Release date: 22 May 2008
BP Egypt, on behalf of its joint venture partners in the Gulf of Suez Petroleum Company (GUPCO), announced today that oil production from the Saqqara field has started
The Saqqara field is located 12.5 kilometres offshore in the central Gulf of Suez. First oil was achieved on 15th May and following commissioning, the field has now ramped up to more than 30,000 barrels a day. Gas production is expected shortly.
Andy Inglis, BP’s Chief Executive of Exploration & Production, said: “Saqqara is another major project delivered successfully. It will contribute to BP’s production profile for the next decade and beyond. Egypt is an important growth area with further potential.”
Hesham Mekawi, President of BP Egypt added: “Saqqara is a technically complex development and its successful delivery represents a new milestone in maximising recovery of oil and gas from the Gulf of Suez. First oil was achieved through hard work and dedication of the Project, Contractor and Operations teams that worked on Saqqara over the last 4 years.”
The Saqqara project is an offshore development with a jacket and unmanned topsides, four wells, and a 13 kilometre pipeline to new dedicated onshore separation and gas processing plant at Ras Shukeir, Gulf of Suez.
Note to editors:
The Saqqara project is executed and operated by Gulf of Suez Petroleum Company (GUPCO), a joint venture between Egyptian General Petroleum Corporation (EGPC) and BP. The main contractors are KBR/ENNPI for the design, Petrojet for the onshore construction and the offshore fabrication work and PMS for the offshore installation.
BP has been operating in Egypt for over 40 years, primarily in oil and gas exploration and production. During that period, BP Egypt has produced almost 40 per cent of Egypt’s entire oil production and close to 30 per cent of gas demand together with partners.
Further information:
Name: Robert Wine
Office: BP press office
Location: London
Phone : +44 (0)20 7496 4076
Name: Mohamed Emara
Location: BP Egypt
Phone : + (202) 2706-2259
Email: mohamed.emara@bp.com
Showing posts with label British Petroleum. Show all posts
Showing posts with label British Petroleum. Show all posts
Wednesday, August 6, 2008
BP news-Kinnoull North Sea Oil Discovery
Release date: 21 May 2008
BP and its co-venturers, ENI UK Ltd and Petro Summit Investment UK Ltd, today announced an oil discovery in North Sea Block 16/23s, some 230 kilometres north-east of Aberdeen, to be named Kinnoull
BP and co-venturers are now evaluating the Kinnoull discovery and potential development options, including a subsea development tied back to BP’s Andrew field which is located around 25 kilometres to the south.
Dave Blackwood, head of BP’s North Sea business, said, “Discoveries like Kinnoull are important additions to our strong resource base in the North Sea. We will now evaluate development options, looking to take advantage of the existing infrastructure in the area.”
Kinnoull is BP’s second operated exploration success this year in the UK Continental Shelf, following the discovery of the South West Foinaven field, west of Shetland, in January.
Notes to Editors
Participants in Kinnoull are BP (77.07%), ENI UK Ltd (16.67%) and Petro Summit Investment UK Ltd (6.27%).
BP and its co-venturers, ENI UK Ltd and Petro Summit Investment UK Ltd, today announced an oil discovery in North Sea Block 16/23s, some 230 kilometres north-east of Aberdeen, to be named Kinnoull
BP and co-venturers are now evaluating the Kinnoull discovery and potential development options, including a subsea development tied back to BP’s Andrew field which is located around 25 kilometres to the south.
Dave Blackwood, head of BP’s North Sea business, said, “Discoveries like Kinnoull are important additions to our strong resource base in the North Sea. We will now evaluate development options, looking to take advantage of the existing infrastructure in the area.”
Kinnoull is BP’s second operated exploration success this year in the UK Continental Shelf, following the discovery of the South West Foinaven field, west of Shetland, in January.
Notes to Editors
Participants in Kinnoull are BP (77.07%), ENI UK Ltd (16.67%) and Petro Summit Investment UK Ltd (6.27%).
Mining News -BP, Santelisa Vale, and Maeda Unveil Plans to Invest R$1.66 Billion in Biofuels
Release date: 24 April 2008
BP announced today that it intends to take a 50 per cent stake in Tropical BioEnergia SA
BP announced today that it intends to take a 50 per cent stake in Tropical BioEnergia SA, a joint venture established by Brazilian companies Santelisa Vale and Maeda Group, which is constructing a 435 million liter (115 million gallons) a year ethanol refinery in Edéia, Goias State, Brazil.
The joint venture, in which Santelisa Vale and Maeda Group would each hold 25 per cent, also intends to progress plans to build a second ethanol refinery, investing a total of approximately R$1.66 billion (US$1 billion) in the two refineries.
Assuming all the required approvals are received, BP will pay around R$100 million (US$59.8 million) for the 50 per cent stake, subject to working capital adjustments, and provide funding for agreed future investment in line with its shareholding. The parties said that they hoped to be able to complete the transaction before the end of June 2008.
“This investment, which is the largest made by an international oil company in the Brazilian ethanol industry represents a significant step in delivering BP’s strategy for biofuels which centres around sustainable feedstocks which do not impact on food supplies and investing in research work to develop the technologies required to produce advanced biofuels,” commented Phil New, head of BP Biofuels. “BP is delighted to be partnering with two Brazilian companies with leading positions in their sectors and we look forward to a long relationship with them.”
The joint venture will focus on potential sugarcane production and the manufacturing and marketing of conventional ethanol, including the associated agricultural assets and cogeneration plants. Sugarcane is the most efficient source of biofuel currently available. Sugarcane lends itself to further improvement through the use of advanced biofuels technology and will therefore be a compelling source of renewable fuel for the foreseeable future. It provides a greenhouse gas emissions reduction of up to 80 per cent.
Operations at the first refinery are expected to commence during the second half of 2008, with full capacity anticipated by mid-2010. The refineries will be positioned to supply the Brazilian ethanol markets with the potential to export to the demand markets of US, Europe and Asia.
Besides developing sustainable biofuels, the refineries are expected to be able to sell surplus electricity, with each of them exporting at least 30 MW of surplus power from integrated bagasse cogeneration facilities. The facilities are also intended to offer a potential platform for deploying future technologies such as lignocellulosics and biobutanol.
The Maeda Group is one of the largest cotton producers in the world. “BP’s decision to join Tropical Bioenergia in this new venture is significant,” said Jorge Maeda, chief executive officer of Maeda Group. “Today we are demonstrating how Maeda’s unique agriculture expertise, attendant network of relationships, and knowledge of the region’s soils, climate and rural labor conditions combined with Santelisa Vale’s sugarcane expertise can provide sustainable renewable and reliable solutions for fuel.” Santelisa Vale Group is the second-largest sugar cane crusher in Brazil and the first in energy cogeneration from bagasse. As it already operates a number of ethanol refineries, Santelisa Vale has expertise along the entire value chain of ethanol/sugar production.
Santelisa Vale Group is the second-largest sugar cane crusher in Brazil and the first in energy cogeneration from bagasse. As it already operates a number of ethanol refineries, Santelisa Vale has expertise along the entire value chain of ethanol/sugar production.
“BP’s proven logistical, technological and fuel supply chain experience will enable a significant enhancement of our strategic plans,” noted Anselmo Lopes Rodrigues, chief executive officer of Santelisa Vale.
Notes to Editors:
Transport accounts for around 21 per cent of all carbon dioxide emissions.
BP is of one of the world’s largest energy companies, providing its customers with fuel for transportation, energy for heat and light, retail services and petrochemicals products for everyday items. It is the largest oil and gas producer in the U.S. and one of the largest refiners. BP also has a global network of around 25,000 service stations.
BP is a leading player in the global biofuels market. In the US, BP has blended and distributed 763 million US gallons of ethanol and about 1 million US gallons of biodiesel in 2007. In Europe, BP has sold 344 million liters of ethanol and 847 million liters of biodiesel in 2007. BP’s sales of biofuels in 2007 accounted for about 10% of the global biofuels market.
Maeda Group is recognized worldwide as being one of the most vertically integrated players in the cotton value chain with 80 years in the industry. The Company has one of the few cotton seed crushing businesses in Brazil, producing several products from cotton seeds: Vegetable oil, which contains no “trans fat” and is used as input in the food industry, Linter (the material around the cotton seeds) used for special products such as money paper and LCD screens and cotton seed meal, used as animal feed.
Santelisa Vale, Brazil’s second largest sugar and ethanol producer and first in energy cogeneration from bagasse, expects to crush 18 million tons of sugar cane in 2008. The company will produce 25 million bags of sugar and 770 million liters of ethanol. Santelisa Vale also produces and sells a surplus of 420,000 Mwh of electricity from sugar cane bagasse – enough to supply a population of 1 million per year. The company, with over 70 years of history, is a leader in technology and innovation within the segment.
Santelisa Vale and Maeda Group were advised by ING Bank.
Further information:
Office: BP Press Office
Location: London
Tel: +44 (0)207 496 4076
Office: BP U.S. Press Office
Location: Chicago
Tel: +1 630 821 3206
Office: BP Brazilian Office
Location: Campinas
Tel: +55 19 3794 8357
Office: Maeda Press Office
Tel: +55 11 2179 7380
Office: Santelisa Vale Press Office
Tel: +55 16 3946-3924
Email: comunicacao@santelisavale.com.br
Office: Ketchum Estratégia Assessoria de Comunicação
Contact: Rafael Presilli / Adriana Toledo
Tel: (11) 5096-4334 ext. 212/280
Email: rafael.presilli@ketchum.com.br / adriana.toledo@ketchum.com.br
In this section
Chesapeake And BP Announce Arkoma Basin Woodford Shale Transaction
BP Expresses Displeasure about TNK-BP CEO’s Visa
BP Signs as London 2012 Partner
BP Buys Whiting Clean Energy Power Plant in Indiana
Energy Consumption Rises as Supplies Lag But Free Energy Markets Do Work
More
Related links
BP’s investments in activities worldwide to bring biofuels into the mainstream
BP Biofuels
Bringing on biofuels
BP Biofuels world advertising
Energy Biosciences Institute
Related downloads
More details on the BP, Santelisa Vale and Maeda Group Partnership
Tropical Factsheet (pdf, 717KB)
back to top
© 1996-2008 BP p.l.c. | Legal Notice | Privacy Statement
BP announced today that it intends to take a 50 per cent stake in Tropical BioEnergia SA
BP announced today that it intends to take a 50 per cent stake in Tropical BioEnergia SA, a joint venture established by Brazilian companies Santelisa Vale and Maeda Group, which is constructing a 435 million liter (115 million gallons) a year ethanol refinery in Edéia, Goias State, Brazil.
