 5%
Aminex chairman Brian Hall commented, "We are very pleased to have been granted this Development license, which represents a major landmark in our Tanzanian operations. The Development License will also benefit Tanzania, paving the way for a further energy source in a market with high and urgent demand.
Kiliwani North is well situated, close to a major pipeline, and the Development License will now enable us to negotiate agreements to access processing and transportation facilities. The existing pipeline has limited capacity but we may expect development of new pipeline infrastructure as a consequence of recent deep water gas discoveries.
The new Development License is a significant step for Aminex in commercializing its Tanzanian operations. Within two months we expect to start new exploration drilling at nearby Nyuni Island, targeting a large gas prospect within the Nyuni PSA. Negotiations are being satisfactorily concluded with the Tanzanian authorities for a new, enlarged Nyuni PSA which will replace the existing Nyuni PSA upon its expiry this year. This will be the first-ever renewal of an expired PSA in Tanzania. In the event that the Nyuni-2 well has not been concluded by the expiry of the current PSA, the Tanzanian authorities have indicated that they will provide an extension to the existing PSA to enable the Nyuni-2 well to be completed.
Shareholders will be kept informed on material events at Nyuni."
Tuesday, April 12, 2011
Aminex plc
Aminex announced that The Minister for Energy & Minerals of Tanzania, the Hon. William Ngeleja, has signed a Development License with the Company's Tanzanian subsidiary, Ndovu Resources Ltd., ('Ndovu') for the Kiliwani North Gas Field in Tanzania. This is a major step in bringing the Kiliwani North Field on to production.
The Development License represents an area carved out of the Nyuni East Songo-Songo Production Sharing Agreement ('Nyuni PSA') which includes the mapped area of the Kiliwani North gas field. The Kiliwani North-1 well flowed gas at a rate of 40 million cubic feet per day (equivalent to 6,700 barrels of oil per day) under full production test conditions. Ndovu manages the Nyuni PSA and the Kiliwani North gas field as operating partner for a four-company consortium.
East Africa has become the subject of high industry interest recently, following successful drilling by large companies operating in deep water, both in Tanzania and in neighboring northern Mozambique. The Kiliwani North Development License is the first new Development License granted in Tanzania as a consequence of exploration drilling carried out in recent times and is a significant milestone in the commercialization of Tanzanian gas.
Kiliwani North has been independently estimated to contain 45 billion cubic feet ('BCF') gas in place on a Pmean Contingent Resources basis, equivalent to 7.5 million barrels of oil. Gas from Kiliwani North will be available to assist in countering current energy shortages in Tanzania.
Another prospect which lies within the development area, known as Fanjove North, but which has yet to be drilled, has been independently estimated to contain in excess of 200 BCF gas in place, equivalent to approximately 30 million barrels of oil, on a Pmean Prospective Resources basis and, subject to the outcome of a planned transition zone seismic survey, may be drilled in due course.
The Kiliwani North wellhead is situated on the southern tip of Songo-Songo island off the coast of Tanzania and is less than 3 kilometers from the nearest access point to the process facilities (being upgraded) at the input end of the Songas common-user pipeline which delivers gas from the neighboring Songo-Songo field to the city of Dar es Salaam. Ndovu has already negotiated a memorandum of understanding for the future sale of gas to industrial users in the Dar es Salaam area and expects to be able to deliver first gas within 12 months.
Partners in the Development License are:
* Ndovu (Aminex) 65%
* RAK Gas Commission 25%
* Key Petroleum 5%
* Bounty Oil 5%
Aminex chairman Brian Hall commented, "We are very pleased to have been granted this Development license, which represents a major landmark in our Tanzanian operations. The Development License will also benefit Tanzania, paving the way for a further energy source in a market with high and urgent demand.
Kiliwani North is well situated, close to a major pipeline, and the Development License will now enable us to negotiate agreements to access processing and transportation facilities. The existing pipeline has limited capacity but we may expect development of new pipeline infrastructure as a consequence of recent deep water gas discoveries.
