Shell Gets Go-Ahead to Drill in Deepwater GOM
Wednesday, March 30, 2011
BOEMRE
The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) approved a deepwater drilling permit for a new well that was described in Shell's recently approved Exploration Plan. The proposed well was also considered in the Site-Specific Environmental Assessment (SEA) completed as part of the plan review. In order to receive the permit approval, Shell complied with rigorous new safety standards implemented in the wake of the Deepwater Horizon explosion and resulting oil spill. This includes satisfying the requirement to demonstrate the capacity to contain a subsea blowout. The approved permit is a permit to drill a new well for Shell's Well #DC001 in Garden Banks Block 427 in 2,721 ft. water depth, approximately 137 miles off the Louisiana coastline, south of Lafayette.
"Today's permit approval represents a culmination of a broad and comprehensive review process involving an exploration plan, a site-specific environmental assessment, and the application for the drilling permit - all of which complied with our rigorous safety and environmental standards," said BOEMRE Director Michael R. Bromwich. "The completion of this process further demonstrates that we are proceeding as quickly as our resources allow to properly regulate offshore oil and gas operations in the most safe and environmentally-responsible manner."
All offshore wells are identified either an exploration or development plan, which require approval prior to drilling permits being issued. Shell's supplemental Exploration Plan which includes Well #DC001 was approved March 21, 2011 as the first new deepwater exploration plan approved since the Deepwater Horizon explosion and resulting oil spill. As part of the plan's review process, BOEMRE prepared a SEA to examine Shell's proposed exploration activities in accordance with the National Environmental Policy Act and the implementation of departmental and bureau regulations.
As part of the permit approval process, the bureau reviewed Shell's containment capability available for the specific well proposed in the permit application. Shell has contracted with the Marine Well Containment Company to use its capping stack to stop the flow of oil should a well control event occur. The capabilities of the capping stack meet the requirements that are specific to the characteristics of the proposed well.
BOEMRE has worked diligently to help industry adapt to and comply with new, rigorous safety practices. These standards ensure that oil and gas development continues, while also incorporating key lessons learned from the Deepwater Horizon oil spill. This new permit meets the new safety regulations and information requirements in Notices to Lessees N06 and N10, and the Interim Final Safety Rule.
Wednesday, March 30, 2011
HWCG Expands Deepwater Capabilities
HWCG Expands Deepwater Capabilities
Wednesday, March 30, 2011
The Helix Well Containment Group
The Helix Well Containment Group (HWCG) announced it will substantially increase its subsea well containment capabilities this year by expanding its ability to control and contain a release in water depths up to 10,000 feet.
HWCG is a consortium of 22 deepwater operators in the Gulf of Mexico that has come together with the common goal of expanding capabilities to quickly and comprehensively respond to such an incident to protect employees, communities and the environment. HWCG's current system is capable of facilitating control and containment of spills in water depths up to 5,600 feet and will utilize Helix Energy Solutions Group's Q4000, the intervention vessel effectively used during the Deepwater Horizon response.
The system features a 10,000 psig capping stack.
By April 8, 2011, the system is expected to have increased containment capacity and capabilities for water depths up to 8,000 feet, as well as capture and processing capabilities of 55,000 barrels of oil per day and 95 million cubic feet of natural gas per day. In the coming weeks, HWCG will also add a 15,000 psig capping stack.
Full operational capability for water depths of up to 10,000 feet is anticipated mid-summer 2011.
"Our enhanced response and containment capabilities would exceed the depth of any well currently drilled or planned by the consortium's 22 members and would allow operators to control capping and containment stacks at the greater depths," said Roger Scheuermann, commercial director for HWCG.
Building upon equipment effectively used in the Deepwater Horizon response, HWCG has signed an agreement with Helix Energy Solutions Group to provide the primary components of the response. Additionally, HWCG has agreements in place with more than 30 service providers who will provide additional services, products and personnel, if needed.
Wednesday, March 30, 2011
The Helix Well Containment Group
The Helix Well Containment Group (HWCG) announced it will substantially increase its subsea well containment capabilities this year by expanding its ability to control and contain a release in water depths up to 10,000 feet.
HWCG is a consortium of 22 deepwater operators in the Gulf of Mexico that has come together with the common goal of expanding capabilities to quickly and comprehensively respond to such an incident to protect employees, communities and the environment. HWCG's current system is capable of facilitating control and containment of spills in water depths up to 5,600 feet and will utilize Helix Energy Solutions Group's Q4000, the intervention vessel effectively used during the Deepwater Horizon response.
The system features a 10,000 psig capping stack.
By April 8, 2011, the system is expected to have increased containment capacity and capabilities for water depths up to 8,000 feet, as well as capture and processing capabilities of 55,000 barrels of oil per day and 95 million cubic feet of natural gas per day. In the coming weeks, HWCG will also add a 15,000 psig capping stack.
Full operational capability for water depths of up to 10,000 feet is anticipated mid-summer 2011.
"Our enhanced response and containment capabilities would exceed the depth of any well currently drilled or planned by the consortium's 22 members and would allow operators to control capping and containment stacks at the greater depths," said Roger Scheuermann, commercial director for HWCG.
Building upon equipment effectively used in the Deepwater Horizon response, HWCG has signed an agreement with Helix Energy Solutions Group to provide the primary components of the response. Additionally, HWCG has agreements in place with more than 30 service providers who will provide additional services, products and personnel, if needed.
LG International to Take Stake in Geopark Assets
LG International to Take Stake in Geopark Assets
Wednesday, March 30, 2011
Geopark Holdings Ltd.
LG International and GeoPark announced the acceleration of their strategic partnership by the acquisition of and investment in certain upstream oil and gas interests of each company.
In 2010, GeoPark and LGI entered into a strategic partnership to acquire a portfolio of oil and gas upstream assets in Latin America. As an initial step to cement this relationship, GeoPark has reached an in-principle agreement to sell to LGI a 10% interest in GeoPark Chile Limited, a company registered in Bermuda, for US $70 million. The transaction is expected to close in 2Q 2011.
In addition, in a separate transaction, and subject to obtaining regulatory approvals, GeoPark has reached an in-principle agreement to invest up to US $10 million in the drilling of an exploration well on the Sholkara prospect in the LGI-operated Block 8 in Kazakhstan, which would give GeoPark effectively a 25% participating interest in Block 8. The Sholkara prospect has an unrisked mean oil resource estimate of 100-400 million barrels and represents an exciting opportunity for GeoPark outside its historical and principal area of focus.
LGI is the energy, natural resource and trading affiliate of LG Corporation, the large international Korean company with 147 subsidiaries operating in over 50 countries and with annual sales exceeding US $100 billion. LGI has successfully invested and operated in the oil and gas exploration and production business for over twenty years including current upstream oil and gas projects in Oman, Vietnam and Kazakhstan. LGI has adopted a long term strategy of investing in oil and gas upstream investments in emerging resource-rich countries and has targeted Latin America as a new growth region.
Both transactions are subject to the signing of definitive legal agreements and final approval of the GeoPark and LGI Boards of Directors.
Commenting on today's announcement, James F. Park, Chief Executive Officer of GeoPark, said, "GeoPark views its strategic partnership with LGI as a key element of its future growth and expansion in Latin America. The opportunity to cement this relationship by an initial sharing of projects builds a solid base for a promising long term and committed acquisition partnership. It also clearly demonstrates the value of the business that GeoPark has developed since 2006. GeoPark's primary operational focus will continue to be on developing an exploration and production business in Latin America and we look forward with genuine excitement to the prospect of growing our business across Latin America in partnership with LGI."
Wednesday, March 30, 2011
Geopark Holdings Ltd.
LG International and GeoPark announced the acceleration of their strategic partnership by the acquisition of and investment in certain upstream oil and gas interests of each company.
In 2010, GeoPark and LGI entered into a strategic partnership to acquire a portfolio of oil and gas upstream assets in Latin America. As an initial step to cement this relationship, GeoPark has reached an in-principle agreement to sell to LGI a 10% interest in GeoPark Chile Limited, a company registered in Bermuda, for US $70 million. The transaction is expected to close in 2Q 2011.
In addition, in a separate transaction, and subject to obtaining regulatory approvals, GeoPark has reached an in-principle agreement to invest up to US $10 million in the drilling of an exploration well on the Sholkara prospect in the LGI-operated Block 8 in Kazakhstan, which would give GeoPark effectively a 25% participating interest in Block 8. The Sholkara prospect has an unrisked mean oil resource estimate of 100-400 million barrels and represents an exciting opportunity for GeoPark outside its historical and principal area of focus.