The joint venture, in which Santelisa Vale and Maeda Group would each hold 25 per cent, also intends to progress plans to build a second ethanol refinery, investing a total of approximately R$1.66 billion (US$1 billion) in the two refineries.
Assuming all the required approvals are received, BP will pay around R$100 million (US$59.8 million) for the 50 per cent stake, subject to working capital adjustments, and provide funding for agreed future investment in line with its shareholding. The parties said that they hoped to be able to complete the transaction before the end of June 2008.
“This investment, which is the largest made by an international oil company in the Brazilian ethanol industry represents a significant step in delivering BP’s strategy for biofuels which centres around sustainable feedstocks which do not impact on food supplies and investing in research work to develop the technologies required to produce advanced biofuels,” commented Phil New, head of BP Biofuels. “BP is delighted to be partnering with two Brazilian companies with leading positions in their sectors and we look forward to a long relationship with them.”
The joint venture will focus on potential sugarcane production and the manufacturing and marketing of conventional ethanol, including the associated agricultural assets and cogeneration plants. Sugarcane is the most efficient source of biofuel currently available. Sugarcane lends itself to further improvement through the use of advanced biofuels technology and will therefore be a compelling source of renewable fuel for the foreseeable future. It provides a greenhouse gas emissions reduction of up to 80 per cent.
Operations at the first refinery are expected to commence during the second half of 2008, with full capacity anticipated by mid-2010. The refineries will be positioned to supply the Brazilian ethanol markets with the potential to export to the demand markets of US, Europe and Asia.
Besides developing sustainable biofuels, the refineries are expected to be able to sell surplus electricity, with each of them exporting at least 30 MW of surplus power from integrated bagasse cogeneration facilities. The facilities are also intended to offer a potential platform for deploying future technologies such as lignocellulosics and biobutanol.
The Maeda Group is one of the largest cotton producers in the world. “BP’s decision to join Tropical Bioenergia in this new venture is significant,” said Jorge Maeda, chief executive officer of Maeda Group. “Today we are demonstrating how Maeda’s unique agriculture expertise, attendant network of relationships, and knowledge of the region’s soils, climate and rural labor conditions combined with Santelisa Vale’s sugarcane expertise can provide sustainable renewable and reliable solutions for fuel.” Santelisa Vale Group is the second-largest sugar cane crusher in Brazil and the first in energy cogeneration from bagasse. As it already operates a number of ethanol refineries, Santelisa Vale has expertise along the entire value chain of ethanol/sugar production.
Santelisa Vale Group is the second-largest sugar cane crusher in Brazil and the first in energy cogeneration from bagasse. As it already operates a number of ethanol refineries, Santelisa Vale has expertise along the entire value chain of ethanol/sugar production.
“BP’s proven logistical, technological and fuel supply chain experience will enable a significant enhancement of our strategic plans,” noted Anselmo Lopes Rodrigues, chief executive officer of Santelisa Vale.
Notes to Editors:
Transport accounts for around 21 per cent of all carbon dioxide emissions.
BP is of one of the world’s largest energy companies, providing its customers with fuel for transportation, energy for heat and light, retail services and petrochemicals products for everyday items. It is the largest oil and gas producer in the U.S. and one of the largest refiners. BP also has a global network of around 25,000 service stations.
BP is a leading player in the global biofuels market. In the US, BP has blended and distributed 763 million US gallons of ethanol and about 1 million US gallons of biodiesel in 2007. In Europe, BP has sold 344 million liters of ethanol and 847 million liters of biodiesel in 2007. BP’s sales of biofuels in 2007 accounted for about 10% of the global biofuels market.
Maeda Group is recognized worldwide as being one of the most vertically integrated players in the cotton value chain with 80 years in the industry. The Company has one of the few cotton seed crushing businesses in Brazil, producing several products from cotton seeds: Vegetable oil, which contains no “trans fat” and is used as input in the food industry, Linter (the material around the cotton seeds) used for special products such as money paper and LCD screens and cotton seed meal, used as animal feed.
Santelisa Vale, Brazil’s second largest sugar and ethanol producer and first in energy cogeneration from bagasse, expects to crush 18 million tons of sugar cane in 2008. The company will produce 25 million bags of sugar and 770 million liters of ethanol. Santelisa Vale also produces and sells a surplus of 420,000 Mwh of electricity from sugar cane bagasse – enough to supply a population of 1 million per year. The company, with over 70 years of history, is a leader in technology and innovation within the segment.
Santelisa Vale and Maeda Group were advised by ING Bank.
Further information:
Office: BP Press Office
Location: London
Tel: +44 (0)207 496 4076
Office: BP U.S. Press Office
Location: Chicago
Tel: +1 630 821 3206
Office: BP Brazilian Office
Location: Campinas
Tel: +55 19 3794 8357
Office: Maeda Press Office
Tel: +55 11 2179 7380
Office: Santelisa Vale Press Office
Tel: +55 16 3946-3924
Email: comunicacao@santelisavale.com.br
Office: Ketchum Estratégia Assessoria de Comunicação
Contact: Rafael Presilli / Adriana Toledo
Tel: (11) 5096-4334 ext. 212/280
Email: rafael.presilli@ketchum.com.br / adriana.toledo@ketchum.com.br
In this section
Chesapeake And BP Announce Arkoma Basin Woodford Shale Transaction
BP Expresses Displeasure about TNK-BP CEO’s Visa
BP Signs as London 2012 Partner
BP Buys Whiting Clean Energy Power Plant in Indiana
Energy Consumption Rises as Supplies Lag But Free Energy Markets Do Work
More
Related links
BP’s investments in activities worldwide to bring biofuels into the mainstream
BP Biofuels
Bringing on biofuels
BP Biofuels world advertising
Energy Biosciences Institute
Related downloads
More details on the BP, Santelisa Vale and Maeda Group Partnership
Tropical Factsheet (pdf, 717KB)
back to top
© 1996-2008 BP p.l.c. | Legal Notice | Privacy Statement
The Azerbaijan International Operating Company (AIOC), operated by BP, today announced the start-up of oil production from the Deep Water...........
The Azerbaijan International Operating Company (AIOC), operated by BP, today announced the start-up of oil production from the Deep Water Gunashli (DWG) platform complex as scheduled.
Start-up of the DWG complex completes the third phase of development of the Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan sector of the Caspian Sea.
ACG participating interests are: BP (operator - 34.1%), Chevron (10.2%), SOCAR (10%), INPEX (10%), StatoilHydro (8.6%), ExxonMobil (8%), TPAO (6.8%), Devon (5.6%), ITOCHU (3.9%), Hess (2.7%).
The DWG complex is located in a water depth of 175 metres on the east side of the Gunashli field. The complex comprises two platforms - a drilling and production platform bridge linked to a water injection and gas compression platform.
Production will increase through 2008 as other pre-drilled wells are brought on-stream, prior to commencing platform drilling. On plateau, the DWG complex will produce approximately 320,000 barrels per day, bringing total ACG oil production, including Chirag, East Azeri, West Azeri and Central Azeri, to over 1 million barrels per day.
“The start up of the DWG complex is an achievement we can all be proud of”, said Bill Schrader, BP’s President in Azerbaijan. “This achievement maintains our track record of on schedule project delivery for the development of the ACG field. I would like to thank the thousands of people, mostly from Azerbaijan, who built the jackets and topsides of this complex, for their dedication and outstanding performance over the past three years. I would also like to congratulate the government, our partners, employees, all the contractors and suppliers for this tremendous achievement.”
Photos available
Note to Editors:
The DWG complex comprises a 48-slot drilling, utilities, and quarters (DUQ) platform and a process, gas compression, water injection and utilities (PCWU) platform. Production export off the complex is via two 30 inch oil pipeline tie-ins and a single 28 inch gas pipeline tie-in into pre-installed pipeline junctions located on the Azeri field subsea export pipelines to the onshore Sangachal Terminal. In addition, uniquely for the ACG project, two subsea water injection manifolds, four water injection supply flowlines, and associated control umbilicals have been installed in the DWG development.
Oil from DWG will be processed in two new oil stabilization process trains at the onshore Sangachal Terminal. Associated gas produced from DWG, less platform fuel needs, will be exported via an existing gas subsea pipeline to the Sangachal Terminal and onward to the Azerigas system for domestic use.
The ACG Production Sharing Agreement (PSA), signed in September 1994, covers the 30 year development of the Azeri-Chirag-Gunashli contract area. The field has been developed in several phases: Chirag has been producing since 1997 as part of the Early Oil Project (EOP). This was followed by Azeri Project Phase 1 - Central Azeri production in early 2005. Successive Phase 2 included West Azeri, which started production in January 2006, and East Azeri, which started production in October 2006. The ACG Phase 3 - Deepwater Gunashli has just started up. Over all production from all phases is expected to be over 1 million barrels per day.
For further information
Name: Tamam Bayatly
Tel.: (994 12) 4979 000
Fax: (994 12) 4979 736
Start-up of the DWG complex completes the third phase of development of the Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan sector of the Caspian Sea.
ACG participating interests are: BP (operator - 34.1%), Chevron (10.2%), SOCAR (10%), INPEX (10%), StatoilHydro (8.6%), ExxonMobil (8%), TPAO (6.8%), Devon (5.6%), ITOCHU (3.9%), Hess (2.7%).
The DWG complex is located in a water depth of 175 metres on the east side of the Gunashli field. The complex comprises two platforms - a drilling and production platform bridge linked to a water injection and gas compression platform.
Production will increase through 2008 as other pre-drilled wells are brought on-stream, prior to commencing platform drilling. On plateau, the DWG complex will produce approximately 320,000 barrels per day, bringing total ACG oil production, including Chirag, East Azeri, West Azeri and Central Azeri, to over 1 million barrels per day.
