Commodity Corner: Crude Advances on A Weaker Dollar
Thursday, April 14, 2011
Rigzone Staff
by Saaniya Bangee
Front-month crude futures gained a dollar Thursday after reversing earlier losses on a weaker greenback. Light sweet crude settled at $108.11 a barrel, up 0.9 percent.
Prior to the dollar's decline, the oil futures price fell to $105.77 during floor trading. The dollar fell against the euro on the U.S. Government's hovering budget battle and reports indicating an increase in jobless claims last week. According to the Department of Labor, applications for initial unemployment benefits soared to their highest level in two months. The Thursday report showed that 412,000 people had applied for claims, reflecting an increase of 27,000 from the previous week.
A weaker dollar increases the appeal of commodities, making it cheaper to purchase with other currencies. The dollar index, which compares the greenback to a basket of foreign currencies, also traded lower at 74.698 Thursday.
Meanwhile, political turmoil continues in the Middle East. Analysts believe Libya's structural problems will not be resolved in the near future but will continue to halt the country's previous exports of 1.5 million barrels a day.
Government reports of an increase in U.S. stockpiles pressured natural gas prices to rise by more than 2 percent Thursday. Prices settled at $4.212 per thousand cubic feet.
The Energy Information Administration (EIA) reported that U.S. gas inventories increased by 28 billion cubic feet last week. As of April 8, stockpiles were 0.6 percent above the five-year average at 1.607 trillion cubic feet.
The intraday range for natural gas was $4.06 to $4.26 per thousand cubic feet.
Gasoline prices lost 0.2 percent, settling at $3.23 a gallon. Thursday's gasoline futures peaked at $3.268, before bottoming out at $3.21.
Thursday, April 14, 2011
Zion O&G Notified of New Exploration License in Israel
Zion O&G Notified of New Exploration License in Israel
Thursday, April 14, 2011
Zion O&G Inc.
Zion reported that the Israeli Petroleum Commissioner's Office, on behalf of the State of Israel, has notified Zion that it will be awarded a new petroleum exploration license on land within Zion's previous (and now expired) Issachar-Zebulun Permit area. The new license has been named by Zion, the Jordan Valley License. Zion expects to formally receive the license soon.
The Jordan Valley License area is to the east of Zion's Joseph license area and Zion's Asher-Menashe license area and to the south of the Sea of Galilee. It traverses south along the western Jordan River Valley.
Zion's Chief Executive Officer, Richard Rinberg, said, "We are truly excited and very pleased that the State of Israel will award us our new Jordan Valley License. We continue to implement our exploration and drilling program and build on our progress to date. In 2011, we intend to acquire additional seismic and other geological and geophysical data in our new license area, as we endeavor to refine our potential drilling prospects in this area. Meanwhile the drilling operations at our Ma'anit-Joseph #3 well continue, as we strive for our primary target in deep Permian age rock, expected at a depth of over 19,000 feet (5,790 meters). The Ma'anit-Joseph #3 well is already one of the deepest wells ever drilled onshore Israel."
Thursday, April 14, 2011
Zion O&G Inc.
Zion reported that the Israeli Petroleum Commissioner's Office, on behalf of the State of Israel, has notified Zion that it will be awarded a new petroleum exploration license on land within Zion's previous (and now expired) Issachar-Zebulun Permit area. The new license has been named by Zion, the Jordan Valley License. Zion expects to formally receive the license soon.
The Jordan Valley License area is to the east of Zion's Joseph license area and Zion's Asher-Menashe license area and to the south of the Sea of Galilee. It traverses south along the western Jordan River Valley.
Zion's Chief Executive Officer, Richard Rinberg, said, "We are truly excited and very pleased that the State of Israel will award us our new Jordan Valley License. We continue to implement our exploration and drilling program and build on our progress to date. In 2011, we intend to acquire additional seismic and other geological and geophysical data in our new license area, as we endeavor to refine our potential drilling prospects in this area. Meanwhile the drilling operations at our Ma'anit-Joseph #3 well continue, as we strive for our primary target in deep Permian age rock, expected at a depth of over 19,000 feet (5,790 meters). The Ma'anit-Joseph #3 well is already one of the deepest wells ever drilled onshore Israel."
Pacific Rubiales Increases Revolving Credit Facility
Pacific Rubiales Increases Revolving Credit Facility
Thursday, April 14, 2011
Pacific Rubiales Energy Corp.
Pacific Rubiales has closed the amendment (the "Amendment") to its existing US $250 million unsecured revolving credit facility (the "Revolving Credit Facility"). As a result of the great interest generated amongst the lending syndicate, the amount of the Revolving Credit Facility was increased from the US $250 million initially committed by the lenders in April 2010 to US $350 million. Bank of America Merrill Lynch acted as Global Coordinator and Sole Bookrunner.
The Amendment was limited to the same lenders under the Revolving Credit Facility and, in addition to increasing its amount of the facility from US $250 million to US $350 million, under the terms of the Amendment the Company extended the term of the Revolving Credit Facility to April 2013 and reduced the applicable commitment fees and the applicable margin.
To date, the Company has not drawn down any funds from the Revolving Credit Facility and the Company does not expect to require any proceeds from the Revolving Credit Facility to fund its 2011 capital expenditure budget. The Revolving Credit Facility will be utilized as needed to take advantage of opportunities in the Colombia E&P sector that may become available and to fulfill the Company's business strategy.
The applicable margin and commitment fees of the Revolving Credit Facility will continue to be determined in accordance with the rating assigned to the Company's senior debt securities by Standard & Poor's Ratings Group and Fitch Inc. Based on the Company's current rating and expected usage, the commitment fee will be reduced from 100 bps to 75 bps and the applicable margin from 325 bps to 250 bps over LIBOR.
Subject to customary acceleration events set forth in the credit agreement relating to the Revolving Credit Facility, or unless terminated earlier by the Company without penalty, repayment of outstanding principal on the Revolving Credit Facility will be made in full on April 26, 2013.
Thursday, April 14, 2011
Pacific Rubiales Energy Corp.
Pacific Rubiales has closed the amendment (the "Amendment") to its existing US $250 million unsecured revolving credit facility (the "Revolving Credit Facility"). As a result of the great interest generated amongst the lending syndicate, the amount of the Revolving Credit Facility was increased from the US $250 million initially committed by the lenders in April 2010 to US $350 million. Bank of America Merrill Lynch acted as Global Coordinator and Sole Bookrunner.
The Amendment was limited to the same lenders under the Revolving Credit Facility and, in addition to increasing its amount of the facility from US $250 million to US $350 million, under the terms of the Amendment the Company extended the term of the Revolving Credit Facility to April 2013 and reduced the applicable commitment fees and the applicable margin.
To date, the Company has not drawn down any funds from the Revolving Credit Facility and the Company does not expect to require any proceeds from the Revolving Credit Facility to fund its 2011 capital expenditure budget. The Revolving Credit Facility will be utilized as needed to take advantage of opportunities in the Colombia E&P sector that may become available and to fulfill the Company's business strategy.
The applicable margin and commitment fees of the Revolving Credit Facility will continue to be determined in accordance with the rating assigned to the Company's senior debt securities by Standard & Poor's Ratings Group and Fitch Inc. Based on the Company's current rating and expected usage, the commitment fee will be reduced from 100 bps to 75 bps and the applicable margin from 325 bps to 250 bps over LIBOR.
Subject to customary acceleration events set forth in the credit agreement relating to the Revolving Credit Facility, or unless terminated earlier by the Company without penalty, repayment of outstanding principal on the Revolving Credit Facility will be made in full on April 26, 2013.
MicroSeismic Names New GM for Denver Office
MicroSeismic Names New GM for Denver Office
Thursday, April 14, 2011
MicroSeismic Inc.
MicroSeismic announced that David Bird has been named General Manager (GM) over MSI's Denver, Colorado, office.
Bird brings over 30 years of geophysical experience to MSI, and joins the company from NFR Energy in Denver, where he served as Senior Geophysical Advisor. Prior to NFR, David held the positions of North American Vice President at Geomage and Exploration Advisor for Samson where he was responsible for coordination of exploration efforts in the Rockies and Canada including final technical and economic review of exploration wells.
Bird's position comes in response to a need for expansion in the Rockies, Mid-Continent region. Increased sales and operations and a number of new employees makes this region a significant focus for MSI's business going forward.
"This is an important and growing market," said Peter Duncan, Ph.D., CEO and Founder of MicroSeismic, Inc. "We're adding David, as a senior lead to grow business and respond to operators in that region."
"I'm really looking forward to the challenge," said David Bird, GM, Denver, MicroSeismic, Inc. "With the increased activity in the Bakken and Niobrara, I see huge potential for expanding MSI's presence in the region."
Thursday, April 14, 2011
MicroSeismic Inc.
MicroSeismic announced that David Bird has been named General Manager (GM) over MSI's Denver, Colorado, office.
Bird brings over 30 years of geophysical experience to MSI, and joins the company from NFR Energy in Denver, where he served as Senior Geophysical Advisor. Prior to NFR, David held the positions of North American Vice President at Geomage and Exploration Advisor for Samson where he was responsible for coordination of exploration efforts in the Rockies and Canada including final technical and economic review of exploration wells.
Bird's position comes in response to a need for expansion in the Rockies, Mid-Continent region. Increased sales and operations and a number of new employees makes this region a significant focus for MSI's business going forward.
"This is an important and growing market," said Peter Duncan, Ph.D., CEO and Founder of MicroSeismic, Inc. "We're adding David, as a senior lead to grow business and respond to operators in that region."
"I'm really looking forward to the challenge," said David Bird, GM, Denver, MicroSeismic, Inc. "With the increased activity in the Bakken and Niobrara, I see huge potential for expanding MSI's presence in the region."
Ford Motor Expands Faulty Air-Bag Recall To Include 1.2 Million Vehicles
Ford Motor Expands Faulty Air-Bag Recall To Include 1.2 Million Vehicles
Apr 14, 2011
Ford Motor Co (NYSE:F) expanded a recall related to faulty air bags to include 1.2 million F-150 pickups and some Lincoln Mark LTs. Previously the recall had only included 144,000 trucks.
Federal regulators have received reports of hundreds of instances of inadvertent air-bag deployments, which have resulted in bruises, cuts, and one chipped tooth, and two drivers said they were knocked unconscious.
Ford said it is not aware of any accidents related to the glitch, which covers trucks from model years 2004 through 2006. Ford resisted the expanded recall because the automaker saw it as unnecessary, but finally caved to pressure from regulators.
Shares of Ford Motor are trading down 1.64% at $14.73.
Apr 14, 2011
Ford Motor Co (NYSE:F) expanded a recall related to faulty air bags to include 1.2 million F-150 pickups and some Lincoln Mark LTs. Previously the recall had only included 144,000 trucks.
Federal regulators have received reports of hundreds of instances of inadvertent air-bag deployments, which have resulted in bruises, cuts, and one chipped tooth, and two drivers said they were knocked unconscious.
Ford said it is not aware of any accidents related to the glitch, which covers trucks from model years 2004 through 2006. Ford resisted the expanded recall because the automaker saw it as unnecessary, but finally caved to pressure from regulators.
Shares of Ford Motor are trading down 1.64% at $14.73.
Crude Prices Rise For Second Day After Report of Reduced Saudi Production
Crude Prices Rise For Second Day After Report of Reduced Saudi Production
Apr 14, 2011
Crude oil climbed for a second day on the New York Mercantile Exchange on a report out of Saudi Arabia that the holder of the world's largest oil reserves, and the second largest producer of oil, has reduced output this month.
May oil futures were up almost 1% to $108.10 per barrel, after the chief economist at Riyadh-based Banque Saudi Fransi said the Kingdom of Saudi Arabia had cut production by 300,000 barrels per day.
Barclays Plc (NYSE:BCS) said the country might be reducing production of its lighter oil blends introduced in response to the disruption of Libyan output last month.
Prices have gone up 18% this year as unrest has swept across the Middle East. Elections in Nigeria later this month have many fearful of decreased output from that country, Africa's top crude producer.
Apr 14, 2011
Crude oil climbed for a second day on the New York Mercantile Exchange on a report out of Saudi Arabia that the holder of the world's largest oil reserves, and the second largest producer of oil, has reduced output this month.
May oil futures were up almost 1% to $108.10 per barrel, after the chief economist at Riyadh-based Banque Saudi Fransi said the Kingdom of Saudi Arabia had cut production by 300,000 barrels per day.
Barclays Plc (NYSE:BCS) said the country might be reducing production of its lighter oil blends introduced in response to the disruption of Libyan output last month.
Prices have gone up 18% this year as unrest has swept across the Middle East. Elections in Nigeria later this month have many fearful of decreased output from that country, Africa's top crude producer.
Alberta Star Drills First Blackfoot Well
Alberta Star Drills First Blackfoot Well
Thursday, April 14, 2011
Alberta Star Development Corp.
Alberta Star has drilled, cased and completed the first well of its Blackfoot Phase 1- three well (1.0 net well to the Company) drilling program on the Blackfoot heavy oil property in Lloydminster, Alberta. The well is located at 3D-11-050-02-W4 and is currently producing and the Company expects that once the well has stabilized, production rates will be comparable to that of surrounding heavy oil wells. The remaining two Blackfoot Phase 1 wells on adjacent sections, are expected to be spudded after spring break-up. The Blackfoot Phase 1 - three well program is scheduled to include drilling and completing three in-fill heavy oil wells at the following locations: 3D-11-050-02-W4 (drilled, completed and on initial production), C6-24-050-02-W4 (pending) and C7-14-050-02-W4 (pending). Once completed, Blackfoot Phase 1 - three well program will increase the number of Lloydminster heavy oil wells that the Company has an interest in, to seventeen. The Company will have a 33.33% working interest in the Blackfoot Phase 1 - three well program wells.