LGI is the energy, natural resource and trading affiliate of LG Corporation, the large international Korean company with 147 subsidiaries operating in over 50 countries and with annual sales exceeding US $100 billion. LGI has successfully invested and operated in the oil and gas exploration and production business for over twenty years including current upstream oil and gas projects in Oman, Vietnam and Kazakhstan. LGI has adopted a long term strategy of investing in oil and gas upstream investments in emerging resource-rich countries and has targeted Latin America as a new growth region.
Both transactions are subject to the signing of definitive legal agreements and final approval of the GeoPark and LGI Boards of Directors.
Commenting on today's announcement, James F. Park, Chief Executive Officer of GeoPark, said, "GeoPark views its strategic partnership with LGI as a key element of its future growth and expansion in Latin America. The opportunity to cement this relationship by an initial sharing of projects builds a solid base for a promising long term and committed acquisition partnership. It also clearly demonstrates the value of the business that GeoPark has developed since 2006. GeoPark's primary operational focus will continue to be on developing an exploration and production business in Latin America and we look forward with genuine excitement to the prospect of growing our business across Latin America in partnership with LGI."
Antrim Reports Year-End 2010 Financial, Operating Results
Antrim Reports Year-End 2010 Financial, Operating Results
Wednesday, March 30, 2011
Wednesday, March 30, 2011
Antrim Energy Inc.
Antrim released its 2010 year-end financial and operating results. The results include a summary and evaluation of reserves that have been independently assessed by McDaniel & Associates Consultants Ltd. in accordance with the standards specified by National Instrument 51-101.
All financial figures are audited and in US dollars except for quarterly figures which are unaudited.
2010 Highlights:
In the United Kingdom, total proved plus probable reserves were 27.7 million boe (net to Antrim) as at December 31, 2010, the same as in 2009. Fyne and Dandy total proved plus probable reserves at December 31, 2010 remained at 17.5 million boe, unchanged from 2009. Two exploration wells are planned for the latter part of 2011 in licences adjacent to Fyne (the "Greater Fyne Area"). The Fyne and Dandy fields represent 50.2% of the Company's total proved plus probable reserves as at December 31, 2010. Causeway total proved plus probable reserves remained at 10.2 million boe (net to Antrim).
In October 2010, Antrim signed an Earn In Agreement ("EIA") with Premier Oil UK Limited ("Premier") to jointly explore development options for Fyne and the Greater Fyne Area located in the UK Central North Sea. Under the terms of the EIA, Premier paid initial consideration of $2 million to Antrim for an option to acquire a 39.9% interest in the UK Continental Shelf ("UKCS") License P077 Block 21/28a (the "Fyne License).
In return, Antrim will receive up to $50 million, less the initial consideration, towards its remaining working interest share of development costs of the Fyne Field. The option to farm-in has not yet been exercised. The UK reserves previously described do not reflect the impact of this transaction as it has not yet closed.
In March 2010, Antrim signed a Conditional Letter Agreement ("CLA") with Valiant Petroleum plc ("Valiant") to sell a 30% interest in UKCS Licenses P201 Block 211/22a South East Area and P1383 Block 211/23d (the "Causeway Licenses"). In return, Antrim will receive up to $21.75 million towards their remaining working interest share of development costs of the Causeway Field. The UK reserves previously described do not reflect the impact of this sale as the transaction has not yet closed.
In Argentina, total proved plus probable reserves in Tierra del Fuego decreased by 22.6% to 7.1 million boe as at December 31, 2010 compared to 9.24 million boe in 2009 (net to Antrim). This reduction was due to 2010 production and the impact of remapping of undeveloped drilling locations in the Los Flamencos gas field following the 2010 drilling campaign.
In Tierra del Fuego, a ten well (net 2.5) development drilling program designed to increase gas and NGL production from the Los Flamencos gas field, commenced in late February 2010 and was completed in December 2010. Eight of the ten wells have been cased as producers and three have been tied in as of December 31, 2010. The remaining five cased wells are expected to be completed and placed on production by the end of the second quarter of 2011.
In December 2010, Antrim signed an agreement with Ras Al Khaimah Gas Tanzania Limited ("RAK Gas") and NOR Energy AS whereby Antrim replaced its previous right to be carried for 30% through the pre-drilling exploration phase of the Pemba-Zanzibar Production Sharing agreement ("P-Z PSA") with a 20% carried interest through the pre-drilling phase and an additional 10% right to participate in the P-Z PSA to be exercised up to 180 days following receipt of the initial drilling results. The carried interests (up to 30%) are to be repaid from future production.
On March 17, 2011, Antrim issued 48,191,700 common shares at a price of Cdn $1.07 per common share for gross proceeds of Cdn $51.6 million (net proceeds Cdn $48.5 million) which included 6,191,700 common shares issued to the underwriters pursuant to the 98.3% exercise of the over-allotment option.
Net proceeds from the equity financing will be used for exploration of the Greater Fyne Area including the "West Teal" Fulmar Prospect at 11,500 feet drilling depth, which contains a discovery well drilled by a previous operator in 1991 that was subsequently abandoned after encountering mechanical problems, and the "Carra" Tay Prospect at 5,000 feet drilling depth.
On March 28, 2011, Antrim announced that it had signed a Letter of Award ("LOA") with AGR Peak Management Limited to drill two wells (the West Teal and Carra Prospects) commencing in the third quarter of 2011. The LOA is for a minimum duration of 50 days.
Net production to Antrim in 2010 was 1,783 boepd compared to 1,840 boepd for 2009. For the three month periods ended December 31, 2010 and 2009, net production was 1,757 and 1,990 boepd respectively. Production decreased due to the sale of the Puesto Guardian property in February 2010 partially offset by production from new wells drilled in Tierra del Fuego. All of Antrim's production is based in Argentina.
Expenditures on petroleum and natural gas properties in 2010 were $6.7 million compared to $4.8 million in 2009. The 2010 capital expenditures are net of $2 million received from Premier for the Fyne option. Capital expenditures in 2010 related to the drilling program in Argentina and ongoing development costs on the UK properties.
In 2011, Antrim will use its strong financial position to take a leading role in the exploration of the Greater Fyne Area. The drilling program is scheduled to begin in the third quarter with a well drilled and tested on the West Teal Prospect (Antrim 100%). The well is expected to take 55 days to drill and test and cost approximately $30 million.
An additional exploration well in the Greater Fyne Area is expected to be drilled on the Carra Prospect. The well is expected to take 19 days to drill, at an estimated cost of $12 million.
An East Fyne appraisal well is scheduled to be drilled on the Fyne Field. This well is intended to de-risk the eastern extent of the Fyne Field and extend the submission deadline of the FDP for Fyne to June 25, 2012.
In Argentina, Antrim's focus will be on the recently acquired Cerro de Los Leones License (Antrim 50.1% and operator) in the Neuquen Basin. A 3-D seismic program is planned to be shot to support the drilling of at least one exploration well on the license in 2011. Cash flow from Antrim's expected 1,800 boepd from Tierra del Fuego will be used to support this exploration program and any new in-country opportunities.
In East Africa, Antrim holds an option to participate up to 30% working interest in an exploration program on the Tanzanian Pemba-Zanzibar License. This region has recently experienced a significant increase in exploration activity, with several major discoveries announced by consortiums led by Anadarko and British Gas. The Pemba-Zanzibar License has been in an effective force majeure for several years. Antrim expects this impasse could be resolved with the recently announced agreement signed with RAK Gas LLC, a UAE-based exploration and production company with interests elsewhere in Tanzania.
Antrim also considers other global exploration opportunities and views its bilateral strategy of balancing longer term and capital-intensive investments in the UK North Sea with shorter investment cycle on-shore exploration and production opportunities as central to its corporate development.
All financial figures are audited and in US dollars except for quarterly figures which are unaudited.
2010 Highlights:
- Conditional sale and farm-out terms agreed for the UK North Sea Causeway and Fyne Development properties
- Multiple exploration targets identified on Antrim's UK North Sea 25th Round licenses
- Two new UK North Sea licenses awarded in the 26th Seaward Licensing Round
- Terms agreed for Antrim's carried interest through the seismic phase on the Pemba-Zanzibar License in Tanzania
- Argentina 2010 drilling program completed - eight wells cased for production
- Average gas price in Argentina increased 20% to $1.84 per mcf over 2009
- Antrim raised $48.5 million in net proceeds from equity financing to drill exploration targets on the UK North Sea 25th Round licenses
- Current cash position of $75 million and no bank debt
In the United Kingdom, total proved plus probable reserves were 27.7 million boe (net to Antrim) as at December 31, 2010, the same as in 2009. Fyne and Dandy total proved plus probable reserves at December 31, 2010 remained at 17.5 million boe, unchanged from 2009. Two exploration wells are planned for the latter part of 2011 in licences adjacent to Fyne (the "Greater Fyne Area"). The Fyne and Dandy fields represent 50.2% of the Company's total proved plus probable reserves as at December 31, 2010. Causeway total proved plus probable reserves remained at 10.2 million boe (net to Antrim).