“The start up of the DWG complex is an achievement we can all be proud of”, said Bill Schrader, BP’s President in Azerbaijan. “This achievement maintains our track record of on schedule project delivery for the development of the ACG field. I would like to thank the thousands of people, mostly from Azerbaijan, who built the jackets and topsides of this complex, for their dedication and outstanding performance over the past three years. I would also like to congratulate the government, our partners, employees, all the contractors and suppliers for this tremendous achievement.”
Photos available
Note to Editors:
The DWG complex comprises a 48-slot drilling, utilities, and quarters (DUQ) platform and a process, gas compression, water injection and utilities (PCWU) platform. Production export off the complex is via two 30 inch oil pipeline tie-ins and a single 28 inch gas pipeline tie-in into pre-installed pipeline junctions located on the Azeri field subsea export pipelines to the onshore Sangachal Terminal. In addition, uniquely for the ACG project, two subsea water injection manifolds, four water injection supply flowlines, and associated control umbilicals have been installed in the DWG development.
Oil from DWG will be processed in two new oil stabilization process trains at the onshore Sangachal Terminal. Associated gas produced from DWG, less platform fuel needs, will be exported via an existing gas subsea pipeline to the Sangachal Terminal and onward to the Azerigas system for domestic use.
The ACG Production Sharing Agreement (PSA), signed in September 1994, covers the 30 year development of the Azeri-Chirag-Gunashli contract area. The field has been developed in several phases: Chirag has been producing since 1997 as part of the Early Oil Project (EOP). This was followed by Azeri Project Phase 1 - Central Azeri production in early 2005. Successive Phase 2 included West Azeri, which started production in January 2006, and East Azeri, which started production in October 2006. The ACG Phase 3 - Deepwater Gunashli has just started up. Over all production from all phases is expected to be over 1 million barrels per day.
For further information
Name: Tamam Bayatly
Tel.: (994 12) 4979 000
Fax: (994 12) 4979 736
Mining News:BP Makes a Significant Deep Gas Discovery in Egypt’s Nile Delta
This mining news was released on 31 January 2008.
BP Egypt today announced that it has made a significant gas discovery at record depths in the Nile Delta.
The Satis discovery is located in the North El Burg Offshore, Nile Delta concession, some 50 kilometres north of Damietta. The well was drilled to a Nile Delta record depth of more than 6,500 metres and is the first significant high-pressure, high-temperature, offshore Oligocene discovery.
Satis is a major technical achievement that demonstrates the great potential of the deeper reservoirs within the Nile Delta and will require further appraisal.
The parties to the North El Burg offshore concession agreement are: BP, operator (50 per cent) and IEOC, the affiliate of Italy’s ENI in Egypt (50 per cent). Satis was drilled by the Constellation II jack-up rig, in a water depth of 90 metres.
Andy Inglis, BP’s chief executive of Exploration & Production said: “This is a significant discovery, which will underscore our position as a major producer in the growing Egyptian gas market for many years to come.”
Notes to Editors:
BP has been operating in Egypt for over 40 years, primarily in oil and gas exploration and production. To date BP Egypt has produced almost 40 per cent of Egypt’s entire oil production and close to 30 per cent of gas demand with its partners.
Egypt’s offshore Nile Delta is an important part of the company’s upstream portfolio. BP has interests in four exploration concessions, with operatorship of three.
Satis is BP’s third deep gas discovery in the Nile Delta. BP made its first discovery at Raven in 2003, followed by the more recent Taurus Deep find in 2007.
Satis is in the North El Burg offshore concession; Raven and Taurus Deep are both within the North Alexandria A concession: BP, operator (60 per cent) and partner RWE Dea (40 per cent). Operatorship of the North El Burg Offshore Concession was awarded to BP Exploration (Delta) Limited in June 2005. The concession lies in water depths of 60 to 100 metres. The concession lies between the Ras El Barr BP-operated development concession and Offshore Baltim development concession operated by IEOC.
EGPC/ EGAS has an entitlement under the concession’s production-sharing arrangements.
Further information:
Name: Mohamed Emara
Location: BP Egypt office
Phone : +202 706 2259
Location: BP press office, London
Phone : +44 (0) 20 7496 4076
BP Egypt today announced that it has made a significant gas discovery at record depths in the Nile Delta.
The Satis discovery is located in the North El Burg Offshore, Nile Delta concession, some 50 kilometres north of Damietta. The well was drilled to a Nile Delta record depth of more than 6,500 metres and is the first significant high-pressure, high-temperature, offshore Oligocene discovery.
Satis is a major technical achievement that demonstrates the great potential of the deeper reservoirs within the Nile Delta and will require further appraisal.
The parties to the North El Burg offshore concession agreement are: BP, operator (50 per cent) and IEOC, the affiliate of Italy’s ENI in Egypt (50 per cent). Satis was drilled by the Constellation II jack-up rig, in a water depth of 90 metres.
Andy Inglis, BP’s chief executive of Exploration & Production said: “This is a significant discovery, which will underscore our position as a major producer in the growing Egyptian gas market for many years to come.”
Notes to Editors:
BP has been operating in Egypt for over 40 years, primarily in oil and gas exploration and production. To date BP Egypt has produced almost 40 per cent of Egypt’s entire oil production and close to 30 per cent of gas demand with its partners.
Egypt’s offshore Nile Delta is an important part of the company’s upstream portfolio. BP has interests in four exploration concessions, with operatorship of three.
Satis is BP’s third deep gas discovery in the Nile Delta. BP made its first discovery at Raven in 2003, followed by the more recent Taurus Deep find in 2007.
Satis is in the North El Burg offshore concession; Raven and Taurus Deep are both within the North Alexandria A concession: BP, operator (60 per cent) and partner RWE Dea (40 per cent). Operatorship of the North El Burg Offshore Concession was awarded to BP Exploration (Delta) Limited in June 2005. The concession lies in water depths of 60 to 100 metres. The concession lies between the Ras El Barr BP-operated development concession and Offshore Baltim development concession operated by IEOC.
EGPC/ EGAS has an entitlement under the concession’s production-sharing arrangements.
Further information:
Name: Mohamed Emara
Location: BP Egypt office
Phone : +202 706 2259
Location: BP press office, London
Phone : +44 (0) 20 7496 4076
Mining news-BP-Masdar and Hydrogen Energy Plan Clean Energy Plant in Abu Dhabi
This news was released on 21 January 2008
World Future Energy Summit, Abu Dhabi
Masdar, Abu Dhabi’s initiative for renewable and alternative energy and clean technology, and Hydrogen Energy, the joint venture between BP Alternative Energy and Rio Tinto, today announced the signing of an agreement to work together on the front-end engineering design of an industrial-scale hydrogen-fired power generation project with capture of the carbon dioxide (CO2), which would then be available for transportation and storage. The plant would be located in Abu Dhabi.
Natural gas would be processed to create hydrogen and CO2. The hydrogen fuel would generate low-carbon electricity. Rather than being emitted to the atmosphere, the CO2 would be captured, ready for transportation and injection into a producing oil field where it could replace natural gas currently being injected into the field to maintain pressure. The injected CO2 has also the potential to increase the proportion of Abu Dhabi’s oil that can be recovered.
Lewis Gillies, Chief Executive of Hydrogen Energy, said: “Through Masdar, Abu Dhabi has shown strong leadership in creating the right environment in which hydrogen power with carbon capture and storage, and other alternative energies, can be deployed successfully. The complementary skills of Masdar and Hydrogen Energy will be a formidable combination. We look forward to making this project a reality. “
“This joint project will bring together - in a single integrated scheme - a number of technologies already operating at scale successfully around the world,” said Dr. Sultan Al Jaber, Chief Executive of Masdar. “Part of our mission at Masdar is to combine our expertise with that of others – and so we are pleased to be able to work with Hydrogen Energy to explore this new and important technology.”
“Hydrogen Energy already has extensive experience in the engineering design of projects such as this which will be extremely valuable in the design and development of the Abu Dhabi project,” Gillies added.
Work has already started and front-end engineering and design of the project is planned to be completed by the end of 2008, at a cost of some US$45 million. At the heart of the plant would be a natural gas reformer and carbon capture facility where 100 million cubic feet of natural gas per day would be transformed into hydrogen and CO2 gases.
The hydrogen gas would be used to fuel gas turbines and generate around 420MW of low-carbon electricity, with water vapour being the main emission. This would be enough to provide more than 5% of all Abu Dhabi’s current power generation capacity.
The project would limit greenhouse gas emissions by capturing some 90% of the CO2 generated, and safely and permanently storing up to 1.7 million tonnes of CO2 per year - the equivalent of decarbonising Abu Dhabi’s entire domestic transport sector.
The CO2 would replace the natural gas currently being injected into oil fields, allowing the gas to be used to fuel Abu Dhabi’s continued growth, or to be exported. If this process was deployed at scale it would potentially release a significant amount of additional natural gas for Abu Dhabi and United Arab Emirates.
The CO2 injected into the oil fields could also potentially enable previously unrecoverable oil to be produced. If deployed widely, this enhanced oil recovery process could boost Abu Dhabi’s oil production significantly. The CO2 would remain stored securely and permanently in the oil field beneath its natural impervious seal.
The overall project would require total capital investment (excluding the investment in CO2 transportation and sequestration) of about AED7 billion (US$2 billion). Subject to the completion of the engineering design and agreement on an enabling commercial structure, the partners aspire to make the decision to proceed with construction by early 2009. This should allow the plant to come into commercial operation in 2012. At peak, about 1000 jobs would be created during construction of the onshore facilities, with up to 100 permanent jobs when the plant is operational.
Announced on the opening day of the Abu Dhabi World Future Energy Summit, the project demonstrates Abu Dhabi’s desire to turn words into action and is a major step for Abu Dhabi to establish leadership in the area of alternative energy technologies.
Notes to editors:
Hydrogen Energy is a 50/50 joint venture between BP Alternative Energy and Rio Tinto established to focus on industrial scale, base-load, hydrogen-fuelled power generation using fossil fuels and carbon capture and storage. It combines BP’s leading position and expertise in chemical processing, low-carbon power generation and carbon capture and storage together with Rio Tinto’s expertise and world-class assets in coal extraction and supply.