Thursday, April 14, 2011
Alberta Star Development Corp.
Alberta Star has drilled, cased and completed the first well of its Blackfoot Phase 1- three well (1.0 net well to the Company) drilling program on the Blackfoot heavy oil property in Lloydminster, Alberta. The well is located at 3D-11-050-02-W4 and is currently producing and the Company expects that once the well has stabilized, production rates will be comparable to that of surrounding heavy oil wells. The remaining two Blackfoot Phase 1 wells on adjacent sections, are expected to be spudded after spring break-up. The Blackfoot Phase 1 - three well program is scheduled to include drilling and completing three in-fill heavy oil wells at the following locations: 3D-11-050-02-W4 (drilled, completed and on initial production), C6-24-050-02-W4 (pending) and C7-14-050-02-W4 (pending). Once completed, Blackfoot Phase 1 - three well program will increase the number of Lloydminster heavy oil wells that the Company has an interest in, to seventeen. The Company will have a 33.33% working interest in the Blackfoot Phase 1 - three well program wells.
Petroleum Exploration Commences Drilling Pakistan Program
Petroleum Exploration Commences Drilling Pakistan Program
Thursday, April 14, 2011
Jura Energy Corp.
Jura has been advised that Petroleum Exploration (PVT) Limited, the operator of Jura's blocks in Pakistan, has concluded all major service contracts required for the 2011 drilling program. The contracts include the provision of drilling rig by CNPC Shuanqing Drilling Engineering Company for a two-well program. The contract can be terminated without penalty following completion of the first well of the program.
The rig will be mobilized to the Wahid-1 well location in the Badin IV North Block for the drilling of a 2,300 meter well to target the A and B sands of the Lower Goru. It is anticipated that drilling of the well will commence in May of 2011. The joint venture partners have elected to defer a decision on the location of the second well of the program at this time.
Jura holds a 27.5% working interest in the Badin IV North Block and is carried through substantially all of its share of the anticipated well cost of US $5.4 million (gross).
Thursday, April 14, 2011
Jura Energy Corp.
Jura has been advised that Petroleum Exploration (PVT) Limited, the operator of Jura's blocks in Pakistan, has concluded all major service contracts required for the 2011 drilling program. The contracts include the provision of drilling rig by CNPC Shuanqing Drilling Engineering Company for a two-well program. The contract can be terminated without penalty following completion of the first well of the program.
The rig will be mobilized to the Wahid-1 well location in the Badin IV North Block for the drilling of a 2,300 meter well to target the A and B sands of the Lower Goru. It is anticipated that drilling of the well will commence in May of 2011. The joint venture partners have elected to defer a decision on the location of the second well of the program at this time.
Jura holds a 27.5% working interest in the Badin IV North Block and is carried through substantially all of its share of the anticipated well cost of US $5.4 million (gross).
Stream O&G to Enter Second Phase of Seismic Prog. at Delvina
Stream O&G to Enter Second Phase of Seismic Prog. at Delvina
Thursday, April 14, 2011
Stream O&G Ltd.
Stream O&G reported the advancement of its Delvina Block gas exploration program Phase II with the award of the seismic tomography contract. This second phase of the seismic program is target oriented, focused on improving the definition of the three structures in preparation for drilling of the exploration wells. The additional seismic data will be integral to the successful execution of the Company's Plan of Exploration ("PoE") on the Delvina Block, accessing over 600 BCF of gas resources.
The field segment of the program will commence in May 2011, providing monitoring of the north, south and east structures adjacent to the existing producing Delvina field. The resulting information will be utilized to determine the location of the planned exploration well.
"Our exploration program at Delvina is moving forward as planned," said Dr. Sotirios Kapotas, President and CEO. "The Delvina gas field and Block offer significant growth potential for the Company, and is expected to provide new opportunities in a scarce gas environment. The production potential can be utilized in various ways to the benefit of Stream adding shareholder value."
Per the November 30, 2010 independent reserves report, the Delvina gas field and block were evaluated to hold approximately 616 BCF of gas initially-in-place (high estimates; AJM Petroleum Consultants). Future activities at Delvina are expected to result in the conversion of possible reserves into probable reserves, while the drilling of the first horizontal well is expected to convert probable into proved reserves and contingent resources into probable reserves. Drilling exploration wells in the adjacent structures is expected to convert prospective resources.
Stream plans to expand its existing gas market and is finalizing gas utilization plans which will support the Delvina development program timelines. A small power generation plant is expected to be installed in 2011 at the Delvina gas field. Plans are being finalized for a large scale power generation plant in support of the Company's full scale field and block development. These activities are expected to provide production for additional markets for power generation, oilfield enhanced oil recovery utilization and other industrial consumers.
Thursday, April 14, 2011
Stream O&G Ltd.
Stream O&G reported the advancement of its Delvina Block gas exploration program Phase II with the award of the seismic tomography contract. This second phase of the seismic program is target oriented, focused on improving the definition of the three structures in preparation for drilling of the exploration wells. The additional seismic data will be integral to the successful execution of the Company's Plan of Exploration ("PoE") on the Delvina Block, accessing over 600 BCF of gas resources.
The field segment of the program will commence in May 2011, providing monitoring of the north, south and east structures adjacent to the existing producing Delvina field. The resulting information will be utilized to determine the location of the planned exploration well.
"Our exploration program at Delvina is moving forward as planned," said Dr. Sotirios Kapotas, President and CEO. "The Delvina gas field and Block offer significant growth potential for the Company, and is expected to provide new opportunities in a scarce gas environment. The production potential can be utilized in various ways to the benefit of Stream adding shareholder value."
Per the November 30, 2010 independent reserves report, the Delvina gas field and block were evaluated to hold approximately 616 BCF of gas initially-in-place (high estimates; AJM Petroleum Consultants). Future activities at Delvina are expected to result in the conversion of possible reserves into probable reserves, while the drilling of the first horizontal well is expected to convert probable into proved reserves and contingent resources into probable reserves. Drilling exploration wells in the adjacent structures is expected to convert prospective resources.
Stream plans to expand its existing gas market and is finalizing gas utilization plans which will support the Delvina development program timelines. A small power generation plant is expected to be installed in 2011 at the Delvina gas field. Plans are being finalized for a large scale power generation plant in support of the Company's full scale field and block development. These activities are expected to provide production for additional markets for power generation, oilfield enhanced oil recovery utilization and other industrial consumers.
Pan Orient Highlights Operating Results for 2010 Year-End
Pan Orient Highlights Operating Results for 2010 Year-End
Thursday, April 14, 2011
Pan Orient Energy Corp.
Pan Orient provided highlights of its 2010 year end and fourth quarter consolidated financial and operating results, and provided an outlook for 2011. Please note that all amounts are in Canadian dollars unless otherwise stated and BOPD refers to barrels of oil per day net to Pan Orient.
At the Citarum PSC in 2010 (onshore Java - Pan Orient 77% working interest and operator) there was completion of the 2D seismic program and the associated seismic data processing and mapping. Targets have been selected for a three well exploration program that is scheduled for commencement of drilling late in the third quarter or early in the fourth quarter of 2011. Capital expenditures in 2010 related to the Citarum PSC were $8.3 million.
Thursday, April 14, 2011
Pan Orient Energy Corp.
Pan Orient provided highlights of its 2010 year end and fourth quarter consolidated financial and operating results, and provided an outlook for 2011. Please note that all amounts are in Canadian dollars unless otherwise stated and BOPD refers to barrels of oil per day net to Pan Orient.
2010 HIGHLIGHTS
- Funds flow from operations of $59.0 million ($1.22 per share) and net income attributable to common shareholders of $20.6 million ($0.43 per share) for 2010.
- Total 2010 capital programs in Thailand, Indonesia and Canada of $61.3 million were financed 96% by after tax funds flow from operations and 4% from working capital.
- Capital expenditures were $43.4 million in Thailand, $17.0 million in Indonesia and $0.9 million in Canada.
- Average 2010 oil sales in Thailand of 3,884 BOPD with 4,056 BOPD for the fourth quarter of 2010.
- Strong generation of after tax funds flow from Thailand operations with $17.7 million for the fourth quarter of 2010 ($47.46 per barrel) and $58.2 million for 2010 ($41.05 per barrel).
- Drilling of 25 exploration and appraisal wells in Thailand during 2010 with 10 wells at the Wichian Buri Extension Field ("WBEXT"), five wells at Bo Rang, seven wells at Na Sanun East, two wells at Concession L33, and one well at Concession L53.
- Discovery of the WBEXT field in Concession L44 (Pan Orient operator and 60% ownership) resulted in a new 12.45 square kilometer production license, 382,051 barrels of oil sales in the second half of 2010, and 8.2 million barrels of proven plus probable reserves were assigned at year-end.
- Drilling of two exploration wells in Concession L33 (Pan Orient operator and 60% ownership) resulted in the first discovery of hydrocarbons at commercial rates in Concession L33, a new 11.94 square kilometer production license, oil sales of 25,039 barrels commencing in November 2010, and 2.8 million barrels of proven plus probable reserves were assigned at year-end.
- At Concession L53 (Pan Orient operator and 100% ownership) a production license of 2 square kilometers was granted to Pan Orient, first oil sales from Concession L53 commenced in August 2010, and 1.4 million barrels of proven plus probable reserves were assigned at year-end.
- Thailand proved plus probable reserves of 31.9 million barrels at December 31, 2010 with 12.4 million barrels of new oil field discoveries in 2010 offset by a 15.7 million barrel downward revision of previously assigned reserves mainly at the Na Sanun Central and NSE-F1 fields in Concession L44/43. The net present value of proved and probable reserves after tax (using forecast prices and discounted at 10%) of Cdn$509 million, representing $9.00 per Pan Orient share based on the current 56.5 million Pan Orient shares outstanding.
- At December 31, 2010 Pan Orient had $31.4 million of working capital and long-term deposits, and no long-term debt.
- Subsequent to the year-end, Pan Orient closed a bought deal financing on March 8, 2011 with the issuance of 7,557,264 shares at a price of $6.55 per share for proceeds of $46.7 million net of expenses.
2010 OPERATING RESULTS
- Total 2010 capital programs in Thailand, Indonesia and Canada of $61.3 million were financed 96% by the $59.0 million in after tax funds flow from operations and 4% from working capital. Capital expenditures were $43.4 million in Thailand, $17.0 million in Indonesia and $0.9 million in Canada.
- Active 2010 drilling program in Thailand with the drilling of 25 wells (15.4 net wells) focused on exploration and appraisal wells to add new reserves and new development drilling opportunities for 2011. Six wells (4.0 net) were drilled in the fourth quarter of 2010, with five appraisal or exploration wells at the WBEXT field in Concession L44, and the L53-C well in Concession L53 (which spudded on December 30, 2010). Total capital expenditures in Thailand were $11.7 million in the fourth quarter of 2010 and a total of $43.4 million in 2010.
- Pan Orient drilled 22 wells in Concession L44 (Pan Orient operator and 60% ownership) during 2010 resulting in 12 producing wells and 5 wells which are waiting for workovers or sidetracking operations to evaluate different potential reservoirs.
- The WBEXT field was discovered in the third quarter of 2010 and a total of 10 exploration or appraisal wells were drilling during the year with capital expenditures for drilling of $14.7 million, and resulted in 382,051 barrels of oil sales. A production license of 12.45 square kilometers was granted for the portion of the field in Concession L44 by the Thailand Department of Mineral Fuels in February 2011. Proved and probable oil reserves assigned at December 31, 2010 were 8.2 million barrels from volcanic and sandstone reservoirs (with 5.3 million barrels assigned to reserves in Concession L44 and 2.9 million barrels assigned to reserves in Concession L33).
- Five wells were drilled at the Bo Rang fields during the first half of 2010 with capital expenditures for drilling of $5.8 million to further appraise and develop this field which was discovered in 2009. Oil sales in 2010 from the four producing wells resulting from this drilling program were 226,504 barrels.
- Seven wells were drilled at Na Sanun East in the Central and NSE-F1 fields during the first half of 2010 to continue appraisal of these fields and to evaluate further exploration potential. The program resulted in three producing wells, the NSE-G3 well which will be sidetracked to test a deeper volcanic objective, the NSE-F4 well which is being evaluated for a potential workover, and two wells not capable of production. Capital expenditures related to this drilling program were $10.7 million and oil sales in 2010 were 69,952 barrels.
- The two exploration wells drilled in Concession L33 (Pan Orient operator and 60% ownership) during the third quarter of 2010 resulted in the first discovery of hydrocarbons at commercial rates in Concession L33. Oil sales commenced in November 2010 with a production license of 11.94 square kilometers for the L33 field being granted by the Thailand Department of Mineral Fuels. Total capital expenditures during 2010 for drilling were $1.9 million and resulted in 25,039 barrels of oil sales and proved and probable oil reserves assigned at December 31, 2010 of 2.8 million barrels.
- Production in Concession L53 (100% ownership by Pan Orient) commenced in August 2010 with the L53-A well being placed back on-stream after Pan Orient received formal approval by the Thailand Department of Mineral Fuels for the 2.0 square kilometers L53-A Production License around the L53-A exploration well. Oil sales were 28,676 barrels in 2010, with 8,097 barrels (88 BOPD) in the fourth quarter of 2010. This new core area of operations west of Bangkok began production during 2010 and revenue from oil sales was used to fund the start-up of operations. This area has active operations in 2011 with a workover of the L53-A well to produce from additional sandstone zones, and drilling of new wells at L53-C (spudded December 30, 2010), L53-B and L53-A1. Proved and probable oil reserves assigned at December 31, 2010 were 1.4 million barrels from sandstone reservoirs.