In October 2010, Antrim signed an Earn In Agreement ("EIA") with Premier Oil UK Limited ("Premier") to jointly explore development options for Fyne and the Greater Fyne Area located in the UK Central North Sea. Under the terms of the EIA, Premier paid initial consideration of $2 million to Antrim for an option to acquire a 39.9% interest in the UK Continental Shelf ("UKCS") License P077 Block 21/28a (the "Fyne License).
In return, Antrim will receive up to $50 million, less the initial consideration, towards its remaining working interest share of development costs of the Fyne Field. The option to farm-in has not yet been exercised. The UK reserves previously described do not reflect the impact of this transaction as it has not yet closed.
In March 2010, Antrim signed a Conditional Letter Agreement ("CLA") with Valiant Petroleum plc ("Valiant") to sell a 30% interest in UKCS Licenses P201 Block 211/22a South East Area and P1383 Block 211/23d (the "Causeway Licenses"). In return, Antrim will receive up to $21.75 million towards their remaining working interest share of development costs of the Causeway Field. The UK reserves previously described do not reflect the impact of this sale as the transaction has not yet closed.
In Argentina, total proved plus probable reserves in Tierra del Fuego decreased by 22.6% to 7.1 million boe as at December 31, 2010 compared to 9.24 million boe in 2009 (net to Antrim). This reduction was due to 2010 production and the impact of remapping of undeveloped drilling locations in the Los Flamencos gas field following the 2010 drilling campaign.
In Tierra del Fuego, a ten well (net 2.5) development drilling program designed to increase gas and NGL production from the Los Flamencos gas field, commenced in late February 2010 and was completed in December 2010. Eight of the ten wells have been cased as producers and three have been tied in as of December 31, 2010. The remaining five cased wells are expected to be completed and placed on production by the end of the second quarter of 2011.
In December 2010, Antrim signed an agreement with Ras Al Khaimah Gas Tanzania Limited ("RAK Gas") and NOR Energy AS whereby Antrim replaced its previous right to be carried for 30% through the pre-drilling exploration phase of the Pemba-Zanzibar Production Sharing agreement ("P-Z PSA") with a 20% carried interest through the pre-drilling phase and an additional 10% right to participate in the P-Z PSA to be exercised up to 180 days following receipt of the initial drilling results. The carried interests (up to 30%) are to be repaid from future production.
On March 17, 2011, Antrim issued 48,191,700 common shares at a price of Cdn $1.07 per common share for gross proceeds of Cdn $51.6 million (net proceeds Cdn $48.5 million) which included 6,191,700 common shares issued to the underwriters pursuant to the 98.3% exercise of the over-allotment option.
Net proceeds from the equity financing will be used for exploration of the Greater Fyne Area including the "West Teal" Fulmar Prospect at 11,500 feet drilling depth, which contains a discovery well drilled by a previous operator in 1991 that was subsequently abandoned after encountering mechanical problems, and the "Carra" Tay Prospect at 5,000 feet drilling depth.
On March 28, 2011, Antrim announced that it had signed a Letter of Award ("LOA") with AGR Peak Management Limited to drill two wells (the West Teal and Carra Prospects) commencing in the third quarter of 2011. The LOA is for a minimum duration of 50 days.
Reserves Summary
Oil and gas revenue of $12.5 million for the year ended December 31, 2010 decreased from $13.0 million in 2009. Revenue decreased as a result of lower oil production partially offset by higher gas production and by higher oil and gas prices received. Antrim generated cash flow from operations of $1.5 million in 2010 compared to a cash flow from operations deficiency of $1.1 million in 2009. Cash flow increased due to lower operating and general and administrative costs and higher interest and other income offset by lower revenue.Net production to Antrim in 2010 was 1,783 boepd compared to 1,840 boepd for 2009. For the three month periods ended December 31, 2010 and 2009, net production was 1,757 and 1,990 boepd respectively. Production decreased due to the sale of the Puesto Guardian property in February 2010 partially offset by production from new wells drilled in Tierra del Fuego. All of Antrim's production is based in Argentina.
Expenditures on petroleum and natural gas properties in 2010 were $6.7 million compared to $4.8 million in 2009. The 2010 capital expenditures are net of $2 million received from Premier for the Fyne option. Capital expenditures in 2010 related to the drilling program in Argentina and ongoing development costs on the UK properties.
2011 Outlook
Antrim expects to have a Field Development Plan for Causeway submitted and approved in 2011 for an anticipated production startup in the middle of 2012. Production startup from the Fyne Field is anticipated in the middle of 2013.In 2011, Antrim will use its strong financial position to take a leading role in the exploration of the Greater Fyne Area. The drilling program is scheduled to begin in the third quarter with a well drilled and tested on the West Teal Prospect (Antrim 100%). The well is expected to take 55 days to drill and test and cost approximately $30 million.
An additional exploration well in the Greater Fyne Area is expected to be drilled on the Carra Prospect. The well is expected to take 19 days to drill, at an estimated cost of $12 million.
An East Fyne appraisal well is scheduled to be drilled on the Fyne Field. This well is intended to de-risk the eastern extent of the Fyne Field and extend the submission deadline of the FDP for Fyne to June 25, 2012.
In Argentina, Antrim's focus will be on the recently acquired Cerro de Los Leones License (Antrim 50.1% and operator) in the Neuquen Basin. A 3-D seismic program is planned to be shot to support the drilling of at least one exploration well on the license in 2011. Cash flow from Antrim's expected 1,800 boepd from Tierra del Fuego will be used to support this exploration program and any new in-country opportunities.
In East Africa, Antrim holds an option to participate up to 30% working interest in an exploration program on the Tanzanian Pemba-Zanzibar License. This region has recently experienced a significant increase in exploration activity, with several major discoveries announced by consortiums led by Anadarko and British Gas. The Pemba-Zanzibar License has been in an effective force majeure for several years. Antrim expects this impasse could be resolved with the recently announced agreement signed with RAK Gas LLC, a UAE-based exploration and production company with interests elsewhere in Tanzania.
Antrim also considers other global exploration opportunities and views its bilateral strategy of balancing longer term and capital-intensive investments in the UK North Sea with shorter investment cycle on-shore exploration and production opportunities as central to its corporate development.
Royal Dutch Shell issued deepwater drilling permit by BOEMRE
Royal Dutch Shell issued deepwater drilling permit by BOEMRE
The Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, approved a deepwater drilling permit for a new well that was described in Shell Offshore’s recently approved Exploration Plan. In order to receive the permit approval, Shell complied with new safety standards implemented in the wake of the Deepwater Horizon explosion and resulting oil spill, BOEMRE said. The approved permit is a permit to drill a new well for Shell’s Well #DC001 in Garden Banks Block 427 in 2,721 ft. water depth, approximately 137 miles off the Louisiana coastline, south of Lafayette.
The Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, approved a deepwater drilling permit for a new well that was described in Shell Offshore’s recently approved Exploration Plan. In order to receive the permit approval, Shell complied with new safety standards implemented in the wake of the Deepwater Horizon explosion and resulting oil spill, BOEMRE said. The approved permit is a permit to drill a new well for Shell’s Well #DC001 in Garden Banks Block 427 in 2,721 ft. water depth, approximately 137 miles off the Louisiana coastline, south of Lafayette.
FirstService launches FS Energy to improve energy efficiency
FirstService launches FS Energy to improve energy efficiency
FirstService announced the official launch of FS Energy, an energy management company that is leading environmental change by improving energy efficiency and lowering operating costs across FirstService's extensive property management portfolio. FS Energy is initially concentrating on the 450 high rise buildings the company manages in New York City.
FirstService announced the official launch of FS Energy, an energy management company that is leading environmental change by improving energy efficiency and lowering operating costs across FirstService's extensive property management portfolio. FS Energy is initially concentrating on the 450 high rise buildings the company manages in New York City.
General Motors to develop Buick plug-in hybrid
General Motors to develop Buick plug-in hybrid
General Motors (GM) is developing a Buick using the Chevrolet Volt's plug-in hybrid technology, reports Bloomberg. According to two people familiar with the project, designers are working on a version of the hybrid Opel Ampera scheduled for sale in Europe this year. The Buick version would go on sale in 2013 if it receives final approval.
General Motors (GM) is developing a Buick using the Chevrolet Volt's plug-in hybrid technology, reports Bloomberg. According to two people familiar with the project, designers are working on a version of the hybrid Opel Ampera scheduled for sale in Europe this year. The Buick version would go on sale in 2013 if it receives final approval.