Masdar: In April 2006, Abu Dhabi, the capital of the United Arab Emirates, launched Masdar, a multi-faceted, multi-billion dollar investment in renewable and alternative energy and clean technology. Masdar is helping to explore, develop and commercialize such future energy sources.
Masdar, which means “the source” in Arabic, has four primary objectives:
To help drive the economic diversification of Abu Dhabi;
To maintain – and expand – Abu Dhabi’s position in evolving global energy markets;
To help Abu Dhabi become a developer of technology; and
To make a meaningful contribution to sustainable human development.
Masdar is driven by the Abu Dhabi Future Energy Company (ADFEC), a wholly owned company of the government of Abu Dhabi through the Mubadala Development Company.Masdar is a comprehensive investment in future energy solutions and clean technology – from design to research laboratory to mass deployment.
World Future Energy Summit, Abu Dhabi
Masdar, Abu Dhabi’s initiative for renewable and alternative energy and clean technology, and Hydrogen Energy, the joint venture between BP Alternative Energy and Rio Tinto, today announced the signing of an agreement to work together on the front-end engineering design of an industrial-scale hydrogen-fired power generation project with capture of the carbon dioxide (CO2), which would then be available for transportation and storage. The plant would be located in Abu Dhabi.
Natural gas would be processed to create hydrogen and CO2. The hydrogen fuel would generate low-carbon electricity. Rather than being emitted to the atmosphere, the CO2 would be captured, ready for transportation and injection into a producing oil field where it could replace natural gas currently being injected into the field to maintain pressure. The injected CO2 has also the potential to increase the proportion of Abu Dhabi’s oil that can be recovered.
Lewis Gillies, Chief Executive of Hydrogen Energy, said: “Through Masdar, Abu Dhabi has shown strong leadership in creating the right environment in which hydrogen power with carbon capture and storage, and other alternative energies, can be deployed successfully. The complementary skills of Masdar and Hydrogen Energy will be a formidable combination. We look forward to making this project a reality. “
“This joint project will bring together - in a single integrated scheme - a number of technologies already operating at scale successfully around the world,” said Dr. Sultan Al Jaber, Chief Executive of Masdar. “Part of our mission at Masdar is to combine our expertise with that of others – and so we are pleased to be able to work with Hydrogen Energy to explore this new and important technology.”
“Hydrogen Energy already has extensive experience in the engineering design of projects such as this which will be extremely valuable in the design and development of the Abu Dhabi project,” Gillies added.
Work has already started and front-end engineering and design of the project is planned to be completed by the end of 2008, at a cost of some US$45 million. At the heart of the plant would be a natural gas reformer and carbon capture facility where 100 million cubic feet of natural gas per day would be transformed into hydrogen and CO2 gases.
The hydrogen gas would be used to fuel gas turbines and generate around 420MW of low-carbon electricity, with water vapour being the main emission. This would be enough to provide more than 5% of all Abu Dhabi’s current power generation capacity.
The project would limit greenhouse gas emissions by capturing some 90% of the CO2 generated, and safely and permanently storing up to 1.7 million tonnes of CO2 per year - the equivalent of decarbonising Abu Dhabi’s entire domestic transport sector.
The CO2 would replace the natural gas currently being injected into oil fields, allowing the gas to be used to fuel Abu Dhabi’s continued growth, or to be exported. If this process was deployed at scale it would potentially release a significant amount of additional natural gas for Abu Dhabi and United Arab Emirates.
The CO2 injected into the oil fields could also potentially enable previously unrecoverable oil to be produced. If deployed widely, this enhanced oil recovery process could boost Abu Dhabi’s oil production significantly. The CO2 would remain stored securely and permanently in the oil field beneath its natural impervious seal.
The overall project would require total capital investment (excluding the investment in CO2 transportation and sequestration) of about AED7 billion (US$2 billion). Subject to the completion of the engineering design and agreement on an enabling commercial structure, the partners aspire to make the decision to proceed with construction by early 2009. This should allow the plant to come into commercial operation in 2012. At peak, about 1000 jobs would be created during construction of the onshore facilities, with up to 100 permanent jobs when the plant is operational.
Announced on the opening day of the Abu Dhabi World Future Energy Summit, the project demonstrates Abu Dhabi’s desire to turn words into action and is a major step for Abu Dhabi to establish leadership in the area of alternative energy technologies.
Notes to editors:
Hydrogen Energy is a 50/50 joint venture between BP Alternative Energy and Rio Tinto established to focus on industrial scale, base-load, hydrogen-fuelled power generation using fossil fuels and carbon capture and storage. It combines BP’s leading position and expertise in chemical processing, low-carbon power generation and carbon capture and storage together with Rio Tinto’s expertise and world-class assets in coal extraction and supply.
Masdar: In April 2006, Abu Dhabi, the capital of the United Arab Emirates, launched Masdar, a multi-faceted, multi-billion dollar investment in renewable and alternative energy and clean technology. Masdar is helping to explore, develop and commercialize such future energy sources.
Masdar, which means “the source” in Arabic, has four primary objectives:
To help drive the economic diversification of Abu Dhabi;
To maintain – and expand – Abu Dhabi’s position in evolving global energy markets;
To help Abu Dhabi become a developer of technology; and
To make a meaningful contribution to sustainable human development.
Masdar is driven by the Abu Dhabi Future Energy Company (ADFEC), a wholly owned company of the government of Abu Dhabi through the Mubadala Development Company.Masdar is a comprehensive investment in future energy solutions and clean technology – from design to research laboratory to mass deployment.
Mining News-BP Reinforces its Commitment to China
This mining news was released on 18 January 2008
BP announced today during a ceremony in the Great Hall of People in Beijing that it had signed a series of agreements to enhance its commitment to China. These agreements involve strategic integration and commercialisation of clean coal , wind power generation and world-class acetic acid production. The British Prime Minister, the Rt. Hon. Gordon Brown and the Chinese Premier Wen Jiabao, as well as officials from both British and Chinese governments, witnessed the signing.
“BP’s total investment in China has exceeded US$4 billion since our arrival some three decades ago,” said Dr Gary Dirks, BP president of Asia Pacific and China, at the signing ceremony. “Our commercial and social investments serve a clear purpose, which is to provide quality products and materials to help Chinese consumers improve their quality of life and protect the well-being of the environment. I am pleased that BP is continuing to take steps in delivering this commitment.”
Clean Energy Commercialisation Centre
BP and the China Academy of Sciences (CAS) signed an agreement to undertake a feasibility study into a proposed Clean Energy Commercialization Centre (CECC) joint venture. This represents a major step forward following the signing of a Memorandum of Understanding in Shanghai last August.
Under the agreement, CECC is intended to integrate individual clean energy related technologies - coal gasification, coal to liquids, coal to chemical, carbon capture and storage, coal bed methane and underground gasification - from CAS institutes and other organizations both within and outside the PRC, into competitive integrated feedstock manufacturing and product distribution systems and solutions such as polygeneration complexes. The CECC would also serve as an international platform to foster collaboration among research institutes, enterprises and other institutions to improve indigenous Chinese innovation capabilities and market applications in areas such as clean coal conversion, zero emission and carbon capture and storage. BP and CAS have also agreed that the CECC would act as a cooperation platform between the two parties in order to support the development of the Sino-UK clean coal conversion related near zero emission initiative, including technology development and demonstration projects.
BP and CAS believe that the commercialisation of clean coal conversion and other clean energy conversion technologies will make an important contribution to China’s future energy security whilst also helping to reduce CO2 emissions and address China’s future energy security and environmental sustainability issues. A full time working team drawn from both BP and CAS has been established to progress the feasibility study and the joint venture contract, with the aim of establishing the CECC joint venture by the end of 2008.
Wind Power
BP signed a framework agreement with Beijing Tianrun New Energy Investment Co., a subsidiary of Goldwind Science and Technology Co., Ltd., with the intention of jointly investing, constructing, and operating three 49.5 megawatt wind power plants near Bayan Obo in Inner Mongolia. The two parties have also agreed to explore further wind power investment opportunities in other areas of Inner Mongolia.
Acetic Acid
BP and Sinopec signed a Memorandum of Understanding to add a new 650k tonnes acetic acid plant at their YARACO joint Venture in Chongqing, upstream Yangtze River, Southwest China. This marks another major milestone in strengthening the existing partnership in acetic acid production and follows on from the successful investment in Yangtze River Acetyls Company (YARACO) in Chongqing, and in the BP Yangtze Petrochemicals Acetyls Company (BYACO) in Nanjing.
This world-scale acetic acid plant, using BP’s leading Cativa(r) technology, would have an annual capacity of 650,000 tonnes. The plant is estimated to be on stream in 2011, when the total production at the YARACO site will be well over one million tonnes per annum, making it one of the largest acetic acid production locations in China.
Notes to Editors:
BP is one of the world’s largest oil, gas and petrochemical companies with operations in over 100 countries, employing a workforce of around 96,000. The company provides fuels for transportation, energy for heat and light, retail services and petrochemical products for everyday items. BP’s upstream activities include oil and gas exploration and production, together with the management of crude oil and natural gas pipelines, processing and export terminals. BP’s downstream operations include oil refineries, petrol stations, lubricants, business marketing and chemicals (Aromatics & Acetyls). BP Alternative Energy, which was launched in 2005, consolidates all of BP’s low-carbon activities such as solar, wind, biofuels and carbon capture and storage. The purpose of BP business is to provide products that satisfy human needs, fuel progress and economic growth and to maintain and invest in a sustainable environment. BP’s current market capitalisation is over $200 billion, ranking No.4 on the 2007 list of Fortune Global 500 Enterprises. Further information about BP can be found on www.bp.com.
BP has been operating in China since the early 1970s and has invested over $4.3 billion in commercial projects. Its activities in China include the production and importation of natural gas, supply of aviation fuel, import and marketing of LPG, fuels retailing, lubricants blending and sales, petrochemical manufacturing and solar electric facilities. As one of China’s largest foreign investors, BP has more than 30 joint ventures and wholly owned companies and about 4,000 staff. Further information about BP China, is available on www.bp.com.cn.
