Commodity Corner: Oil Edges on Economic Worry
Thursday, April 28, 2011
Rigzone Staff
by Saaniya Bangee
Front-month crude settled nearly flat on Thursday as concerns grew of slowing U.S. economic growth.
Light, sweet oil retreated earlier highs to end the trading session at $112.86 a barrel, 10 cents higher than the previous day. Crude prices peaked as high as $113.97 a barrel. On Thursday, a weaker dollar provided support for crude prices. Likewise, the Dollar Index, which compares the greenback to a basket of foreign currencies, fell to its lowest level since July 31, 2008.
Although the U.S. economy grew by 1.8 percent in the first quarter, investors remain weary of the economy. At Wednesday's press conference, Fed Chairman Ben Bernanke said he didn't know when the Fed would tighten interest rates. Investors interpreted Wednesday's comments as the economy not being strong enough to handle higher interest rates.
According to the U.S. Labor Department, initial unemployment claims soared to their highest in three months. Analysts fear this could mean fewer cars on the road as it gets closer to the summer driving season.
Meanwhile, natural gas rallied Thursday after government reports signaled an increase in demand. Natural gas for June delivery rose 3.7 percent, settling at $4.571 per thousand cubic feet. Prices fluctuated between $4.396 and $4.599, before ending the day at their highest since Jan. 24.
During the week ended April 22, 31 billion cubic feet of gas was added to stockpiles, as reported by the U.S. Energy Information Administration (EIA).
May gasoline hit fresh 33-month highs settling at $3.43 a gallon. The intraday range for gasoline was $3.39 to $3.48 Thursday.
Thursday, April 28, 2011
Aladdin Spuds Exploration Well in Eastern Turke
Aladdin Spuds Exploration Well in Eastern Turkey
Thursday, April 28, 2011
Exile Resources Inc.
Exile Resources Iannounced that, with partner Valeura Energy Inc. and operator Aladdin Middle East Ltd., it had spud the Company's first exploration well, Bostanci-1, on April 24, 2011 in Turkey. This well is located in the southern most corner of the Rubai License 2600 adjacent to the borders with Iraq and Syria.
"The Bostanci structure is a large surface anticline, with Cretaceous Mardin limestones interpreted to lie within the core of the structure as the reservoir target," said Tony Henshaw, President and CEO, of Exile Resources.
Due to surface location constraints, the Bostanci wellsite is located to the north of the target and will require a deviated well, of approximately 11,400 feet measured depth, to reach the interpreted reservoir level. This is expected to take approximately 70-80 days to drill. Exile and Valeura are sharing equally the drilling costs of the well, estimated to be $6.2 million excluding completion and cased-hole testing. This expenditure would take Exile's equity to just under 29%.
The Ogunduk area is still under evaluation, as the partners continue to evaluate the results from the seismic program and consider other leads on the License area.
Thursday, April 28, 2011
Exile Resources Inc.
Exile Resources Iannounced that, with partner Valeura Energy Inc. and operator Aladdin Middle East Ltd., it had spud the Company's first exploration well, Bostanci-1, on April 24, 2011 in Turkey. This well is located in the southern most corner of the Rubai License 2600 adjacent to the borders with Iraq and Syria.
"The Bostanci structure is a large surface anticline, with Cretaceous Mardin limestones interpreted to lie within the core of the structure as the reservoir target," said Tony Henshaw, President and CEO, of Exile Resources.
Due to surface location constraints, the Bostanci wellsite is located to the north of the target and will require a deviated well, of approximately 11,400 feet measured depth, to reach the interpreted reservoir level. This is expected to take approximately 70-80 days to drill. Exile and Valeura are sharing equally the drilling costs of the well, estimated to be $6.2 million excluding completion and cased-hole testing. This expenditure would take Exile's equity to just under 29%.
The Ogunduk area is still under evaluation, as the partners continue to evaluate the results from the seismic program and consider other leads on the License area.
Petrobras Begins Lula Nordeste EWT
Petrobras Begins Lula Nordeste EWT
Thursday, April 28, 2011
Petrobras
Petrobras has started the Extended Well Test (EWT) in the northeastern area of Lula Field, in the Santos Basin pre-salt, approximately 300 kilometers off the coast of Rio de Janeiro.
The EWT is taking place in the FPSO BW Cidade de São Vicente, anchored at a depth of 2,120 meters. Production should remain at around 14 thousand barrels of oil per day.
The information obtained in the test of Lula Nordeste will aid studies for the development of the project of the second definitive production system to be installed in the Lula field, called Lula Nordeste Pilot, through FPSO Cidade de Paraty.
The EWT of Lula Nordeste is a project of the consortium formed by Petrobras (operator, with 65% interest), BG Group (25%) and Galp Energia (10%).
Thursday, April 28, 2011
Petrobras
Petrobras has started the Extended Well Test (EWT) in the northeastern area of Lula Field, in the Santos Basin pre-salt, approximately 300 kilometers off the coast of Rio de Janeiro.
The EWT is taking place in the FPSO BW Cidade de São Vicente, anchored at a depth of 2,120 meters. Production should remain at around 14 thousand barrels of oil per day.
The information obtained in the test of Lula Nordeste will aid studies for the development of the project of the second definitive production system to be installed in the Lula field, called Lula Nordeste Pilot, through FPSO Cidade de Paraty.
The EWT of Lula Nordeste is a project of the consortium formed by Petrobras (operator, with 65% interest), BG Group (25%) and Galp Energia (10%).
Nighthawk Briefs Jolly Ranch Reserves Report
Nighthawk Briefs Jolly Ranch Reserves Report
Thursday, April 28, 2011
Nighthawk Energy plc
Nighthawk announced the conclusions of the Gaffney, Cline and Associates ("GCA") Reserves and Resource Report on the Jolly Ranch Project, in which the Company holds a 50% working interest.
Highlights
Reserves
The declaration of Proved Reserves by GCA has been limited to wells that are projected to recover 20,000 barrels or more. The declaration is based on Decline Curve Analysis, assigning reserves as defined by the SPE Petroleum Resources Management System ("PRMS"). Therefore, proved reserves have only been attributed, at this stage, for two wells with continuous production from the Cherokee formation, namely the Craig 4-4 and Craig 16-32.
Furthermore, it should be noted that these reserves are limited to discrete interbedded Cherokee intervals within these wells. Other horizons, especially within the Atoka formation, have been excluded due to the current lack of adequate production data or the absence of data in the case of uncompleted horizons. The current and future work program will focus on determining the correct method and optimum target within these other horizons to build value.
All of the reserves quoted below are gross, representing 100% of the working interest in the project.
Proved Reserves
The Craig 4-4 is completed in two Cherokee horizons; the Tebo between 6,644 ft and 6,664 ft and the Tebo 'B', between 6,705 ft and 6,711 ft. The Craig 16-32 is completed in the Cherokee 'A' between 6,526 ft and 6,530 ft.
Resource Assessment
Inclusion of Contingent and Prospective Resources requires working interest lands to be developed and further wells to be drilled, which are likely to be both vertical and horizontal. Future production is estimated based on the projected recovery from the decline curves of analogous wells derived from the results of pilot projects.
The Jolly Ranch Cherokee/Atoka shale oil project is in the early stages of development and is still in the process of determining the optimum completion and stimulation technique and the optimum intervals on which to apply these techniques. Given the low number of wells drilled to date compared to the potential development program, the current set of wells with estimated ultimate recovery of 20,000 barrels or more (considered to be the economic minimum) is too small to extrapolate across the wider project area with statistical confidence.
In addition, as directly analogous plays are rare, the type curves are unique to each play and it will take more wells to fully develop confident projections of ultimate recovery.
Additional recompletions and further drilling/stimulation have to be undertaken to increase and confirm the body of knowledge such that it can be consistently and prudently applied to a wider area. As such, it would be misleading to generate a resource estimate at this time without more wells with successful completions as well as further production track record.
Regional Activity
Available results indicate other operators in the county have targeted the Cherokee 'A' unit with encouraging results. Great Plains Field vertical wells, approximately four miles south east of the Company's John Craig 7-2 well, have cumulative production exceeding 60,000 bbl in the Cherokee 'A' per well.
In addition, Newfield Exploration Company recently drilled the Mosher 1-1H, approximately five miles to the North East of the Craig Ranch area, and completed the Cherokee 'A' unit through a horizontal lateral. Due to the confidential nature of the well, little information has been released, but it is reported on the online Colorado State Oil and Gas Information System that the well produced approximately 10,000 barrels of oil over the last six months of 2010. This is encouraging and further evaluation will be needed as production increases and data becomes available.
Tim Heeley, CEO of Nighthawk, commented, "Although as expected these initial reserve numbers are low this merely reflects the fact we are in the early days of developing the Jolly Ranch shale project.
"The GCA report underlines the potential value and highlights the additional work required in order to determine the optimal commercial completion and stimulation techniques for the project's Cherokee and Atoka shale acreage.
"Drilling by other companies in the area, plus continued leasing activity, helps reinforce our strategy and we will continue to execute our work program in a logical fashion to achieve our strategic goals."
Thursday, April 28, 2011
Nighthawk Energy plc
Nighthawk announced the conclusions of the Gaffney, Cline and Associates ("GCA") Reserves and Resource Report on the Jolly Ranch Project, in which the Company holds a 50% working interest.
Highlights
- 2P Reserves only assigned to the two wells projected, on the basis of production to date, to recover greater than 20,000 bbl (gross)
- 3P Reserves attributed over limited areal extent of just five wells (c. 200 acres of the project's 410,000 acres)
- Reserves assessment based on Decline Curve Analysis method and derivation of "type curves"
- Reserves currently based only on two discrete intervals in the Cherokee formation
- Well portfolio needs expanding to establish Contingent Resources numbers and provide a true reflection of project's value
- Report highlights additional work required in order to determine the optimal commercial completion technique
Reserves
The declaration of Proved Reserves by GCA has been limited to wells that are projected to recover 20,000 barrels or more. The declaration is based on Decline Curve Analysis, assigning reserves as defined by the SPE Petroleum Resources Management System ("PRMS"). Therefore, proved reserves have only been attributed, at this stage, for two wells with continuous production from the Cherokee formation, namely the Craig 4-4 and Craig 16-32.
Furthermore, it should be noted that these reserves are limited to discrete interbedded Cherokee intervals within these wells. Other horizons, especially within the Atoka formation, have been excluded due to the current lack of adequate production data or the absence of data in the case of uncompleted horizons. The current and future work program will focus on determining the correct method and optimum target within these other horizons to build value.
All of the reserves quoted below are gross, representing 100% of the working interest in the project.
Proved Reserves
The Craig 4-4 is completed in two Cherokee horizons; the Tebo between 6,644 ft and 6,664 ft and the Tebo 'B', between 6,705 ft and 6,711 ft. The Craig 16-32 is completed in the Cherokee 'A' between 6,526 ft and 6,530 ft.
Resource Assessment
Inclusion of Contingent and Prospective Resources requires working interest lands to be developed and further wells to be drilled, which are likely to be both vertical and horizontal. Future production is estimated based on the projected recovery from the decline curves of analogous wells derived from the results of pilot projects.
The Jolly Ranch Cherokee/Atoka shale oil project is in the early stages of development and is still in the process of determining the optimum completion and stimulation technique and the optimum intervals on which to apply these techniques. Given the low number of wells drilled to date compared to the potential development program, the current set of wells with estimated ultimate recovery of 20,000 barrels or more (considered to be the economic minimum) is too small to extrapolate across the wider project area with statistical confidence.
In addition, as directly analogous plays are rare, the type curves are unique to each play and it will take more wells to fully develop confident projections of ultimate recovery.
Additional recompletions and further drilling/stimulation have to be undertaken to increase and confirm the body of knowledge such that it can be consistently and prudently applied to a wider area. As such, it would be misleading to generate a resource estimate at this time without more wells with successful completions as well as further production track record.
Regional Activity
Available results indicate other operators in the county have targeted the Cherokee 'A' unit with encouraging results. Great Plains Field vertical wells, approximately four miles south east of the Company's John Craig 7-2 well, have cumulative production exceeding 60,000 bbl in the Cherokee 'A' per well.
In addition, Newfield Exploration Company recently drilled the Mosher 1-1H, approximately five miles to the North East of the Craig Ranch area, and completed the Cherokee 'A' unit through a horizontal lateral. Due to the confidential nature of the well, little information has been released, but it is reported on the online Colorado State Oil and Gas Information System that the well produced approximately 10,000 barrels of oil over the last six months of 2010. This is encouraging and further evaluation will be needed as production increases and data becomes available.
Tim Heeley, CEO of Nighthawk, commented, "Although as expected these initial reserve numbers are low this merely reflects the fact we are in the early days of developing the Jolly Ranch shale project.
"The GCA report underlines the potential value and highlights the additional work required in order to determine the optimal commercial completion and stimulation techniques for the project's Cherokee and Atoka shale acreage.
"Drilling by other companies in the area, plus continued leasing activity, helps reinforce our strategy and we will continue to execute our work program in a logical fashion to achieve our strategic goals."