Credit Suisse Lowers U.S. GDP Forecasts for First Half 2011
Credit Suisse Lowers U.S. GDP Forecasts for First Half 2011
Credit Suisse has revised down its U.S. GDP forecasts for the first half of 2011. The firm now expects 2.5% real GDP growth in Q1, down from its previous forecast of 3.5%. Its Q2 forecast was also revised down to 3.3% from 3.7%. However, the firm's 2011 second half forecasts remain unaltered at 3.8% and 4.0% for Q3 and Q4, respectively. Credit Suisse expects full year 2011 growth of 3.4% on a year-over-year basis and 3% on an annual average basis. This is down from its previous estimate of 3.8% and 3.3%, respectively. The firm sees 4.0% real GDP growth in 2012.
Credit Suisse issued a statement saying: The first quarter's forecast revision is mostly due to current quarter accounting. The monthly building blocks that add up to GDP have consistently printed below expectations this quarter, defying the much rosier readings from other parallel evidence on the economy (such as the ISM surveys). The list of GDP "source data" disappointments includes home sales, housing starts, capital goods shipments, non-residential construction, federal spending, and a sharp increase in the trade deficit. Most importantly, the GDP's largest building block - consumer spending - is slowing sharply on a sequential basis, on track for less than 2% growth in Q1, compared to 4% growth in Q4. Our revision to second quarter growth is partly a consequence of higher oil prices and the negative effect on real income growth. Consumer confidence gauges also fell sharply in March, presumably due to higher gasoline prices. Another reason for our Q2 downgrade is housing, particularly the 22% plunge in February housing starts. Falling starts will impact future readings on construction outlays and the associated GDP component - residential investment.
Credit Suisse has revised down its U.S. GDP forecasts for the first half of 2011. The firm now expects 2.5% real GDP growth in Q1, down from its previous forecast of 3.5%. Its Q2 forecast was also revised down to 3.3% from 3.7%. However, the firm's 2011 second half forecasts remain unaltered at 3.8% and 4.0% for Q3 and Q4, respectively. Credit Suisse expects full year 2011 growth of 3.4% on a year-over-year basis and 3% on an annual average basis. This is down from its previous estimate of 3.8% and 3.3%, respectively. The firm sees 4.0% real GDP growth in 2012.
Credit Suisse issued a statement saying: The first quarter's forecast revision is mostly due to current quarter accounting. The monthly building blocks that add up to GDP have consistently printed below expectations this quarter, defying the much rosier readings from other parallel evidence on the economy (such as the ISM surveys). The list of GDP "source data" disappointments includes home sales, housing starts, capital goods shipments, non-residential construction, federal spending, and a sharp increase in the trade deficit. Most importantly, the GDP's largest building block - consumer spending - is slowing sharply on a sequential basis, on track for less than 2% growth in Q1, compared to 4% growth in Q4. Our revision to second quarter growth is partly a consequence of higher oil prices and the negative effect on real income growth. Consumer confidence gauges also fell sharply in March, presumably due to higher gasoline prices. Another reason for our Q2 downgrade is housing, particularly the 22% plunge in February housing starts. Falling starts will impact future readings on construction outlays and the associated GDP component - residential investment.
ConocoPhillips up 2% on Plans to Explore Angola, Poland for Oil, Gas
ConocoPhillips up 2% on Plans to Explore Angola, Poland for Oil, Gas
ConocoPhillips is up 1.56% to $80.04, helped by the general bullish sentiment on energy shares Wednesday, as well plans to expand its operations in Angola, the Gulf of Mexico and Poland.
The company is negotiating leases on two deepwater blocks in Angola, exploring for oil and gas in the deepwater area of the Gulf of Mexico, and is active in exploring for resources in Poland. It has rights to one million acres in several different parts of the country, according to Investopedia.
ConocoPhillips is up 1.56% to $80.04, helped by the general bullish sentiment on energy shares Wednesday, as well plans to expand its operations in Angola, the Gulf of Mexico and Poland.
The company is negotiating leases on two deepwater blocks in Angola, exploring for oil and gas in the deepwater area of the Gulf of Mexico, and is active in exploring for resources in Poland. It has rights to one million acres in several different parts of the country, according to Investopedia.
Edge Boosts Production, Drills 3 Wells
Edge Boosts Production, Drills 3 Wells
Wednesday, March 30, 2011
Wednesday, March 30, 2011
Edge Resources Inc.
Edge has completed the first three wells of a multi-well drilling program. Additionally, the Company has increased production by fracturing and tying two wells into its 100% owned and operated, dedicated shallow-gas infrastructure.
The drilling rig, on contract from Ensign Energy Services, moved to the Company's location directly from northern Alberta on March 14, 2011. The rig drilled the first of at least eight licensed locations, with several others soon to be licensed and drilled. The rig was released because of "spring breakup", a period during which the winter frost comes out of the ground and the various counties restrict the movement of large equipment over the roads.
Brad Nichol, President and CEO of Edge commented, "I'm pleased with the operational team's ability to have squeezed this rig into our drilling plan prior to break-up versus waiting until break-up is over and competing with many other companies for the rigs. I am equally impressed with how quickly my team reacted to the availability of fracturing equipment.
On notice that the equipment was coming available, we immediately moved to put that equipment to work on our wells, and already have two of those wells producing into our own pipeline."
The Company commenced fracturing operations on several wells, after waiting since December 2010 for equipment to come available. The Company has successfully fractured two wells, both of which were immediately tied-into 100% owned and operated, existing shallow-gas infrastructure. Other wells will be fractured as part of this program but will not be tied-into pipeline until after spring breakup.
These two wells are flowing over 1,000 mcf/day (167 boe/day) on initial production, which adds significantly to the Company's total production mix. The Company is now generating significant revenue and positive cash flow on a monthly basis.
The Company has very low operating and F&D costs, and expects to be profitable at a natural gas price of less than $2.00/mcf.
Edge has now earned or acquired a total of 23 sections of Edmonton Sands natural gas property, each containing one drilled Edmonton Sands well. The Company has executed agreements that allow for up to another 27 sections of prospective Edmonton Sands land to be earned by drilling 1 well on each respective section.
The drilling rig, on contract from Ensign Energy Services, moved to the Company's location directly from northern Alberta on March 14, 2011. The rig drilled the first of at least eight licensed locations, with several others soon to be licensed and drilled. The rig was released because of "spring breakup", a period during which the winter frost comes out of the ground and the various counties restrict the movement of large equipment over the roads.
Brad Nichol, President and CEO of Edge commented, "I'm pleased with the operational team's ability to have squeezed this rig into our drilling plan prior to break-up versus waiting until break-up is over and competing with many other companies for the rigs. I am equally impressed with how quickly my team reacted to the availability of fracturing equipment.
On notice that the equipment was coming available, we immediately moved to put that equipment to work on our wells, and already have two of those wells producing into our own pipeline."
The Company commenced fracturing operations on several wells, after waiting since December 2010 for equipment to come available. The Company has successfully fractured two wells, both of which were immediately tied-into 100% owned and operated, existing shallow-gas infrastructure. Other wells will be fractured as part of this program but will not be tied-into pipeline until after spring breakup.
These two wells are flowing over 1,000 mcf/day (167 boe/day) on initial production, which adds significantly to the Company's total production mix. The Company is now generating significant revenue and positive cash flow on a monthly basis.
The Company has very low operating and F&D costs, and expects to be profitable at a natural gas price of less than $2.00/mcf.
Edge has now earned or acquired a total of 23 sections of Edmonton Sands natural gas property, each containing one drilled Edmonton Sands well. The Company has executed agreements that allow for up to another 27 sections of prospective Edmonton Sands land to be earned by drilling 1 well on each respective section.
Europa O&G Updates Ops
Europa O&G Updates Ops
Wednesday, March 30, 2011
Europa O&G plc
Europa O&G provided an update on several active projects.
The lower of these, Zone 2, produced oil at rates of around 80bopd with strong associated gas but very little water. Heavy wax build-up in the well and the high gas rates are thought to have impaired flow through the beam pump.
Zone 1 produces much higher volumes of fluid, but with a high water cut. Net oil production from this zone under a beam pump regime is 40bopd. The beam pump, however, is only able to drawdown the well some 300psi, indicating that there is significant production upside with a properly configured pump. It should be possible with a jet pump to produce drawdown in the region of 1,500psi or more and the main constraint will be fluid handling capacity. The recent successful re-completion of WF-3 as a water disposal well is key tool in managing this issue long term.
A jet pump system has been sourced and will be commissioned to undertake further tests on both zones. Following the results of these new tests, a longer term zonal production strategy will be decided.