In November 2001, BP established the “Clean Energy: Facing the Future” programme in China with the Chinese Academy of Sciences. BP has agreed to invest US$30 million over a thirty-year period to fund research in clean energy technologies. The programme aims to develop and prove new clean energy options for China and the rest of the world. The programme includes several projects at CAS’s Dalian Institute of Chemical Physics and Shenyang Institute of Metals Research.
BP and Chinese Academy of Sciences (CAS) signed a Memorandum of Understanding (MoU) on August 1, 2007, announcing their intent to establish the Clean Energy Commercialisation Centre (CECC). In December 2007, a joint working group was set up to push forward this ambitious project, under the guidance of a newly-established joint steering commission.
Acetic acid is an important organic chemical raw material, widely used in industries such as chemical engineering, light & textile, medicine, pesticide and dye. In 1995, BP and Sinopec jointly established Yangtze River Acetyls Company (YARACO) at Southwestern Chongqing Municipality. Since then, YARACO has been expanded twice to bring its initial acetic acid capacity from 150, 000 tonnes to 350, 000 tonnes a year, and also to include an 80,000 tonnes a year esters plant.
BP is the top acetic acid producer in the world and 80 per cent of the world’s acetic acid facilities incorporate BP’s leading patented Cativa(r) catalyst technology, characterised by low energy consumption and high conversion efficiency. Compared with traditional methanol production technology, Cativa(r) can reduce energy consumption by 30 per cent and reduce greenhouse gas emission by 33 per cent.
BP Alternative Energy, formed in 2005, brings together all BP’s interests in zero and low-carbon power - BP Solar, the company’s photovoltaic business; wind power generation; biofuels and hydrogen power, which combines fossil fuel power generation with carbon capture and storage to provide extremely low carbon power. For more information about BP Alternative Energy, please visit www.bpalternativeenergy.com.
BP and China Xinjiang SunOasis Co., Ltd jointly built a solar power joint venture in Xi’an in 2005, to tap the growing Chinese solar energy market and provide clean and sustainable power for China’s booming economic growth. BP has constructed the largest grid-connected solar power project in Asia in the Shenzhen International Horticultural Expo Park, south China’s Guangdong province. Another solar power demonstration project, the Solar Sail, is being set up by BP Solar at Guangdong Science Centre and is expected to cut at least 45 tonnes of CO2 emissions every year.
Further information:
Location: BP China Press Office
Phone : +8610 84795122
BP announced today during a ceremony in the Great Hall of People in Beijing that it had signed a series of agreements to enhance its commitment to China. These agreements involve strategic integration and commercialisation of clean coal , wind power generation and world-class acetic acid production. The British Prime Minister, the Rt. Hon. Gordon Brown and the Chinese Premier Wen Jiabao, as well as officials from both British and Chinese governments, witnessed the signing.
“BP’s total investment in China has exceeded US$4 billion since our arrival some three decades ago,” said Dr Gary Dirks, BP president of Asia Pacific and China, at the signing ceremony. “Our commercial and social investments serve a clear purpose, which is to provide quality products and materials to help Chinese consumers improve their quality of life and protect the well-being of the environment. I am pleased that BP is continuing to take steps in delivering this commitment.”
Clean Energy Commercialisation Centre
BP and the China Academy of Sciences (CAS) signed an agreement to undertake a feasibility study into a proposed Clean Energy Commercialization Centre (CECC) joint venture. This represents a major step forward following the signing of a Memorandum of Understanding in Shanghai last August.
Under the agreement, CECC is intended to integrate individual clean energy related technologies - coal gasification, coal to liquids, coal to chemical, carbon capture and storage, coal bed methane and underground gasification - from CAS institutes and other organizations both within and outside the PRC, into competitive integrated feedstock manufacturing and product distribution systems and solutions such as polygeneration complexes. The CECC would also serve as an international platform to foster collaboration among research institutes, enterprises and other institutions to improve indigenous Chinese innovation capabilities and market applications in areas such as clean coal conversion, zero emission and carbon capture and storage. BP and CAS have also agreed that the CECC would act as a cooperation platform between the two parties in order to support the development of the Sino-UK clean coal conversion related near zero emission initiative, including technology development and demonstration projects.
BP and CAS believe that the commercialisation of clean coal conversion and other clean energy conversion technologies will make an important contribution to China’s future energy security whilst also helping to reduce CO2 emissions and address China’s future energy security and environmental sustainability issues. A full time working team drawn from both BP and CAS has been established to progress the feasibility study and the joint venture contract, with the aim of establishing the CECC joint venture by the end of 2008.
Wind Power
BP signed a framework agreement with Beijing Tianrun New Energy Investment Co., a subsidiary of Goldwind Science and Technology Co., Ltd., with the intention of jointly investing, constructing, and operating three 49.5 megawatt wind power plants near Bayan Obo in Inner Mongolia. The two parties have also agreed to explore further wind power investment opportunities in other areas of Inner Mongolia.
Acetic Acid
BP and Sinopec signed a Memorandum of Understanding to add a new 650k tonnes acetic acid plant at their YARACO joint Venture in Chongqing, upstream Yangtze River, Southwest China. This marks another major milestone in strengthening the existing partnership in acetic acid production and follows on from the successful investment in Yangtze River Acetyls Company (YARACO) in Chongqing, and in the BP Yangtze Petrochemicals Acetyls Company (BYACO) in Nanjing.
This world-scale acetic acid plant, using BP’s leading Cativa(r) technology, would have an annual capacity of 650,000 tonnes. The plant is estimated to be on stream in 2011, when the total production at the YARACO site will be well over one million tonnes per annum, making it one of the largest acetic acid production locations in China.
Notes to Editors:
BP is one of the world’s largest oil, gas and petrochemical companies with operations in over 100 countries, employing a workforce of around 96,000. The company provides fuels for transportation, energy for heat and light, retail services and petrochemical products for everyday items. BP’s upstream activities include oil and gas exploration and production, together with the management of crude oil and natural gas pipelines, processing and export terminals. BP’s downstream operations include oil refineries, petrol stations, lubricants, business marketing and chemicals (Aromatics & Acetyls). BP Alternative Energy, which was launched in 2005, consolidates all of BP’s low-carbon activities such as solar, wind, biofuels and carbon capture and storage. The purpose of BP business is to provide products that satisfy human needs, fuel progress and economic growth and to maintain and invest in a sustainable environment. BP’s current market capitalisation is over $200 billion, ranking No.4 on the 2007 list of Fortune Global 500 Enterprises. Further information about BP can be found on www.bp.com.
BP has been operating in China since the early 1970s and has invested over $4.3 billion in commercial projects. Its activities in China include the production and importation of natural gas, supply of aviation fuel, import and marketing of LPG, fuels retailing, lubricants blending and sales, petrochemical manufacturing and solar electric facilities. As one of China’s largest foreign investors, BP has more than 30 joint ventures and wholly owned companies and about 4,000 staff. Further information about BP China, is available on www.bp.com.cn.
In November 2001, BP established the “Clean Energy: Facing the Future” programme in China with the Chinese Academy of Sciences. BP has agreed to invest US$30 million over a thirty-year period to fund research in clean energy technologies. The programme aims to develop and prove new clean energy options for China and the rest of the world. The programme includes several projects at CAS’s Dalian Institute of Chemical Physics and Shenyang Institute of Metals Research.
BP and Chinese Academy of Sciences (CAS) signed a Memorandum of Understanding (MoU) on August 1, 2007, announcing their intent to establish the Clean Energy Commercialisation Centre (CECC). In December 2007, a joint working group was set up to push forward this ambitious project, under the guidance of a newly-established joint steering commission.
Acetic acid is an important organic chemical raw material, widely used in industries such as chemical engineering, light & textile, medicine, pesticide and dye. In 1995, BP and Sinopec jointly established Yangtze River Acetyls Company (YARACO) at Southwestern Chongqing Municipality. Since then, YARACO has been expanded twice to bring its initial acetic acid capacity from 150, 000 tonnes to 350, 000 tonnes a year, and also to include an 80,000 tonnes a year esters plant.
BP is the top acetic acid producer in the world and 80 per cent of the world’s acetic acid facilities incorporate BP’s leading patented Cativa(r) catalyst technology, characterised by low energy consumption and high conversion efficiency. Compared with traditional methanol production technology, Cativa(r) can reduce energy consumption by 30 per cent and reduce greenhouse gas emission by 33 per cent.
BP Alternative Energy, formed in 2005, brings together all BP’s interests in zero and low-carbon power - BP Solar, the company’s photovoltaic business; wind power generation; biofuels and hydrogen power, which combines fossil fuel power generation with carbon capture and storage to provide extremely low carbon power. For more information about BP Alternative Energy, please visit www.bpalternativeenergy.com.
BP and China Xinjiang SunOasis Co., Ltd jointly built a solar power joint venture in Xi’an in 2005, to tap the growing Chinese solar energy market and provide clean and sustainable power for China’s booming economic growth. BP has constructed the largest grid-connected solar power project in Asia in the Shenzhen International Horticultural Expo Park, south China’s Guangdong province. Another solar power demonstration project, the Solar Sail, is being set up by BP Solar at Guangdong Science Centre and is expected to cut at least 45 tonnes of CO2 emissions every year.
Further information:
Location: BP China Press Office
Phone : +8610 84795122
Mining News-BP-Energy Consumption Rises as Supplies Lag But Free Energy Markets Do Work
This news was released on 11 June 2008
“The defining feature of global energy markets remains high and volatile prices, reflecting a tight balance of supply and demand. This has put issues such as energy security and alternative energies at the forefront of the political agenda worldwide,” said Tony Hayward, BP’s chief executive at the launch of the 2008 BP Statistical Review of World Energy.
The Review shows that the world’s fossil fuel resource base remains sufficient to support growing levels of production but the continued weakness in oil supply and increasing demand outside the OECD also highlight the challenges that industry faces in maintaining secure energy supplies.
“Declining oil production in the OECD highlights the fact that, while resources are not a constraint globally, the resources within reach of private investment by companies like BP are limited. Political factors, barriers to entry, and high taxes all play a role here. In other words, when it comes to producing more oil, the problems are above ground, not below it. They are not geological, but political,” added Hayward.
“But despite high and volatile energy prices, the world’s energy markets continue to deliver reliable energy supplies,” said Hayward.