AED Welcomes New CEO
AED Welcomes New CEO
Thursday, April 28, 2011
AED Oil Ltd.
AED announced the appointment of Mr. John F. Imle, Jr. to the role of Chief Executive Officer, effective May 1, 2011. John was invited by the AED Board to take the CEO position in order to strengthen the operational and technical focus of the Executive team and manage the critical next stages of AED's significant exploration, appraisal and development programs. His immediate priorities are to augment the existing management team, direct value adding programs and attract the additional capital required for enhancing the value of the Company's assets. John will also continue in his role as a Director of the Company.
John originally joined the Board as Nations Petroleum's representative in early 2010, following AED's acquisition of Nations' assets in Indonesia (Rombebai and South Madura PSCs) and Brunei (Block L). John's appointment as CEO is concurrent with John stepping down from his role at Nations Petroleum. He has operational knowledge of AED's assets in Brunei and Indonesia and, as a petroleum engineer, brings over 40 years' experience in the oil and gas industry to the post. His career highlights include operations management and Executive-level positions at the U.S. energy company Unocal Corporation. He became Unocal's Head of Global Oil, Gas and Geothermal and then rose to the ranks of President and Vice Chairman. He served on Unocal's Board of Directors for over 10 years.
"I'm excited about the potential of AED's portfolio," John said. "The recent confirmation of the positive results from our exploration wells in Block L, Brunei should, once appraised and developed, provide substantial cash flow in the medium term. Modern 3D seismic surveys over the Jerudong Oil Field, also in Block L, should lead to early gas and oil production, which supports AED's confidence in the block. In Indonesia, we have recently announced a two-year extension of the exploration contract at Rombebai. We believe there is an opportunity for a gas discovery of LNG scale and that the potential to acquire new 3D seismic in the South Madura PSC, will help identify further potential prospects."
"These opportunities combine to make AED an attractive opportunity for investors and strategic partners alike. I have confidence that with appropriate funding, AED's current Asian portfolio will develop into a significant group of producing assets. This is in addition to AED's Puffin and Talbot Fields in the Timor Sea which, given higher oil prices and advancing technology, should prove commercially attractive. The operator, Sinopec, is reviewing new seismic data and will issue reports and recommendations in the near future."
AED Chairman, Mr. David Dix, welcomed John's appointment, "AED will benefit from John's extensive experience. I am excited about his appointment as he already knows the AED team and Board well and I'm confident he will work successfully with them as the Company continues to enhance its high-impact portfolio. I will assist John during a handover period (approximately three months), after which I plan to continue serving AED in the role of Non-Executive Chairman."
Thursday, April 28, 2011
AED Oil Ltd.
AED announced the appointment of Mr. John F. Imle, Jr. to the role of Chief Executive Officer, effective May 1, 2011. John was invited by the AED Board to take the CEO position in order to strengthen the operational and technical focus of the Executive team and manage the critical next stages of AED's significant exploration, appraisal and development programs. His immediate priorities are to augment the existing management team, direct value adding programs and attract the additional capital required for enhancing the value of the Company's assets. John will also continue in his role as a Director of the Company.
John originally joined the Board as Nations Petroleum's representative in early 2010, following AED's acquisition of Nations' assets in Indonesia (Rombebai and South Madura PSCs) and Brunei (Block L). John's appointment as CEO is concurrent with John stepping down from his role at Nations Petroleum. He has operational knowledge of AED's assets in Brunei and Indonesia and, as a petroleum engineer, brings over 40 years' experience in the oil and gas industry to the post. His career highlights include operations management and Executive-level positions at the U.S. energy company Unocal Corporation. He became Unocal's Head of Global Oil, Gas and Geothermal and then rose to the ranks of President and Vice Chairman. He served on Unocal's Board of Directors for over 10 years.
"I'm excited about the potential of AED's portfolio," John said. "The recent confirmation of the positive results from our exploration wells in Block L, Brunei should, once appraised and developed, provide substantial cash flow in the medium term. Modern 3D seismic surveys over the Jerudong Oil Field, also in Block L, should lead to early gas and oil production, which supports AED's confidence in the block. In Indonesia, we have recently announced a two-year extension of the exploration contract at Rombebai. We believe there is an opportunity for a gas discovery of LNG scale and that the potential to acquire new 3D seismic in the South Madura PSC, will help identify further potential prospects."
"These opportunities combine to make AED an attractive opportunity for investors and strategic partners alike. I have confidence that with appropriate funding, AED's current Asian portfolio will develop into a significant group of producing assets. This is in addition to AED's Puffin and Talbot Fields in the Timor Sea which, given higher oil prices and advancing technology, should prove commercially attractive. The operator, Sinopec, is reviewing new seismic data and will issue reports and recommendations in the near future."
AED Chairman, Mr. David Dix, welcomed John's appointment, "AED will benefit from John's extensive experience. I am excited about his appointment as he already knows the AED team and Board well and I'm confident he will work successfully with them as the Company continues to enhance its high-impact portfolio. I will assist John during a handover period (approximately three months), after which I plan to continue serving AED in the role of Non-Executive Chairman."
Fuse 5 Opens New Shop
Fuse 5 Opens New Shop
Thursday, April 28, 2011
Fuse 5
Fuse 5 announced the opening of a new office in Pittsburgh, Pa., expanding the organization's scope of services and broadening its ability to serve companies in the energy industry.
Meredith Dugas, M.B.A., who has nearly a decade of experience in writing and strategy development and execution, has been hired to lead the new location and will serve as the agency's Vice President of Strategic Services.
"Over the last several years, we've dedicated a tremendous amount of resources to clients in the energy industry, from managing high-profile events to executing nationwide advertising campaigns," said Shari King, owner and CEO of Fuse 5. "Meredith has a strong background in nearly every aspect of marketing and communications, and her leadership skills – combined with her experience in community relations – will add a lot of value to companies both in and out of the energy sector."
"Moving into Pittsburgh is a natural step in the progression of our overall strategy to expand the services we provide to companies with interests in the major U.S. shale plays," said Doug Williams, President of Fuse 5. "With resources both in Houston and Pittsburgh, we are now uniquely positioned to meet virtually any requirement of organizations working in the Marcellus and Utica formations."
Throughout her career, Dugas has worked with a range of companies spanning multiple industries – from oil and gas, healthcare, and legal to wealth management, education, and technology. She has held positions in an agency setting and most recently worked as the Manager of Internal Communications for the renowned Memorial Hermann-Texas Medical Center Campus located in Houston.
In that role, she served as editor of six major publications, three of which were produced monthly. She established, managed and executed communication plans in support of organizational goals and collaborated with executive-level leadership to resolve specific communication challenges, including position eliminations, corporate restructures, and the impact of healthcare reform at the hospital, local, and national levels.
Dugas is a graduate of the University of Houston, earning both a Bachelor of Arts in public relations and a Master of Business Administration.
Thursday, April 28, 2011
Fuse 5
Fuse 5 announced the opening of a new office in Pittsburgh, Pa., expanding the organization's scope of services and broadening its ability to serve companies in the energy industry.
Meredith Dugas, M.B.A., who has nearly a decade of experience in writing and strategy development and execution, has been hired to lead the new location and will serve as the agency's Vice President of Strategic Services.
"Over the last several years, we've dedicated a tremendous amount of resources to clients in the energy industry, from managing high-profile events to executing nationwide advertising campaigns," said Shari King, owner and CEO of Fuse 5. "Meredith has a strong background in nearly every aspect of marketing and communications, and her leadership skills – combined with her experience in community relations – will add a lot of value to companies both in and out of the energy sector."
"Moving into Pittsburgh is a natural step in the progression of our overall strategy to expand the services we provide to companies with interests in the major U.S. shale plays," said Doug Williams, President of Fuse 5. "With resources both in Houston and Pittsburgh, we are now uniquely positioned to meet virtually any requirement of organizations working in the Marcellus and Utica formations."
Throughout her career, Dugas has worked with a range of companies spanning multiple industries – from oil and gas, healthcare, and legal to wealth management, education, and technology. She has held positions in an agency setting and most recently worked as the Manager of Internal Communications for the renowned Memorial Hermann-Texas Medical Center Campus located in Houston.
In that role, she served as editor of six major publications, three of which were produced monthly. She established, managed and executed communication plans in support of organizational goals and collaborated with executive-level leadership to resolve specific communication challenges, including position eliminations, corporate restructures, and the impact of healthcare reform at the hospital, local, and national levels.
Dugas is a graduate of the University of Houston, earning both a Bachelor of Arts in public relations and a Master of Business Administration.
Sevan Marine Says Hello to New CEO
Sevan Marine Says Hello to New CEO
Thursday, April 28, 2011
Sevan Marine ASA
Mr. Jan Erik Tveteraas will retire from the position as CEO of Sevan Marine ASA to take on the position as CEO of Sevan Drilling ASA. Mr. Tveteraas was a founding shareholder of Sevan Marine ASA and has been the CEO since the inception in 2001. He has been proposed by the nomination committee as a Board member of Sevan Marine.
Carl Lieungh has been appointed new CEO of Sevan Marine ASA following the general meeting in Sevan Marine.
Mr. Lieungh comes from the position as CEO for Norse Cutting & Abandonment AS (NCA) and has more than 25 years of experience from the oil and gas industry including management and development of enterprises, project management, marketing and international business development. Mr. Lieungh has held key positions within these areas as Senior Vice President for Business Development of the Oil, Gas and Marine Solutions Division in Siemens AG, President for Kvaerner Process System Group of companies and Managing Director of Hitec Framnes AS.
Mr. Lieungh holds a Master of Science from the Norwegian Institute of Technology and Master of Management from The Norwegian School of Management.
Chairman of the Board, Arne Smedal, commented, "We are very pleased to announce that Carl Lieungh has accepted the position as CEO in Sevan Marine ASA. Mr. Lieungh has extensive knowledge about international business and the offshore industry in general and we are convinced that Mr. Lieungh’s industrial experience will be valuable to Sevan Marine ASA. I want to thank Jan Erik Tveteraas for his valuable contribution to the commercialization of the Sevan technology, and wish him all success with his new role in Sevan Drilling ASA where Sevan Marine ASA remains a main shareholder."
Thursday, April 28, 2011
Sevan Marine ASA
Mr. Jan Erik Tveteraas will retire from the position as CEO of Sevan Marine ASA to take on the position as CEO of Sevan Drilling ASA. Mr. Tveteraas was a founding shareholder of Sevan Marine ASA and has been the CEO since the inception in 2001. He has been proposed by the nomination committee as a Board member of Sevan Marine.
Carl Lieungh has been appointed new CEO of Sevan Marine ASA following the general meeting in Sevan Marine.
Mr. Lieungh comes from the position as CEO for Norse Cutting & Abandonment AS (NCA) and has more than 25 years of experience from the oil and gas industry including management and development of enterprises, project management, marketing and international business development. Mr. Lieungh has held key positions within these areas as Senior Vice President for Business Development of the Oil, Gas and Marine Solutions Division in Siemens AG, President for Kvaerner Process System Group of companies and Managing Director of Hitec Framnes AS.
Mr. Lieungh holds a Master of Science from the Norwegian Institute of Technology and Master of Management from The Norwegian School of Management.
Chairman of the Board, Arne Smedal, commented, "We are very pleased to announce that Carl Lieungh has accepted the position as CEO in Sevan Marine ASA. Mr. Lieungh has extensive knowledge about international business and the offshore industry in general and we are convinced that Mr. Lieungh’s industrial experience will be valuable to Sevan Marine ASA. I want to thank Jan Erik Tveteraas for his valuable contribution to the commercialization of the Sevan technology, and wish him all success with his new role in Sevan Drilling ASA where Sevan Marine ASA remains a main shareholder."
Eni, Sonatrach Team Up in Algeria Shale JV
Eni, Sonatrach Team Up in Algeria Shale JV
Thursday, April 28, 2011
Eni S.p.A.
Eni and Sonatrach signed a cooperation agreement for the development of unconventional oil, with particular focus on shale gas reinforcing the close relationship between the two companies.
With extensive experience in exploration and production of unconventional oil, Eni and Sonatrach will jointly implement activities to assess the technical and commercial feasibility of exploration and operational initiatives in shale gas.
Based on previous assessments, Eni confirms the significant shale gas reserves in Algeria which Eni and Sonatrach wish to explore and develop. This will enable both companies to make important discoveries which will enhance the gas potential of the country.
Thursday, April 28, 2011
Eni S.p.A.
Eni and Sonatrach signed a cooperation agreement for the development of unconventional oil, with particular focus on shale gas reinforcing the close relationship between the two companies.
With extensive experience in exploration and production of unconventional oil, Eni and Sonatrach will jointly implement activities to assess the technical and commercial feasibility of exploration and operational initiatives in shale gas.
Based on previous assessments, Eni confirms the significant shale gas reserves in Algeria which Eni and Sonatrach wish to explore and develop. This will enable both companies to make important discoveries which will enhance the gas potential of the country.
TransAtlantic to Buy Thrace Basin Assets
TransAtlantic to Buy Thrace Basin Assets
Thursday, April 28, 2011
TransAtlantic Petroleum Ltd.