- The independent reserves evaluation conducted by Gaffney, Cline & Associates (Consultants) Pte. Ltd. of Singapore ("Gaffney Cline") for the Thailand assets at December 31, 2010 assigned proved plus probable reserves of 31.9 million barrels at December 31, 2010, a 13% decrease from 36.7 million barrels at December 31, 2009. Proved plus probable reserves at December 31, 2010 include 12.4 million barrels of new oil field discoveries in 2010 at the Wichian Buri Extension field ("WBEXT") in Concessions L44/43 & L33/43, the L33 field in Concession L33/43, and the L53A field in Concession L53/48 offset by a 15.7 million barrel downward revision of previously assigned reserves mainly at the Na Sanun Central and NSE-F1 fields in Concession L44/43.
- The net present value of proved and probable reserves after tax for the four concessions in Thailand, using forecast prices and discounted at 10%, is Cdn$509 million, an increase of 11% over the prior year and representing $9.00 per Pan Orient share, based on the current 56.5 million Pan Orient shares outstanding.
- Average Thailand oil sales in 2010 were 3,884 BOPD and 4,056 BOPD for the fourth quarter of 2010. Pan Orient continued to experience significant fluctuations in production levels in 2010 from volcanic reservoirs which can be initially very prolific before they achieve a stabilized production level and water cut.
- Oil sales averaged 2,246 BOPD in the first quarter of 2011 reflecting the temporary shut-in of WBEXT-1, WBEXT-1A and WBEXT-1B wells starting in December 2010 at the expiry of their respective 90 day production test periods, and reduced oil production of the WBEXT-1C well as a result of water incursion as outlined in the press releases of January 6th and February 9th, 2011. The WBEXT production license was granted on February 24, 2011 and the three temporarily shut-in wells were brought on-stream at reduced rates to minimize the water cut.
- The oil sands project at Sawn Lake, Alberta operated by Andora Energy Corporation (which is owned 53.4% by Pan Orient) as at December 31, 2010 was evaluated by Sproule Associates Ltd. ("Sproule"). The contingent resource volumes estimated in the Sproule report are considered contingent until such time as commercial recovery has been demonstrated, regulatory approvals have been obtained and the company has committed to proceed with commercial development. Contingent Resources are further classified as "High", "Best" and "Low" in accordance with the level of certainty.
- Capital expenditures in Indonesia were $1.6 million for the fourth quarter and a total of $17.0 million for 2010.
At the Citarum PSC in 2010 (onshore Java - Pan Orient 77% working interest and operator) there was completion of the 2D seismic program and the associated seismic data processing and mapping. Targets have been selected for a three well exploration program that is scheduled for commencement of drilling late in the third quarter or early in the fourth quarter of 2011. Capital expenditures in 2010 related to the Citarum PSC were $8.3 million.
PetroLatina Ramps Production in 1Q11
PetroLatina Ramps Production in 1Q11
Thursday, April 14, 2011
PetroLatina Energy plc
PetroLatina announced a production update in respect of the first quarter of 2011.
The Company achieved total gross production from its Tisquirama, La Paloma and Midas license blocks located in the Middle Magdelana Valley, Colombia, in the three months to 31 March 2011 of 193,790 barrels of oil (bbls) (2010 equivalent period: 155,323 bbls) and total net production of 90,536 bbls (2010 equivalent period: 72,465 bbls) at an average gross production rate of 2,154 barrels of oil per day (bopd) (2010 equivalent period: 1,726 bopd) and an average net production rate of 1,006 bopd (2010 equivalent period: 805 bopd).
As announced previously, the Serafin-1 gas well located in the Company's Tisquirama license block is currently on an extended 6 month production test at a flow rate of 5.5 MMscf/d of gas and a well pressure of 1,850 pounds per square inch (psi). The well has, during the test period to date, achieved total gross production of 95.98 MMscf of gas (15,997 barrels of oil equivalent) and total net production of 44.15MMscf (7,359 boe). Gas produced during the 6 month extended test period is being sold to Ecopetrol S.A. at 90% of the regulated price for Texaco for Barranca-Ballena's gas (as regulated by CREG, the Regulatory Commission of Energy and Gas of Colombia). The regulated price is currently $4.2562/million British thermal unit (BTU). The Serafin-1 well is jointly owned by PetroLatina (50%) and PetroSantander Corporation (50%).
The Company expects to release the results of an updated independent reserves report commissioned from Ryder Scott Company, L.P. and various geological and petrophysical studies during the current quarter.
Juan Carlos Rodriguez, Chief Executive of PetroLatina, commented, "Our first quarter average production rates and the initial results to date from the Serafin-1 gas well have been very encouraging and in line with our expectations. We continue to pursue our strategy of seeking to increase production and reserves and expect to resume our development drilling in a more effective and low risk manner later this year."
Thursday, April 14, 2011
PetroLatina Energy plc
PetroLatina announced a production update in respect of the first quarter of 2011.
The Company achieved total gross production from its Tisquirama, La Paloma and Midas license blocks located in the Middle Magdelana Valley, Colombia, in the three months to 31 March 2011 of 193,790 barrels of oil (bbls) (2010 equivalent period: 155,323 bbls) and total net production of 90,536 bbls (2010 equivalent period: 72,465 bbls) at an average gross production rate of 2,154 barrels of oil per day (bopd) (2010 equivalent period: 1,726 bopd) and an average net production rate of 1,006 bopd (2010 equivalent period: 805 bopd).
As announced previously, the Serafin-1 gas well located in the Company's Tisquirama license block is currently on an extended 6 month production test at a flow rate of 5.5 MMscf/d of gas and a well pressure of 1,850 pounds per square inch (psi). The well has, during the test period to date, achieved total gross production of 95.98 MMscf of gas (15,997 barrels of oil equivalent) and total net production of 44.15MMscf (7,359 boe). Gas produced during the 6 month extended test period is being sold to Ecopetrol S.A. at 90% of the regulated price for Texaco for Barranca-Ballena's gas (as regulated by CREG, the Regulatory Commission of Energy and Gas of Colombia). The regulated price is currently $4.2562/million British thermal unit (BTU). The Serafin-1 well is jointly owned by PetroLatina (50%) and PetroSantander Corporation (50%).
The Company expects to release the results of an updated independent reserves report commissioned from Ryder Scott Company, L.P. and various geological and petrophysical studies during the current quarter.
Juan Carlos Rodriguez, Chief Executive of PetroLatina, commented, "Our first quarter average production rates and the initial results to date from the Serafin-1 gas well have been very encouraging and in line with our expectations. We continue to pursue our strategy of seeking to increase production and reserves and expect to resume our development drilling in a more effective and low risk manner later this year."
KBR Bags Contract for Saudi Aramco
KBR Bags Contract for Saudi Aramco
Thursday, April 14, 2011
KBR Inc.
KBR announced that its newly-established Middle East-based Engineering Company has been awarded an engineering and project management services contract by the Saudi Arabian Oil Company (Saudi Aramco) as part of its General Engineering Services Plus (GES+) initiative. The partners in this new Engineering Company, including Abdulhadi and Al-Moaibed Consulting Engineering Co. (AMCDE) and Kellogg, Brown and Root, were selected following a competitive bidding process. The GES+ contract period is for five years with options available for extensions.
The finalization of this contract qualifies the new Engineering Company to execute front-end engineering design (FEED), detailed design, material procurement, and project management services (PMS) to support Saudi Aramco's capital programs. The Company will be an independent standalone company operating exclusively in the Middle East, and will employ and train Saudi nationals.
"We are proud to sign this contract with Saudi Aramco under its GES+ Initiative and look forward to the successful execution of future projects," said Khaled Abu-Nasrah, President, KBR Middle East. "KBR's work in the Middle East is integral to the company's rich legacy and the award of this contract further solidifies KBR's commitment to the region and to our long-time client, Saudi Aramco."
Thursday, April 14, 2011
KBR Inc.
KBR announced that its newly-established Middle East-based Engineering Company has been awarded an engineering and project management services contract by the Saudi Arabian Oil Company (Saudi Aramco) as part of its General Engineering Services Plus (GES+) initiative. The partners in this new Engineering Company, including Abdulhadi and Al-Moaibed Consulting Engineering Co. (AMCDE) and Kellogg, Brown and Root, were selected following a competitive bidding process. The GES+ contract period is for five years with options available for extensions.
The finalization of this contract qualifies the new Engineering Company to execute front-end engineering design (FEED), detailed design, material procurement, and project management services (PMS) to support Saudi Aramco's capital programs. The Company will be an independent standalone company operating exclusively in the Middle East, and will employ and train Saudi nationals.
"We are proud to sign this contract with Saudi Aramco under its GES+ Initiative and look forward to the successful execution of future projects," said Khaled Abu-Nasrah, President, KBR Middle East. "KBR's work in the Middle East is integral to the company's rich legacy and the award of this contract further solidifies KBR's commitment to the region and to our long-time client, Saudi Aramco."
Chevron Plans To Invest In Kazakh Wind Power Project
Chevron Plans To Invest In Kazakh Wind Power Project
Apr 14, 2011
Energy giant Chevron (NYSE:CVX) plans to invest in a wind power project in Kazakhstan, the Kazakh presidential administration said Thursday, quoting Chevron CEO John Watson, who is currently visiting the Central Asian republic.
"Chevron will invest in the construction of a wind farm and will contribute its share to the development of renewable energy sources in Kazakhstan," presidential website www.akorda.kz quoted Watson as saying, in comments translated into Russian.
No further details were given concerning the project.
Watson met with President Nursultan Nazarbayev less than two weeks after the veteran leader was re-elected to a fourth term by a landslide.
Kazakhstan is Central Asia's largest economy, and holds about 3% of the world's recoverable oil reserves. Its output of crude oil has doubled in the past 10 years, becoming the second biggest oil producer in the former Soviet Union after Russia.
The Chevron led Tengizchevroil consortium is the country's largest oil producer, accounting for 25.9 million metric tons out of a total crude oil output of 79.5 million metric tons.
Shares of Chevron are trading up 0.47% at $104.3.
Apr 14, 2011
Energy giant Chevron (NYSE:CVX) plans to invest in a wind power project in Kazakhstan, the Kazakh presidential administration said Thursday, quoting Chevron CEO John Watson, who is currently visiting the Central Asian republic.
"Chevron will invest in the construction of a wind farm and will contribute its share to the development of renewable energy sources in Kazakhstan," presidential website www.akorda.kz quoted Watson as saying, in comments translated into Russian.
No further details were given concerning the project.
Watson met with President Nursultan Nazarbayev less than two weeks after the veteran leader was re-elected to a fourth term by a landslide.
Kazakhstan is Central Asia's largest economy, and holds about 3% of the world's recoverable oil reserves. Its output of crude oil has doubled in the past 10 years, becoming the second biggest oil producer in the former Soviet Union after Russia.
The Chevron led Tengizchevroil consortium is the country's largest oil producer, accounting for 25.9 million metric tons out of a total crude oil output of 79.5 million metric tons.
Shares of Chevron are trading up 0.47% at $104.3.
Analysis: Another Look at The Bird
Analysis: Another Look at The Bird
Thursday, April 14, 2011
Rigzone Staff
by Trey Cowan
In a January 5, 2011 article, we dubbed the Dow Jones Transportation Index (DJT) the canary in the coal mine based on its predictive properties relative to oil price declines.
Par for the course, the recent decline in WTI crude prices was in fact preceded by a pullback in the DJT last week. Specifically, the DJT fell 3% for the week ending April 8th. Crude futures were advancing last week (improving 4%). With the last two daily declines, oil prices are now 6% below their recent peak closing price of $112.73, set last Friday on April 8th.
Given their lagging tendency, relative to the Dow Jones Transportation Index, we would expect this recent correction in oil prices to find its bottom soon.
Why this pattern occurs is really no mystery. The transportation markets are a leading indicator of the market's perception on economic activity. Higher fuel prices at some point curtail activity levels across the board, effectively diminishing demand for not just fuel but all goods and services. Should we see a dramatic pullback in the transportation index beyond the recent low set in March, barring other factors extant to macroeconomic conditions, then we would expect oil to retrace back to levels of $90 per barrel seen at onset of the year.
We are already starting to see signs that higher gasoline prices are causing a shift in consumer behavior. At the pump, gas station owners have begun to report that the frequency of customers and volume of gasoline purchases is dropping on a weekly basis. The numbers support these claims as the MasterCard Spending Pulse, which tracks sales at 140,000 gas stations, reports gasoline consumption has been falling for the past 6 weeks straight.
Back in January we warned of this phenomenon regarding demand destruction in our article "Panning Out". Here is what we said:
There is a real threshold that causes consumers to modify their driving patterns (i.e. a shrinking discretionary budget giving way to a reduction in miles driven) that could stall the current economic recovery underway.
Assuming that the average amount of annual discretionary spent per US household is approximately $1,000, then a $0.75 per gallon increase in gas prices would absorb practically all the discretionary budget for a two-car family. Using average 2010 gasoline prices as the base, this would imply that US drivers will see their discretionary budgets evaporate once gasoline prices top $3.50 per gallon.
As demonstrated in the following chart, you can see that what is occurring today corresponds with our January prediction.