According to the Review, world economic growth was strong last year, despite financial market turmoil which began in August, and this continued to support global energy consumption. And although growth in primary energy consumption slowed in 2007 compared to 2006, at 2.4% it was still above the 10-year average for the fifth consecutive year.
The oil price has been on an upward path for more than six years, which according to BP’s data series going back to 1861, is the longest period of rising prices on record.
“This year’s Statistical Review shows very clearly that markets do work, and that consumers and producers respond to changes in energy prices when given the opportunity to do so. However, in many places, policies interfere with market mechanisms and access to economically rational upstream reserves is difficult. Further, in a number of countries consumers are shielded from price increases via subsidies,” commented Christof Rühl, BP’s chief economist at the Review’s launch.
Oil: Dated Brent crude oil averaged $72.39 per barrel in 2007, an increase of 11%. Prices rose steadily throughout the year, from a low of just over $50 in mid-January to above $96 by year-end. Temporary bottlenecks caused the USA benchmark WTI to trade at a discount to Brent for the first time since 1979. Discounts for heavy, sour crudes remained high reflecting constraints on upgrading capacity in refining.
Global oil consumption grew by 1.1% in 2007, or 1 million barrels per day (bpd), slightly below the 10-year average. Consumption in the oil exporting regions of the Middle East, South and Central America, and Africa accounted for two-thirds of the world’s growth. The Asia-Pacific region grew by 2.3%, even though growth in China and Japan was below average, with strong growth in a number of emerging economies. OECD consumption fell by 0.9%, or nearly 400,000 bpd.
Global oil production fell by 0.2%, or 130,000 bpd, the first decline since 2002. OPEC production dropped by 350,000 bpd due to the cumulative impact of production cuts implemented in November 2006 and February 2007. Increased output in Angola and Iraq, and growing supply of condensates/NGLs, partially offset larger cuts in other OPEC countries.
Oil production growth outside OPEC remained weak, rising by just over 200,000 bpd in 2007; OECD output fell for a fifth consecutive year. FSU output rose by nearly 500,000 bpd, with Azerbaijan and Russia each growing by more than 200,000 bpd.
Proved oil reserves were essentially flat in 2007-at 1.24 trillion barrels-and are sufficient to meet current production for more than 41 years. However, the 2006 world total was revised up by 31 billion barrels upon receipt of more complete information.
Gas: World natural gas consumption grew by an above-average 3.1% in 2007, although only North America, Asia-Pacific, and Africa recorded above average regional growth. The USA accounted for nearly half of the world’s gas consumption growth, driven by cold winter weather and strong demand for gas in power generation. Chinese consumption grew by 19.9% and accounted for the second-largest increment to global gas consumption. EU consumption declined by 1.6%-the second consecutive decline-in face of warm winter weather.
Gas production rose by 2.4% in 2007. The USA accounted for the largest increment to supply, growing by 4.3%, the strongest growth since 1984. EU production declined by 6.4%, with UK output falling by 9.5%, the world’s largest volumetric decline for a second consecutive year. A small decline in Russian production was more than offset by strong growth elsewhere in the FSU. China and Qatar recorded the second- and third-largest increments to production, increasing by 18.4% and 17.9% respectively.
LNG shipments rose by 7.3%, supported by continued growth in shipments from Qatar and Nigeria. USA LNG receipts rose by one-third as a large price premium to European spot markets resulted in the diversion of cargoes to the USA.
Coal: Coal was the fastest growing fuel in the world for the fourth consecutive year. Global consumption rose by 4.5%. Consumption growth was widespread, with growth in every region except the Middle East exceeding the 10-year average. Chinese coal consumption rose by 7.9%, the weakest growth since 2002, but more than two-thirds of global growth. Indian consumption rose by 6.6%, and OECD consumption rose by 1.3%, both above average figures.
Nuclear and hydroelectric: Nuclear power output fell by 2%, the steepest decline on record. However, more than 90% of this decline was accounted for by Germany and Japan-which saw the world’s largest nuclear power plant closed following an earthquake. Hydroelectric generation increased by 1.7%, slightly below the 10-year average. Increased capacity in China and Brazil was partially offset by drought-related declines in the USA and Southern Europe.
Renewables: Renewable energy remains a small share of total global energy use, but most renewable sources experienced rapid growth in 2007. Ethanol output rose by 27.8%. Global capacity for wind and solar electricity generation grew broadly in line with historical averages of 28.5% and 37%, respectively.
Note to editors:
The BP Statistical Review of World Energy is available online at www.bp.com/statisticalreview. The website contains all the tables and charts found in the printed edition plus some additional data, an energy charting tool and a conversion calculator.
Further information and media request for hard copies:
Office: BP press office
Phone:+44 (0)20 7496 4076
source : www.bp.com
“The defining feature of global energy markets remains high and volatile prices, reflecting a tight balance of supply and demand. This has put issues such as energy security and alternative energies at the forefront of the political agenda worldwide,” said Tony Hayward, BP’s chief executive at the launch of the 2008 BP Statistical Review of World Energy.
The Review shows that the world’s fossil fuel resource base remains sufficient to support growing levels of production but the continued weakness in oil supply and increasing demand outside the OECD also highlight the challenges that industry faces in maintaining secure energy supplies.
“Declining oil production in the OECD highlights the fact that, while resources are not a constraint globally, the resources within reach of private investment by companies like BP are limited. Political factors, barriers to entry, and high taxes all play a role here. In other words, when it comes to producing more oil, the problems are above ground, not below it. They are not geological, but political,” added Hayward.
“But despite high and volatile energy prices, the world’s energy markets continue to deliver reliable energy supplies,” said Hayward.
According to the Review, world economic growth was strong last year, despite financial market turmoil which began in August, and this continued to support global energy consumption. And although growth in primary energy consumption slowed in 2007 compared to 2006, at 2.4% it was still above the 10-year average for the fifth consecutive year.
The oil price has been on an upward path for more than six years, which according to BP’s data series going back to 1861, is the longest period of rising prices on record.
“This year’s Statistical Review shows very clearly that markets do work, and that consumers and producers respond to changes in energy prices when given the opportunity to do so. However, in many places, policies interfere with market mechanisms and access to economically rational upstream reserves is difficult. Further, in a number of countries consumers are shielded from price increases via subsidies,” commented Christof Rühl, BP’s chief economist at the Review’s launch.
Oil: Dated Brent crude oil averaged $72.39 per barrel in 2007, an increase of 11%. Prices rose steadily throughout the year, from a low of just over $50 in mid-January to above $96 by year-end. Temporary bottlenecks caused the USA benchmark WTI to trade at a discount to Brent for the first time since 1979. Discounts for heavy, sour crudes remained high reflecting constraints on upgrading capacity in refining.
Global oil consumption grew by 1.1% in 2007, or 1 million barrels per day (bpd), slightly below the 10-year average. Consumption in the oil exporting regions of the Middle East, South and Central America, and Africa accounted for two-thirds of the world’s growth. The Asia-Pacific region grew by 2.3%, even though growth in China and Japan was below average, with strong growth in a number of emerging economies. OECD consumption fell by 0.9%, or nearly 400,000 bpd.
Global oil production fell by 0.2%, or 130,000 bpd, the first decline since 2002. OPEC production dropped by 350,000 bpd due to the cumulative impact of production cuts implemented in November 2006 and February 2007. Increased output in Angola and Iraq, and growing supply of condensates/NGLs, partially offset larger cuts in other OPEC countries.
Oil production growth outside OPEC remained weak, rising by just over 200,000 bpd in 2007; OECD output fell for a fifth consecutive year. FSU output rose by nearly 500,000 bpd, with Azerbaijan and Russia each growing by more than 200,000 bpd.
Proved oil reserves were essentially flat in 2007-at 1.24 trillion barrels-and are sufficient to meet current production for more than 41 years. However, the 2006 world total was revised up by 31 billion barrels upon receipt of more complete information.
Gas: World natural gas consumption grew by an above-average 3.1% in 2007, although only North America, Asia-Pacific, and Africa recorded above average regional growth. The USA accounted for nearly half of the world’s gas consumption growth, driven by cold winter weather and strong demand for gas in power generation. Chinese consumption grew by 19.9% and accounted for the second-largest increment to global gas consumption. EU consumption declined by 1.6%-the second consecutive decline-in face of warm winter weather.
Gas production rose by 2.4% in 2007. The USA accounted for the largest increment to supply, growing by 4.3%, the strongest growth since 1984. EU production declined by 6.4%, with UK output falling by 9.5%, the world’s largest volumetric decline for a second consecutive year. A small decline in Russian production was more than offset by strong growth elsewhere in the FSU. China and Qatar recorded the second- and third-largest increments to production, increasing by 18.4% and 17.9% respectively.
LNG shipments rose by 7.3%, supported by continued growth in shipments from Qatar and Nigeria. USA LNG receipts rose by one-third as a large price premium to European spot markets resulted in the diversion of cargoes to the USA.
Coal: Coal was the fastest growing fuel in the world for the fourth consecutive year. Global consumption rose by 4.5%. Consumption growth was widespread, with growth in every region except the Middle East exceeding the 10-year average. Chinese coal consumption rose by 7.9%, the weakest growth since 2002, but more than two-thirds of global growth. Indian consumption rose by 6.6%, and OECD consumption rose by 1.3%, both above average figures.
Nuclear and hydroelectric: Nuclear power output fell by 2%, the steepest decline on record. However, more than 90% of this decline was accounted for by Germany and Japan-which saw the world’s largest nuclear power plant closed following an earthquake. Hydroelectric generation increased by 1.7%, slightly below the 10-year average. Increased capacity in China and Brazil was partially offset by drought-related declines in the USA and Southern Europe.
Renewables: Renewable energy remains a small share of total global energy use, but most renewable sources experienced rapid growth in 2007. Ethanol output rose by 27.8%. Global capacity for wind and solar electricity generation grew broadly in line with historical averages of 28.5% and 37%, respectively.
Note to editors:
The BP Statistical Review of World Energy is available online at www.bp.com/statisticalreview. The website contains all the tables and charts found in the printed edition plus some additional data, an energy charting tool and a conversion calculator.