TransAtlantic and Mustafa Mehmet Corporation ("MMC") have entered into a definitive share purchase agreement. The Purchase Agreement follows the Option Agreement the Company entered into on November 8, 2011 and the subsequent exercise of the option on February 10, 2011. Under the Purchase Agreement, MMC agreed to sell, and TransAtlantic Worldwide agreed to purchase, all of the shares of Thrace Basin Natural Gas Turkiye Corporation ("TBNG").
Under the terms of the Purchase Agreement, TransAtlantic Worldwide or its assigns will acquire all of the shares of TBNG in exchange for the Company issuing 18.5 million of its common shares and for the transfer of certain overriding royalty interests (ranging from 1.0% to 2.5% of the working interests owned by TBNG on specified exploration licenses) to MMC or an affiliate.
TBNG and its sister company, Pinnacle Turkey, Inc. ("PTI"), currently produce an aggregate of approximately 25.0 million cubic feet of natural gas per day in the Thrace Basin region of northwestern Turkey and hold interests in approximately 600,000 net onshore acres and 360,000 net offshore acres in the Thrace Basin and approximately 305,000 net onshore acres in the Gaziantep region of southeastern Turkey. As previously announced, the Company expects that third party investors, including Valeura Energy Inc., will provide between $90.0 and $100.0 million in cash to acquire between approximately 59.5% and 65% of the current production and acreage owned by TBNG and PTI.
Closing of the transactions contemplated by the Purchase Agreement is expected to occur late in the second quarter of 2011 and is subject to, among other conditions, the receipt of consents from all required regulatory authorities, including the Competition Board of the Republic of Turkey.
Thursday, April 28, 2011
TransAtlantic Petroleum Ltd.
TransAtlantic and Mustafa Mehmet Corporation ("MMC") have entered into a definitive share purchase agreement. The Purchase Agreement follows the Option Agreement the Company entered into on November 8, 2011 and the subsequent exercise of the option on February 10, 2011. Under the Purchase Agreement, MMC agreed to sell, and TransAtlantic Worldwide agreed to purchase, all of the shares of Thrace Basin Natural Gas Turkiye Corporation ("TBNG").
Under the terms of the Purchase Agreement, TransAtlantic Worldwide or its assigns will acquire all of the shares of TBNG in exchange for the Company issuing 18.5 million of its common shares and for the transfer of certain overriding royalty interests (ranging from 1.0% to 2.5% of the working interests owned by TBNG on specified exploration licenses) to MMC or an affiliate.
TBNG and its sister company, Pinnacle Turkey, Inc. ("PTI"), currently produce an aggregate of approximately 25.0 million cubic feet of natural gas per day in the Thrace Basin region of northwestern Turkey and hold interests in approximately 600,000 net onshore acres and 360,000 net offshore acres in the Thrace Basin and approximately 305,000 net onshore acres in the Gaziantep region of southeastern Turkey. As previously announced, the Company expects that third party investors, including Valeura Energy Inc., will provide between $90.0 and $100.0 million in cash to acquire between approximately 59.5% and 65% of the current production and acreage owned by TBNG and PTI.
Closing of the transactions contemplated by the Purchase Agreement is expected to occur late in the second quarter of 2011 and is subject to, among other conditions, the receipt of consents from all required regulatory authorities, including the Competition Board of the Republic of Turkey.
Aladdin Spuds Exploration Well in Eastern Turkey
Aladdin Spuds Exploration Well in Eastern Turkey
Thursday, April 28, 2011
Exile Resources Inc.
Exile Resources Iannounced that, with partner Valeura Energy Inc. and operator Aladdin Middle East Ltd., it had spud the Company's first exploration well, Bostanci-1, on April 24, 2011 in Turkey. This well is located in the southern most corner of the Rubai License 2600 adjacent to the borders with Iraq and Syria.
"The Bostanci structure is a large surface anticline, with Cretaceous Mardin limestones interpreted to lie within the core of the structure as the reservoir target," said Tony Henshaw, President and CEO, of Exile Resources.
Due to surface location constraints, the Bostanci wellsite is located to the north of the target and will require a deviated well, of approximately 11,400 feet measured depth, to reach the interpreted reservoir level. This is expected to take approximately 70-80 days to drill. Exile and Valeura are sharing equally the drilling costs of the well, estimated to be $6.2 million excluding completion and cased-hole testing. This expenditure would take Exile's equity to just under 29%.
The Ogunduk area is still under evaluation, as the partners continue to evaluate the results from the seismic program and consider other leads on the License area.
Thursday, April 28, 2011
Exile Resources Inc.
Exile Resources Iannounced that, with partner Valeura Energy Inc. and operator Aladdin Middle East Ltd., it had spud the Company's first exploration well, Bostanci-1, on April 24, 2011 in Turkey. This well is located in the southern most corner of the Rubai License 2600 adjacent to the borders with Iraq and Syria.
"The Bostanci structure is a large surface anticline, with Cretaceous Mardin limestones interpreted to lie within the core of the structure as the reservoir target," said Tony Henshaw, President and CEO, of Exile Resources.
Due to surface location constraints, the Bostanci wellsite is located to the north of the target and will require a deviated well, of approximately 11,400 feet measured depth, to reach the interpreted reservoir level. This is expected to take approximately 70-80 days to drill. Exile and Valeura are sharing equally the drilling costs of the well, estimated to be $6.2 million excluding completion and cased-hole testing. This expenditure would take Exile's equity to just under 29%.
The Ogunduk area is still under evaluation, as the partners continue to evaluate the results from the seismic program and consider other leads on the License area.
Cabot Charges Ahead in US Shale Plays
Cabot Charges Ahead in US Shale Plays
Thursday, April 28, 2011
Cabot O&G Corp.
Cabot O&G announced continued achievement of milestones in the Marcellus, drilling success in the Eagle Ford and agreements in principle for its Haynesville joint venture effort. "We continue to build momentum in our two areas of focus for 2011," said Dan O. Dinges, Chairman, President and Chief Executive Officer. "Additionally, we have streamlined our east Texas operation with arrangements that are accretive to Cabot."
North Region
In the Marcellus, the Company ended the quarter producing at a curtailed rate of 320 Mmcf gross per day. This represents a production increase since year-end of 90 Mmcf per day as the benefits of the Lathrop expansion began to show up in production.
Contributing to these totals was the completion of several multi-well pads that were turned in line, albeit at curtailed rates. Cabot's first six-well pad added 51 Mmcf gross per day, although infrastructure limits are restricting its full productive capacity. A two-well pad with 29 completion stages is producing 36 Mmcf gross per day. "The productivity we have seen repeatedly for the last 18 months provides a great deal of confidence in our program," commented Dinges. "Tempering this excitement is the 'blocking and tackling' in the trenches to get the infrastructure in place timely to exploit these results."
In regards to the infrastructure build-out, all seven compressors at Lathrop are installed, and the Company is working on additional dehydration and more piping to reach full functionality. This effort will afford Cabot 450 Mmcf per day of takeaway capacity from this station and together with the Teel station provides a total of 550 Mmcf per day of capacity. "In conjunction with this growing capacity of Lathrop, we have identified and secured markets throughout the summer that will allow us to utilize a portion of this additional capacity," stated Dinges. "However, we will still have excess production capacity until the Springville pipeline to Transco becomes operational, which is scheduled during the third quarter."
To highlight the productivity of Cabot's Marcellus acreage, last week Cabot achieved 100 Bcf of cumulative production in Susquehanna – a feat that took just under three years. At the current production rate, it will take less than one year to achieve the next 100 Bcf of cumulative production.
In other North Region news, the Pennsylvania Department of Environmental Protection (PaDEP) has requested the industry to stop disposing of frac flowback fluids at certain approved sites. "We fully support this action by the PaDEP and the Pennsylvania administration," said Dinges. "Since late 2009, we have been recycling 100 percent of our frac fluid returns. We are committed to performing all our operations using best practices and endorse continuing improvements in those practices to minimize impact on the environment and communities in which we operate."
"Additionally, we converted our drilling operation to utilize a closed loop system by the fourth quarter of 2010. This eliminates the need for open pits at drill sites and significantly enhances our fluid management capabilities," added Dinges.
South Region
In the Eagle Ford shale, the Company added three more successful operated completions with 24-hour initial production rates ranging from 345 to 958 barrels of oil per day equivalent. "This range of results highlights the variability as we continue to evaluate completion techniques in the early stages of development in this play," stated Dinges. "Presently we have three more wells drilled, cased and in the queue for completion in our Buckhorn area."
At the Haynesville area, Cabot has signed two deals with industry peers that provide the Company with a carried interest in the initial well for 24 units. In the third deal, Cabot has elected to sell several non-operated units producing 4 Mmcf per day. This deal is signed and under the normal due diligence evaluation. Closing is scheduled for early May with approximately $50 to $55 million in proceeds expected from all these transactions.
"We are pleased with the joint venture outcome as we accomplished our goal of being carried by selling one-third of our acreage and eliminating the need for near term capital allocation in this area," said Dinges.
Thursday, April 28, 2011
Cabot O&G Corp.
Cabot O&G announced continued achievement of milestones in the Marcellus, drilling success in the Eagle Ford and agreements in principle for its Haynesville joint venture effort. "We continue to build momentum in our two areas of focus for 2011," said Dan O. Dinges, Chairman, President and Chief Executive Officer. "Additionally, we have streamlined our east Texas operation with arrangements that are accretive to Cabot."
North Region
In the Marcellus, the Company ended the quarter producing at a curtailed rate of 320 Mmcf gross per day. This represents a production increase since year-end of 90 Mmcf per day as the benefits of the Lathrop expansion began to show up in production.
Contributing to these totals was the completion of several multi-well pads that were turned in line, albeit at curtailed rates. Cabot's first six-well pad added 51 Mmcf gross per day, although infrastructure limits are restricting its full productive capacity. A two-well pad with 29 completion stages is producing 36 Mmcf gross per day. "The productivity we have seen repeatedly for the last 18 months provides a great deal of confidence in our program," commented Dinges. "Tempering this excitement is the 'blocking and tackling' in the trenches to get the infrastructure in place timely to exploit these results."
In regards to the infrastructure build-out, all seven compressors at Lathrop are installed, and the Company is working on additional dehydration and more piping to reach full functionality. This effort will afford Cabot 450 Mmcf per day of takeaway capacity from this station and together with the Teel station provides a total of 550 Mmcf per day of capacity. "In conjunction with this growing capacity of Lathrop, we have identified and secured markets throughout the summer that will allow us to utilize a portion of this additional capacity," stated Dinges. "However, we will still have excess production capacity until the Springville pipeline to Transco becomes operational, which is scheduled during the third quarter."
To highlight the productivity of Cabot's Marcellus acreage, last week Cabot achieved 100 Bcf of cumulative production in Susquehanna – a feat that took just under three years. At the current production rate, it will take less than one year to achieve the next 100 Bcf of cumulative production.
In other North Region news, the Pennsylvania Department of Environmental Protection (PaDEP) has requested the industry to stop disposing of frac flowback fluids at certain approved sites. "We fully support this action by the PaDEP and the Pennsylvania administration," said Dinges. "Since late 2009, we have been recycling 100 percent of our frac fluid returns. We are committed to performing all our operations using best practices and endorse continuing improvements in those practices to minimize impact on the environment and communities in which we operate."
"Additionally, we converted our drilling operation to utilize a closed loop system by the fourth quarter of 2010. This eliminates the need for open pits at drill sites and significantly enhances our fluid management capabilities," added Dinges.
South Region
In the Eagle Ford shale, the Company added three more successful operated completions with 24-hour initial production rates ranging from 345 to 958 barrels of oil per day equivalent. "This range of results highlights the variability as we continue to evaluate completion techniques in the early stages of development in this play," stated Dinges. "Presently we have three more wells drilled, cased and in the queue for completion in our Buckhorn area."
At the Haynesville area, Cabot has signed two deals with industry peers that provide the Company with a carried interest in the initial well for 24 units. In the third deal, Cabot has elected to sell several non-operated units producing 4 Mmcf per day. This deal is signed and under the normal due diligence evaluation. Closing is scheduled for early May with approximately $50 to $55 million in proceeds expected from all these transactions.
"We are pleased with the joint venture outcome as we accomplished our goal of being carried by selling one-third of our acreage and eliminating the need for near term capital allocation in this area," said Dinges.
Nighthawk Cites Jolly Ranch Reserves Report
Nighthawk Cites Jolly Ranch Reserves Report
Thursday, April 28, 2011
Nighthawk Energy plc
Nighthawk announced the conclusions of the Gaffney, Cline and Associates ("GCA") Reserves and Resource Report on the Jolly Ranch Project, in which the Company holds a 50% working interest.
Highlights
Reserves
The declaration of Proved Reserves by GCA has been limited to wells that are projected to recover 20,000 barrels or more. The declaration is based on Decline Curve Analysis, assigning reserves as defined by the SPE Petroleum Resources Management System ("PRMS"). Therefore, proved reserves have only been attributed, at this stage, for two wells with continuous production from the Cherokee formation, namely the Craig 4-4 and Craig 16-32.