The new Development License is a significant step for Aminex in commercializing its Tanzanian operations. Within two months we expect to start new exploration drilling at nearby Nyuni Island, targeting a large gas prospect within the Nyuni PSA. Negotiations are being satisfactorily concluded with the Tanzanian authorities for a new, enlarged Nyuni PSA which will replace the existing Nyuni PSA upon its expiry this year. This will be the first-ever renewal of an expired PSA in Tanzania. In the event that the Nyuni-2 well has not been concluded by the expiry of the current PSA, the Tanzanian authorities have indicated that they will provide an extension to the existing PSA to enable the Nyuni-2 well to be completed.
Shareholders will be kept informed on material events at Nyuni."
Statoil Mulls Reducing Stake in Gassled Pipeline
Statoil Mulls Reducing Stake in Gassled Pipeline
Tuesday, April 12, 2011
Dow Jones Newswires
by Katarina Gustafsson
Norwegian oil and gas major Statoil is evaluating a sale of some of its shares in the Gassled joint venture pipeline, according to a company spokesman.
"We consider reducing our ownership share in Gassled and believe that could potentially make capital available that we could manage elsewhere where we could use our experience and competence to create more value," Bard Glad Pedersen told Dow Jones Newswires. "We aren't considering to sell out, just to reduce our ownership."
The spokesman declined to comment on whether the firm, which owns 28.5% of Gassled, had been approached by potential buyers and said a transaction would require the approval of Norway's Ministry of Petroleum and Energy.
Norwegian daily Aftenposten reported Tuesday that Statoil, Shell and Total want to sell stakes in Gassled to "foreign funds" based outside Norway, citing unnamed sources.
Gassled is used for transporting Norwegian gas to mainland Europe and the U.K. Its largest shareholder is state-run oil company Petero, which has a 45.8% stake.
U.S. oil major ExxonMobil last year sold its 8% stake in Gassled for around 6 billion kroner ($1.12 billion), so the pipeline's market value may be around NOK75 billion. Bard Glad Pedersen declined to comment on the figure.
Norwegian authorities would like the current ownership structure to remain in place but have few means to prevent a sale, Aftenposten cites Oil and Energy Ministry spokesman Erik Johnsen as saying.
Shell and Total decline to comment on the issue, Aftenposten said.
Tuesday, April 12, 2011
Dow Jones Newswires
by Katarina Gustafsson
Norwegian oil and gas major Statoil is evaluating a sale of some of its shares in the Gassled joint venture pipeline, according to a company spokesman.
"We consider reducing our ownership share in Gassled and believe that could potentially make capital available that we could manage elsewhere where we could use our experience and competence to create more value," Bard Glad Pedersen told Dow Jones Newswires. "We aren't considering to sell out, just to reduce our ownership."
The spokesman declined to comment on whether the firm, which owns 28.5% of Gassled, had been approached by potential buyers and said a transaction would require the approval of Norway's Ministry of Petroleum and Energy.
Norwegian daily Aftenposten reported Tuesday that Statoil, Shell and Total want to sell stakes in Gassled to "foreign funds" based outside Norway, citing unnamed sources.
Gassled is used for transporting Norwegian gas to mainland Europe and the U.K. Its largest shareholder is state-run oil company Petero, which has a 45.8% stake.
U.S. oil major ExxonMobil last year sold its 8% stake in Gassled for around 6 billion kroner ($1.12 billion), so the pipeline's market value may be around NOK75 billion. Bard Glad Pedersen declined to comment on the figure.
Norwegian authorities would like the current ownership structure to remain in place but have few means to prevent a sale, Aftenposten cites Oil and Energy Ministry spokesman Erik Johnsen as saying.
Shell and Total decline to comment on the issue, Aftenposten said.
Eni Boosts Gas Estimates at Sankofa Discovery Offshore Ghana
Eni Boosts Gas Estimates at Sankofa Discovery Offshore Ghana
Tuesday, April 12, 2011
Eni S.p.A
Eni announced the successful appraisal and testing of the Sankofa discovery in the Offshore Cape Three Points (OCTP) license, offshore Ghana.