Further information and media request for hard copies:
Office: BP press office
Phone:+44 (0)20 7496 4076
source : www.bp.com
Mining news-BP-Energy Consumption Rises as Supplies Lag But Free Energy Markets Do Work
Release date: 11 June 2008
“The defining feature of global energy markets remains high and volatile prices, reflecting a tight balance of supply and demand. This has put issues such as energy security and alternative energies at the forefront of the political agenda worldwide,” said Tony Hayward, BP’s chief executive at the launch of the 2008 BP Statistical Review of World Energy.
The Review shows that the world’s fossil fuel resource base remains sufficient to support growing levels of production but the continued weakness in oil supply and increasing demand outside the OECD also highlight the challenges that industry faces in maintaining secure energy supplies.
“Declining oil production in the OECD highlights the fact that, while resources are not a constraint globally, the resources within reach of private investment by companies like BP are limited. Political factors, barriers to entry, and high taxes all play a role here. In other words, when it comes to producing more oil, the problems are above ground, not below it. They are not geological, but political,” added Hayward.
“But despite high and volatile energy prices, the world’s energy markets continue to deliver reliable energy supplies,” said Hayward.
According to the Review, world economic growth was strong last year, despite financial market turmoil which began in August, and this continued to support global energy consumption. And although growth in primary energy consumption slowed in 2007 compared to 2006, at 2.4% it was still above the 10-year average for the fifth consecutive year.
The oil price has been on an upward path for more than six years, which according to BP’s data series going back to 1861, is the longest period of rising prices on record.
“This year’s Statistical Review shows very clearly that markets do work, and that consumers and producers respond to changes in energy prices when given the opportunity to do so. However, in many places, policies interfere with market mechanisms and access to economically rational upstream reserves is difficult. Further, in a number of countries consumers are shielded from price increases via subsidies,” commented Christof Rühl, BP’s chief economist at the Review’s launch.
Oil: Dated Brent crude oil averaged $72.39 per barrel in 2007, an increase of 11%. Prices rose steadily throughout the year, from a low of just over $50 in mid-January to above $96 by year-end. Temporary bottlenecks caused the USA benchmark WTI to trade at a discount to Brent for the first time since 1979. Discounts for heavy, sour crudes remained high reflecting constraints on upgrading capacity in refining.
Global oil consumption grew by 1.1% in 2007, or 1 million barrels per day (bpd), slightly below the 10-year average. Consumption in the oil exporting regions of the Middle East, South and Central America, and Africa accounted for two-thirds of the world’s growth. The Asia-Pacific region grew by 2.3%, even though growth in China and Japan was below average, with strong growth in a number of emerging economies. OECD consumption fell by 0.9%, or nearly 400,000 bpd.
Global oil production fell by 0.2%, or 130,000 bpd, the first decline since 2002. OPEC production dropped by 350,000 bpd due to the cumulative impact of production cuts implemented in November 2006 and February 2007. Increased output in Angola and Iraq, and growing supply of condensates/NGLs, partially offset larger cuts in other OPEC countries.
Oil production growth outside OPEC remained weak, rising by just over 200,000 bpd in 2007; OECD output fell for a fifth consecutive year. FSU output rose by nearly 500,000 bpd, with Azerbaijan and Russia each growing by more than 200,000 bpd.
Proved oil reserves were essentially flat in 2007-at 1.24 trillion barrels-and are sufficient to meet current production for more than 41 years. However, the 2006 world total was revised up by 31 billion barrels upon receipt of more complete information.
Gas: World natural gas consumption grew by an above-average 3.1% in 2007, although only North America, Asia-Pacific, and Africa recorded above average regional growth. The USA accounted for nearly half of the world’s gas consumption growth, driven by cold winter weather and strong demand for gas in power generation. Chinese consumption grew by 19.9% and accounted for the second-largest increment to global gas consumption. EU consumption declined by 1.6%-the second consecutive decline-in face of warm winter weather.
Gas production rose by 2.4% in 2007. The USA accounted for the largest increment to supply, growing by 4.3%, the strongest growth since 1984. EU production declined by 6.4%, with UK output falling by 9.5%, the world’s largest volumetric decline for a second consecutive year. A small decline in Russian production was more than offset by strong growth elsewhere in the FSU. China and Qatar recorded the second- and third-largest increments to production, increasing by 18.4% and 17.9% respectively.
LNG shipments rose by 7.3%, supported by continued growth in shipments from Qatar and Nigeria. USA LNG receipts rose by one-third as a large price premium to European spot markets resulted in the diversion of cargoes to the USA.
Coal: Coal was the fastest growing fuel in the world for the fourth consecutive year. Global consumption rose by 4.5%. Consumption growth was widespread, with growth in every region except the Middle East exceeding the 10-year average. Chinese coal consumption rose by 7.9%, the weakest growth since 2002, but more than two-thirds of global growth. Indian consumption rose by 6.6%, and OECD consumption rose by 1.3%, both above average figures.
Nuclear and hydroelectric: Nuclear power output fell by 2%, the steepest decline on record. However, more than 90% of this decline was accounted for by Germany and Japan-which saw the world’s largest nuclear power plant closed following an earthquake. Hydroelectric generation increased by 1.7%, slightly below the 10-year average. Increased capacity in China and Brazil was partially offset by drought-related declines in the USA and Southern Europe.
Renewables: Renewable energy remains a small share of total global energy use, but most renewable sources experienced rapid growth in 2007. Ethanol output rose by 27.8%. Global capacity for wind and solar electricity generation grew broadly in line with historical averages of 28.5% and 37%, respectively.
Note to editors:
The BP Statistical Review of World Energy is available online at www.bp.com/statisticalreview. The website contains all the tables and charts found in the printed edition plus some additional data, an energy charting tool and a conversion calculator.
Further information and media request for hard copies:
Office: BP press office
Phone:+44 (0)20 7496 4076
“The defining feature of global energy markets remains high and volatile prices, reflecting a tight balance of supply and demand. This has put issues such as energy security and alternative energies at the forefront of the political agenda worldwide,” said Tony Hayward, BP’s chief executive at the launch of the 2008 BP Statistical Review of World Energy.
The Review shows that the world’s fossil fuel resource base remains sufficient to support growing levels of production but the continued weakness in oil supply and increasing demand outside the OECD also highlight the challenges that industry faces in maintaining secure energy supplies.
“Declining oil production in the OECD highlights the fact that, while resources are not a constraint globally, the resources within reach of private investment by companies like BP are limited. Political factors, barriers to entry, and high taxes all play a role here. In other words, when it comes to producing more oil, the problems are above ground, not below it. They are not geological, but political,” added Hayward.
“But despite high and volatile energy prices, the world’s energy markets continue to deliver reliable energy supplies,” said Hayward.
According to the Review, world economic growth was strong last year, despite financial market turmoil which began in August, and this continued to support global energy consumption. And although growth in primary energy consumption slowed in 2007 compared to 2006, at 2.4% it was still above the 10-year average for the fifth consecutive year.
The oil price has been on an upward path for more than six years, which according to BP’s data series going back to 1861, is the longest period of rising prices on record.
“This year’s Statistical Review shows very clearly that markets do work, and that consumers and producers respond to changes in energy prices when given the opportunity to do so. However, in many places, policies interfere with market mechanisms and access to economically rational upstream reserves is difficult. Further, in a number of countries consumers are shielded from price increases via subsidies,” commented Christof Rühl, BP’s chief economist at the Review’s launch.
Oil: Dated Brent crude oil averaged $72.39 per barrel in 2007, an increase of 11%. Prices rose steadily throughout the year, from a low of just over $50 in mid-January to above $96 by year-end. Temporary bottlenecks caused the USA benchmark WTI to trade at a discount to Brent for the first time since 1979. Discounts for heavy, sour crudes remained high reflecting constraints on upgrading capacity in refining.
Global oil consumption grew by 1.1% in 2007, or 1 million barrels per day (bpd), slightly below the 10-year average. Consumption in the oil exporting regions of the Middle East, South and Central America, and Africa accounted for two-thirds of the world’s growth. The Asia-Pacific region grew by 2.3%, even though growth in China and Japan was below average, with strong growth in a number of emerging economies. OECD consumption fell by 0.9%, or nearly 400,000 bpd.
Global oil production fell by 0.2%, or 130,000 bpd, the first decline since 2002. OPEC production dropped by 350,000 bpd due to the cumulative impact of production cuts implemented in November 2006 and February 2007. Increased output in Angola and Iraq, and growing supply of condensates/NGLs, partially offset larger cuts in other OPEC countries.
Oil production growth outside OPEC remained weak, rising by just over 200,000 bpd in 2007; OECD output fell for a fifth consecutive year. FSU output rose by nearly 500,000 bpd, with Azerbaijan and Russia each growing by more than 200,000 bpd.
Proved oil reserves were essentially flat in 2007-at 1.24 trillion barrels-and are sufficient to meet current production for more than 41 years. However, the 2006 world total was revised up by 31 billion barrels upon receipt of more complete information.
Gas: World natural gas consumption grew by an above-average 3.1% in 2007, although only North America, Asia-Pacific, and Africa recorded above average regional growth. The USA accounted for nearly half of the world’s gas consumption growth, driven by cold winter weather and strong demand for gas in power generation. Chinese consumption grew by 19.9% and accounted for the second-largest increment to global gas consumption. EU consumption declined by 1.6%-the second consecutive decline-in face of warm winter weather.
Gas production rose by 2.4% in 2007. The USA accounted for the largest increment to supply, growing by 4.3%, the strongest growth since 1984. EU production declined by 6.4%, with UK output falling by 9.5%, the world’s largest volumetric decline for a second consecutive year. A small decline in Russian production was more than offset by strong growth elsewhere in the FSU. China and Qatar recorded the second- and third-largest increments to production, increasing by 18.4% and 17.9% respectively.
LNG shipments rose by 7.3%, supported by continued growth in shipments from Qatar and Nigeria. USA LNG receipts rose by one-third as a large price premium to European spot markets resulted in the diversion of cargoes to the USA.
Coal: Coal was the fastest growing fuel in the world for the fourth consecutive year. Global consumption rose by 4.5%. Consumption growth was widespread, with growth in every region except the Middle East exceeding the 10-year average. Chinese coal consumption rose by 7.9%, the weakest growth since 2002, but more than two-thirds of global growth. Indian consumption rose by 6.6%, and OECD consumption rose by 1.3%, both above average figures.