The workover of WF-7, which required a new bottom hole assembly, is due to commence this week and it is hoped the well will be back onstream within the next 2 weeks. Once WF-7 is back onstream, it is expected that Group production should be approximately 300bopd with further upside expected following installation of the jet pump on WF-9 and well stimulation work at Crosby Warren.
Discussions are ongoing with regard to the acquisition of a new 3D seismic survey jointly with neighboring license holders later this year which would lead to a much more robust subsurface model for both the Crosby Warren field and the Company's nearby Wressle exploration prospect.
The joint venture group has applied for a license extension in order to pursue the remaining undrilled prospectivity on the license and the associated work program is currently being agreed with the authorities. Barchiz-1 sidetrack is expected to be drilled in the second half of 2011.
In the meantime and following the success of the CGG work, further 3D seismic data is planned for later this year. This survey, which could be acquired in Q4 2011, will quantify the western extent of the Berenx structure, which tested dry gas in the 1970's.
Acquiring this survey will fulfil the work commitment of the first phase of the permit and allow for automatic renewal in early 2012.
The Company is actively engaged in new venture activity, including current and near-term licensing rounds in its core area of NW and Continental Europe. The aim is to add significant high impact exploration acreage into the asset portfolio for drilling in 2012 onwards.
Paul Barrett, Managing Director, said, "There has been significant progress in a number of value-enhancing projects and we look forward to a sustained newsflow from seismic, drilling and new venture activity through the coming 12 months. Production growth over the coming months is expected to support this activity."
Wednesday, March 30, 2011
Europa O&G plc
Europa O&G provided an update on several active projects.
Highlights
- UK Production tested oil from two zones in the new onshore West Firsby well
- WF-9
- Installation of jet pump is key to maximizing rates
- Well stimulation work being planned for Crosby Warren
- Romania Barchiz-1 sidetrack to deepen the well to the primary target
- France 3D reprocessing complete at Berenx, new 3D and engineering work planned
West Firsby
Two zonal pumping tests have been conducted on the new WF-9 well. As previously reported, the well encountered oil in two reservoir zones.The lower of these, Zone 2, produced oil at rates of around 80bopd with strong associated gas but very little water. Heavy wax build-up in the well and the high gas rates are thought to have impaired flow through the beam pump.
Zone 1 produces much higher volumes of fluid, but with a high water cut. Net oil production from this zone under a beam pump regime is 40bopd. The beam pump, however, is only able to drawdown the well some 300psi, indicating that there is significant production upside with a properly configured pump. It should be possible with a jet pump to produce drawdown in the region of 1,500psi or more and the main constraint will be fluid handling capacity. The recent successful re-completion of WF-3 as a water disposal well is key tool in managing this issue long term.
A jet pump system has been sourced and will be commissioned to undertake further tests on both zones. Following the results of these new tests, a longer term zonal production strategy will be decided.
The workover of WF-7, which required a new bottom hole assembly, is due to commence this week and it is hoped the well will be back onstream within the next 2 weeks. Once WF-7 is back onstream, it is expected that Group production should be approximately 300bopd with further upside expected following installation of the jet pump on WF-9 and well stimulation work at Crosby Warren.
Crosby Warren
Engineering studies are complete on the question of undertaking a new hydraulic frac stimulation of the CW-1 reservoir. The study has shown that the historical frac has become ineffective over time. Consequently, a repeat frac stimulation presents an opportunity to significantly increase field production. The original frac was highly successful and led to a 15 fold increase in production rate. It is hoped that this work can be carried out in the next 2-4 months.Discussions are ongoing with regard to the acquisition of a new 3D seismic survey jointly with neighboring license holders later this year which would lead to a much more robust subsurface model for both the Crosby Warren field and the Company's nearby Wressle exploration prospect.
Barchiz
Barchiz-1, drilled late last year, recovered oil on DST from a shallow sandstone reservoir with approximately 35 feet of net pay. The main exploration target of the well was not reached due to technical constraints. Following partner meetings last week, Europa has declared an intention to deepen the Barchiz-1 well to the primary objective as a sole-risk operation, subject to financing. The Operator proposed acquiring further seismic data along trend from Barchiz to identify a new exploration well location in the play. However, the Directors' view is that this an opportunity to test whether the Oligocene reservoir is present beneath the current well TD, a concept supported by nearby well control.The joint venture group has applied for a license extension in order to pursue the remaining undrilled prospectivity on the license and the associated work program is currently being agreed with the authorities. Barchiz-1 sidetrack is expected to be drilled in the second half of 2011.
Berenx
Planning the appraisal of this potentially multi-TCF gas project has taken a step forward with the completion of 3D seismic reprocessing by CGG, which has greatly improved the seismic image. NRG, the Aberdeen-based well engineering company, have been retained to undertake detailed well engineering for the planned Berenx-3 appraisal well.In the meantime and following the success of the CGG work, further 3D seismic data is planned for later this year. This survey, which could be acquired in Q4 2011, will quantify the western extent of the Berenx structure, which tested dry gas in the 1970's.
Acquiring this survey will fulfil the work commitment of the first phase of the permit and allow for automatic renewal in early 2012.
General
It should be noted that achieving optimum rates on the new West Firsby well will take some weeks and that, in conjunction with the earlier drilling delays this will generate full year (to July 31, 2011) projected revenue and profits below market expectations.The Company is actively engaged in new venture activity, including current and near-term licensing rounds in its core area of NW and Continental Europe. The aim is to add significant high impact exploration acreage into the asset portfolio for drilling in 2012 onwards.
Paul Barrett, Managing Director, said, "There has been significant progress in a number of value-enhancing projects and we look forward to a sustained newsflow from seismic, drilling and new venture activity through the coming 12 months. Production growth over the coming months is expected to support this activity."
Lamprell Bags Weatherford Contract
Lamprell Bags Weatherford Contract
Wednesday, March 30, 2011
The rigs have a static hook load capacity of 1,500,000 lbs and 800,000 lbs set back capacity.
The mast will accommodate a 750T top drive supplied by three triplex mud pumps rated at 2200HP with a 7500psi high pressure mud system. The rig will be powered by five 3516B CAT engines. Lamprell will fabricate the rigs at its yard in Jebel Ali. The project is planned to be completed during the first quarter 2012.
Commenting on the contract award Nigel McCue, Chief Executive Officer, Lamprell said, "We are delighted to be announcing this significant new contract award from Weatherford.
We believe that this land rig award, the largest yet for our oilfield engineering business, demonstrates the exciting opportunity to develop Lamprell's offering in this developing regional market. We look forward to working with Weatherford on this important project."
Wednesday, March 30, 2011
Lamprell
Lamprell has received a new contract award from Weatherford Drilling International for the engineering, construction and delivery of two 3000HP land drilling rigs, with a total contract value of $41 million.The rigs have a static hook load capacity of 1,500,000 lbs and 800,000 lbs set back capacity.
The mast will accommodate a 750T top drive supplied by three triplex mud pumps rated at 2200HP with a 7500psi high pressure mud system. The rig will be powered by five 3516B CAT engines. Lamprell will fabricate the rigs at its yard in Jebel Ali. The project is planned to be completed during the first quarter 2012.
Commenting on the contract award Nigel McCue, Chief Executive Officer, Lamprell said, "We are delighted to be announcing this significant new contract award from Weatherford.
We believe that this land rig award, the largest yet for our oilfield engineering business, demonstrates the exciting opportunity to develop Lamprell's offering in this developing regional market. We look forward to working with Weatherford on this important project."
Obama to call for more use of natural gas, biofuels
Obama to call for more use of natural gas, biofuels
President Obama will set a goal today of reducing the nation's oil imports by one-third by 2020, according to The Washington Post. The president will call on Congress and Americans to accomplish the goal by conserving energy, using more natural gas and biofuels, setting higher fuel standards for heavy trucks, and drilling for oil in more areas.
President Obama will set a goal today of reducing the nation's oil imports by one-third by 2020, according to The Washington Post. The president will call on Congress and Americans to accomplish the goal by conserving energy, using more natural gas and biofuels, setting higher fuel standards for heavy trucks, and drilling for oil in more areas.
Solimar: Potential Oil Pay at San Joaquin Basin
Solimar: Potential Oil Pay at San Joaquin Basin
Wednesday, March 30, 2011
Wednesday, March 30, 2011
Solimar Energy
Zodiac Exploration of Canada has announced potential oil pay of up to 1,000 feet in sandstone and fractured oil shale reservoirs in its Zodiac 4-9 well in the NW San Joaquin Basin. Solimar Energy has a 1.13% carried interest in the well and in a very large, approximately 101,000 acre surrounding acreage position. Solimar also owns a small, 0.5% royalty over some 26,000 acres of this acreage position.