The Sankofa-2 well was drilled in 864 meters water depth at a distance of about 55 km from the coast and successfully appraised the Sankofa discovery. The well was tested and delivered a (constrained) rate of approximately 29,5 mmscfd of high quality gas and 1000 boepd of 52° API condensate. The appraisal well confirmed the presence of 35m net gas and condensate sands of the Cretaceous age with excellent reservoir characteristics. A six meter oil leg, which will be the object of further studies, was also encountered.
Initial evaluations indicate that the appraisal well has significantly increased the preliminary estimate of gas in place at the discovery, confirming Sankofa's potential to become the first development of non-associated gas from the Ghana offshore.
The Sankofa well results provide evidence of the success of the exploration activities carried out by the Eni-led consortium, in full compliance with safety and environmental protection standards.
Eni Ghana Exploration and Production Limited is the operator of the OCTP license with a 47.22% interest, Vitol Upstream Ghana Limited 37.78% and state company Ghana National Petroleum Corporation GNPC (15.00%). GNPC will have a back in option for an additional 5%.
Eni continues to work with its partners and the Republic of Ghana to advance its exploration and appraisal programs, as well as contribute to the development of a gas infrastructure in the country.
Eni has been present in Sub-Saharan Africa since the early 1960s and is currently operating in Angola, Nigeria, Togo, Ghana, Republic of Congo, Gabon and Mozambique. Eni's operated production in the area is around 450,000 barrels of oil equivalent per day.
Tuesday, April 12, 2011
Eni S.p.A
Eni announced the successful appraisal and testing of the Sankofa discovery in the Offshore Cape Three Points (OCTP) license, offshore Ghana.
The Sankofa-2 well was drilled in 864 meters water depth at a distance of about 55 km from the coast and successfully appraised the Sankofa discovery. The well was tested and delivered a (constrained) rate of approximately 29,5 mmscfd of high quality gas and 1000 boepd of 52° API condensate. The appraisal well confirmed the presence of 35m net gas and condensate sands of the Cretaceous age with excellent reservoir characteristics. A six meter oil leg, which will be the object of further studies, was also encountered.
Initial evaluations indicate that the appraisal well has significantly increased the preliminary estimate of gas in place at the discovery, confirming Sankofa's potential to become the first development of non-associated gas from the Ghana offshore.
The Sankofa well results provide evidence of the success of the exploration activities carried out by the Eni-led consortium, in full compliance with safety and environmental protection standards.
Eni Ghana Exploration and Production Limited is the operator of the OCTP license with a 47.22% interest, Vitol Upstream Ghana Limited 37.78% and state company Ghana National Petroleum Corporation GNPC (15.00%). GNPC will have a back in option for an additional 5%.
Eni continues to work with its partners and the Republic of Ghana to advance its exploration and appraisal programs, as well as contribute to the development of a gas infrastructure in the country.
Eni has been present in Sub-Saharan Africa since the early 1960s and is currently operating in Angola, Nigeria, Togo, Ghana, Republic of Congo, Gabon and Mozambique. Eni's operated production in the area is around 450,000 barrels of oil equivalent per day.
Statoil Drills Duster in Norwegian Sea
Statoil Drills Duster in Norwegian Sea
Tuesday, April 12, 2011
Norwegian Petroleum Directorate
Statoil, operator of production license 429, is in the process of completing drilling of delineation well 6407/4-2 on the 6407/4-1gas/condensate discovery.
The discovery was proven in 1985, in Middle Jurassic reservoir rocks (the Garn formation) about 25 kilometers west of the Mikkel field. Before well 6407/4-2 was drilled, the resource estimate for the discovery was 2.55 billion standard cubic meters (Sm3) of recoverable gas and 0.67 million Sm3 of recoverable condensate.
The primary exploration target for the well was to delineate the 6407/4-1 gas/condensate discovery. The secondary exploration target was to prove petroleum in Middle Jurassic reservoir rocks (the Ile formation).
In the primary target, reservoir rocks in the Garn formation were encountered, with poorer reservoir quality than expected. The secondary target in the Ile formation had reservoir rocks with the expected reservoir quality.
Data acquisition and sampling have been carried out. Both exploration targets in the well were water-bearing.
This is the first exploration well in production license 429. The license was awarded in APA 2006.