Sustained energy demand destruction, in our opinion, would likely spread to other areas of the economy. So, while government officials look to higher energy prices as a means to spur innovation in alternative energy sources, the trade-off could be a derailment of the current economic recovery. While we do not have a calamity or supply disruption that at other times would merit tapping the Strategic Petroleum Reserve, a whole-hearted dismissal of utilizing this tool puts the United States' energy policy in a game of chicken with our economic recovery.
Thursday, April 14, 2011
Rigzone Staff
by Trey Cowan
In a January 5, 2011 article, we dubbed the Dow Jones Transportation Index (DJT) the canary in the coal mine based on its predictive properties relative to oil price declines.
Par for the course, the recent decline in WTI crude prices was in fact preceded by a pullback in the DJT last week. Specifically, the DJT fell 3% for the week ending April 8th. Crude futures were advancing last week (improving 4%). With the last two daily declines, oil prices are now 6% below their recent peak closing price of $112.73, set last Friday on April 8th.
Given their lagging tendency, relative to the Dow Jones Transportation Index, we would expect this recent correction in oil prices to find its bottom soon.
Why this pattern occurs is really no mystery. The transportation markets are a leading indicator of the market's perception on economic activity. Higher fuel prices at some point curtail activity levels across the board, effectively diminishing demand for not just fuel but all goods and services. Should we see a dramatic pullback in the transportation index beyond the recent low set in March, barring other factors extant to macroeconomic conditions, then we would expect oil to retrace back to levels of $90 per barrel seen at onset of the year.
We are already starting to see signs that higher gasoline prices are causing a shift in consumer behavior. At the pump, gas station owners have begun to report that the frequency of customers and volume of gasoline purchases is dropping on a weekly basis. The numbers support these claims as the MasterCard Spending Pulse, which tracks sales at 140,000 gas stations, reports gasoline consumption has been falling for the past 6 weeks straight.
Back in January we warned of this phenomenon regarding demand destruction in our article "Panning Out". Here is what we said:
There is a real threshold that causes consumers to modify their driving patterns (i.e. a shrinking discretionary budget giving way to a reduction in miles driven) that could stall the current economic recovery underway.
Assuming that the average amount of annual discretionary spent per US household is approximately $1,000, then a $0.75 per gallon increase in gas prices would absorb practically all the discretionary budget for a two-car family. Using average 2010 gasoline prices as the base, this would imply that US drivers will see their discretionary budgets evaporate once gasoline prices top $3.50 per gallon.
As demonstrated in the following chart, you can see that what is occurring today corresponds with our January prediction.
Sustained energy demand destruction, in our opinion, would likely spread to other areas of the economy. So, while government officials look to higher energy prices as a means to spur innovation in alternative energy sources, the trade-off could be a derailment of the current economic recovery. While we do not have a calamity or supply disruption that at other times would merit tapping the Strategic Petroleum Reserve, a whole-hearted dismissal of utilizing this tool puts the United States' energy policy in a game of chicken with our economic recovery.
Aminex Receives Extension for Nyuni PSA
Aminex Receives Extension for Nyuni PSA
Thursday, April 14, 2011
Aminex plc
Aminex has received a formal extension of 6 months to the Nyuni East Songo-Songo Productions Sharing Agreement (Nyuni PSA) from the Tanzanian Ministry of Energy and Minerals. This extension is to cover the likely eventuality that the Nyuni-2 well, due to be spudded in the next few weeks, will not be completed within the life of the existing Nyuni PSA which expires this year.
As announced on April 12, the Minister of Energy and Minerals has now signed a 25-year Development License for the Kiliwani North Gas Field. This license area has been carved out from the Nyuni PSA. Terms for a new and expanded PSA to replace the expiring Nyuni PSA have been negotiated and agreed and are expected to be formally concluded in due course.
Aminex chairman Brian Hall commented, "We are very grateful for the co-operation we have received from the Tanzanian authorities in facilitating completion of our current drilling program and we are looking forward to continuing activity in this interesting part of the East African coastal margin."
The Nyuni PSA is held as follows:
* Ndovu Resources Ltd. 65% (operator)
* RAK Gas Commission 25%
* Bounty Oil 5%
* Key Petroleum 5%
Thursday, April 14, 2011
Aminex plc
Aminex has received a formal extension of 6 months to the Nyuni East Songo-Songo Productions Sharing Agreement (Nyuni PSA) from the Tanzanian Ministry of Energy and Minerals. This extension is to cover the likely eventuality that the Nyuni-2 well, due to be spudded in the next few weeks, will not be completed within the life of the existing Nyuni PSA which expires this year.
As announced on April 12, the Minister of Energy and Minerals has now signed a 25-year Development License for the Kiliwani North Gas Field. This license area has been carved out from the Nyuni PSA. Terms for a new and expanded PSA to replace the expiring Nyuni PSA have been negotiated and agreed and are expected to be formally concluded in due course.
Aminex chairman Brian Hall commented, "We are very grateful for the co-operation we have received from the Tanzanian authorities in facilitating completion of our current drilling program and we are looking forward to continuing activity in this interesting part of the East African coastal margin."
The Nyuni PSA is held as follows:
* Ndovu Resources Ltd. 65% (operator)
* RAK Gas Commission 25%
* Bounty Oil 5%
* Key Petroleum 5%
French, US, Canadian Oil Ventures in Libya
French, US, Canadian Oil Ventures in Libya
Thursday, April 14, 2011
Deutsche Presse-Agentur (dpa)
Three Libyan oil ventures involving French, US and Canadian companies had their assets frozen by the European Union on Thursday, as it issued a fresh round of sanctions in a bid to increase pressure on the regime of Moammer Gaddafi.
Sanctions against a total of 11 Libyan energy firms came into force Thursday.
The three joint ventures are between Libya's National Oil Corporation and France-based Total, and the US-based Occidental Petroleum Corporation and Petro Canada.
The other companies targeted by the sanctions are all subsidiaries of the National Oil Corporation.
These sanctions add to the 16 energy companies already placed under sanctions, implementing a "de facto oil and gas embargo," said German Foreign Minister Guido Westerwelle on Tuesday while announcing the extra sanctions.
The EU also froze the assets of 15 other Libyan companies, including banks, investment firms and Libyan Arab Airlines, which is owned by the Libyan government.
Libya's ambassador to Chad and the governor of Libya's southern Ghat district were also hit with travel bans and asset freezes for recruiting mercenaries to support Gaddafi's regime.
Some two dozen people, including Gaddafi, his relatives and close associates, had earlier been targeted by EU sanctions.
One, however, had his travel ban and asset freeze lifted on Thursday, former foreign minister Musa Kusa, who had been defected on March 30, in Britain.
Thursday, April 14, 2011
Deutsche Presse-Agentur (dpa)
Three Libyan oil ventures involving French, US and Canadian companies had their assets frozen by the European Union on Thursday, as it issued a fresh round of sanctions in a bid to increase pressure on the regime of Moammer Gaddafi.
Sanctions against a total of 11 Libyan energy firms came into force Thursday.
The three joint ventures are between Libya's National Oil Corporation and France-based Total, and the US-based Occidental Petroleum Corporation and Petro Canada.
The other companies targeted by the sanctions are all subsidiaries of the National Oil Corporation.
These sanctions add to the 16 energy companies already placed under sanctions, implementing a "de facto oil and gas embargo," said German Foreign Minister Guido Westerwelle on Tuesday while announcing the extra sanctions.
The EU also froze the assets of 15 other Libyan companies, including banks, investment firms and Libyan Arab Airlines, which is owned by the Libyan government.
Libya's ambassador to Chad and the governor of Libya's southern Ghat district were also hit with travel bans and asset freezes for recruiting mercenaries to support Gaddafi's regime.
Some two dozen people, including Gaddafi, his relatives and close associates, had earlier been targeted by EU sanctions.
One, however, had his travel ban and asset freeze lifted on Thursday, former foreign minister Musa Kusa, who had been defected on March 30, in Britain.
Petrobras CEO: Ready to Enter Kazakh Market
Petrobras CEO: Ready to Enter Kazakh Market
Thursday, April 14, 2011
Asia Pulse Pte. Ltd.
Petrobras, the Brazilian energy giant, is hoping to enter Kazakhstan's oil sector and is currently in cooperation talks with the state-owned oil firm, KazMunayGas, to do so.
"Kazakhstan is the largest crude oil producer of the world. We have had some business meetings with the KazMunayGas executives to discuss possible cooperation between the companies," CEO of Brazil's Petrobras Jose Sergio Gabrieli told Kazinform agency.
According to him, Petrobras is ready to work together with Kazakh oil and gas companies.
"Unfortunately, we have no business ties with Kazakhstan to date, but we hope to tune up cooperation soon," he said.
Thursday, April 14, 2011
Asia Pulse Pte. Ltd.
Petrobras, the Brazilian energy giant, is hoping to enter Kazakhstan's oil sector and is currently in cooperation talks with the state-owned oil firm, KazMunayGas, to do so.
"Kazakhstan is the largest crude oil producer of the world. We have had some business meetings with the KazMunayGas executives to discuss possible cooperation between the companies," CEO of Brazil's Petrobras Jose Sergio Gabrieli told Kazinform agency.
According to him, Petrobras is ready to work together with Kazakh oil and gas companies.
"Unfortunately, we have no business ties with Kazakhstan to date, but we hope to tune up cooperation soon," he said.
Iran's South Azadegan Oil Field's Crude Output to Rise
Iran's South Azadegan Oil Field's Crude Output to Rise
Thursday, April 14, 2011
Knight Ridder/Tribune Business News
by A.Yusifzade, Trend News Agency, Baku, Azerbaijan
Iran 's South Azadegan oilfield's crude production is expected to reach 320,000 barrels per day (bpd) after completing the first phase of the development project during the next four years, the Managing director of Iran's Petroleum Engineering and Development Company Naji Sadouni said, according to Shana.
Sadouni said that completing the second phase of the project will boost the output up to 600,000 bpd.
China will invest $2.5 billion in developing the projects of the South Azadegan oilfield on Iran's side of the Iraqi border, Sadouni told Mehr news agency.
The first phase of the development project has already been started, Sadouni added.
Sadouni put the current output of the field at about 55,000 bpd.
He did not specify which Chinese company would deal with the development.
In 2009, the China National Petroleum Corporation and the National Iranian Oil Company signed a $1.76 billion deal to develop the neighboring North Azadegan field, where they hope to extract 75,000 bpd.
At present, Sinopec is engaged in the Yadavaran oilfield, which is adjacent to Azadegan oilfield.
Azadegan oil field, covering a 900 square km area, is located 80 km west of Ahwaz city in the south-western province of Khuzestan.
Azadegan is one of the world's largest deposits with 42 billion-barrel-reserves.
Iran has OPEC's second-highest oil output. After Russia, its natural gas reserves rank second in the world.
Thursday, April 14, 2011
Knight Ridder/Tribune Business News
by A.Yusifzade, Trend News Agency, Baku, Azerbaijan
Iran 's South Azadegan oilfield's crude production is expected to reach 320,000 barrels per day (bpd) after completing the first phase of the development project during the next four years, the Managing director of Iran's Petroleum Engineering and Development Company Naji Sadouni said, according to Shana.
Sadouni said that completing the second phase of the project will boost the output up to 600,000 bpd.
China will invest $2.5 billion in developing the projects of the South Azadegan oilfield on Iran's side of the Iraqi border, Sadouni told Mehr news agency.
The first phase of the development project has already been started, Sadouni added.
Sadouni put the current output of the field at about 55,000 bpd.
He did not specify which Chinese company would deal with the development.
In 2009, the China National Petroleum Corporation and the National Iranian Oil Company signed a $1.76 billion deal to develop the neighboring North Azadegan field, where they hope to extract 75,000 bpd.
At present, Sinopec is engaged in the Yadavaran oilfield, which is adjacent to Azadegan oilfield.
Azadegan oil field, covering a 900 square km area, is located 80 km west of Ahwaz city in the south-western province of Khuzestan.
Azadegan is one of the world's largest deposits with 42 billion-barrel-reserves.
Iran has OPEC's second-highest oil output. After Russia, its natural gas reserves rank second in the world.
Zipcar Prices Its IPO At $18, Above The Expected Range
Zipcar Prices Its IPO At $18, Above The Expected Range
Apr 14, 2011
Zipcar (NASDAQ:ZIP) priced its IPO at $18, above the expected range of $14-$16 per share. The Cambridge, Massachusetts based company sold about 9.68 million shares, giving the company a value of approximately $175 million.
Zipcar offers self-service vehicles for use by the hour or by the day. It is a membership-based company and claims over 560,000 members, which the company refers to as "Zipsters."
Zipcar offers more than 30 makes and models and has operations in New York, Chicago, London, Washington D.C., San Francisco, Toronto, Philadelphia, Boston, Seattle, Vancouver, Baltimore, Atlanta, Portland and Pittsburgh, as well as 230 colleges and universities serving a potential 1.7 million students.
Zipcar has 468 full-time employees and reportedly had 2010 revenue of $186.1 million, up 42% from 2009.
The company has an 80% market share in the U.S. and an approximately 50% market share worldwide, based on its total membership.
Zipcar will begin trading today on the Nasdaq Global Market under the ticker symbol "ZIP."
Apr 14, 2011
Zipcar (NASDAQ:ZIP) priced its IPO at $18, above the expected range of $14-$16 per share. The Cambridge, Massachusetts based company sold about 9.68 million shares, giving the company a value of approximately $175 million.
Zipcar offers self-service vehicles for use by the hour or by the day. It is a membership-based company and claims over 560,000 members, which the company refers to as "Zipsters."