In addition to the minority position in the Zodiac acreage, Solimar has approximately 20,000 mostly operated acres with interests from 33.33% to 75% in other leases within and adjacent the NW San Joaquin Basin oil shale play trend. Oil shales of the Kreyenhagen and McLure (Monterey equivalent) Formations are proven producers in the area and the main targets.
The Company also has a back in right for a 10% interest in a further approximately 2,900 acres in the trend flanking the Kettleman Middle Dome which is also productive from the fractured oil shales and is the subject of a redevelopment program.
There is accelerating industry activity in California oil shales lead mainly by major oil companies that is revaluing Solimar Energy's San Joaquin Basin acreage.
Key offset industry activity includes:
The Company has been aggressively building its acreage position and adding to its California (Ventura) based operating team over the past 15 months and is positioning to exploit both its conventional (sandstone which includes the recent Guijarral Hills discovery) and unconventional (oil shales) reservoir projects.
The timing of execution of the Company's strategy to accumulate oil prone acreage focussed in the San Joaquin Basin has been excellent:
More detail will be provided in due course about each of the Company's projects that have potential for oil shale production as the individual work plans are crystallized. The following brief descriptions are examples however of two large projects the Company has that are expected to significantly impact the Company in 2011.
The Company's largest project is at Kreyenhagen with over 15,000 operated acres under lease and containing extensive occurrences of thick Kreyenhagen and McLure Formation oil shales within targetable depths. Both these formations are oil productive in the adjacent oil fields where these rocks are the subject of active field redevelopment programs.
The Company is in the early stages of evaluation of the Kreyenhagen Project which also contains a large, known shallow oil accumulation in a sandstone reservoir.
There may be up to 300 million barrels of oil in place within this reservoir in the project acreage.
The Kreyenhagen Project will be the subject of considerable field activity by Solimar commencing in 2011 including re entry and production testing of some suspended wells.
The Company is also watching closely the progress of the Zodiac 4-9 well which Canadian listed Zodiac Exploration recently drilled to almost 15.000 feet and announced on 21 March a potential oil pay of over 1,000 feet in the well. Solimar has a 1.13% interest free carried through the Zodiac 4-9 and a following well in a very large acreage position totaling some 101,000 acres. In addition the Company owns a small 0.5% royalty over approximately 26,000 acres within this overall acreage position but not at the well location.
The well is being prepared for production testing as part of a program to verify the commercial potential of the multiple potential pay zones encountered.
Commenting on the evolving potential of Solimar's San Joaquin Basin acreage, CEO John Begg said, "We spent much of last year securing an acreage position focused on the oil prolific San Joaquin Basin. This strategy has placed the Company in an exciting position literally and figuratively. In most cases our immediate neighbors are major oil companies that are accelerating their work programs in the San Joaquin Basin on play types represented in our acreage. So not only do we have active programs of our own that could deliver a substantial uplift in value but escalating industry activity in and adjacent our acreage that could also be transformational at no cost to the Company."
In addition to the minority position in the Zodiac acreage, Solimar has approximately 20,000 mostly operated acres with interests from 33.33% to 75% in other leases within and adjacent the NW San Joaquin Basin oil shale play trend. Oil shales of the Kreyenhagen and McLure (Monterey equivalent) Formations are proven producers in the area and the main targets.
The Company also has a back in right for a 10% interest in a further approximately 2,900 acres in the trend flanking the Kettleman Middle Dome which is also productive from the fractured oil shales and is the subject of a redevelopment program.
There is accelerating industry activity in California oil shales lead mainly by major oil companies that is revaluing Solimar Energy's San Joaquin Basin acreage.
Key offset industry activity includes:
- The Zodiac 4-9 well which is being prepared for a flow testing program after encountering potentially 1,000 feet of pay in both sandstone and shale reservoirs
- Occidental Petroleum have become the biggest acreage holder in the NW San Joaquin oil shale trend and are already producing 45,000 bopd from fractured oil shales in California
- Chevron are redeveloping the giant Kettleman Dome field immediately adjacent Solimar's acreage focusing on production from the Kreyenhagen Shale
- A multi party JV has been successfully redeveloping the Kettleman Middle Dome which is productive from sandstone reservoirs and both the Kreyenhagen and McLure Oil Shales. Additional appraisal drilling immediately adjacent Solimar's back in right acreage is planned within 12 months
Update Summary
The Board of Solimar provided this brief update note to inform shareholders that very positive commercial activity is occurring within and adjacent the Company's asset focus area the San Joaquin Basin, with particular emphasis on the development of fractured oil shales.The Company has been aggressively building its acreage position and adding to its California (Ventura) based operating team over the past 15 months and is positioning to exploit both its conventional (sandstone which includes the recent Guijarral Hills discovery) and unconventional (oil shales) reservoir projects.
The timing of execution of the Company's strategy to accumulate oil prone acreage focussed in the San Joaquin Basin has been excellent:
- Oil prices are now very high relative to the USA domestic gas price supporting robust project economics
- Land prices for oil shale acreage are increasing in California. However Solimar believes large uplifts are still likely to bring California into line with other states of the USA where oil shale land prices can be up to 10 times higher than in California.
More detail will be provided in due course about each of the Company's projects that have potential for oil shale production as the individual work plans are crystallized. The following brief descriptions are examples however of two large projects the Company has that are expected to significantly impact the Company in 2011.
The Company's largest project is at Kreyenhagen with over 15,000 operated acres under lease and containing extensive occurrences of thick Kreyenhagen and McLure Formation oil shales within targetable depths. Both these formations are oil productive in the adjacent oil fields where these rocks are the subject of active field redevelopment programs.
The Company is in the early stages of evaluation of the Kreyenhagen Project which also contains a large, known shallow oil accumulation in a sandstone reservoir.
There may be up to 300 million barrels of oil in place within this reservoir in the project acreage.
The Kreyenhagen Project will be the subject of considerable field activity by Solimar commencing in 2011 including re entry and production testing of some suspended wells.
The Company is also watching closely the progress of the Zodiac 4-9 well which Canadian listed Zodiac Exploration recently drilled to almost 15.000 feet and announced on 21 March a potential oil pay of over 1,000 feet in the well. Solimar has a 1.13% interest free carried through the Zodiac 4-9 and a following well in a very large acreage position totaling some 101,000 acres. In addition the Company owns a small 0.5% royalty over approximately 26,000 acres within this overall acreage position but not at the well location.
The well is being prepared for production testing as part of a program to verify the commercial potential of the multiple potential pay zones encountered.
Commenting on the evolving potential of Solimar's San Joaquin Basin acreage, CEO John Begg said, "We spent much of last year securing an acreage position focused on the oil prolific San Joaquin Basin. This strategy has placed the Company in an exciting position literally and figuratively. In most cases our immediate neighbors are major oil companies that are accelerating their work programs in the San Joaquin Basin on play types represented in our acreage. So not only do we have active programs of our own that could deliver a substantial uplift in value but escalating industry activity in and adjacent our acreage that could also be transformational at no cost to the Company."
Tullow Sells Uganda Stake to Total, CNOOC for $2.9B
Tullow Sells Uganda Stake to Total, CNOOC for $2.9B
Wednesday, March 30, 2011
Tullow Oil plc
Tullow has signed Sale and Purchase Agreements (SPAs) with CNOOC and Total in respect of the sale of a one third interest to each party of the interests Tullow holds in Exploration Areas 1, 2 and 3A in Uganda. Tullow will retain a one third interest. The terms of the transactions include a total cash consideration payable to Tullow of US $2.9 billion.
With the signing of these SPAs, a key condition of the Memorandum of Understanding (MoU) agreed between Tullow, the Government of Uganda (GoU) and the Uganda Revenue Authority (URA) on March 15, 2011, has been satisfied. The next step is for Tullow to make certain tax related payments to the GoU, on receipt of which all relevant consents become final and the other provisions of the MoU become effective.
Under the MoU, Tullow and its new Partners, CNOOC and Total, have been granted new licenses over EA-1 and an onshore area of EA-3A and the partnership's rights to develop the Kingfisher discovery have been confirmed. A clear plan for the resolution of tax disputes on the various asset sales has been agreed by the GoU, the URA and Tullow.
Tullow and its Partners will now reactivate the significant program of exploration and appraisal drilling and progress their development plans for the basin which they will jointly present to the Government of Uganda for approval.