The well was drilled to a vertical depth of 4207 meters below sea level, and was terminated in the Ile formation in the Middle Jurassic. The water depth at the site is 222 meters. The well will now be permanently plugged and abandoned.
The 6407/4-2 well was drilled by the Transocean Leader drilling facility, which will now proceed to production license 312 in the Norwegian Sea to drill wildcat well 6407/3-1 S where Statoil Petroleum AS is the operator.
Tuesday, April 12, 2011
Norwegian Petroleum Directorate
Statoil, operator of production license 429, is in the process of completing drilling of delineation well 6407/4-2 on the 6407/4-1gas/condensate discovery.
The discovery was proven in 1985, in Middle Jurassic reservoir rocks (the Garn formation) about 25 kilometers west of the Mikkel field. Before well 6407/4-2 was drilled, the resource estimate for the discovery was 2.55 billion standard cubic meters (Sm3) of recoverable gas and 0.67 million Sm3 of recoverable condensate.
The primary exploration target for the well was to delineate the 6407/4-1 gas/condensate discovery. The secondary exploration target was to prove petroleum in Middle Jurassic reservoir rocks (the Ile formation).
In the primary target, reservoir rocks in the Garn formation were encountered, with poorer reservoir quality than expected. The secondary target in the Ile formation had reservoir rocks with the expected reservoir quality.
Data acquisition and sampling have been carried out. Both exploration targets in the well were water-bearing.
This is the first exploration well in production license 429. The license was awarded in APA 2006.
The well was drilled to a vertical depth of 4207 meters below sea level, and was terminated in the Ile formation in the Middle Jurassic. The water depth at the site is 222 meters. The well will now be permanently plugged and abandoned.
The 6407/4-2 well was drilled by the Transocean Leader drilling facility, which will now proceed to production license 312 in the Norwegian Sea to drill wildcat well 6407/3-1 S where Statoil Petroleum AS is the operator.
Petrobras Confirms High Productivity in Guara
Petrobras Confirms High Productivity in Guara
Tuesday, April 12, 2011
Petrobras
Petrobras has completed the formation test in the first extension well of Guará confirming the accumulation's high productivity estimates, located in ultra deep waters, in the Santos Basin pre-salt.
During the test in well 3-SPS-69 (3-BRSA-788), located in block BM-S-9, flow rates of approximately 6 thousand barrels per day of good quality oil (30º API) were confirmed, limited to the capacity of the equipment used. Initial production potential is approximately 50 thousand barrels of oil per day.
Also referred to as Guará Norte, the well is located at a water depth of 2,118 meters, about 305 kilometers off the coast of the State of São Paulo, 15 kilometers northeast of 1-SPS-55 (Guará discovery well).
The formation test of discovery well 1-SPS-55, executed earlier, had already showed similar numbers to the results of Guará Norte well, demonstrating excellent quality of the reservoirs.
At the moment the second extension well, Guará Sul (3-SPS-82A), about 7 kilometers south of the Guará discovery well is being drilled.
The consortium, formed by Petrobras (45% - operator), BG Group (30%) and Repsol Sinopec Brasil (25%), will give continuity to the activities and investments necessary to assess the deposits discovered in this area, as per the Evaluation Plan approved by the National Petroleum, Natural Gas and Biofuels Agency (ANP).
Tuesday, April 12, 2011
Petrobras
Petrobras has completed the formation test in the first extension well of Guará confirming the accumulation's high productivity estimates, located in ultra deep waters, in the Santos Basin pre-salt.
During the test in well 3-SPS-69 (3-BRSA-788), located in block BM-S-9, flow rates of approximately 6 thousand barrels per day of good quality oil (30º API) were confirmed, limited to the capacity of the equipment used. Initial production potential is approximately 50 thousand barrels of oil per day.
Also referred to as Guará Norte, the well is located at a water depth of 2,118 meters, about 305 kilometers off the coast of the State of São Paulo, 15 kilometers northeast of 1-SPS-55 (Guará discovery well).
The formation test of discovery well 1-SPS-55, executed earlier, had already showed similar numbers to the results of Guará Norte well, demonstrating excellent quality of the reservoirs.