Furthermore, it should be noted that these reserves are limited to discrete interbedded Cherokee intervals within these wells. Other horizons, especially within the Atoka formation, have been excluded due to the current lack of adequate production data or the absence of data in the case of uncompleted horizons. The current and future work program will focus on determining the correct method and optimum target within these other horizons to build value.
All of the reserves quoted below are gross, representing 100% of the working interest in the project.
Proved Reserves
The Craig 4-4 is completed in two Cherokee horizons; the Tebo between 6,644 ft and 6,664 ft and the Tebo 'B', between 6,705 ft and 6,711 ft. The Craig 16-32 is completed in the Cherokee 'A' between 6,526 ft and 6,530 ft.
Resource Assessment
Inclusion of Contingent and Prospective Resources requires working interest lands to be developed and further wells to be drilled, which are likely to be both vertical and horizontal. Future production is estimated based on the projected recovery from the decline curves of analogous wells derived from the results of pilot projects.
The Jolly Ranch Cherokee/Atoka shale oil project is in the early stages of development and is still in the process of determining the optimum completion and stimulation technique and the optimum intervals on which to apply these techniques. Given the low number of wells drilled to date compared to the potential development program, the current set of wells with estimated ultimate recovery of 20,000 barrels or more (considered to be the economic minimum) is too small to extrapolate across the wider project area with statistical confidence.
In addition, as directly analogous plays are rare, the type curves are unique to each play and it will take more wells to fully develop confident projections of ultimate recovery.
Additional recompletions and further drilling/stimulation have to be undertaken to increase and confirm the body of knowledge such that it can be consistently and prudently applied to a wider area. As such, it would be misleading to generate a resource estimate at this time without more wells with successful completions as well as further production track record.
Regional Activity
Available results indicate other operators in the county have targeted the Cherokee 'A' unit with encouraging results. Great Plains Field vertical wells, approximately four miles south east of the Company's John Craig 7-2 well, have cumulative production exceeding 60,000 bbl in the Cherokee 'A' per well.
In addition, Newfield Exploration Company recently drilled the Mosher 1-1H, approximately five miles to the North East of the Craig Ranch area, and completed the Cherokee 'A' unit through a horizontal lateral. Due to the confidential nature of the well, little information has been released, but it is reported on the online Colorado State Oil and Gas Information System that the well produced approximately 10,000 barrels of oil over the last six months of 2010. This is encouraging and further evaluation will be needed as production increases and data becomes available.
Tim Heeley, CEO of Nighthawk, commented, "Although as expected these initial reserve numbers are low this merely reflects the fact we are in the early days of developing the Jolly Ranch shale project.
"The GCA report underlines the potential value and highlights the additional work required in order to determine the optimal commercial completion and stimulation techniques for the project's Cherokee and Atoka shale acreage.
"Drilling by other companies in the area, plus continued leasing activity, helps reinforce our strategy and we will continue to execute our work program in a logical fashion to achieve our strategic goals."
Thursday, April 28, 2011
Nighthawk Energy plc
Nighthawk announced the conclusions of the Gaffney, Cline and Associates ("GCA") Reserves and Resource Report on the Jolly Ranch Project, in which the Company holds a 50% working interest.
Highlights
- 2P Reserves only assigned to the two wells projected, on the basis of production to date, to recover greater than 20,000 bbl (gross)
- 3P Reserves attributed over limited areal extent of just five wells (c. 200 acres of the project's 410,000 acres)
- Reserves assessment based on Decline Curve Analysis method and derivation of "type curves"
- Reserves currently based only on two discrete intervals in the Cherokee formation
- Well portfolio needs expanding to establish Contingent Resources numbers and provide a true reflection of project's value
- Report highlights additional work required in order to determine the optimal commercial completion technique
Reserves
The declaration of Proved Reserves by GCA has been limited to wells that are projected to recover 20,000 barrels or more. The declaration is based on Decline Curve Analysis, assigning reserves as defined by the SPE Petroleum Resources Management System ("PRMS"). Therefore, proved reserves have only been attributed, at this stage, for two wells with continuous production from the Cherokee formation, namely the Craig 4-4 and Craig 16-32.
Furthermore, it should be noted that these reserves are limited to discrete interbedded Cherokee intervals within these wells. Other horizons, especially within the Atoka formation, have been excluded due to the current lack of adequate production data or the absence of data in the case of uncompleted horizons. The current and future work program will focus on determining the correct method and optimum target within these other horizons to build value.
All of the reserves quoted below are gross, representing 100% of the working interest in the project.
Proved Reserves
The Craig 4-4 is completed in two Cherokee horizons; the Tebo between 6,644 ft and 6,664 ft and the Tebo 'B', between 6,705 ft and 6,711 ft. The Craig 16-32 is completed in the Cherokee 'A' between 6,526 ft and 6,530 ft.
Resource Assessment
Inclusion of Contingent and Prospective Resources requires working interest lands to be developed and further wells to be drilled, which are likely to be both vertical and horizontal. Future production is estimated based on the projected recovery from the decline curves of analogous wells derived from the results of pilot projects.
The Jolly Ranch Cherokee/Atoka shale oil project is in the early stages of development and is still in the process of determining the optimum completion and stimulation technique and the optimum intervals on which to apply these techniques. Given the low number of wells drilled to date compared to the potential development program, the current set of wells with estimated ultimate recovery of 20,000 barrels or more (considered to be the economic minimum) is too small to extrapolate across the wider project area with statistical confidence.
In addition, as directly analogous plays are rare, the type curves are unique to each play and it will take more wells to fully develop confident projections of ultimate recovery.
Additional recompletions and further drilling/stimulation have to be undertaken to increase and confirm the body of knowledge such that it can be consistently and prudently applied to a wider area. As such, it would be misleading to generate a resource estimate at this time without more wells with successful completions as well as further production track record.
Regional Activity
Available results indicate other operators in the county have targeted the Cherokee 'A' unit with encouraging results. Great Plains Field vertical wells, approximately four miles south east of the Company's John Craig 7-2 well, have cumulative production exceeding 60,000 bbl in the Cherokee 'A' per well.
In addition, Newfield Exploration Company recently drilled the Mosher 1-1H, approximately five miles to the North East of the Craig Ranch area, and completed the Cherokee 'A' unit through a horizontal lateral. Due to the confidential nature of the well, little information has been released, but it is reported on the online Colorado State Oil and Gas Information System that the well produced approximately 10,000 barrels of oil over the last six months of 2010. This is encouraging and further evaluation will be needed as production increases and data becomes available.
Tim Heeley, CEO of Nighthawk, commented, "Although as expected these initial reserve numbers are low this merely reflects the fact we are in the early days of developing the Jolly Ranch shale project.
"The GCA report underlines the potential value and highlights the additional work required in order to determine the optimal commercial completion and stimulation techniques for the project's Cherokee and Atoka shale acreage.
"Drilling by other companies in the area, plus continued leasing activity, helps reinforce our strategy and we will continue to execute our work program in a logical fashion to achieve our strategic goals."
OXY Touts $1.1B in 1Q 2011
OXY Touts $1.1B in 1Q 2011
Thursday, April 28, 2011
Occidental Petroleum Corp.
Occidental Petroleum Corporation (OXY) announced core income of $1.6 billion ($1.96 per diluted share) for the first quarter of 2011, compared with $1.1 billion ($1.35 per diluted share) for the first quarter of 2010. Net income for the first quarter of 2011 was $1.5 billion ($1.90 per diluted share), compared with $1.1 billion ($1.31 per diluted share) for the first quarter of 2010.
In announcing the results, Dr. Ray R. Irani, Chairman and Chief Executive Officer, said, "The first quarter of 2011 core income of $1.6 billion was 45-percent higher than the first quarter of 2010. Our oil and gas production for the first quarter of 2011 increased over 4 percent, as compared to the first quarter of 2010, to 730,000 BOE per day."
QUARTERLY RESULTS
Oil and Gas
Oil and gas segment earnings were $2.5 billion for the first quarter of 2011, compared with $1.9 billion for the same period in 2010. The increase in the first quarter of 2011 results was due to higher crude oil prices and higher sales volumes in the Middle East, partially offset by higher operating costs and DD&A rates.
For the first quarter of 2011, daily oil and gas production volumes averaged 730,000 barrels of oil equivalent (BOE), compared with 701,000 BOE in the first quarter of 2010. Volumes increased over 4 percent, primarily in domestic gas and NGL production and Middle East/North Africa crude oil volumes. The domestic gas increase was from the new acquisition in South Texas, which closed in the first quarter of 2011. The Middle East/North Africa increase included new production from Iraq and higher volumes from the Mukhaizna field in Oman.
As a result of higher year-over-year average oil prices affecting production sharing and similar contracts, production was negatively impacted in the Middle East/North Africa, Long Beach and Colombia by 12,000 BOE per day. Dolphin and Elk Hills volumes were also lower from planned maintenance and production shut-downs in the first quarter of 2011.
Daily sales volumes increased over 6 percent from 685,000 BOE per day in the first quarter of 2010 to 728,000 BOE per day in the first quarter of 2011.
Oxy's realized price for worldwide crude oil was $92.14 per barrel for the first quarter of 2011, compared with $74.09 per barrel for the first quarter of 2010. Worldwide realized NGL prices rose from $47.48 per barrel in the first quarter of 2010 to $52.64 per barrel in the first quarter of 2011. Domestic realized gas prices dropped from $5.62 per Mcf in the first quarter of 2010 to $4.21 per Mcf for the first quarter of 2011.
Thursday, April 28, 2011
Occidental Petroleum Corp.
Occidental Petroleum Corporation (OXY) announced core income of $1.6 billion ($1.96 per diluted share) for the first quarter of 2011, compared with $1.1 billion ($1.35 per diluted share) for the first quarter of 2010. Net income for the first quarter of 2011 was $1.5 billion ($1.90 per diluted share), compared with $1.1 billion ($1.31 per diluted share) for the first quarter of 2010.
In announcing the results, Dr. Ray R. Irani, Chairman and Chief Executive Officer, said, "The first quarter of 2011 core income of $1.6 billion was 45-percent higher than the first quarter of 2010. Our oil and gas production for the first quarter of 2011 increased over 4 percent, as compared to the first quarter of 2010, to 730,000 BOE per day."
QUARTERLY RESULTS
Oil and Gas
Oil and gas segment earnings were $2.5 billion for the first quarter of 2011, compared with $1.9 billion for the same period in 2010. The increase in the first quarter of 2011 results was due to higher crude oil prices and higher sales volumes in the Middle East, partially offset by higher operating costs and DD&A rates.
For the first quarter of 2011, daily oil and gas production volumes averaged 730,000 barrels of oil equivalent (BOE), compared with 701,000 BOE in the first quarter of 2010. Volumes increased over 4 percent, primarily in domestic gas and NGL production and Middle East/North Africa crude oil volumes. The domestic gas increase was from the new acquisition in South Texas, which closed in the first quarter of 2011. The Middle East/North Africa increase included new production from Iraq and higher volumes from the Mukhaizna field in Oman.
As a result of higher year-over-year average oil prices affecting production sharing and similar contracts, production was negatively impacted in the Middle East/North Africa, Long Beach and Colombia by 12,000 BOE per day. Dolphin and Elk Hills volumes were also lower from planned maintenance and production shut-downs in the first quarter of 2011.
Daily sales volumes increased over 6 percent from 685,000 BOE per day in the first quarter of 2010 to 728,000 BOE per day in the first quarter of 2011.
Oxy's realized price for worldwide crude oil was $92.14 per barrel for the first quarter of 2011, compared with $74.09 per barrel for the first quarter of 2010. Worldwide realized NGL prices rose from $47.48 per barrel in the first quarter of 2010 to $52.64 per barrel in the first quarter of 2011. Domestic realized gas prices dropped from $5.62 per Mcf in the first quarter of 2010 to $4.21 per Mcf for the first quarter of 2011.
Change in Oil Funding Priorities Concerns Western Legislators
Change in Oil Funding Priorities Concerns Western Legislators
Thursday, April 28, 2011
The Bismarck Tribune, Bismarck, North Dakota
by Rebecca Beitsch, The Bismarck Tribune, N.D.
Lawmakers have passed a bill that changes the way oil money will be allocated amid cries from some western legislators that it will short the oil producing counties.
House Bill 1451, which now goes to the governor for signature, eliminates the Permanent Oil Trust Fund, where most oil revenue goes now, and disperses it into other funds --mainly the state's general fund -- while all setting the stage for locking more of it away in the Legacy Fund down the road.
Some legislators' problem with the Permanent Oil Trust Fund was one of semantics -- they complained there was nothing permanent about it and the fund should be dissolved and dispersed into more project-specific funds.
The bill does just that, putting more money from oil revenue into the general fund to cover projects that would've likely been funded by oil money anyway. The rest of the money funnels into funds, hitting an upper limit before moving into the next one like a line of dominoes.