Commenting, Aidan Heavey, Chief Executive, said, "These agreements have secured the future of oil production in Uganda. Tullow, its partners and the Government of Uganda will now agree a development plan for the Lake Albert Rift Basin with a target of delivering production of at least 200,000 bopd and potentially much more as we continue to explore and appraise the basin. We are looking forward to working with CNOOC and Total, and continuing our strong relationship with the Government to bring the benefits of the oil to the people of Uganda."
Wednesday, March 30, 2011
Tullow Oil plc
Tullow has signed Sale and Purchase Agreements (SPAs) with CNOOC and Total in respect of the sale of a one third interest to each party of the interests Tullow holds in Exploration Areas 1, 2 and 3A in Uganda. Tullow will retain a one third interest. The terms of the transactions include a total cash consideration payable to Tullow of US $2.9 billion.
With the signing of these SPAs, a key condition of the Memorandum of Understanding (MoU) agreed between Tullow, the Government of Uganda (GoU) and the Uganda Revenue Authority (URA) on March 15, 2011, has been satisfied. The next step is for Tullow to make certain tax related payments to the GoU, on receipt of which all relevant consents become final and the other provisions of the MoU become effective.
Under the MoU, Tullow and its new Partners, CNOOC and Total, have been granted new licenses over EA-1 and an onshore area of EA-3A and the partnership's rights to develop the Kingfisher discovery have been confirmed. A clear plan for the resolution of tax disputes on the various asset sales has been agreed by the GoU, the URA and Tullow.
Tullow and its Partners will now reactivate the significant program of exploration and appraisal drilling and progress their development plans for the basin which they will jointly present to the Government of Uganda for approval.
Commenting, Aidan Heavey, Chief Executive, said, "These agreements have secured the future of oil production in Uganda. Tullow, its partners and the Government of Uganda will now agree a development plan for the Lake Albert Rift Basin with a target of delivering production of at least 200,000 bopd and potentially much more as we continue to explore and appraise the basin. We are looking forward to working with CNOOC and Total, and continuing our strong relationship with the Government to bring the benefits of the oil to the people of Uganda."
Statoil, KazMunaiGas Team Up in Caspian Sea JV
Statoil, KazMunaiGas Team Up in Caspian Sea JV
Wednesday, March 30, 2011
Wednesday, March 30, 2011
Statoil
Statoil and KazMunaiGas have signed the Heads of Agreement (HoA) on the Abay block in the Kazakhstani sector of the Caspian Sea.
Under the HoA, the parties plan to conduct evaluation of the hydrocarbon potential of the Abay block in the Northern Caspian Sea. Statoil and KazMunaiGas will jointly establish a company that will serve as operator of the project. The exploration work program will cover seismic surveys, data acquisition and the drilling of one exploration well.
"Joint cooperation in the Abay block is an important strategic step for Statoil as we continue our international growth. This agreement marks an important milestone in Statoil's re-entry into Kazakhstan and I am very pleased that we have strengthened our partnership with KazMunaiGas," said Tim Dodson, executive vice president for Exploration in Statoil.
In addition to the work program the joint operating company will participate in social investment projects including training of local personnel. Statoil will provide financial and technical assistance to KazMunaiGas' project to build, own and operate a jack-up drilling rig for the use in the Caspian Sea.
"We are interested in cooperation with Statoil in attracting and using their experience and technologies in operating international offshore oil and gas projects. The HoA signing confirms the intentions of the parties about the strategic partnership of our two companies on the joint activities in the Caspian Sea," said Kairgeldy Kabyldin, Chairman of the management board of JSC NC KazMunaiGas.
The Abay block is located 65 km from the shore, at a water depth of 8-10 meters.
Under the HoA, the parties plan to conduct evaluation of the hydrocarbon potential of the Abay block in the Northern Caspian Sea. Statoil and KazMunaiGas will jointly establish a company that will serve as operator of the project. The exploration work program will cover seismic surveys, data acquisition and the drilling of one exploration well.
"Joint cooperation in the Abay block is an important strategic step for Statoil as we continue our international growth. This agreement marks an important milestone in Statoil's re-entry into Kazakhstan and I am very pleased that we have strengthened our partnership with KazMunaiGas," said Tim Dodson, executive vice president for Exploration in Statoil.
In addition to the work program the joint operating company will participate in social investment projects including training of local personnel. Statoil will provide financial and technical assistance to KazMunaiGas' project to build, own and operate a jack-up drilling rig for the use in the Caspian Sea.
"We are interested in cooperation with Statoil in attracting and using their experience and technologies in operating international offshore oil and gas projects. The HoA signing confirms the intentions of the parties about the strategic partnership of our two companies on the joint activities in the Caspian Sea," said Kairgeldy Kabyldin, Chairman of the management board of JSC NC KazMunaiGas.
The Abay block is located 65 km from the shore, at a water depth of 8-10 meters.
Tethys Contracts Rig, Accelerates Drilling Program in Oman
Tethys Contracts Rig, Accelerates Drilling Program in Oman
Wednesday, March 30, 2011
Wednesday, March 30, 2011
Tethys Petroleum Ltd.
The development and exploration program on Blocks 3 and 4 onshore the Sultanate of Oman accelerates after a second drilling rig has been contracted. The first well being drilled by this rig is the Farha South-6 well ("FS-6") on Block 3.
The new rig, a 750 horsepower Deutag T-55, is operated by UK drilling contractor KCA Deutag Drilling Company. The new rig will be used alongside the Abraj 204 rig already in use on the Blocks, and currently drilling the SE-7 exploration well on Block 4.
"We are very pleased that the work program of Blocks 3 and 4 of Oman is been accelerated, underpinning both the extent of Blocks 3 & 4 areas which remain un-explored to-date as well as remaining geological uncertainties before a fully-fledged development plan is put in place.
Two rigs will allow a speedier drilling schedule for 2011," said Magnus Nordin, Managing Director of Tethys Oil AB.
FS-6 is drilled as a vertical well, designed to target the lower Barik formation. The drill site is located 140 meters southeast of well FS-4 and 750 meters south-southwest of well FS-3.
Tethys has a 30 percent interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20 percent and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50 percent.
The new rig, a 750 horsepower Deutag T-55, is operated by UK drilling contractor KCA Deutag Drilling Company. The new rig will be used alongside the Abraj 204 rig already in use on the Blocks, and currently drilling the SE-7 exploration well on Block 4.
"We are very pleased that the work program of Blocks 3 and 4 of Oman is been accelerated, underpinning both the extent of Blocks 3 & 4 areas which remain un-explored to-date as well as remaining geological uncertainties before a fully-fledged development plan is put in place.
Two rigs will allow a speedier drilling schedule for 2011," said Magnus Nordin, Managing Director of Tethys Oil AB.
FS-6 is drilled as a vertical well, designed to target the lower Barik formation. The drill site is located 140 meters southeast of well FS-4 and 750 meters south-southwest of well FS-3.
Tethys has a 30 percent interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20 percent and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50 percent.
PTTEP Withdraws Stake in Egypt Well
PTTEP Withdraws Stake in Egypt Well
Wednesday, March 30, 2011
PTTEP
PTT Exploration and Production Public Company Limited (PTTEP) announced its subsidiary PTTEP Sidi Abd El Rahman has withdrawn the entire 30% participation interest from Sidi Abd El Rahman Offshore Project in the Arab Republic of Egypt after fulfillment of the exploration work commitment. The withdrawal will be fully effective upon receiving an official approval from the government of the Arab Republic of Egypt.
In addition, PTTEP would like to report the drilling result of an exploration well in Rommana project, which is an onshore block in the Arab Republic of Egypt. The joint ventures include Sipetrol International S.A. (Operator), PTTEP Rommana Co. Ltd. (a subsidiary of PTTEP), and Centrica Resources Ltd., which hold the participation interests of 40%, 30%, and 30%, respectively. The exploration well, Moon Sinai-1, was spudded on January 6, 2011. It was drilled to an approximate total depth of 1,440 meters without petroleum shows, therefore; the well will be written off within the accounting period of the first quarter 2011, with an approximate total cost to PTTEP of US $1 million.
Wednesday, March 30, 2011
PTTEP
PTT Exploration and Production Public Company Limited (PTTEP) announced its subsidiary PTTEP Sidi Abd El Rahman has withdrawn the entire 30% participation interest from Sidi Abd El Rahman Offshore Project in the Arab Republic of Egypt after fulfillment of the exploration work commitment. The withdrawal will be fully effective upon receiving an official approval from the government of the Arab Republic of Egypt.
In addition, PTTEP would like to report the drilling result of an exploration well in Rommana project, which is an onshore block in the Arab Republic of Egypt. The joint ventures include Sipetrol International S.A. (Operator), PTTEP Rommana Co. Ltd. (a subsidiary of PTTEP), and Centrica Resources Ltd., which hold the participation interests of 40%, 30%, and 30%, respectively. The exploration well, Moon Sinai-1, was spudded on January 6, 2011. It was drilled to an approximate total depth of 1,440 meters without petroleum shows, therefore; the well will be written off within the accounting period of the first quarter 2011, with an approximate total cost to PTTEP of US $1 million.