At the moment the second extension well, Guará Sul (3-SPS-82A), about 7 kilometers south of the Guará discovery well is being drilled.
The consortium, formed by Petrobras (45% - operator), BG Group (30%) and Repsol Sinopec Brasil (25%), will give continuity to the activities and investments necessary to assess the deposits discovered in this area, as per the Evaluation Plan approved by the National Petroleum, Natural Gas and Biofuels Agency (ANP).
Chevron Expects 1Q Earnings to Rise, Helped by Higher Prices
Chevron Expects 1Q Earnings to Rise, Helped by Higher Prices
Tuesday, April 12, 2011
Dow Jones Newswires
by Isabel Ordonez & Ben Lefebvre
Chevron said it expects first-quarter earnings to rise from the prior quarter, helped by higher oil prices and slightly offset by lower profits from its refining and marketing arm.
The outlook from the second-largest U.S. oil company by market value after Exxon Mobil Corp. signals that major oil companies will report a surge in quarterly earnings for the period ended March 31, boosted by climbing oil prices, which appreciated in average almost $20 a barrel compared with the same quarter a year ago, says Fadel Gheit, an analyst at Oppenheimer & Co.
Chevron said an interim earnings update released Monday afternoon that its exploration and production earnings for the first quarter will be higher than fourth quarter, but added that profits will be hurt by less production received due to the negative effect of production-sharing contracts signed with foreign governments. These type of contracts lower the reserves the company can book when oil prices rise.
Chevron said that, during the first two months of the quarter, the company received $88.23 a barrel for crude oil from its U.S. fields, up 11% from the prior quarter and up 20% from a year earlier. Natural-gas prices rose 14% from the prior quarter but fell 22% from the year-earlier period to $4.15 per thousand cubic feet.
San Ramon, Calf.-based Chevron said its U.S. production in the first two months of the quarter was 686,000 barrels of oil equivalent per day. For the full first quarter of 2010, production was 734,000 barrels of oil equivalent a day. International output was 2.07 million barrels of oil equivalent per day in January through February. For the entire quarter a year earlier, daily international production reached 2.05 million barrels of oil equivalent.
Shares rose 1.8% to $109.76 in after-hours action. As of the close, the stock had risen 36% in the past year.
Chevron said it expects its downstream quarterly earnings to sink as it processed less fuel to sell than during the same period of the year before. The company said its U.S. plants processed 870 million barrels of oil a day into gasoline, diesel and other fuels through February 2011, compared to 889 barrels a day for the first full quarter of 2010.
Despite the lower sales volumes, Chevron realized a higher profit margin for the fuel it sold during the quarter. Refining margins at its U.S. plants averaged $21.08 through March, 40% higher than in the full quarter of 2010.
The oil giant also said its refining and marketing earnings in the first quarter are expected to be negatively impacted by the adjustment in the accounting of the fair value of some assets tied to oil prices. Oppenheimer's Gheit said this is likely to mean the company's downstream earnings will be affected by the difference between the price the company paid for oil and what it was worth by the time it was delivered to the company's refineries.
Chevron also noted that it expects to post between $250 million and $350 million of after-tax charges for the quarter. It said it expects the total charges to be at the high end of the guidance range.
The company has reported better results of late, helped by higher prices. In January, Chevron said its fourth-quarter earnings jumped 72%.
Chevron is slated to report first-quarter earnings on April 29.
Tuesday, April 12, 2011
Dow Jones Newswires
by Isabel Ordonez & Ben Lefebvre
Chevron said it expects first-quarter earnings to rise from the prior quarter, helped by higher oil prices and slightly offset by lower profits from its refining and marketing arm.
The outlook from the second-largest U.S. oil company by market value after Exxon Mobil Corp. signals that major oil companies will report a surge in quarterly earnings for the period ended March 31, boosted by climbing oil prices, which appreciated in average almost $20 a barrel compared with the same quarter a year ago, says Fadel Gheit, an analyst at Oppenheimer & Co.
Chevron said an interim earnings update released Monday afternoon that its exploration and production earnings for the first quarter will be higher than fourth quarter, but added that profits will be hurt by less production received due to the negative effect of production-sharing contracts signed with foreign governments. These type of contracts lower the reserves the company can book when oil prices rise.