After the first $200 million goes into the general fund, the next $341 million would fund property tax relief. Then comes more money into the general fund, allotments into the newly-created Strategic Investment and Improvements Fund, then into disaster relief, and then back to the Strategic Investment and Improvements Fund before 25 percent of whatever is left over goes into the Legacy Fund. Created by voter referendum in 2010, the Legacy Fund locks some of the oil revenue away, untouchable by the Legislature until 2017.
As the bill came to a final vote Tuesday in the Senate, some expressed concern about putting even more money in the Legacy Fund, though money is not projected to reach that fund this biennium.
Sen. John Andrist, R-Crosby, said investing in infrastructure, particularly in the western part of the state, should be a No. 1 priority.
"I'm afraid we're going to get short changed because we'll be trying to save money rather than invest it in infrastructure in the oil producing counties that supplied those funds," Andrist said, adding that the infrastructure money from this session had been scattered through the state rather than targeted at the west.
Other discussion surrounded eliminating the Permanent Oil Trust Fund.
Sen. Dwight Cook, R-Mandan, said centralizing spending from one source would be more transparent. Others argued the opposite, saying it made it unclear to what extent oil was funding state projects.
"I think it's always good to know when the state is spending oil money," said Sen. Jim Dotzenrod, D-Wyndmere.
Sen. John Warner, R-Ryder, said much of the state's spending is due to oil, but he's concerned transferring more to the general fund will tempt legislators to spend.
"We can only put so much in the general fund or we'll overspend," Warner said.
Thursday, April 28, 2011
The Bismarck Tribune, Bismarck, North Dakota
by Rebecca Beitsch, The Bismarck Tribune, N.D.
Lawmakers have passed a bill that changes the way oil money will be allocated amid cries from some western legislators that it will short the oil producing counties.
House Bill 1451, which now goes to the governor for signature, eliminates the Permanent Oil Trust Fund, where most oil revenue goes now, and disperses it into other funds --mainly the state's general fund -- while all setting the stage for locking more of it away in the Legacy Fund down the road.
Some legislators' problem with the Permanent Oil Trust Fund was one of semantics -- they complained there was nothing permanent about it and the fund should be dissolved and dispersed into more project-specific funds.
The bill does just that, putting more money from oil revenue into the general fund to cover projects that would've likely been funded by oil money anyway. The rest of the money funnels into funds, hitting an upper limit before moving into the next one like a line of dominoes.
After the first $200 million goes into the general fund, the next $341 million would fund property tax relief. Then comes more money into the general fund, allotments into the newly-created Strategic Investment and Improvements Fund, then into disaster relief, and then back to the Strategic Investment and Improvements Fund before 25 percent of whatever is left over goes into the Legacy Fund. Created by voter referendum in 2010, the Legacy Fund locks some of the oil revenue away, untouchable by the Legislature until 2017.
As the bill came to a final vote Tuesday in the Senate, some expressed concern about putting even more money in the Legacy Fund, though money is not projected to reach that fund this biennium.
Sen. John Andrist, R-Crosby, said investing in infrastructure, particularly in the western part of the state, should be a No. 1 priority.
"I'm afraid we're going to get short changed because we'll be trying to save money rather than invest it in infrastructure in the oil producing counties that supplied those funds," Andrist said, adding that the infrastructure money from this session had been scattered through the state rather than targeted at the west.
Other discussion surrounded eliminating the Permanent Oil Trust Fund.
Sen. Dwight Cook, R-Mandan, said centralizing spending from one source would be more transparent. Others argued the opposite, saying it made it unclear to what extent oil was funding state projects.
"I think it's always good to know when the state is spending oil money," said Sen. Jim Dotzenrod, D-Wyndmere.
Sen. John Warner, R-Ryder, said much of the state's spending is due to oil, but he's concerned transferring more to the general fund will tempt legislators to spend.
"We can only put so much in the general fund or we'll overspend," Warner said.
Premier to Plug, Abandon Well at Vietnam Block
Premier to Plug, Abandon Well at Vietnam Block
Thursday, April 28, 2011
Pan Pacific Petroleum NL
Premier Oil Vietnam South B.V. ("Premier"), the operator of the Block 07/03 Production Sharing Contract, has advised that the CRD-2X-ST appraisal well operations have been successfully completed and that the CRD-2X well will now be plugged and abandoned as planned.
The CRD-2X appraisal well was spudded by the semi-submersible drilling rig the Ocean General on Thursday, February 10. The well was planned to evaluate the oil and gas discovered in multiple stacked Miocene and Oligocene reservoir sands by CRD-1X in 2009 with the aim of reducing uncertainty in whether the CRD (Cá Rong Ðo) structure contains sufficient volumes to support a potential development. CRD-1X tested two zones in the Miocene sands which flowed oil at a combined rate of 3,265.4 BOPD plus 8.1 MMSCFD, through a 48/64" choke, with no water. However, it was not possible to flow test the Oligocene sands at that time.
CRD-2X reached a total depth of 3,785 m BRT on March 10, and following evaluation of the section by logging, drill stem tests of two
reservoir zones in the Oligocene section were conducted. The first zone tested flowed gas and condensate at rates of 9.7 MMSCFD and 870 BOPD respectively through a 40/64" choke. The second zone tested flowed gas and condensate at rates of 17 MMSCFD and 1730 BOPD respectively through a 56/64" choke. The total net condensate/gas pay in this well was 72m, a significant increase compared with the 17 m of net pay penetrated in the Oligocene section in the up dip CRD-1X well.
CRD-2X was subsequently sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands. This sidetrack well CRD-2X-ST reached its planned total depth of 3,340 m BRT in the Miocene section and intersected 18.3m of net oil pay in the Miocene sands. This compares with 34.4m of net oil pay intersected in the Miocene section in the up dip CRD-1X well, and 3.8m in the down dip CRD-2X well.
These well results, including strong flows from the Oligocene sands have provided important information that will assist in the assessment of the resource potential of the CRD structure. The Operator will now undertake further studies to determine the feasibility of a commercial development.
Partners in the Vietnam Block 07/03 are:
Thursday, April 28, 2011
Pan Pacific Petroleum NL
Premier Oil Vietnam South B.V. ("Premier"), the operator of the Block 07/03 Production Sharing Contract, has advised that the CRD-2X-ST appraisal well operations have been successfully completed and that the CRD-2X well will now be plugged and abandoned as planned.
The CRD-2X appraisal well was spudded by the semi-submersible drilling rig the Ocean General on Thursday, February 10. The well was planned to evaluate the oil and gas discovered in multiple stacked Miocene and Oligocene reservoir sands by CRD-1X in 2009 with the aim of reducing uncertainty in whether the CRD (Cá Rong Ðo) structure contains sufficient volumes to support a potential development. CRD-1X tested two zones in the Miocene sands which flowed oil at a combined rate of 3,265.4 BOPD plus 8.1 MMSCFD, through a 48/64" choke, with no water. However, it was not possible to flow test the Oligocene sands at that time.
CRD-2X reached a total depth of 3,785 m BRT on March 10, and following evaluation of the section by logging, drill stem tests of two
reservoir zones in the Oligocene section were conducted. The first zone tested flowed gas and condensate at rates of 9.7 MMSCFD and 870 BOPD respectively through a 40/64" choke. The second zone tested flowed gas and condensate at rates of 17 MMSCFD and 1730 BOPD respectively through a 56/64" choke. The total net condensate/gas pay in this well was 72m, a significant increase compared with the 17 m of net pay penetrated in the Oligocene section in the up dip CRD-1X well.
CRD-2X was subsequently sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands. This sidetrack well CRD-2X-ST reached its planned total depth of 3,340 m BRT in the Miocene section and intersected 18.3m of net oil pay in the Miocene sands. This compares with 34.4m of net oil pay intersected in the Miocene section in the up dip CRD-1X well, and 3.8m in the down dip CRD-2X well.
These well results, including strong flows from the Oligocene sands have provided important information that will assist in the assessment of the resource potential of the CRD structure. The Operator will now undertake further studies to determine the feasibility of a commercial development.
Partners in the Vietnam Block 07/03 are:
- Pan Pacific Petroleum (Vietnam) Pty Ltd 5% (a wholly owned subsidiary of Pan Pacific Petroleum NL)
- Premier Oil Vietnam South B.V. (Operator) 30%
- Vietnam American Exploration Company, LLC. 40% (a wholly owned subsidiary of Pitkin Petroleum Plc)
- PearlOil (Ophiolite) Ltd. 15%
- PetroVietnam Exploration and Production Corporation Ltd 10%
Cougar O&G Acquires Assets in Alberta
Cougar O&G Acquires Assets in Alberta
Thursday, April 28, 2011
Cougar O&G Canada Inc.
Cougar O&G has closed the acquisition of several operated and non-operated oil and natural gas properties ("Properties") in Alberta.
Cougar acquired the Properties from a private company. The Properties include the following assets:
Mr. William Tighe, CEO and Chairman of the Board for Cougar stated, "We are delighted that this asset acquisition has closed. The acquisition did not have a debt or equity cost to the Corporation and it had an immediate strategic value. It provides access to a defined Cardium horizontal oil prospect, a profitable CBM natural gas production field with a long reserve life and an undeveloped land base close to our Alexander oil prospect.
"In the Trout production area, the horizontal well continues to steadily improve as the drilling fluid lost to the formation is recovered. The reservoir pressure is increasing and the fluid level in the wellbore continues to increase. A temporary hydraulic pump jack was installed on the well just prior to breakup and once the lease conditions dry up we hope to replace that with an electric submersible pump which will result in the higher production rate required to properly evaluate the well.
"The geological and geophysical work continues regarding the evaluation of the new Trout 3D seismic data shot in January and within the next two weeks we plan to kick off the permitting of a Q3 multiwell oil drilling program."
Thursday, April 28, 2011
Cougar O&G Canada Inc.
Cougar O&G has closed the acquisition of several operated and non-operated oil and natural gas properties ("Properties") in Alberta.
Cougar acquired the Properties from a private company. The Properties include the following assets:
- 4 producing non-operated CBM gas wellsand associated gathering and production facilities located in Central Alberta with a net production of approximately 25 BOEPD.
- 3 suspended Cardium oil wells located in central Alberta with the potential to reactivate 2 of the wells this summer for an estimated net production of 25bbl per day. The wells are also located in an area that has recently proven successful for horizontal Cardium oil development.
- 5 standing natural gas wells in central and southern Alberta. These wells require additional workover and/or tie-in work and will be evaluated for development, farmout or divestiture.
- 3200 net acres of mineral rights adjacent to Cougar's oil producing Alexander property. These mineral rights include all P&NG rights and will be evaluated for oil production potential.
Mr. William Tighe, CEO and Chairman of the Board for Cougar stated, "We are delighted that this asset acquisition has closed. The acquisition did not have a debt or equity cost to the Corporation and it had an immediate strategic value. It provides access to a defined Cardium horizontal oil prospect, a profitable CBM natural gas production field with a long reserve life and an undeveloped land base close to our Alexander oil prospect.
"In the Trout production area, the horizontal well continues to steadily improve as the drilling fluid lost to the formation is recovered. The reservoir pressure is increasing and the fluid level in the wellbore continues to increase. A temporary hydraulic pump jack was installed on the well just prior to breakup and once the lease conditions dry up we hope to replace that with an electric submersible pump which will result in the higher production rate required to properly evaluate the well.
"The geological and geophysical work continues regarding the evaluation of the new Trout 3D seismic data shot in January and within the next two weeks we plan to kick off the permitting of a Q3 multiwell oil drilling program."
Tri-Valley Concludes Phase I of Claflin Drilling Program
Tri-Valley Concludes Phase I of Claflin Drilling Program
Thursday, April 28, 2011
Tri-Valley Corp.
Tri-Valley has completed an expanded Phase 1 development drilling program at its Claflin oil project, located in the Edison Oil Field near Bakersfield, California. The Company has drilled eight new wells, up from the six wells initially planned. These new wells are part of Tri-Valley's overall plan to drill a total of 22 new wells at Claflin during 2011 to convert 2.1 million barrels of net proved undeveloped oil reserves (PUDs) on the property to proved developed and producing (PDP) status and to increase oil production. The net proved undeveloped reserves were included in the reserves disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2010, and filed with the U.S. Securities and Exchange Commission on March 22, 2011.
Tri-Valley is currently completing the installation of well-site production equipment and tie-in of the new wells to existing production facilities at Claflin. The Company expects to commence an initial steam injection cycle on the first well in early May and that the new wells will have received an initial steam injection cycle by the end of July; however, new steam generating capacity being installed at Claflin could accelerate completion of this initial steam injection work on the new wells. First oil production is anticipated from some of the new wells by June. Following first production from these new wells, there will be a 90-day evaluation period during which Tri-Valley will analyze the performance of the new wells prior to commencement of the second phase of the Claflin development to complete the remaining 14 new wells by the end of the year.
"We are ahead of schedule on our plans to develop the Claflin property to drive increased oil production in 2011," said Maston N. Cunningham, President and CEO of Tri-Valley Corporation. "Our plan calls for a total of 13 new vertical wells and nine new horizontal wells to be drilled on the property this year. If we are successful, we expect to exit 2011 with gross daily production of about 800 barrels of oil from the property."