Zipcar offers more than 30 makes and models and has operations in New York, Chicago, London, Washington D.C., San Francisco, Toronto, Philadelphia, Boston, Seattle, Vancouver, Baltimore, Atlanta, Portland and Pittsburgh, as well as 230 colleges and universities serving a potential 1.7 million students.
Zipcar has 468 full-time employees and reportedly had 2010 revenue of $186.1 million, up 42% from 2009.
The company has an 80% market share in the U.S. and an approximately 50% market share worldwide, based on its total membership.
Zipcar will begin trading today on the Nasdaq Global Market under the ticker symbol "ZIP."
Offshore Officials Get In-Depth Look
Offshore Officials Get In-Depth Look
Thursday, April 14, 2011
Houston Chronicle
by Jennifer A. Dlouhy
The top U.S. officials in charge of offshore oil and gas exploration on Wednesday got a close-up look at the first deep-water drilling project approved since last year's oil spill.
Interior Secretary Ken Salazar and his chief offshore regulator, Michael Bromwich, spent two hours examining new safety systems -- including one spurred by the spill -- on the Ensco 8501 rig that is about to begin drilling a bypass well for Noble Energy in the Gulf of Mexico.
They touched drilling fluids hauled from pits on the semisubmersible rig, interviewed workers about their jobs and studied the systems used as a last line of defense against surging oil and gas.
Afterward, Salazar said he was impressed that "testing capabilities have been significantly enhanced since a year ago."
"We're starting to see the beginning of a significant change in the culture that holds great promise," Salazar added.
Within days, the Ensco 8501 is set to begin drilling the well in Noble Energy's Santiago prospect 70 miles southeast of Venice, La., resuming work that started just four days before the blowout of BP's Macondo well and destruction of the Deepwater Horizon drilling rig last April 20.
Houston-based Noble drilled more than 7,000 feet below the seafloor in 6,500 feet of water before it was forced to plug the well under a moratorium on deep-water drilling that took effect weeks after the Macondo blowout.
The new bypass drilling is meant to get around the plugs in the original well.
Although Noble Energy is the operator of the project, with a 23.25 percent working interest, BP owns 46.5 percent of it. The other partners in the project are Red Willow Offshore and Houston Energy Deepwater Ventures.
Noble Energy secured its permit to resume work at the site on Feb. 28, becoming the first of 10 deep-water projects blocked by last year's ban that now have gotten the green light. So far, drilling has begun on just one: a well in Shell Oil's Cardamom Deep discovery 137 miles off the Louisiana coast.
One hundred twenty-three people now are working at the Noble Energy well, including 78 who work for Ensco and others employed by about a half-dozen other contractors.
Workers on the rig -- built as a collaboration between Ensco and Noble two and a half years ago -- stressed the safety practices onboard. At one point, an Ensco worker reminded Salazar and Bromwich to don protective glasses and earplugs.
Although blowout preventers are built to shear through drill pipe, they can't cut through thick joints connecting pipe. That means drillers must know whether narrow pipe or joints are passing through the device.
"What will give me comfort that in this rig, that will not happen?" he asked.
Don Williamson, the rig manager, stressed that the driller always knows the position of the pipe.
The Hydril blowout preventer being used at the Noble Energy well is two and a half years old -- the same age as the rig itself.
After last year's spill, the government stepped up testing requirements for blowout preventers, including access points called hot stab panels that allow remote controlled vehicles to operate equipment deep beneath the surface.
On the Ensco 8501, that meant installing new equipment from Oceaneering that allows the workers on the surface to conduct quicker, more efficient tests of the hot stab function.
"It's greatly enhanced our ability to test the stabs on the surface," said Rusty Critselous, a drill site leader for Noble Energy. "With this little unit, our hot stab lines are shorter and the testing process is quicker."
"That regulation is causing us to develop new and better ways to develop these testing techniques," Bemis said.
Bromwich, director of the Interior Department's Bureau of Ocean Energy Management, Regulation and Enforcement, observed later that it was gratifying that the federal requirements had spurred innovation, but said he would prefer the industry to have its own incentives for safety improvements.
"What's been missing from the industry over the last several decades has been the drive to innovate for safety without new requirements," Bromwich said.
The backdrop for the visit Wednesday was continuing tension between the oil industry and the Obama administration.
Oil industry representatives have complained that the administration is moving too slowly to restart offshore drilling following last year's spill.
Thursday, April 14, 2011
Houston Chronicle
by Jennifer A. Dlouhy
The top U.S. officials in charge of offshore oil and gas exploration on Wednesday got a close-up look at the first deep-water drilling project approved since last year's oil spill.
Interior Secretary Ken Salazar and his chief offshore regulator, Michael Bromwich, spent two hours examining new safety systems -- including one spurred by the spill -- on the Ensco 8501 rig that is about to begin drilling a bypass well for Noble Energy in the Gulf of Mexico.
They touched drilling fluids hauled from pits on the semisubmersible rig, interviewed workers about their jobs and studied the systems used as a last line of defense against surging oil and gas.
Afterward, Salazar said he was impressed that "testing capabilities have been significantly enhanced since a year ago."
"We're starting to see the beginning of a significant change in the culture that holds great promise," Salazar added.
Within days, the Ensco 8501 is set to begin drilling the well in Noble Energy's Santiago prospect 70 miles southeast of Venice, La., resuming work that started just four days before the blowout of BP's Macondo well and destruction of the Deepwater Horizon drilling rig last April 20.
Houston-based Noble drilled more than 7,000 feet below the seafloor in 6,500 feet of water before it was forced to plug the well under a moratorium on deep-water drilling that took effect weeks after the Macondo blowout.
The new bypass drilling is meant to get around the plugs in the original well.
Although Noble Energy is the operator of the project, with a 23.25 percent working interest, BP owns 46.5 percent of it. The other partners in the project are Red Willow Offshore and Houston Energy Deepwater Ventures.
Noble Energy secured its permit to resume work at the site on Feb. 28, becoming the first of 10 deep-water projects blocked by last year's ban that now have gotten the green light. So far, drilling has begun on just one: a well in Shell Oil's Cardamom Deep discovery 137 miles off the Louisiana coast.
One hundred twenty-three people now are working at the Noble Energy well, including 78 who work for Ensco and others employed by about a half-dozen other contractors.
Workers on the rig -- built as a collaboration between Ensco and Noble two and a half years ago -- stressed the safety practices onboard. At one point, an Ensco worker reminded Salazar and Bromwich to don protective glasses and earplugs.
Blowout preventer
Inside the drilling shack at the heart of the rig, the two officials pressed workers to answer questions about the blowout preventer designed as a final barrier against loss of well control. A four-month examination of the blowout preventer used at BP's well concluded it was unable to slash through off-center drill pipe, seal the well hole and trap oil underground.Although blowout preventers are built to shear through drill pipe, they can't cut through thick joints connecting pipe. That means drillers must know whether narrow pipe or joints are passing through the device.
'Give me comfort?'
Salazar wanted to know what would ensure that pipe joints weren't in the way."What will give me comfort that in this rig, that will not happen?" he asked.
Don Williamson, the rig manager, stressed that the driller always knows the position of the pipe.
The Hydril blowout preventer being used at the Noble Energy well is two and a half years old -- the same age as the rig itself.
After last year's spill, the government stepped up testing requirements for blowout preventers, including access points called hot stab panels that allow remote controlled vehicles to operate equipment deep beneath the surface.
On the Ensco 8501, that meant installing new equipment from Oceaneering that allows the workers on the surface to conduct quicker, more efficient tests of the hot stab function.
"It's greatly enhanced our ability to test the stabs on the surface," said Rusty Critselous, a drill site leader for Noble Energy. "With this little unit, our hot stab lines are shorter and the testing process is quicker."
'New and better ways'
Bob Bemis, Noble Energy's vice president of environmental, health and safety, said the federal mandate prompted the change."That regulation is causing us to develop new and better ways to develop these testing techniques," Bemis said.
Bromwich, director of the Interior Department's Bureau of Ocean Energy Management, Regulation and Enforcement, observed later that it was gratifying that the federal requirements had spurred innovation, but said he would prefer the industry to have its own incentives for safety improvements.
"What's been missing from the industry over the last several decades has been the drive to innovate for safety without new requirements," Bromwich said.
The backdrop for the visit Wednesday was continuing tension between the oil industry and the Obama administration.
Oil industry representatives have complained that the administration is moving too slowly to restart offshore drilling following last year's spill.
'Fracking' Deemed Eco-Safe at Hearing
'Fracking' Deemed Eco-Safe at Hearing
Thursday, April 14, 2011
Tulsa World, Okla.
by Jim Myers
Oklahoma Corporation Commissioner Jeff Cloud told key U.S. senators that his agency's record on protecting water from pollution makes it clear that states, not the federal government, should regulate hydraulic fracturing.
The decades-old practice has helped spark a natural-gas boom in parts of the country, along with growing controversy.
"During more than half a century of hydraulic fracturing experience, there has not been a single documented instance of contamination to groundwater or drinking water as a result of hydraulic fracturing," Cloud told the Senate Environment and Public Works Committee.
That record, he said, covers more than 100,000 wells in Oklahoma.
Cloud's testimony triggered praise from an unlikely source, Sen. Ben Cardin, D-Md., who not only led the hearing into natural-gas drilling and public health but who also represents a state that has imposed a moratorium on "fracking operations."
Cardin was critical of both the industry, which he accused of failing to meet even minimally acceptable performance levels for protecting human health, and regulatory agencies that in his view also have failed to do what is necessary to protect drinking water supplies.
What especially impressed Cardin was Cloud's explanation that Oklahoma requires the fluids used in fracking to be either recycled or injected into wells.
Cloud repeatedly offered assurances that those fluids never get into the state's water.
Cardin urged other states to follow Oklahoma's lead.
"I think we need to learn from best practices, and we have seen some of that catch on from other states," he said, also citing the record in Colorado.
In some areas, the fluids reportedly are taken to municipal wastewater treatment plants.
Sen. Jim Inhofe of Oklahoma, the committee's top Republican and a key player on environmental issues in Congress, also welcomed Cloud's testimony about the state's "long and successful history of regulating hydraulic fracturing."
"Oklahoma has long been a leader in natural gas production, and hydraulic fracturing plays a key role in providing affordable domestic energy," Inhofe said.
Tuesday's hearing came as natural gas is generating more attention, both negative and positive, as an alternative to oil as a transportation fuel. Rising oil prices and an abundance of domestic natural gas have sparked the interest of politicians, but environmental concerns accompanying the gas boom have prompted states like Maryland and New York to step back from increased drilling activity.
Sen. Robert Casey, D-Pa., is sponsoring legislation to repeal the so-called loophole for the industry and require the disclosure of chemicals used in fracking.
Casey admitted that for decades his state did not take the correct approach to regulating coal mining. Today, he said, "we have to get it right on natural gas."
According to Cardin, who cited a number of violations, and statements from others at the hearing, Pennsylvania is still struggling when it comes to regulation.
The U.S. Environmental Protection Agency also did not escape critical questions, especially concerning its take on the use of diesel fuel in fracking and whether firms that use diesel fuel must apply for a permit.
Thursday, April 14, 2011
Tulsa World, Okla.
by Jim Myers
Oklahoma Corporation Commissioner Jeff Cloud told key U.S. senators that his agency's record on protecting water from pollution makes it clear that states, not the federal government, should regulate hydraulic fracturing.
The decades-old practice has helped spark a natural-gas boom in parts of the country, along with growing controversy.
"During more than half a century of hydraulic fracturing experience, there has not been a single documented instance of contamination to groundwater or drinking water as a result of hydraulic fracturing," Cloud told the Senate Environment and Public Works Committee.
That record, he said, covers more than 100,000 wells in Oklahoma.
Cloud's testimony triggered praise from an unlikely source, Sen. Ben Cardin, D-Md., who not only led the hearing into natural-gas drilling and public health but who also represents a state that has imposed a moratorium on "fracking operations."
Cardin was critical of both the industry, which he accused of failing to meet even minimally acceptable performance levels for protecting human health, and regulatory agencies that in his view also have failed to do what is necessary to protect drinking water supplies.
What especially impressed Cardin was Cloud's explanation that Oklahoma requires the fluids used in fracking to be either recycled or injected into wells.
Cloud repeatedly offered assurances that those fluids never get into the state's water.
Cardin urged other states to follow Oklahoma's lead.
"I think we need to learn from best practices, and we have seen some of that catch on from other states," he said, also citing the record in Colorado.
In some areas, the fluids reportedly are taken to municipal wastewater treatment plants.
Sen. Jim Inhofe of Oklahoma, the committee's top Republican and a key player on environmental issues in Congress, also welcomed Cloud's testimony about the state's "long and successful history of regulating hydraulic fracturing."
"Oklahoma has long been a leader in natural gas production, and hydraulic fracturing plays a key role in providing affordable domestic energy," Inhofe said.
Tuesday's hearing came as natural gas is generating more attention, both negative and positive, as an alternative to oil as a transportation fuel. Rising oil prices and an abundance of domestic natural gas have sparked the interest of politicians, but environmental concerns accompanying the gas boom have prompted states like Maryland and New York to step back from increased drilling activity.
Sen. Robert Casey, D-Pa., is sponsoring legislation to repeal the so-called loophole for the industry and require the disclosure of chemicals used in fracking.
Casey admitted that for decades his state did not take the correct approach to regulating coal mining. Today, he said, "we have to get it right on natural gas."
According to Cardin, who cited a number of violations, and statements from others at the hearing, Pennsylvania is still struggling when it comes to regulation.
