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.
Subscribe to:
Posts (Atom)