"With the closing of our recent private placement financing, we raised nearly five million dollars in new capital that will allow us to pursue our development plans at Claflin," continued Mr. Cunningham. "We would like to welcome Ironman Energy Master Fund, an experienced oil and gas investment fund and major participant in our recent financing, as a significant new shareholder of Tri-Valley Corporation."
"Negotiations with adjacent land and mineral owners to secure permits for the 3-D seismic acquisition area for the Claflin and adjoining Brea properties have taken more time than originally planned, but we believe that seismic acquisition work should start by the end of May," added Mr. Cunningham. "This new 3-D data will useful for our exploitation plans for Claflin and Brea, including better geologic control during horizontal drilling operations later this year in the second phase of Claflin development."
Thursday, April 28, 2011
Tri-Valley Corp.
Tri-Valley has completed an expanded Phase 1 development drilling program at its Claflin oil project, located in the Edison Oil Field near Bakersfield, California. The Company has drilled eight new wells, up from the six wells initially planned. These new wells are part of Tri-Valley's overall plan to drill a total of 22 new wells at Claflin during 2011 to convert 2.1 million barrels of net proved undeveloped oil reserves (PUDs) on the property to proved developed and producing (PDP) status and to increase oil production. The net proved undeveloped reserves were included in the reserves disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2010, and filed with the U.S. Securities and Exchange Commission on March 22, 2011.
Tri-Valley is currently completing the installation of well-site production equipment and tie-in of the new wells to existing production facilities at Claflin. The Company expects to commence an initial steam injection cycle on the first well in early May and that the new wells will have received an initial steam injection cycle by the end of July; however, new steam generating capacity being installed at Claflin could accelerate completion of this initial steam injection work on the new wells. First oil production is anticipated from some of the new wells by June. Following first production from these new wells, there will be a 90-day evaluation period during which Tri-Valley will analyze the performance of the new wells prior to commencement of the second phase of the Claflin development to complete the remaining 14 new wells by the end of the year.
"We are ahead of schedule on our plans to develop the Claflin property to drive increased oil production in 2011," said Maston N. Cunningham, President and CEO of Tri-Valley Corporation. "Our plan calls for a total of 13 new vertical wells and nine new horizontal wells to be drilled on the property this year. If we are successful, we expect to exit 2011 with gross daily production of about 800 barrels of oil from the property."
"With the closing of our recent private placement financing, we raised nearly five million dollars in new capital that will allow us to pursue our development plans at Claflin," continued Mr. Cunningham. "We would like to welcome Ironman Energy Master Fund, an experienced oil and gas investment fund and major participant in our recent financing, as a significant new shareholder of Tri-Valley Corporation."
"Negotiations with adjacent land and mineral owners to secure permits for the 3-D seismic acquisition area for the Claflin and adjoining Brea properties have taken more time than originally planned, but we believe that seismic acquisition work should start by the end of May," added Mr. Cunningham. "This new 3-D data will useful for our exploitation plans for Claflin and Brea, including better geologic control during horizontal drilling operations later this year in the second phase of Claflin development."
Frac Plugging Op Underway at Samson's Earl Well
Frac Plugging Op Underway at Samson's Earl Well
Thursday, April 28, 2011
Samson O&G Ltd.
Samson O&G advised that operations on the Earl #1-13H to drill out the 19 frac plugs is underway. This operation, which commenced last week, has been hampered by difficult weather conditions, by the stand down of the rig crew for Easter and by equipment breakdowns. The operation is now back on track, however and the first of the nineteen plugs had been drilled as of 0700 hours CST this morning.
Prior to the first plug being drilled, the oil rate from the well for the previous 24 hours was 292 BOPD. After the first plug was drilled, the rate was measured at 960 BOPD over a two hour period, prior to commencing the drill out of the second plug. Neither of these rates is considered to be a conclusive indicator of the well's initial production performance, as this can only be determined once all of the plugs have been removed. Samson is, however, encouraged by the marked increase in the oil rate from just one of the nineteen plugs being removed.
Thursday, April 28, 2011
Samson O&G Ltd.
Samson O&G advised that operations on the Earl #1-13H to drill out the 19 frac plugs is underway. This operation, which commenced last week, has been hampered by difficult weather conditions, by the stand down of the rig crew for Easter and by equipment breakdowns. The operation is now back on track, however and the first of the nineteen plugs had been drilled as of 0700 hours CST this morning.
Prior to the first plug being drilled, the oil rate from the well for the previous 24 hours was 292 BOPD. After the first plug was drilled, the rate was measured at 960 BOPD over a two hour period, prior to commencing the drill out of the second plug. Neither of these rates is considered to be a conclusive indicator of the well's initial production performance, as this can only be determined once all of the plugs have been removed. Samson is, however, encouraged by the marked increase in the oil rate from just one of the nineteen plugs being removed.
Mideast Oil Recovery Enters A New Phase
Mideast Oil Recovery Enters A New Phase
Thursday, April 28, 2011
Dow Jones Newswires
by Angus McDowall & Oliver Klaus
It has always been an axiom of world energy markets that Persian Gulf oil is both easy and cheap to produce.
The crude that gushes from the scorching desert sands of Saudi Arabia, for example, is widely thought to cost less than $5 a barrel to produce, compared to the $70 price tag on raising a barrel from deep Atlantic waters.
But many of the Persian Gulf oilfields have been producing for decades, and an increasing number of the newer fields in the region contain heavier and harder-to-extract crudes. Squeezing out the remaining reserves from some existing fields and developing new, more complicated ones will be costlier and will require more advanced technology, according to analysts and oilfield engineers.
As a result, more Gulf countries are exploring the use of enhanced oil recovery, or EOR, a collection of technologies that coaxes substantially more oil from the ground by injecting steam, gas and chemicals deep below the surface.
"The Middle East countries have varying levels of maturity in their fields," said Chris Graham, a Middle East analyst at Edinburgh-based oil consultancy Wood Mackenzie. While the major OPEC producers in the region mostly don't need to use EOR techniques, the situation is different for the smaller non-OPEC producers such as Oman and Bahrain. In those countries, "you've got maturing production profiles and each barrel becomes more difficult and more costly to extract," Graham said.
And even the large OPEC producers such as Kuwait have started to turn to EOR technology as they seek to develop new, more complex, heavy-crude reservoirs on which they will have to rely for future production growth. EOR tends to be needed most when oil is heavy--sometimes as thick as asphalt--and only flows when it is melted with steam, as is the case in some of Kuwait's yet-to-be-developed fields.
"EOR will become over the years an important component of what the industry collectively has to develop," said Jean-Luc Guizion, president of exploration and production at Total. "The luck of the Middle East countries is they have a lot of resources so they have ample time to plan the necessary EOR improvement."
According to technicians at one company with EOR operations, the methods can improve recovery rates in some fields by 40%, but at an additional cost of anywhere between $20 and $60 per barrel of oil.
In the so-called Partitioned Neutral Zone, shared between Saudi Arabia and Kuwait, Chevron is involved in an EOR scheme aimed at developing heavier crudes using steamflooding. Abu Dhabi Co. for Onshore Oil Exploration is working on an EOR project involving carbon dioxide injection. And Saudi Aramco is working on plans to implement a CO2 EOR demonstration plant in the next two years, although this project is, for now, aimed at trapping emissions rather than boosting recovery rates.
EOR techniques have been in use since the 1970s, when they mostly involved injecting seawater into reservoirs in order to maintain pressure and squeeze more oil from the porous, sponge-like rock where it is deposited. Now there's a far more diverse range of techniques on offer and experts say that each field requires its own mix of EOR techniques that can only be determined by complex analysis of field conditions and economics.
In the ancient and complex Marmul block in Oman, for instance, the oil is heavy and viscous. To improve the mix of oil and water in the field, the operating company, Petroleum Development Oman, which is 34% owned by Shell, injected polymer into the reservoir, allowing the crude to flow more freely and improving recovery by 10%.
Bahrain's energy minister Abdul Hussain bin Ali Mirza says his country's aging Bahrain field--where EOR boosted output from an average of 29,000 barrels a day to a level of 40,000 barrels a day within a year--will see output hit 100,000 barrels a day within seven years.
However, while Middle East producers are starting to take a closer look at EOR, many are handicapped by the reliance of the technology on gas, which is sometimes used as an injectant and sometimes burned to generate another common injectant, steam. Despite massive reserves in countries like Qatar, natural gas is in short supply in most other countries in the region due to its increased usage in power generation and in industries such as petrochemicals.
Accordingly, there is a new focus on alternative technology solutions, including the use of solar power to generate steam for injecting into oilfields.
One such new technology has been developed by Glasspoint, a U.S.-based company that says it can generate steam using the sun's heat at lower cost than by burning gas. It locates the solar installations inside large commercial greenhouses, which protect the delicate panels from harsh desert winds, according to Rod MacGregor, the company's chief executive.
Thursday, April 28, 2011
Dow Jones Newswires
by Angus McDowall & Oliver Klaus
It has always been an axiom of world energy markets that Persian Gulf oil is both easy and cheap to produce.
The crude that gushes from the scorching desert sands of Saudi Arabia, for example, is widely thought to cost less than $5 a barrel to produce, compared to the $70 price tag on raising a barrel from deep Atlantic waters.
But many of the Persian Gulf oilfields have been producing for decades, and an increasing number of the newer fields in the region contain heavier and harder-to-extract crudes. Squeezing out the remaining reserves from some existing fields and developing new, more complicated ones will be costlier and will require more advanced technology, according to analysts and oilfield engineers.
As a result, more Gulf countries are exploring the use of enhanced oil recovery, or EOR, a collection of technologies that coaxes substantially more oil from the ground by injecting steam, gas and chemicals deep below the surface.
"The Middle East countries have varying levels of maturity in their fields," said Chris Graham, a Middle East analyst at Edinburgh-based oil consultancy Wood Mackenzie. While the major OPEC producers in the region mostly don't need to use EOR techniques, the situation is different for the smaller non-OPEC producers such as Oman and Bahrain. In those countries, "you've got maturing production profiles and each barrel becomes more difficult and more costly to extract," Graham said.
And even the large OPEC producers such as Kuwait have started to turn to EOR technology as they seek to develop new, more complex, heavy-crude reservoirs on which they will have to rely for future production growth. EOR tends to be needed most when oil is heavy--sometimes as thick as asphalt--and only flows when it is melted with steam, as is the case in some of Kuwait's yet-to-be-developed fields.
"EOR will become over the years an important component of what the industry collectively has to develop," said Jean-Luc Guizion, president of exploration and production at Total. "The luck of the Middle East countries is they have a lot of resources so they have ample time to plan the necessary EOR improvement."
According to technicians at one company with EOR operations, the methods can improve recovery rates in some fields by 40%, but at an additional cost of anywhere between $20 and $60 per barrel of oil.
In the so-called Partitioned Neutral Zone, shared between Saudi Arabia and Kuwait, Chevron is involved in an EOR scheme aimed at developing heavier crudes using steamflooding. Abu Dhabi Co. for Onshore Oil Exploration is working on an EOR project involving carbon dioxide injection. And Saudi Aramco is working on plans to implement a CO2 EOR demonstration plant in the next two years, although this project is, for now, aimed at trapping emissions rather than boosting recovery rates.
EOR techniques have been in use since the 1970s, when they mostly involved injecting seawater into reservoirs in order to maintain pressure and squeeze more oil from the porous, sponge-like rock where it is deposited. Now there's a far more diverse range of techniques on offer and experts say that each field requires its own mix of EOR techniques that can only be determined by complex analysis of field conditions and economics.
In the ancient and complex Marmul block in Oman, for instance, the oil is heavy and viscous. To improve the mix of oil and water in the field, the operating company, Petroleum Development Oman, which is 34% owned by Shell, injected polymer into the reservoir, allowing the crude to flow more freely and improving recovery by 10%.
Bahrain's energy minister Abdul Hussain bin Ali Mirza says his country's aging Bahrain field--where EOR boosted output from an average of 29,000 barrels a day to a level of 40,000 barrels a day within a year--will see output hit 100,000 barrels a day within seven years.
However, while Middle East producers are starting to take a closer look at EOR, many are handicapped by the reliance of the technology on gas, which is sometimes used as an injectant and sometimes burned to generate another common injectant, steam. Despite massive reserves in countries like Qatar, natural gas is in short supply in most other countries in the region due to its increased usage in power generation and in industries such as petrochemicals.
Accordingly, there is a new focus on alternative technology solutions, including the use of solar power to generate steam for injecting into oilfields.
One such new technology has been developed by Glasspoint, a U.S.-based company that says it can generate steam using the sun's heat at lower cost than by burning gas. It locates the solar installations inside large commercial greenhouses, which protect the delicate panels from harsh desert winds, according to Rod MacGregor, the company's chief executive.
Otto Drills Ahead at Duhat Well
Otto Drills Ahead at Duhat Well
Otto provided the following update on the progress of the Duhat-1 well that was spudded on April 19, 2011. The well has been drilled to 205m TVD (True Vertical Depth) and 13 3/8" casing has been set and cemented. Current operations are pressure testing the Blow Out Preventer and installing flare lines prior to drilling ahead in 12 ¼" hole.