The U.S. Environmental Protection Agency also did not escape critical questions, especially concerning its take on the use of diesel fuel in fracking and whether firms that use diesel fuel must apply for a permit.
Duncan Energy Increases Quarterly Cash Distribution
Duncan Energy Increases Quarterly Cash Distribution
Apr 14, 2011
Duncan Energy Partners (NYSE:DEP) announced its board of directors had declared an increase in the quarterly cash distribution rate paid to partners to $0.4575 per common unit, or $1.83 per unit on an annualized basis.
The quarterly distribution will be paid on Friday, May 6, 2011, to unit holders of record at the close of business on Friday, April 29, 2011.
The distribution is 2.2% increase from Q1 of 2010 and is the 10th consecutive quarterly distribution increase.
The stock is up 22.62% over the last 3 months.
Apr 14, 2011
Duncan Energy Partners (NYSE:DEP) announced its board of directors had declared an increase in the quarterly cash distribution rate paid to partners to $0.4575 per common unit, or $1.83 per unit on an annualized basis.
The quarterly distribution will be paid on Friday, May 6, 2011, to unit holders of record at the close of business on Friday, April 29, 2011.
The distribution is 2.2% increase from Q1 of 2010 and is the 10th consecutive quarterly distribution increase.
The stock is up 22.62% over the last 3 months.
Foster Wheeler Secures Statoil Snohvit Development Contract
Foster Wheeler Secures Statoil Snohvit Development Contract
Thursday, April 14, 2011
Foster Wheeler AG
Foster Wheeler's subsidiary Global Engineering and Construction Group has received a contract from Statoil Petroleum AS for the pre-front-end engineering (pre-FEED) for the Snohvit Future Development Project at Statoil's Melkoya-based LNG facility on Melkøya Island approximately 450 km north of the Arctic Circle, Hammerfest, Norway.
The Foster Wheeler contract value for this project was not disclosed and the first release of work will be included in the company's first-quarter 2011 results. Statoil has informed Foster Wheeler that further releases of pre-FEED work to Foster Wheeler under the existing contract are likely to be made during 2011, depending upon the development option(s) selected by Statoil.
Foster Wheeler's scope of work will include concept design activities in order to support the finalization of the development concept and of the plant capacity for the expansion of LNG production at the Melkoya LNG facility, as well as energy optimization investigations. Foster Wheeler's involvement through this contract will continue through 2011.
"We have been working with Statoil for some time on a number of studies for the expansion of the Melkoya LNG facility," said Umberto della Sala, interim chief executive officer, Foster Wheeler AG. "This latest award reflects Statoil's confidence in our in-depth LNG expertise and the combined added value delivered by our specialist studies team in our Business Solutions Group and by our engineering, procurement and construction experts in developing execution strategies to underpin the concept development, including modularization. Delivering technically complex projects in challenging locations is an area in which we specialize and have a long and proven track record."
The existing Snohvit LNG facility is the world's northernmost LNG facility and has a design capacity of 4.2 million tonnes per annum (mtpa). Commissioned in 2007, it processes gas transported through 143-km pipeline from the subsea facilities on the Snohvit and Albatross fields, which comprise the first offshore developments in the Barents Sea.
Thursday, April 14, 2011
Foster Wheeler AG
Foster Wheeler's subsidiary Global Engineering and Construction Group has received a contract from Statoil Petroleum AS for the pre-front-end engineering (pre-FEED) for the Snohvit Future Development Project at Statoil's Melkoya-based LNG facility on Melkøya Island approximately 450 km north of the Arctic Circle, Hammerfest, Norway.
The Foster Wheeler contract value for this project was not disclosed and the first release of work will be included in the company's first-quarter 2011 results. Statoil has informed Foster Wheeler that further releases of pre-FEED work to Foster Wheeler under the existing contract are likely to be made during 2011, depending upon the development option(s) selected by Statoil.
Foster Wheeler's scope of work will include concept design activities in order to support the finalization of the development concept and of the plant capacity for the expansion of LNG production at the Melkoya LNG facility, as well as energy optimization investigations. Foster Wheeler's involvement through this contract will continue through 2011.
"We have been working with Statoil for some time on a number of studies for the expansion of the Melkoya LNG facility," said Umberto della Sala, interim chief executive officer, Foster Wheeler AG. "This latest award reflects Statoil's confidence in our in-depth LNG expertise and the combined added value delivered by our specialist studies team in our Business Solutions Group and by our engineering, procurement and construction experts in developing execution strategies to underpin the concept development, including modularization. Delivering technically complex projects in challenging locations is an area in which we specialize and have a long and proven track record."
The existing Snohvit LNG facility is the world's northernmost LNG facility and has a design capacity of 4.2 million tonnes per annum (mtpa). Commissioned in 2007, it processes gas transported through 143-km pipeline from the subsea facilities on the Snohvit and Albatross fields, which comprise the first offshore developments in the Barents Sea.
Halliburton Selected for Statoil's Ops Offshore Norway
Halliburton Selected for Statoil's Ops Offshore Norway
Thursday, April 14, 2011
Halliburton
Halliburton has been awarded a contract by Statoil to provide integrated drilling and well services offshore Norway with options up to eight years in duration with extended scope and activity.
Traditionally, Statoil has procured drilling and well services on a discrete basis. This is the first time Statoil has awarded an integrated well services contract in Norway, which includes project management by Halliburton, with the intent to increase efficiency and reduce development costs.
Under the first phase of the contract, Halliburton will provide directional drilling and logging-while-drilling services, surface data logging, drill bits, hole enlargement and coring services, cementing and pumping services, drilling and completion fluids, completion services – including multilateral junctions, SmartWell® completion systems and VersaFlex® expandable liner hangers – and project management.
The contract is part of Statoil's Fast Track Field Development initiative that has been launched to minimize the time from discovery to production and reduce development costs. In the Fast Track project, the service company and operator work more closely together as an integrated team. This results in better operational efficiency on the rigs, which, in turn, results in lower overall project costs for the operator. This allows the operator to develop marginal oil discoveries that would have been deemed uneconomical using traditional contracting models. For this contract, Halliburton's onshore operations team will integrate with Statoil's team in Stavanger, Norway.
"We are delighted with this contract, and we look forward to collaborating with Statoil to accelerate the field development and impact the production on the Norwegian Continental Shelf," said Jorunn Saetre, Halliburton's area vice president for Scandinavia.
Thursday, April 14, 2011
Halliburton
Halliburton has been awarded a contract by Statoil to provide integrated drilling and well services offshore Norway with options up to eight years in duration with extended scope and activity.
Traditionally, Statoil has procured drilling and well services on a discrete basis. This is the first time Statoil has awarded an integrated well services contract in Norway, which includes project management by Halliburton, with the intent to increase efficiency and reduce development costs.
Under the first phase of the contract, Halliburton will provide directional drilling and logging-while-drilling services, surface data logging, drill bits, hole enlargement and coring services, cementing and pumping services, drilling and completion fluids, completion services – including multilateral junctions, SmartWell® completion systems and VersaFlex® expandable liner hangers – and project management.
The contract is part of Statoil's Fast Track Field Development initiative that has been launched to minimize the time from discovery to production and reduce development costs. In the Fast Track project, the service company and operator work more closely together as an integrated team. This results in better operational efficiency on the rigs, which, in turn, results in lower overall project costs for the operator. This allows the operator to develop marginal oil discoveries that would have been deemed uneconomical using traditional contracting models. For this contract, Halliburton's onshore operations team will integrate with Statoil's team in Stavanger, Norway.
"We are delighted with this contract, and we look forward to collaborating with Statoil to accelerate the field development and impact the production on the Norwegian Continental Shelf," said Jorunn Saetre, Halliburton's area vice president for Scandinavia.
Gulf Keystone Boosts Estimates from Shaikan Discovery
Gulf Keystone Boosts Estimates from Shaikan Discovery
Thursday, April 14, 2011
Gulf Keystone Petroleum Ltd.
Gulf Keystone announced a major revision of the gross oil-in-place volumes for the Shaikan discovery in the Kurdistan Region of Iraq.
The revised gross oil-in-place volumes for the Shaikan discovery, as calculated by Dynamic Global Advisors (DGA), independent Houston-based exploration consultants, are a P90 value of 4.9 billion barrels to a P10 value of 10.8 billion barrels of oil-in-place with a mean value of 7.5 billion barrels and a P1 value of 15 billion barrels.
This is a very significant upward revision from the previously announced range of 1.9 to 7.4 billion barrels of gross oil-in-place with a mean value of 4.2 billion barrels and a P1 value of 13 billion barrels, also calculated by DGA. The revision is based on the data acquired since the last resource evaluation of the Shaikan discovery by DGA issued in January 2010, which was supported by an additional third party analysis by Ryder Scott consultants with a range of gross total petroleum-initially-in-place (PIIP) of 1.52 (P90) to 7.52 (P10) billion barrels.
The new data has been acquired as a result of:
* Shaikan-2 oil discovery and well test in the upper section of the Jurassic section, nine km to the east of Shaikan-1
* Shaikan-1 extended well test production
* Shaikan-3 testing and production results
* Preliminary results of the analysis of 3D seismic data acquired for the Shaikan (599km²) and Sheikh Adi (215km²) blocks
* Evaluation of existing seismic lines and regional geological data for the Ber Bahr, Akri-Bijeel (Bijeel-1 well) and Sheikh Adi blocks.
* PVT (pressure, volume, temperature) analysis of oil samples from the Triassic Kurre Chine tests at Shaikan-1.
The Shaikan-2 appraisal well is now drilling deeper into the Jurassic and is scheduled to drill on into the Triassic. Once the well reaches TD at the bottom of the Triassic or into the top of the Permian interval, the Company will consider a possible further revision of the Shaikan oil-in-place volumes, taking into account additional information from the reservoirs previously only penetrated by Shaikan-1 and from potential additional discoveries from possible zones below those reached by Shaikan-1, projected by DGA to contain an additional 1 to 5 billion barrels of prospective resources.
John Gerstenlauer, Gulf Keystone's Chief Operating Officer, commented, "We have always believed that the initial gross oil-in-place range for the Shaikan discovery was a conservative estimate that would increase as more information became available. This gross oil-in-place volumes revision by DGA, entirely supported by the Company's management and Board of Directors, confirms that belief. We eagerly look forward to additional drilling results from Shaikan-2, the soon to be spudded Shaikan-4 and the remainder of the Shaikan appraisal drilling program. We firmly believe that even with this upward revision the numbers for the Shaikan discovery are still conservative."
Thursday, April 14, 2011
Gulf Keystone Petroleum Ltd.
Gulf Keystone announced a major revision of the gross oil-in-place volumes for the Shaikan discovery in the Kurdistan Region of Iraq.
The revised gross oil-in-place volumes for the Shaikan discovery, as calculated by Dynamic Global Advisors (DGA), independent Houston-based exploration consultants, are a P90 value of 4.9 billion barrels to a P10 value of 10.8 billion barrels of oil-in-place with a mean value of 7.5 billion barrels and a P1 value of 15 billion barrels.
This is a very significant upward revision from the previously announced range of 1.9 to 7.4 billion barrels of gross oil-in-place with a mean value of 4.2 billion barrels and a P1 value of 13 billion barrels, also calculated by DGA. The revision is based on the data acquired since the last resource evaluation of the Shaikan discovery by DGA issued in January 2010, which was supported by an additional third party analysis by Ryder Scott consultants with a range of gross total petroleum-initially-in-place (PIIP) of 1.52 (P90) to 7.52 (P10) billion barrels.
The new data has been acquired as a result of:
* Shaikan-2 oil discovery and well test in the upper section of the Jurassic section, nine km to the east of Shaikan-1
* Shaikan-1 extended well test production
* Shaikan-3 testing and production results
* Preliminary results of the analysis of 3D seismic data acquired for the Shaikan (599km²) and Sheikh Adi (215km²) blocks
* Evaluation of existing seismic lines and regional geological data for the Ber Bahr, Akri-Bijeel (Bijeel-1 well) and Sheikh Adi blocks.
* PVT (pressure, volume, temperature) analysis of oil samples from the Triassic Kurre Chine tests at Shaikan-1.
The Shaikan-2 appraisal well is now drilling deeper into the Jurassic and is scheduled to drill on into the Triassic. Once the well reaches TD at the bottom of the Triassic or into the top of the Permian interval, the Company will consider a possible further revision of the Shaikan oil-in-place volumes, taking into account additional information from the reservoirs previously only penetrated by Shaikan-1 and from potential additional discoveries from possible zones below those reached by Shaikan-1, projected by DGA to contain an additional 1 to 5 billion barrels of prospective resources.
John Gerstenlauer, Gulf Keystone's Chief Operating Officer, commented, "We have always believed that the initial gross oil-in-place range for the Shaikan discovery was a conservative estimate that would increase as more information became available. This gross oil-in-place volumes revision by DGA, entirely supported by the Company's management and Board of Directors, confirms that belief. We eagerly look forward to additional drilling results from Shaikan-2, the soon to be spudded Shaikan-4 and the remainder of the Shaikan appraisal drilling program. We firmly believe that even with this upward revision the numbers for the Shaikan discovery are still conservative."
Wood Group Kenny Lands Browse LNG Gig
Wood Group Kenny Lands Browse LNG Gig
Thursday, April 14, 2011
Wood Group
Wood Group Kenny has been awarded a contract to support the Browse liquefied natural gas (LNG) development located offshore in Western Australia's Kimberley region, approximately 425km northwest of Broome.