SBM Offshore Secures LOI for EPCI Supply
SBM Offshore Secures LOI for EPCI Supply
Wednesday, March 30, 2011
Wednesday, March 30, 2011
SBM Offshore N.V.
SBM Offshore has executed a Letter of Intent (LOI) with OSX 2 Leasing BV, an indirect subsidiary of OSX Brasil and part of the EBX Group. This LOI will permit SBM to start project activities, including early engineering and procurement up to $25MM, relating to the future conversion, supply and installation of a floating production, storage and offloading vessel to OSX (FPSO OSX-2). The full EPCI contract for FPSO OSX-2 is expected to be executed within a month.
FPSO OSX-2 will be chartered by OSX to its customer OGX Petróleo e Gás Ltda. (OGX), also a company of the EBX Group, and will be deployed on oil fields in the Campos basin offshore Brazil. First oil is targeted by 3Q 2013.
FPSO OSX-2 will be chartered by OSX to its customer OGX Petróleo e Gás Ltda. (OGX), also a company of the EBX Group, and will be deployed on oil fields in the Campos basin offshore Brazil. First oil is targeted by 3Q 2013.
BP employee loses laptop with personal data of claimants
BP employee loses laptop with personal data of claimants
According to a BP (BP) spokesperson, an employee lost a laptop containing personal data belonging to thousands of Louisiana residents who filed claims for compensation after the Gulf oil spill. The laptop contained data of about 13,000 people, who were notified about the potential data security breach.
According to a BP (BP) spokesperson, an employee lost a laptop containing personal data belonging to thousands of Louisiana residents who filed claims for compensation after the Gulf oil spill. The laptop contained data of about 13,000 people, who were notified about the potential data security breach.
BHP First To Resume Drilling GOM Deep-Water Well
BHP First To Resume Drilling GOM Deep-Water Well
Wednesday, March 30, 2011
Dow Jones Newswires
Wednesday, March 30, 2011
Dow Jones Newswires
by Ryan Dezember
BHP Billiton began late Monday drilling a deep-water well in the Gulf of Mexico, the first such work to take place since the U.S. government banned deep-water drilling in response to last year's oil spill, reported the head of the conglomerate's oil and gas business.
Speaking to investors during the Howard Weil Energy Conference here, J. Michael Yeager said that a rig had moved onto its Shenzi prospect and resumed drilling a well there.
"We're back there drilling and we're delighted to be doing that but we're a long way from the five rigs we had when the moratorium hit," Yeager said.
The U.S. government instituted a six-month ban on deep-water drilling after Transocean's Deepwater Horizon, which was being leased by BP, exploded, killing 11 and unleashing the largest offshore oil spill in U.S. history. Even after the government's official ban was lifted in October, no drilling permits were issued by regulators until Feb. 28.
BHP, the third largest producer in the Gulf, was given permission March 11 to resume drilling its well, work that was stalled by the moratorium. The Anglo-Australian conglomerate's permit is one of six U.S. regulators have issued in recent weeks.
Yeager said that the drilling ban stalled work on 11 Gulf of Mexico wells, trimming BHP's expected 2011 output of the equivalent of 165 million barrels of oil per day by 12 million barrels, Yeager said.
"It's been quite devastating but we're very glad to be out there," Yeager said.
Yeager also said that separate U.S. regulators on Tuesday approved BHP's $4.75 billion purchase of Chesapeake's Fayetteville Shale natural gas fields in Arkansas. The largest ever shale asset deal in U.S. history, encompassing 480,000 acres and pipelines, should close on Thursday, Yeager said.
BHP plans to spend between $800 million to $1 billion annually over the next decade to develop the Arkansas fields in an effort to triple production from the equivalent 65,000 barrels of oil per day seen now, Yeager said.
The move into North America, where the gas that is produced is sold domestically in the world's largest natural gas market, helps BHP expand its market, which is currently weighted toward selling to China, Yeager said.
"We have 60% of our assets in Australia sold to China," he said. "That's a risk that we'd like to diversify away from."
Speaking to investors during the Howard Weil Energy Conference here, J. Michael Yeager said that a rig had moved onto its Shenzi prospect and resumed drilling a well there.
"We're back there drilling and we're delighted to be doing that but we're a long way from the five rigs we had when the moratorium hit," Yeager said.
The U.S. government instituted a six-month ban on deep-water drilling after Transocean's Deepwater Horizon, which was being leased by BP, exploded, killing 11 and unleashing the largest offshore oil spill in U.S. history. Even after the government's official ban was lifted in October, no drilling permits were issued by regulators until Feb. 28.
BHP, the third largest producer in the Gulf, was given permission March 11 to resume drilling its well, work that was stalled by the moratorium. The Anglo-Australian conglomerate's permit is one of six U.S. regulators have issued in recent weeks.
Yeager said that the drilling ban stalled work on 11 Gulf of Mexico wells, trimming BHP's expected 2011 output of the equivalent of 165 million barrels of oil per day by 12 million barrels, Yeager said.
"It's been quite devastating but we're very glad to be out there," Yeager said.
Yeager also said that separate U.S. regulators on Tuesday approved BHP's $4.75 billion purchase of Chesapeake's Fayetteville Shale natural gas fields in Arkansas. The largest ever shale asset deal in U.S. history, encompassing 480,000 acres and pipelines, should close on Thursday, Yeager said.
BHP plans to spend between $800 million to $1 billion annually over the next decade to develop the Arkansas fields in an effort to triple production from the equivalent 65,000 barrels of oil per day seen now, Yeager said.
The move into North America, where the gas that is produced is sold domestically in the world's largest natural gas market, helps BHP expand its market, which is currently weighted toward selling to China, Yeager said.
"We have 60% of our assets in Australia sold to China," he said. "That's a risk that we'd like to diversify away from."
Aker Solutions Awarded LOI for Fossekall-Dompap Project Development
Aker Solutions Awarded LOI for Fossekall-Dompap Project Development
Wednesday, March 30, 2011
Aker Solutions
Aker Solutions has been awarded a letter of intent (LOI) by Statoil for the engineering, procurement and construction of a subsea production system for the Fossekall-Dompap project on the Norwegian continental shelf. Aker Solutions estimates the contract value to be approximately NOK 1 billion.
Scope of work includes three template-manifold structures, 11 subsea trees, a control system and a tie-in system. The contract also contains several options for other field developments on the Norwegian continental shelf which Statoil may exercise.
"We are honored to be so deeply involved in this innovative fast track project. Our goal is to deliver optimum standardized technologies in order to satisfy our customers' requirements. We look forward to working with Statoil on these new frontiers, which offers further growth potential opportunities," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.
Management, engineering and procurement of the subsea production system will be primarily performed at Aker Solutions' headquarters in Oslo, Norway. Fabrication of the subsea trees will be completed at the Tranby manufacturing center, Norway, production of the template-manifolds will be carried out at the Egersund yard,Norway, and the control system from Aberdeen, UK. Final deliveries will be made in 2Q 2013.
Fossekall-Dompap is a fast track project located north of the Norne field, 200 kilometers west from Sandessjoen and occupies blocks 6608/10 and 6608/11 in a water depth of approximately 380 meters.
Wednesday, March 30, 2011
Aker Solutions
Aker Solutions has been awarded a letter of intent (LOI) by Statoil for the engineering, procurement and construction of a subsea production system for the Fossekall-Dompap project on the Norwegian continental shelf. Aker Solutions estimates the contract value to be approximately NOK 1 billion.
Scope of work includes three template-manifold structures, 11 subsea trees, a control system and a tie-in system. The contract also contains several options for other field developments on the Norwegian continental shelf which Statoil may exercise.
"We are honored to be so deeply involved in this innovative fast track project. Our goal is to deliver optimum standardized technologies in order to satisfy our customers' requirements. We look forward to working with Statoil on these new frontiers, which offers further growth potential opportunities," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.
Management, engineering and procurement of the subsea production system will be primarily performed at Aker Solutions' headquarters in Oslo, Norway. Fabrication of the subsea trees will be completed at the Tranby manufacturing center, Norway, production of the template-manifolds will be carried out at the Egersund yard,Norway, and the control system from Aberdeen, UK. Final deliveries will be made in 2Q 2013.
Fossekall-Dompap is a fast track project located north of the Norne field, 200 kilometers west from Sandessjoen and occupies blocks 6608/10 and 6608/11 in a water depth of approximately 380 meters.
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