Performance of both the rig and mud system has been satisfactory with the well being on track to reach TD (Total Depth) as programmed.
Otto provided the following update on the progress of the Duhat-1 well that was spudded on April 19, 2011. The well has been drilled to 205m TVD (True Vertical Depth) and 13 3/8" casing has been set and cemented. Current operations are pressure testing the Blow Out Preventer and installing flare lines prior to drilling ahead in 12 ¼" hole.
Performance of both the rig and mud system has been satisfactory with the well being on track to reach TD (Total Depth) as programmed.
Apache Boosts 1Q Production by 25%
Apache Boosts 1Q Production by 25%
Thursday, April 28, 2011
Apache Corp.
Apache reported production of 732,000 barrels of oil equivalent (boe) per day and earnings of $1.1 billion, or $2.86 per diluted share, for the three-month period ending March 31, 2011. These compare with production of 586,000 boe per day and net income of $705 million, or $2.08 per diluted share, for the same period in the prior year.
"Apache is beginning the year with a solid, strong performance," said G. Steven Farris, chairman and chief executive officer. "Despite a number of challenges, our diversified portfolio of assets delivered exceptional earnings and operating results. Liquids production increased 57,000 barrels to 358,000 barrels per day, which enabled Apache to achieve stand-out earnings and cash flow as a leading beneficiary of rising oil prices."
Higher oil prices and production from new wells drilled during the quarter and assets acquired during 2010 combined to increase revenues to $3.9 billion, up from $2.7 billion last year. Cash from operations before changes in operating assets and liabilities* increased 43 percent from the prior year to $2.2 billion. Excluding certain items that management believes affect the comparability of operating results, Apache reported adjusted earnings* of $1.1 billion in first quarter 2011 compared with $712 million in the year-earlier period. On a per-share basis, adjusted earnings were $2.90 in the first quarter compared with $2.10 per diluted share in the prior-year period.
Liquid hydrocarbons represented 49 percent of production and 77 percent of revenues. Approximately 60 percent of the company's oil production came from operations outside North America and received in excess of a $10 premium per barrel compared with domestic production benchmarked to West Texas Intermediate prices.
On the operational front, the company achieved several milestones. These include:
"We continue to strengthen our land position, both in North America and internationally. Our LNG initiatives, Kitimat in Canada and Wheatstone in Australia, are steadily progressing toward project sanction with their respective joint venture partnerships," Farris said.
"Apache's opportunity set has never been more robust. We have a deep backlog of exploitation opportunities across our portfolio. In addition to our legacy plays in core areas, we have other potentially large-scale, long-life assets such as deepwater, LNG, and unconventional plays that can provide lasting, long-term value to our shareholders."
Thursday, April 28, 2011
Apache Corp.
Apache reported production of 732,000 barrels of oil equivalent (boe) per day and earnings of $1.1 billion, or $2.86 per diluted share, for the three-month period ending March 31, 2011. These compare with production of 586,000 boe per day and net income of $705 million, or $2.08 per diluted share, for the same period in the prior year.
"Apache is beginning the year with a solid, strong performance," said G. Steven Farris, chairman and chief executive officer. "Despite a number of challenges, our diversified portfolio of assets delivered exceptional earnings and operating results. Liquids production increased 57,000 barrels to 358,000 barrels per day, which enabled Apache to achieve stand-out earnings and cash flow as a leading beneficiary of rising oil prices."
Higher oil prices and production from new wells drilled during the quarter and assets acquired during 2010 combined to increase revenues to $3.9 billion, up from $2.7 billion last year. Cash from operations before changes in operating assets and liabilities* increased 43 percent from the prior year to $2.2 billion. Excluding certain items that management believes affect the comparability of operating results, Apache reported adjusted earnings* of $1.1 billion in first quarter 2011 compared with $712 million in the year-earlier period. On a per-share basis, adjusted earnings were $2.90 in the first quarter compared with $2.10 per diluted share in the prior-year period.
Liquid hydrocarbons represented 49 percent of production and 77 percent of revenues. Approximately 60 percent of the company's oil production came from operations outside North America and received in excess of a $10 premium per barrel compared with domestic production benchmarked to West Texas Intermediate prices.
On the operational front, the company achieved several milestones. These include:
- Apache's most prolific development well in the Forties field (North Sea), which came online at approximately 11,800 barrels of oil per day.
- In the Permian Basin, Apache is operating 24 rigs, up nearly five-fold from a year ago. Targeting primarily oil objectives, Apache drilled 110 wells including 15 horizontals during the first quarter.
- Since drilling the first-ever horizontal Hogshooter well last year, Apache has drilled six wells into this oil-rich segment of the Anadarko basin's Granite Wash formation. To date, every well has tested in excess of 1,000 barrels of oil and 2 million cubic feet of gas per day.
- The company's first operated deepwater production in the Gulf of Mexico with start-up at the Balboa field.
- Offshore Australia, Apache's Zola discovery well encountered 410 feet of net gas pay.
- In Egypt, Apache operated 22 rigs during the quarter, drilling 33 wells, including the company's first wells in the Tayim development lease in West Kalabsha producing from deeper Paleozoic pay. Apache's production remained online throughout the quarter, increasing sequentially from the previous three months.
"We continue to strengthen our land position, both in North America and internationally. Our LNG initiatives, Kitimat in Canada and Wheatstone in Australia, are steadily progressing toward project sanction with their respective joint venture partnerships," Farris said.
"Apache's opportunity set has never been more robust. We have a deep backlog of exploitation opportunities across our portfolio. In addition to our legacy plays in core areas, we have other potentially large-scale, long-life assets such as deepwater, LNG, and unconventional plays that can provide lasting, long-term value to our shareholders."
President Petroleum Updates AU Ops
President Petroleum Updates AU Ops
Thursday, April 28, 2011
President Petroleum Co. plc
President Petroleum provided the following operational update.
Australia
The Northumberland 2 well was a wild cat, high risk well. As such the results themselves while not showing commercial quantities of hydrocarbons are not seen by President as negative for the whole of the PEL 82 License nor a depletion of potential value of that License.
To the contrary, the results are both intriguing and encouraging and President continues to analyze the data.
Louisiana
President is now taking steps to optimize the potential of its existing production base.
Positive production performance is now being achieved with an increased weighting of oil to gas as a result of East White Lake acquisition in 2010.
In this regard:
Peter Levine, Chairman of President Petroleum Company Holdings BV commented, "The recent drilling in Australia highlighted the overall potential of PEL 82 and it would be premature to ignore the prospective value of this Block at this stage. For a first well on an unexplored license the results were encouraging. Detailed analysis work continues and we will update investors in due course on our forward plans for PEL 82.
"The Group remains committed to using its strong cash position to achieve growth by acquisition, particularly of production or near production opportunities with material upside both on reserves and production itself.
"Active steps are also being taken to make the most of production upgrading and opportunities in our existing licenses and elsewhere. The substantial tax losses will now be utilized as a tool to increase the bottom line benefit.
"Both myself and the main Board are committed to generate significant growth from our solid base."
Thursday, April 28, 2011
President Petroleum Co. plc
President Petroleum provided the following operational update.
Australia
The Northumberland 2 well was a wild cat, high risk well. As such the results themselves while not showing commercial quantities of hydrocarbons are not seen by President as negative for the whole of the PEL 82 License nor a depletion of potential value of that License.
To the contrary, the results are both intriguing and encouraging and President continues to analyze the data.
Louisiana
President is now taking steps to optimize the potential of its existing production base.
Positive production performance is now being achieved with an increased weighting of oil to gas as a result of East White Lake acquisition in 2010.
In this regard:
- First of scheduled Proven Undeveloped ("PUD") opportunities increased oil production by 30%
- Five further PUD opportunities have been identified collectively having the potential to materially increase production, and improve the bias to oil (over 50%)
- Drilling of the first PUD has already commenced with up to four others due to commence sequentially over the next six months
- Initial capital costs not material to substantial cash balances of PPC; average payback for each PUD is estimated at six months; will not impair PPC ability to pursue acquisitions
- Majority of targets have long production profiles
- NPV per barrel on the oil wells are estimated to be some $45 on an oil price of $100 WTI, a significantly higher value than previously expected
- President is currently enjoying very beneficial relief from severance tax on some of its Louisiana production
- The Company's substantial tax losses in Louisiana will not only shield the Group from corporate tax but allows the Group to consider acquisition of low risk production opportunities which can be exploited with greater bottom line impact
Peter Levine, Chairman of President Petroleum Company Holdings BV commented, "The recent drilling in Australia highlighted the overall potential of PEL 82 and it would be premature to ignore the prospective value of this Block at this stage. For a first well on an unexplored license the results were encouraging. Detailed analysis work continues and we will update investors in due course on our forward plans for PEL 82.
"The Group remains committed to using its strong cash position to achieve growth by acquisition, particularly of production or near production opportunities with material upside both on reserves and production itself.
"Active steps are also being taken to make the most of production upgrading and opportunities in our existing licenses and elsewhere. The substantial tax losses will now be utilized as a tool to increase the bottom line benefit.
"Both myself and the main Board are committed to generate significant growth from our solid base."
Exxon Reports Strong Q1, Beats EPS By $0.08, Revs Slight Miss
Exxon Reports Strong Q1, Beats EPS By $0.08, Revs Slight Miss
Apr 28, 2011
Exxon Mobil (NYSE:XOM) reported EPS of $2.14 today, beating the consensus estimate for $2.06 per share. Revenue for the quarter was up 26% year-over-year to $114.00 billion, but fell short of the consensus estimate for $114.85 billion.
Apr 28, 2011
Exxon Mobil (NYSE:XOM) reported EPS of $2.14 today, beating the consensus estimate for $2.06 per share. Revenue for the quarter was up 26% year-over-year to $114.00 billion, but fell short of the consensus estimate for $114.85 billion.
Sterling Declares Force Majeure at Black Sea Blocks
Sterling Declares Force Majeure at Black Sea Blocks
Thursday, April 28, 2011
Sterling Resources Ltd.
Sterling Resources has declared Force Majeure on its Midia and Pelican Blocks in the Black Sea after the Company has been unable to undertake Petroleum operations for reasons outside of its control.
In early 2011, after extensive and lengthy efforts, the Company finally obtained from the relevant Governmental authorities the environmental and drilling permits necessary for operations on the Midia and Pelican Blocks. The National Agency of Mineral Resources ("NAMR") has given approval to a 2011 work program based on which Sterling is obligated to undertake certain offshore activities which include the drilling of 2 offshore wells, acquiring 1,050 linear kilometers of 2D seismic and undertaking investigations and studies to bring the Ana and Doina discoveries forward for development.
However, in July 2009 the Romanian Parliament passed a law requiring construction permits for certain offshore activities. Sterling has sought clarification of this requirement from relevant authorities, as the activities contemplated under the 2011 work program clearly appear to have aspects that will require a construction permit. It is Sterling's view that, after having received responses from certain relevant governmental authorities, that the authorities are currently unable or unwilling to provide construction permits for offshore oil and gas activities.
The effect of this situation, which the Company views as political in nature, is to render it impossible for the Company to undertake Petroleum Operations at the present time. Sterling has thus issued a notice to NAMR, stating that the total lack of clarity on the applicable procedure and authority for issuance of construction permits constitutes an event of Force Majeure under the Concession Agreement.
Under the terms of the Concession Agreement NAMR must, within 15 days of this notification, either agree with the invocation of Force Majeure, the effect of which would be to extend the duration of the Concession Agreement, or reject the Company's invocation putting the two parties into a dispute resolution procedure which could ultimately be decided in international arbitration.
Mike Azancot, Sterling's Chief Executive Officer, said, "Despite this unfortunate situation we look forward to working with the NAMR and other Romanian authorities to find a resolution that will allow the Company to fulfill its obligations, preserve its rights and ultimately achieve success for the Company and the people of Romania. With a satisfactory resolution achieved, we are hopeful that we can advance our plans to undertake further exploration on these very prospective blocks and bring Ana and Doina to production within 3 years. This will bring significant benefits to Romania in terms of greater energy self-sufficiency, the likely award of construction and oil service contracts to local companies, and encouraging a wide range of companies to explore offshore Romania."
Thursday, April 28, 2011
Sterling Resources Ltd.
Sterling Resources has declared Force Majeure on its Midia and Pelican Blocks in the Black Sea after the Company has been unable to undertake Petroleum operations for reasons outside of its control.
In early 2011, after extensive and lengthy efforts, the Company finally obtained from the relevant Governmental authorities the environmental and drilling permits necessary for operations on the Midia and Pelican Blocks. The National Agency of Mineral Resources ("NAMR") has given approval to a 2011 work program based on which Sterling is obligated to undertake certain offshore activities which include the drilling of 2 offshore wells, acquiring 1,050 linear kilometers of 2D seismic and undertaking investigations and studies to bring the Ana and Doina discoveries forward for development.