Nuclear and hydroelectric: Nuclear power output fell by 2%, the steepest decline on record. However, more than 90% of this decline was accounted for by Germany and Japan-which saw the world’s largest nuclear power plant closed following an earthquake. Hydroelectric generation increased by 1.7%, slightly below the 10-year average. Increased capacity in China and Brazil was partially offset by drought-related declines in the USA and Southern Europe.
Renewables: Renewable energy remains a small share of total global energy use, but most renewable sources experienced rapid growth in 2007. Ethanol output rose by 27.8%. Global capacity for wind and solar electricity generation grew broadly in line with historical averages of 28.5% and 37%, respectively.
Note to editors:
The BP Statistical Review of World Energy is available online at www.bp.com/statisticalreview. The website contains all the tables and charts found in the printed edition plus some additional data, an energy charting tool and a conversion calculator.
Further information and media request for hard copies:
Office: BP press office
Phone:+44 (0)20 7496 4076
Mining News-While posting huge profits, new report shows oil, gas, mining companies pay a lowe
Durango, CO, 04/15: A new report shows that Colorado taxpayers are paying more in taxes than the oil and gas companies producing in the state — even as these companies post enormous profits. Colorado taxpayers are paying 4.63% in tax, while the companies that are charging record prices at the pump and in our homes are paying 2% in combined state income and severance taxes. In 2007, British Petroleum, one of the major oil producers in Colorado, reported $20 billion profits. Governor Ritter’s 2008 Colorado state budget proposal is only $18 billion.
Gwen Lachelt, director of the Oil & Gas Accountability Project (OGAP), said, “this tax day, as Coloradans dig deep to pay for the services we all need, it borders on the criminal that multibillion dollar companies are paying a lower tax rate than those struggling with the increased gas prices charged by those same companies.” She continued, “it’s especially ridiculous when you consider that one company operating in Colorado — British Petroleum — declared more 2007 profits than the entire 2008 Colorado state budget proposal.”
The report Mining Taxes in Ten Western States, prepared by Dr. Robert Ginsburg from the Center on Work and Community Development, analyzes state mining taxation around the west by applying five standard economic principles of fiscal extraction policy. Using these standards, the report finds current taxes in the ten states, Alaska, Arizona, Colorado, Montana, Nevada, New Mexico, North Dakota, South Dakota, Utah and Wyoming, are insufficient and in need of reform.
The five principles are:
Be fair in assessing tax burden on companies and efficient in minimizing the impact on important production and investment decisions;
Be responsive to growth in the industry;
Generate stable and consistent revenues;
Be transparent and accountable to reduce error and instill public confidence; and
Generate sufficient revenue to compensate the state for any operational impacts and to allow the state to have sufficient revenue in reserve when the commodity is completely removed.
A core principle of mining taxation, as explained in the report, is the recognition that the taxation must recognize the one-time nature of the industry. Once the mineral has been removed, the industry will leave, leaving state and local governments with the increased needs of an economically bust community, as well as a loss of tax revenue. A fair tax system will utilize boom period revenues to prepare for this inevitable downturn. Such sovereign or permanent wealth funds are common in many oil, gas, and mining dependent countries. In the western United States, Alaska has such a fund for oil and gas revenue, but it does not apply to mining, and no other state has any such fund.
For More Information
Mining Taxes in Ten Western States
Gwen Lachelt, Oil & Gas Accountability Project, 970-759-4387
EARTHWORKS | 1612 K St., NW, Suite 808 | Washington, D.C., USA 20006
202.887.1872 | info@earthworksaction.org | Privacy Policy
Gwen Lachelt, director of the Oil & Gas Accountability Project (OGAP), said, “this tax day, as Coloradans dig deep to pay for the services we all need, it borders on the criminal that multibillion dollar companies are paying a lower tax rate than those struggling with the increased gas prices charged by those same companies.” She continued, “it’s especially ridiculous when you consider that one company operating in Colorado — British Petroleum — declared more 2007 profits than the entire 2008 Colorado state budget proposal.”
The report Mining Taxes in Ten Western States, prepared by Dr. Robert Ginsburg from the Center on Work and Community Development, analyzes state mining taxation around the west by applying five standard economic principles of fiscal extraction policy. Using these standards, the report finds current taxes in the ten states, Alaska, Arizona, Colorado, Montana, Nevada, New Mexico, North Dakota, South Dakota, Utah and Wyoming, are insufficient and in need of reform.
The five principles are:
Be fair in assessing tax burden on companies and efficient in minimizing the impact on important production and investment decisions;
Be responsive to growth in the industry;
Generate stable and consistent revenues;
Be transparent and accountable to reduce error and instill public confidence; and
Generate sufficient revenue to compensate the state for any operational impacts and to allow the state to have sufficient revenue in reserve when the commodity is completely removed.
A core principle of mining taxation, as explained in the report, is the recognition that the taxation must recognize the one-time nature of the industry. Once the mineral has been removed, the industry will leave, leaving state and local governments with the increased needs of an economically bust community, as well as a loss of tax revenue. A fair tax system will utilize boom period revenues to prepare for this inevitable downturn. Such sovereign or permanent wealth funds are common in many oil, gas, and mining dependent countries. In the western United States, Alaska has such a fund for oil and gas revenue, but it does not apply to mining, and no other state has any such fund.
For More Information
Mining Taxes in Ten Western States
Gwen Lachelt, Oil & Gas Accountability Project, 970-759-4387
EARTHWORKS | 1612 K St., NW, Suite 808 | Washington, D.C., USA 20006
202.887.1872 | info@earthworksaction.org | Privacy Policy
Mining News-While posting huge profits, new report shows oil, gas, mining companies pay a lower tax rate than the average Coloradan
Durango, CO, 04/15: A new report shows that Colorado taxpayers are paying more in taxes than the oil and gas companies producing in the state — even as these companies post enormous profits. Colorado taxpayers are paying 4.63% in tax, while the companies that are charging record prices at the pump and in our homes are paying 2% in combined state income and severance taxes. In 2007, British Petroleum, one of the major oil producers in Colorado, reported $20 billion profits. Governor Ritter’s 2008 Colorado state budget proposal is only $18 billion.
Gwen Lachelt, director of the Oil & Gas Accountability Project (OGAP), said, “this tax day, as Coloradans dig deep to pay for the services we all need, it borders on the criminal that multibillion dollar companies are paying a lower tax rate than those struggling with the increased gas prices charged by those same companies.” She continued, “it’s especially ridiculous when you consider that one company operating in Colorado — British Petroleum — declared more 2007 profits than the entire 2008 Colorado state budget proposal.”
The report Mining Taxes in Ten Western States, prepared by Dr. Robert Ginsburg from the Center on Work and Community Development, analyzes state mining taxation around the west by applying five standard economic principles of fiscal extraction policy. Using these standards, the report finds current taxes in the ten states, Alaska, Arizona, Colorado, Montana, Nevada, New Mexico, North Dakota, South Dakota, Utah and Wyoming, are insufficient and in need of reform.
The five principles are:
Be fair in assessing tax burden on companies and efficient in minimizing the impact on important production and investment decisions;
Be responsive to growth in the industry;
Generate stable and consistent revenues;
Be transparent and accountable to reduce error and instill public confidence; and
Generate sufficient revenue to compensate the state for any operational impacts and to allow the state to have sufficient revenue in reserve when the commodity is completely removed.
A core principle of mining taxation, as explained in the report, is the recognition that the taxation must recognize the one-time nature of the industry. Once the mineral has been removed, the industry will leave, leaving state and local governments with the increased needs of an economically bust community, as well as a loss of tax revenue. A fair tax system will utilize boom period revenues to prepare for this inevitable downturn. Such sovereign or permanent wealth funds are common in many oil, gas, and mining dependent countries. In the western United States, Alaska has such a fund for oil and gas revenue, but it does not apply to mining, and no other state has any such fund.
For More Information
Mining Taxes in Ten Western States
Gwen Lachelt, Oil & Gas Accountability Project, 970-759-4387
EARTHWORKS | 1612 K St., NW, Suite 808 | Washington, D.C., USA 20006
202.887.1872 | info@earthworksaction.org | Privacy Policy
Gwen Lachelt, director of the Oil & Gas Accountability Project (OGAP), said, “this tax day, as Coloradans dig deep to pay for the services we all need, it borders on the criminal that multibillion dollar companies are paying a lower tax rate than those struggling with the increased gas prices charged by those same companies.” She continued, “it’s especially ridiculous when you consider that one company operating in Colorado — British Petroleum — declared more 2007 profits than the entire 2008 Colorado state budget proposal.”
The report Mining Taxes in Ten Western States, prepared by Dr. Robert Ginsburg from the Center on Work and Community Development, analyzes state mining taxation around the west by applying five standard economic principles of fiscal extraction policy. Using these standards, the report finds current taxes in the ten states, Alaska, Arizona, Colorado, Montana, Nevada, New Mexico, North Dakota, South Dakota, Utah and Wyoming, are insufficient and in need of reform.
The five principles are:
Be fair in assessing tax burden on companies and efficient in minimizing the impact on important production and investment decisions;
Be responsive to growth in the industry;
Generate stable and consistent revenues;
Be transparent and accountable to reduce error and instill public confidence; and
Generate sufficient revenue to compensate the state for any operational impacts and to allow the state to have sufficient revenue in reserve when the commodity is completely removed.
A core principle of mining taxation, as explained in the report, is the recognition that the taxation must recognize the one-time nature of the industry. Once the mineral has been removed, the industry will leave, leaving state and local governments with the increased needs of an economically bust community, as well as a loss of tax revenue. A fair tax system will utilize boom period revenues to prepare for this inevitable downturn. Such sovereign or permanent wealth funds are common in many oil, gas, and mining dependent countries. In the western United States, Alaska has such a fund for oil and gas revenue, but it does not apply to mining, and no other state has any such fund.
For More Information
Mining Taxes in Ten Western States
Gwen Lachelt, Oil & Gas Accountability Project, 970-759-4387
EARTHWORKS | 1612 K St., NW, Suite 808 | Washington, D.C., USA 20006
202.887.1872 | info@earthworksaction.org | Privacy Policy
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