Leading international subsea engineering company, J P Kenny Pty, together with its related Wood Group Kenny sister companies, will perform subsea and pipelines front end engineering design (FEED) for Browse. The FEED project commenced in February 2011 and will take place over the next 12-15 months based at the new Browse Project office in Perth. The first gas from Browse is expected in 2017.
Wood Group Kenny is also participating in the riser FEED work for Browse, through MCS Kenny, and will support Aker Solutions in delivering design and engineering solutions for the steel catenary risers (SCRs) on Browse.
Steve Wayman, CEO, Wood Group Kenny said, "We are delighted to be working with Woodside on the highly prestigious Browse development. This is a technically demanding and complex deepwater development that will enable us to demonstrate our continuing commitment to excellence in international offshore projects."
Morgan Harland, subsea and pipelines manager for Woodside Energy said, "Browse is one of the largest offshore developments currently being undertaken worldwide. Wood Group has significant subsea and pipeline engineering skills and expertise and we look forward to working with Wood Group and our partners on the successful completion of these important engineering contracts."
Thursday, April 14, 2011
Wood Group
Wood Group Kenny has been awarded a contract to support the Browse liquefied natural gas (LNG) development located offshore in Western Australia's Kimberley region, approximately 425km northwest of Broome.
Leading international subsea engineering company, J P Kenny Pty, together with its related Wood Group Kenny sister companies, will perform subsea and pipelines front end engineering design (FEED) for Browse. The FEED project commenced in February 2011 and will take place over the next 12-15 months based at the new Browse Project office in Perth. The first gas from Browse is expected in 2017.
Wood Group Kenny is also participating in the riser FEED work for Browse, through MCS Kenny, and will support Aker Solutions in delivering design and engineering solutions for the steel catenary risers (SCRs) on Browse.
Steve Wayman, CEO, Wood Group Kenny said, "We are delighted to be working with Woodside on the highly prestigious Browse development. This is a technically demanding and complex deepwater development that will enable us to demonstrate our continuing commitment to excellence in international offshore projects."
Morgan Harland, subsea and pipelines manager for Woodside Energy said, "Browse is one of the largest offshore developments currently being undertaken worldwide. Wood Group has significant subsea and pipeline engineering skills and expertise and we look forward to working with Wood Group and our partners on the successful completion of these important engineering contracts."
OGX Hits Oil Pay in Campos Basin
OGX Hits Oil Pay in Campos Basin
Thursday, April 14, 2011
OGX S.A.
OGX has identified the presence of hydrocarbons in the Albian section of well 1-OGX-33-RJS, which is located in the BM-C-41 block, in the shallow waters of the Campos Basin. OGX holds a 100% working interest in this block.
An oil column of approximately 95 meters with approximately 42 meters of net pay has been identified in the carbonate reservoirs of the Albian section. The drilling of well OGX-33, also known as the Chimborazo prospect, was concluded at a final depth of 3,755 meters.
The OGX-33 well is situated 84 kilometers off the coast of Rio de Janeiro at a water depth of about 127 meters. The rig, Pride Venezuela, left the well on April 9, 2011. Drilling of the third extension well (OGX-42) of the Pipeline accumulation has been initiated.
Thursday, April 14, 2011
OGX S.A.
OGX has identified the presence of hydrocarbons in the Albian section of well 1-OGX-33-RJS, which is located in the BM-C-41 block, in the shallow waters of the Campos Basin. OGX holds a 100% working interest in this block.
An oil column of approximately 95 meters with approximately 42 meters of net pay has been identified in the carbonate reservoirs of the Albian section. The drilling of well OGX-33, also known as the Chimborazo prospect, was concluded at a final depth of 3,755 meters.
The OGX-33 well is situated 84 kilometers off the coast of Rio de Janeiro at a water depth of about 127 meters. The rig, Pride Venezuela, left the well on April 9, 2011. Drilling of the third extension well (OGX-42) of the Pipeline accumulation has been initiated.
BP, Rosneft Extend Deadline for Share Swap
BP, Rosneft Extend Deadline for Share Swap
Thursday, April 14, 2011
BP plc
BP has agreed with Rosneft to extend the deadline for completing the share swap agreement (previously announced on January 14) to May 16, 2011. The agreement between the two companies followed the April 8, decision of the arbitral tribunal to allow them to discuss extension of the deadline. This means that the share swap agreement will now not terminate on April 14, 2011.
The share swap agreement, between BP and Rosneft, together with the related Arctic Opportunity, were originally announced on January 14, 2011. Both the share swap agreement and the Arctic Opportunity remain subject to an interim injunction.
BP intends to continue with the arbitration process to obtain a final award on all outstanding issues, including whether or not the interim injunction should continue.
BP remains fully committed to TNK-BP as its primary business vehicle in Russia and fully supports its strategy and investment program, which should ensure its success for decades to come. BP also owns a 1.3% interest in Rosneft and has been exploring offshore Sakhalin for over a decade and engaging in Arctic studies.
Thursday, April 14, 2011
BP plc
BP has agreed with Rosneft to extend the deadline for completing the share swap agreement (previously announced on January 14) to May 16, 2011. The agreement between the two companies followed the April 8, decision of the arbitral tribunal to allow them to discuss extension of the deadline. This means that the share swap agreement will now not terminate on April 14, 2011.
The share swap agreement, between BP and Rosneft, together with the related Arctic Opportunity, were originally announced on January 14, 2011. Both the share swap agreement and the Arctic Opportunity remain subject to an interim injunction.
BP intends to continue with the arbitration process to obtain a final award on all outstanding issues, including whether or not the interim injunction should continue.
BP remains fully committed to TNK-BP as its primary business vehicle in Russia and fully supports its strategy and investment program, which should ensure its success for decades to come. BP also owns a 1.3% interest in Rosneft and has been exploring offshore Sakhalin for over a decade and engaging in Arctic studies.
Atrush Well Delivers for Marathon Consortium
Atrush Well Delivers for Marathon Consortium
Thursday, April 14, 2011
Marathon Oil Corp.
Marathon has participated in the Atrush-1 discovery well, located approximately 55 miles northwest of Erbil in the Kurdistan Region of Iraq.
The Atrush-1 well was drilled to a total depth of approximately 11,000 feet, and encountered 400 feet of net pay in the Jurassic zones. Drill stem tests were conducted to establish reservoir pressure gradients, fluid content and properties, and reservoir deliverability. Flow rates were established totaling more than 6,000 barrels of oil per day (bopd) from three horizons. The flow rates were limited by tubing sizes and testing equipment.
Marathon holds a 20 percent interest in the Atrush block. The well was operated by the joint-venture company General Exploration Partners, Inc., a subsidiary of Aspect Holdings, LLC and ShaMaran Petroleum, Inc., which holds an 80 percent working interest in the block.
Thursday, April 14, 2011
Marathon Oil Corp.
Marathon has participated in the Atrush-1 discovery well, located approximately 55 miles northwest of Erbil in the Kurdistan Region of Iraq.
The Atrush-1 well was drilled to a total depth of approximately 11,000 feet, and encountered 400 feet of net pay in the Jurassic zones. Drill stem tests were conducted to establish reservoir pressure gradients, fluid content and properties, and reservoir deliverability. Flow rates were established totaling more than 6,000 barrels of oil per day (bopd) from three horizons. The flow rates were limited by tubing sizes and testing equipment.
Marathon holds a 20 percent interest in the Atrush block. The well was operated by the joint-venture company General Exploration Partners, Inc., a subsidiary of Aspect Holdings, LLC and ShaMaran Petroleum, Inc., which holds an 80 percent working interest in the block.
El Paso Corp. to Solely Develop Eagle Ford Play
El Paso Corp. to Solely Develop Eagle Ford Play
Thursday, April 14, 2011
El Paso Corp.
El Paso Corporation has decided to develop its Eagle Ford Shale program without a partner. This decision follows an extensive evaluation of proposals from potential partners.
"While interest in our Eagle Ford shale position was high, we believe that we will create greater value for shareholders by developing it
ourselves," said Brent Smolik, president of El Paso Exploration & Production Company. "The Eagle Ford shale program is one of our most
valuable assets, and we are very excited about the future of this program. It is a key resource for oil reserves and production growth;
the wells in our Central area in LaSalle County, Texas are exceeding our expectations, and we continue to drive efficiencies in our
drilling and completion processes as we have in the Haynesville shale program."
Thursday, April 14, 2011
El Paso Corp.
El Paso Corporation has decided to develop its Eagle Ford Shale program without a partner. This decision follows an extensive evaluation of proposals from potential partners.
"While interest in our Eagle Ford shale position was high, we believe that we will create greater value for shareholders by developing it
ourselves," said Brent Smolik, president of El Paso Exploration & Production Company. "The Eagle Ford shale program is one of our most
valuable assets, and we are very excited about the future of this program. It is a key resource for oil reserves and production growth;
the wells in our Central area in LaSalle County, Texas are exceeding our expectations, and we continue to drive efficiencies in our
drilling and completion processes as we have in the Haynesville shale program."
Major Gas Find at Apache's Zola Well
Major Gas Find at Apache's Zola Well
Thursday, April 14, 2011
OMV
OMV announced Apache has discovered gas on the North West Shelf of Australia in the Zola-1 exploration well. This represents one of the largest gas discoveries by the company. Zola-1 is located in the WA-290-P exploration permit and is around 100 km from the Western Australian coast. The discovery well Zola-1 and the subsequently drilled sidetrack appraisal well Zola-1/ST-1 have confirmed the existence of sandstone layers with 130 m of net gas pay in an area south of the giant Gorgon gas field. New 3D seismic data will be acquired to further assess the potential of the discovery.
The sidetrack appraisal well to the original Zola-1 discovery well was drilled down to a total depth of 4,713 m (true vertical depth). An extensive wireline measurement and pressure testing program confirmed the presence of gas within several high quality sands of the target Triassic Mungaroo Formation. The well and sidetrack were drilled in a water depth of 285 m and encountered 130 m of net gas pay. Both will be plugged and abandoned as per plan.
In order to further assess the development potential of Zola, OMV and its partners in WA-290-P, Apache (operator), Santos, Nippon Oil Exploration and Tap Oil, have agreed to acquire a new high resolution 3D seismic survey over the permit, which is likely to commence mid 2011.
Jaap Huijskes, member of the OMV Executive Board responsible for Exploration and Production (E&P), stated, "Zola-1 is one of OMV's biggest gas discoveries and is the result of a successful and safely carried out exploration and appraisal drilling campaign. We are very
proud of OMV's exploration activities in Australia, which have culminated in this significant discovery on the North West Shelf. The next step will be to further appraise the gas discovery, including the acquisition of a new 3D seismic survey."
Balanced international E&P portfolio
In 2010, OMV's oil and gas production was 318,000 boe/d and its proven reserves were about 1.15 bn boe at year-end. In its core countries in Romania and Austria, OMV is focusing on reducing the natural decline and on enhancing the recovery rates from mature fields. Future growth is expected to come via new field developments, exploration and acquisitions internationally. OMV intends to grow the existing portfolio to and beyond critical mass, on a production per country basis, and is looking to find new growth areas within the Caspian, Middle East and North Africa regions where OMV can leverage on its existing E&P exposure.
WA-290-P Joint Venture
* OMV Australia: 20%
* Apache (operator): 30.25%
* Santos: 24.75%
* Nippon Oil Exploration: 15%
* Tap Oil: 10%
Thursday, April 14, 2011
OMV
OMV announced Apache has discovered gas on the North West Shelf of Australia in the Zola-1 exploration well. This represents one of the largest gas discoveries by the company. Zola-1 is located in the WA-290-P exploration permit and is around 100 km from the Western Australian coast. The discovery well Zola-1 and the subsequently drilled sidetrack appraisal well Zola-1/ST-1 have confirmed the existence of sandstone layers with 130 m of net gas pay in an area south of the giant Gorgon gas field. New 3D seismic data will be acquired to further assess the potential of the discovery.
The sidetrack appraisal well to the original Zola-1 discovery well was drilled down to a total depth of 4,713 m (true vertical depth). An extensive wireline measurement and pressure testing program confirmed the presence of gas within several high quality sands of the target Triassic Mungaroo Formation. The well and sidetrack were drilled in a water depth of 285 m and encountered 130 m of net gas pay. Both will be plugged and abandoned as per plan.
In order to further assess the development potential of Zola, OMV and its partners in WA-290-P, Apache (operator), Santos, Nippon Oil Exploration and Tap Oil, have agreed to acquire a new high resolution 3D seismic survey over the permit, which is likely to commence mid 2011.
Jaap Huijskes, member of the OMV Executive Board responsible for Exploration and Production (E&P), stated, "Zola-1 is one of OMV's biggest gas discoveries and is the result of a successful and safely carried out exploration and appraisal drilling campaign. We are very
proud of OMV's exploration activities in Australia, which have culminated in this significant discovery on the North West Shelf. The next step will be to further appraise the gas discovery, including the acquisition of a new 3D seismic survey."
Balanced international E&P portfolio
In 2010, OMV's oil and gas production was 318,000 boe/d and its proven reserves were about 1.15 bn boe at year-end. In its core countries in Romania and Austria, OMV is focusing on reducing the natural decline and on enhancing the recovery rates from mature fields. Future growth is expected to come via new field developments, exploration and acquisitions internationally. OMV intends to grow the existing portfolio to and beyond critical mass, on a production per country basis, and is looking to find new growth areas within the Caspian, Middle East and North Africa regions where OMV can leverage on its existing E&P exposure.