Chevron said that, during the first two months of the quarter, the company received $88.23 a barrel for crude oil from its U.S. fields, up 11% from the prior quarter and up 20% from a year earlier. Natural-gas prices rose 14% from the prior quarter but fell 22% from the year-earlier period to $4.15 per thousand cubic feet.
San Ramon, Calf.-based Chevron said its U.S. production in the first two months of the quarter was 686,000 barrels of oil equivalent per day. For the full first quarter of 2010, production was 734,000 barrels of oil equivalent a day. International output was 2.07 million barrels of oil equivalent per day in January through February. For the entire quarter a year earlier, daily international production reached 2.05 million barrels of oil equivalent.
Shares rose 1.8% to $109.76 in after-hours action. As of the close, the stock had risen 36% in the past year.
Chevron said it expects its downstream quarterly earnings to sink as it processed less fuel to sell than during the same period of the year before. The company said its U.S. plants processed 870 million barrels of oil a day into gasoline, diesel and other fuels through February 2011, compared to 889 barrels a day for the first full quarter of 2010.
Despite the lower sales volumes, Chevron realized a higher profit margin for the fuel it sold during the quarter. Refining margins at its U.S. plants averaged $21.08 through March, 40% higher than in the full quarter of 2010.
The oil giant also said its refining and marketing earnings in the first quarter are expected to be negatively impacted by the adjustment in the accounting of the fair value of some assets tied to oil prices. Oppenheimer's Gheit said this is likely to mean the company's downstream earnings will be affected by the difference between the price the company paid for oil and what it was worth by the time it was delivered to the company's refineries.
Chevron also noted that it expects to post between $250 million and $350 million of after-tax charges for the quarter. It said it expects the total charges to be at the high end of the guidance range.
The company has reported better results of late, helped by higher prices. In January, Chevron said its fourth-quarter earnings jumped 72%.
Chevron is slated to report first-quarter earnings on April 29.
Ford says Asia-Pacific operations may have to stop production
Ford says Asia-Pacific operations may have to stop production
Due to parts shortages from Japan, Ford (F) says its operations in the Asia-Pacific region may have to slow or stop production later this month. The automaker, which has 13 plants in the Asia-Pacific region, has temporarily halted operations in the U.S. and Europe because of shortages.
The company expects its operations will be affected beginning the last week of April into May. Ford said in an SEC filing, "We continue to assess the impact of the earthquake and resulting events in Japan on our Automotive operations.
Although we have no production facilities in Japan, we do obtain materials and components from suppliers located in Japan, and we are working closely with those suppliers to assess their production and shipping capabilities and to minimize any disruptions.
We also are pursuing other sources of supply as necessary and practicable...Because the situation in Japan continues to develop, supply interruptions related to other materials and components from Japan could manifest themselves in the weeks ahead.
Should the supply of a key material or component from Japan be disrupted and an alternate supply not be available, we could have to reduce or temporarily cease production of vehicles, which could adversely affect our and Ford Motor Credit Company's financial condition and results of operations."
Due to parts shortages from Japan, Ford (F) says its operations in the Asia-Pacific region may have to slow or stop production later this month. The automaker, which has 13 plants in the Asia-Pacific region, has temporarily halted operations in the U.S. and Europe because of shortages.
The company expects its operations will be affected beginning the last week of April into May. Ford said in an SEC filing, "We continue to assess the impact of the earthquake and resulting events in Japan on our Automotive operations.
Although we have no production facilities in Japan, we do obtain materials and components from suppliers located in Japan, and we are working closely with those suppliers to assess their production and shipping capabilities and to minimize any disruptions.
We also are pursuing other sources of supply as necessary and practicable...Because the situation in Japan continues to develop, supply interruptions related to other materials and components from Japan could manifest themselves in the weeks ahead.
Should the supply of a key material or component from Japan be disrupted and an alternate supply not be available, we could have to reduce or temporarily cease production of vehicles, which could adversely affect our and Ford Motor Credit Company's financial condition and results of operations."
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