WA-290-P Joint Venture
* OMV Australia: 20%
* Apache (operator): 30.25%
* Santos: 24.75%
* Nippon Oil Exploration: 15%
* Tap Oil: 10%
The Labor Department Reported Jobless Claims Rose 27,000 To 412,000, Wholesale Costs Up 0.7%
The Labor Department Reported Jobless Claims Rose 27,000 To 412,000, Wholesale Costs Up 0.7%
Apr 14, 2011
The Labor Department reported that applications for jobless benefits rose 27,000 in the week ended April 9 to 412,000. Economists had expected that claims would be little changed at 380,000, according to a Bloomberg News survey.
The labor market is showing signs of strengthening as payrolls increase, which could help to sustain gains in consumer spending.
The average of new claims over the past four weeks rose by 5,500 to 395,750. The Labor Department also reported that wholesale costs in the U.S. rose 0.7% in March, led by higher prices for energy, light trucks and passenger cars. Economists had expected a 1% gain on average for the producer price index.
The increase was smaller than forecast as food prices unexpectedly dropped. The core measure, excluding food and energy costs, rose 0.3%.
Apr 14, 2011
The Labor Department reported that applications for jobless benefits rose 27,000 in the week ended April 9 to 412,000. Economists had expected that claims would be little changed at 380,000, according to a Bloomberg News survey.
The labor market is showing signs of strengthening as payrolls increase, which could help to sustain gains in consumer spending.
The average of new claims over the past four weeks rose by 5,500 to 395,750. The Labor Department also reported that wholesale costs in the U.S. rose 0.7% in March, led by higher prices for energy, light trucks and passenger cars. Economists had expected a 1% gain on average for the producer price index.
The increase was smaller than forecast as food prices unexpectedly dropped. The core measure, excluding food and energy costs, rose 0.3%.
Statoil Strikes Oil Offshore Brazil
Statoil Strikes Oil Offshore Brazil
Thursday, April 14, 2011
Statoil
A new oil find has been made by Statoil immediately adjacent the Peregrino field in the Campos Basin offshore Brazil.
An exploration well drilled in the Peregrino South structure a few kilometers south of Peregrino has encountered oil in sandstones of the Carapebus geological formation.
A significant gross oil column of 130 meters has been proven in the well and further work will be performed to confirm the volumes.
The drilling operation is still ongoing to penetrate deeper reservoir units and explore additional upside potential below the main reservoir unit.
Significant upside
"The results confirm the significant potential in the Peregrino area and underline the beliefs we have had in the upside,” said Tim Dodson, executive vice president for Exploration in Statoil.
"The well verifies the upside potential and will together with the Peregrino Southwest discovery from 2007 play an important role in further development of the Peregrino area."
"The results will indeed be implemented into our plans for further development of the field," said Kjetil Hove, head of Statoil's Brazil activities and vice president in the company's Development and Production International business area.
Following the completion of the Peregrino South well, one additional appraisal well in the Peregrino Southwest structure will be drilled to conclude the overall size of the new development.
Peregrino start-up
Oil production from the Peregrino field started last week and will gradually ramp up to a plateau of 100,000 barrels of oil equivalent per day, making Statoil an important long-term operator and partner in Brazil's growing oil and gas industry.
The initial development of the field is estimated to contain 300 to 600 recoverable million barrels of oil equivalents, and the new discovery will add additional volumes going forward.
Drilling of the well is being carried out by the Blackford Dolphin rig at a water depth of 120 meters.
Operated by Statoil, the Peregrino field is 85 kilometers off the Brazilian coast from Rio de Janeiro. In May 2010 Statoil sold a 40% stake of the Peregrino field to the Sinochem Group. Statoil holds 60% ownership and the operatorship of the field and Sinochem the remaining 40%. The closing of the transaction is pending governmental approvals.
Thursday, April 14, 2011
Statoil
A new oil find has been made by Statoil immediately adjacent the Peregrino field in the Campos Basin offshore Brazil.
An exploration well drilled in the Peregrino South structure a few kilometers south of Peregrino has encountered oil in sandstones of the Carapebus geological formation.
A significant gross oil column of 130 meters has been proven in the well and further work will be performed to confirm the volumes.
The drilling operation is still ongoing to penetrate deeper reservoir units and explore additional upside potential below the main reservoir unit.
Significant upside
"The results confirm the significant potential in the Peregrino area and underline the beliefs we have had in the upside,” said Tim Dodson, executive vice president for Exploration in Statoil.
"The well verifies the upside potential and will together with the Peregrino Southwest discovery from 2007 play an important role in further development of the Peregrino area."
"The results will indeed be implemented into our plans for further development of the field," said Kjetil Hove, head of Statoil's Brazil activities and vice president in the company's Development and Production International business area.
Following the completion of the Peregrino South well, one additional appraisal well in the Peregrino Southwest structure will be drilled to conclude the overall size of the new development.
Peregrino start-up
Oil production from the Peregrino field started last week and will gradually ramp up to a plateau of 100,000 barrels of oil equivalent per day, making Statoil an important long-term operator and partner in Brazil's growing oil and gas industry.
The initial development of the field is estimated to contain 300 to 600 recoverable million barrels of oil equivalents, and the new discovery will add additional volumes going forward.
Drilling of the well is being carried out by the Blackford Dolphin rig at a water depth of 120 meters.
Operated by Statoil, the Peregrino field is 85 kilometers off the Brazilian coast from Rio de Janeiro. In May 2010 Statoil sold a 40% stake of the Peregrino field to the Sinochem Group. Statoil holds 60% ownership and the operatorship of the field and Sinochem the remaining 40%. The closing of the transaction is pending governmental approvals.
Ford's Asia plants could see idle time
Ford's Asia plants could see idle time
Apr 14, 2011
Ford (F) CEO Alan Mulally announced the company's Asia-Pacific operations will feel more negative effects from the Japanese disaster, with its factories in the region short on Japanese-made parts. Though Mulally stated the company's earnings and business plan are not yet affected, that could change if idle time in these plants goes on too long.
Apr 14, 2011
Ford (F) CEO Alan Mulally announced the company's Asia-Pacific operations will feel more negative effects from the Japanese disaster, with its factories in the region short on Japanese-made parts. Though Mulally stated the company's earnings and business plan are not yet affected, that could change if idle time in these plants goes on too long.
GM on schedule to cut costs of next-generation Volt
GM on schedule to cut costs of next-generation Volt
Apr 14, 2011
Alan Taub, GM (GM) vice president for global research and development, says the automaker is "on track" to reduce the cost of the second- and third-generation extended range Chevrolet Volt. Taub says the company has a plan to reduce costs "all the way through 2020 and Generation 3". GM has sold about 1,200 Volts so far this year.
Apr 14, 2011
Alan Taub, GM (GM) vice president for global research and development, says the automaker is "on track" to reduce the cost of the second- and third-generation extended range Chevrolet Volt. Taub says the company has a plan to reduce costs "all the way through 2020 and Generation 3". GM has sold about 1,200 Volts so far this year.
House Panel Votes to Force More Oil Leases in U.S. Waters
House Panel Votes to Force More Oil Leases in U.S. Waters
Thursday, April 14, 2011
Dow Jones Newswires
by Ryan Tracy
A bill requiring the U.S. to open areas off the Virginia coast and in the Gulf of Mexico to oil and gas exploration cleared a key hurdle in the U.S. House Wednesday. The House Natural Resources Committee voted to approve the leasing measure, paving the way for a vote by the full House next month. Earlier Wednesday, the committee also voted to establish a 60-day maximum for the Interior Department to approve or deny offshore drilling permits. If Interior took longer, the permit would be deemed approved.
The bills are part of an effort by House Republicans to support domestic oil and gas production, which they have stepped up in recent months in the face of rising gasoline prices. Democrats have pushed back, saying that Congress should focus on providing incentives for non-traditional energy sources and reducing energy consumption.
All but two Democrats voted against the bills on offshore leasing. The bills' prospects are less certain in the Senate, where Democrats hold a majority.
One proposal approved Wednesday would override a decision last year from the Obama administration not to open the U.S. Atlantic Coast to offshore drilling. It directs the Interior Department to lease areas off the Virginia coast within one year after the bill becomes law.
The bills would also direct Interior to move forward with three new leases in the Gulf, declaring previous environmental reviews of those areas to be sufficient. The administration has delayed its Gulf leasing plans and is conducting new environmental reviews following the Deepwater Horizon disaster nearly one year ago.
"What we're attempting to do is provide some certainty to those who would give us American-made energy," said Rep. Doc Hastings (R., Wash.), chairman of the Natural Resources Committee, and a main sponsor of the bills.
During debate on the proposals, Rep. Rush Holt (D., N.J.) argued that Interior shouldn't move forward with new leases without a new environmental analysis based on lessons learned from the Deepwater Horizon. He said previous reviews had been "very clearly and woefully flawed." Rep. Doug Lamborn (R., Colo.) countered that further environmental reviews would take place as companies apply for permission to explore and drill new wells. Hastings noted that the legislation approved Wednesday requires Interior to conduct a safety review for each drilling permit. Still, Democrats criticized their counterparts for not taking up a bill that would implement recommendations of a presidential commission that studied last year's oil spill. Congress hasn't yet sent the president a bill in response to the disaster, which began with the explosion on a rig leased by BP on April 20.
A proposal to add safety regulations to the House bills, offered Wednesday by Rep. Ed Markey (D., Mass.), was voted down by the Republican majority. "This amendment would micromanage and dictate thorough safety standards" that should be established by the Interior Department, Lamborn said. The majority also rejected a host of proposals from lawmakers in coastal states designed to restrict exploration in the Pacific and Atlantic Oceans.
The legislation would also extend by one year leases impacted by the Obama administration's moratorium on drilling after the Deepwater Horizon disaster. The provision would apply to wells that weren't producing before April 30. It was added to the bill Wednesday in an amendment offered by Rep. Bill Flores (R., Texas).
Lawmakers briefly considered inserting a provision to require oil and natural gas facilities to use only equipment and materials produced in the U.S, but Rep. John Garamendi (D., Calif.) withdrew the amendment after other lawmakers said it was too inflexible. Some Republicans seemed open to the concept, however, and Garamendi said he might offer a different version at a later date.
Also Wednesday, the committee voted to require Interior to open up more resource-rich areas to exploration as part of its next five-year leasing plan. The full Republican-controlled House is expected vote on the bills next month.
Thursday, April 14, 2011
Dow Jones Newswires
by Ryan Tracy
A bill requiring the U.S. to open areas off the Virginia coast and in the Gulf of Mexico to oil and gas exploration cleared a key hurdle in the U.S. House Wednesday. The House Natural Resources Committee voted to approve the leasing measure, paving the way for a vote by the full House next month. Earlier Wednesday, the committee also voted to establish a 60-day maximum for the Interior Department to approve or deny offshore drilling permits. If Interior took longer, the permit would be deemed approved.
The bills are part of an effort by House Republicans to support domestic oil and gas production, which they have stepped up in recent months in the face of rising gasoline prices. Democrats have pushed back, saying that Congress should focus on providing incentives for non-traditional energy sources and reducing energy consumption.
All but two Democrats voted against the bills on offshore leasing. The bills' prospects are less certain in the Senate, where Democrats hold a majority.
One proposal approved Wednesday would override a decision last year from the Obama administration not to open the U.S. Atlantic Coast to offshore drilling. It directs the Interior Department to lease areas off the Virginia coast within one year after the bill becomes law.
The bills would also direct Interior to move forward with three new leases in the Gulf, declaring previous environmental reviews of those areas to be sufficient. The administration has delayed its Gulf leasing plans and is conducting new environmental reviews following the Deepwater Horizon disaster nearly one year ago.
"What we're attempting to do is provide some certainty to those who would give us American-made energy," said Rep. Doc Hastings (R., Wash.), chairman of the Natural Resources Committee, and a main sponsor of the bills.
During debate on the proposals, Rep. Rush Holt (D., N.J.) argued that Interior shouldn't move forward with new leases without a new environmental analysis based on lessons learned from the Deepwater Horizon. He said previous reviews had been "very clearly and woefully flawed." Rep. Doug Lamborn (R., Colo.) countered that further environmental reviews would take place as companies apply for permission to explore and drill new wells. Hastings noted that the legislation approved Wednesday requires Interior to conduct a safety review for each drilling permit. Still, Democrats criticized their counterparts for not taking up a bill that would implement recommendations of a presidential commission that studied last year's oil spill. Congress hasn't yet sent the president a bill in response to the disaster, which began with the explosion on a rig leased by BP on April 20.
A proposal to add safety regulations to the House bills, offered Wednesday by Rep. Ed Markey (D., Mass.), was voted down by the Republican majority. "This amendment would micromanage and dictate thorough safety standards" that should be established by the Interior Department, Lamborn said. The majority also rejected a host of proposals from lawmakers in coastal states designed to restrict exploration in the Pacific and Atlantic Oceans.
The legislation would also extend by one year leases impacted by the Obama administration's moratorium on drilling after the Deepwater Horizon disaster. The provision would apply to wells that weren't producing before April 30. It was added to the bill Wednesday in an amendment offered by Rep. Bill Flores (R., Texas).
Lawmakers briefly considered inserting a provision to require oil and natural gas facilities to use only equipment and materials produced in the U.S, but Rep. John Garamendi (D., Calif.) withdrew the amendment after other lawmakers said it was too inflexible. Some Republicans seemed open to the concept, however, and Garamendi said he might offer a different version at a later date.
Also Wednesday, the committee voted to require Interior to open up more resource-rich areas to exploration as part of its next five-year leasing plan. The full Republican-controlled House is expected vote on the bills next month.
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