However, in July 2009 the Romanian Parliament passed a law requiring construction permits for certain offshore activities. Sterling has sought clarification of this requirement from relevant authorities, as the activities contemplated under the 2011 work program clearly appear to have aspects that will require a construction permit. It is Sterling's view that, after having received responses from certain relevant governmental authorities, that the authorities are currently unable or unwilling to provide construction permits for offshore oil and gas activities.
The effect of this situation, which the Company views as political in nature, is to render it impossible for the Company to undertake Petroleum Operations at the present time. Sterling has thus issued a notice to NAMR, stating that the total lack of clarity on the applicable procedure and authority for issuance of construction permits constitutes an event of Force Majeure under the Concession Agreement.
Under the terms of the Concession Agreement NAMR must, within 15 days of this notification, either agree with the invocation of Force Majeure, the effect of which would be to extend the duration of the Concession Agreement, or reject the Company's invocation putting the two parties into a dispute resolution procedure which could ultimately be decided in international arbitration.
Mike Azancot, Sterling's Chief Executive Officer, said, "Despite this unfortunate situation we look forward to working with the NAMR and other Romanian authorities to find a resolution that will allow the Company to fulfill its obligations, preserve its rights and ultimately achieve success for the Company and the people of Romania. With a satisfactory resolution achieved, we are hopeful that we can advance our plans to undertake further exploration on these very prospective blocks and bring Ana and Doina to production within 3 years. This will bring significant benefits to Romania in terms of greater energy self-sufficiency, the likely award of construction and oil service contracts to local companies, and encouraging a wide range of companies to explore offshore Romania."
Petroceltic Sells Stake in Isarene Block
Petroceltic Sells Stake in Isarene Block
Thursday, April 28, 2011
Petroceltic International Inc.
Petroceltic announced the sale, subject to the satisfaction of certain conditions, of an 18.375% interest in the Isarene Production Sharing Contract ("PSC"), which includes the world class Ain Tsila gas condensate discovery, onshore Algeria, to ENEL Trade S.p.A. ("ENEL"), a fully owned subsidiary of ENEL.
The assignment is to be effected by way of a sale and purchase agreement under which, ENEL has agreed to acquire an 18.375% interest in the rights, benefits and liabilities of the PSC for the Isarene perimeter (Blocks 228 and 229a). The PSC was signed between Petroceltic and the Algerian National Company for Hydrocarbons ("Sonatrach") in April 2005.
Under the terms of the agreement ENEL has:
On completion of the appraisal drilling program, or if the agreed budget limits are exceeded, Petroceltic and ENEL will fund any additional costs relating to the PSC in proportion to their participating interests.
ENEL is Italy's largest power producer, and the second largest electrical utility company in Europe by installed capacity. Enel is Sonatrach's main end-user customer of Algerian gas, as well as a partner in both the Medgaz and the Galsi trans Mediterranean pipelines, the former in operation since early 2011 with a nominal capacity of 8 BCM of gas per year and the latter, still under development, with a planned capacity on completion of 8 BCM of gas per year. Both of these developments have been undertaken to facilitate increased Algerian gas pipeline exports to Southern Europe.
This assignment has been submitted for approval to Sonatrach which is a 25% partner in the PSC, and is also subject to the usual approvals by the Algerian regulatory authorities. Upon completion of the sale, ENEL will hold an 18.375% participating interest in the PSC, Petroceltic will hold 56.625% and Sonatrach will hold the remaining 25%. Petroceltic will continue as Operator for the permit.
Brian O'Cathain, Chief Executive of Petroceltic, commented, "We are delighted to have ENEL joining us in the Isarene Block in Algeria. ENEL is a well-established partner of Sonatrach, and their unparalleled knowledge of European gas markets will greatly enhance our ability to bring the Isarene gas to market. This transaction is a strong endorsement of the quality of the Isarene asset and an important financial support to our ongoing appraisal campaign and future development planning. We look forward to a long and fruitful partnership with ENEL and Sonatrach."
Thursday, April 28, 2011
Petroceltic International Inc.
Petroceltic announced the sale, subject to the satisfaction of certain conditions, of an 18.375% interest in the Isarene Production Sharing Contract ("PSC"), which includes the world class Ain Tsila gas condensate discovery, onshore Algeria, to ENEL Trade S.p.A. ("ENEL"), a fully owned subsidiary of ENEL.
The assignment is to be effected by way of a sale and purchase agreement under which, ENEL has agreed to acquire an 18.375% interest in the rights, benefits and liabilities of the PSC for the Isarene perimeter (Blocks 228 and 229a). The PSC was signed between Petroceltic and the Algerian National Company for Hydrocarbons ("Sonatrach") in April 2005.
Under the terms of the agreement ENEL has:
- Agreed to pay up to US $36.75 million to Petroceltic, which equates to 24.5% of all back costs incurred from signing of the PSC in 2005 until the end of the exploration period in April 2010.
- Committed to fund 49% of the cost of the first six appraisal wells in an enlarged Isarene appraisal campaign (including AT-4 which has been completed and the second well of the campaign, AT-5, currently drilling the horizontal section) and of a contingent additional well, which costs are capped, in aggregate, at US $145 million.
- Agreed to pay Petroceltic a contingent cash consideration, up to a maximum of US $75 million, determined by the level of recoverable hydrocarbon reserves approved by the Algerian Authorities in the Final Discovery Report, which is expected to be submitted by the parties in early 2012.
On completion of the appraisal drilling program, or if the agreed budget limits are exceeded, Petroceltic and ENEL will fund any additional costs relating to the PSC in proportion to their participating interests.
ENEL is Italy's largest power producer, and the second largest electrical utility company in Europe by installed capacity. Enel is Sonatrach's main end-user customer of Algerian gas, as well as a partner in both the Medgaz and the Galsi trans Mediterranean pipelines, the former in operation since early 2011 with a nominal capacity of 8 BCM of gas per year and the latter, still under development, with a planned capacity on completion of 8 BCM of gas per year. Both of these developments have been undertaken to facilitate increased Algerian gas pipeline exports to Southern Europe.
This assignment has been submitted for approval to Sonatrach which is a 25% partner in the PSC, and is also subject to the usual approvals by the Algerian regulatory authorities. Upon completion of the sale, ENEL will hold an 18.375% participating interest in the PSC, Petroceltic will hold 56.625% and Sonatrach will hold the remaining 25%. Petroceltic will continue as Operator for the permit.
Brian O'Cathain, Chief Executive of Petroceltic, commented, "We are delighted to have ENEL joining us in the Isarene Block in Algeria. ENEL is a well-established partner of Sonatrach, and their unparalleled knowledge of European gas markets will greatly enhance our ability to bring the Isarene gas to market. This transaction is a strong endorsement of the quality of the Isarene asset and an important financial support to our ongoing appraisal campaign and future development planning. We look forward to a long and fruitful partnership with ENEL and Sonatrach."
Drilling Recommenced at Petro Matad's Davsan Tolgoi Well
Drilling Recommenced at Petro Matad's Davsan Tolgoi Well
Thursday, April 28, 2011
Petro Matad Ltd.
Petro Matad announced that drilling operations at the Company's Davsan Tolgoi-4 well ("DT-4") have recommenced following the winter shut down.
In early December 2010 the Company suspended the drilling of the DT-4 at a depth of 1,271 meters and an orderly shutdown and hibernation was successfully carried out. In the last few weeks the Company and its drilling contractor, DQE International, have been undertaking preparatory work including the reinstatement of the drilling team and operational camp.
As previously announced the rig remained on-site throughout the winter months, it has now been re-commissioned, serviced and tested and is currently working on cleaning out the hole ahead of further drilling. Night time temperatures are still below zero, but 24 hour operations are anticipated to commence tomorrow and drilling towards the target depth of 2,020 meters is scheduled to recommence over the weekend.
Thursday, April 28, 2011
Petro Matad Ltd.
Petro Matad announced that drilling operations at the Company's Davsan Tolgoi-4 well ("DT-4") have recommenced following the winter shut down.
In early December 2010 the Company suspended the drilling of the DT-4 at a depth of 1,271 meters and an orderly shutdown and hibernation was successfully carried out. In the last few weeks the Company and its drilling contractor, DQE International, have been undertaking preparatory work including the reinstatement of the drilling team and operational camp.
As previously announced the rig remained on-site throughout the winter months, it has now been re-commissioned, serviced and tested and is currently working on cleaning out the hole ahead of further drilling. Night time temperatures are still below zero, but 24 hour operations are anticipated to commence tomorrow and drilling towards the target depth of 2,020 meters is scheduled to recommence over the weekend.
Noble Energy 1Q Earnings Fall on Charges
Noble Energy 1Q Earnings Fall on Charges
Thursday, April 28, 2011
Noble Energy Inc.
Noble reported first quarter 2011 net income of $14 million, or $0.08 per share diluted, on revenues of $899 million. The Company's first quarter 2010 net income was $237 million, or $1.34 per share diluted, on revenues of $733 million. First quarter 2011 net income includes items that are not typically considered by analysts in published estimates. Excluding the impact of these items, which were primarily unrealized commodity derivative losses and a rig standby charge in the deepwater Gulf of Mexico, first quarter 2011 adjusted net income was $240 million, or $1.35 per share diluted. Adjusted net income for the first quarter of 2010 was $138 million, or $0.78 per share diluted.
Discretionary cash flow for the first quarter 2011 was $576 million, compared to $447 million for the similar quarter in 2010. Net cash provided by operating activities was $484 million, and capital expenditures were $545 million.
Key highlights for the first quarter 2011 include:
Charles D. Davidson, Noble Energy's Chairman and CEO, commented, "Noble Energy's first quarter has delivered a great start to 2011. With high liquid volumes and pricing, combined with good cost control, the business generated very strong cash flow. Our balance sheet was further fortified with a successful debt offering, and as a result, the Company is in a very strong position. Operationally, we remain focused on delivering production and cash flow growth from our base of discovered resources and major project developments. We are excited to have active investment programs ongoing in all four of our core areas, including development of our major projects, as well as exploration, appraisal, and development drilling underway throughout our global portfolio."
Total sales volumes for the first quarter 2011 averaged 215 MBoe/d. Approximately 40 percent of the Company's sales volumes were liquids, with 31 percent international natural gas, and the remainder U.S. natural gas. Production volumes were 216 MBoe/d.
The Company's international sales volumes were 101 MBoe/d, a 25 percent increase versus the first quarter 2010. Lower facility maintenance downtime and higher liquid liftings in Equatorial Guinea resulted in a 15 MBoe/d increase. Natural gas sales in Israel were up 61 percent to 140 million cubic feet per day (MMcf/d), with the higher volumes attributable to increased overall demand for natural gas in power generation, as well as the impact of lower competing imports. In the North Sea, strong performance and additional deliverability at Dumbarton and Lochranza accounted for increased oil volumes. The Company's 2010 volumes included 30 MMcf/d of natural gas in Ecuador, where the Company's production sharing contract was terminated in late 2010.
Noble Energy's U.S. volumes were 114 MBoe/d for the first quarter of 2011. Winter storms reduced the Company's onshore U.S. volumes in the first quarter 2011 by nearly 2 MBoe/d on average. In addition, U.S. volumes do not include the approximately 6 MBoe/d of Mid-continent and Illinois basin oil assets which were sold in the third quarter 2010. In the DJ basin, first quarter 2011 volumes averaged over 56 MBoe/d, up 12 percent from the first quarter 2010. The increase is primarily attributed to ongoing vertical and horizontal drilling at Wattenberg, as well as the impact of the asset acquisition that closed in the first quarter last year. The Company experienced natural declines in various onshore natural gas plays and the deepwater Gulf of Mexico versus the first quarter last year.
Global crude oil pricing averaged $97.15 per barrel for the first quarter 2011, up 31 percent from the same period last year. Natural gas realizations in the U.S. averaged $4.07 per thousand cubic feet (Mcf), down from $5.46 per Mcf in the first quarter 2010. In Israel, natural gas realizations continue to benefit from strong global liquid markets, with pricing averaging $4.19 per Mcf. Natural gas liquid pricing in the U.S. averaged $47.80 per barrel, or 52 percent of the Company's average U.S. crude oil realization.
Total production costs per barrel of oil equivalent (Boe), including lease operating expenses, production and ad valorem taxes, and transportation were down 6 percent from the first quarter of 2010 to $7.34 per Boe. Lease operating expense was $4.75 per Boe and depreciation, depletion, and amortization was $11.42 per Boe. The Company's mix of production, with higher volumes in low-cost areas such as Equatorial Guinea and Israel, contributed to lower per unit rates versus the first quarter last year.
Exploration expense for the first quarter 2011 included $26 million of seismic expenditures, including data acquisitions in the DJ basin, offshore Nicaragua and offshore France. General and administrative expenses were up primarily related to increased staffing for the development of the Company's major development projects. The Company's adjusted effective tax rate and deferred portion were both 34 percent for the first quarter 2011.
Other operating income/expense includes an $18 million rig standby charge incurred as a result of the time required to obtain deepwater Gulf of Mexico drilling permits post the moratorium. Included in other income/expense for the first quarter 2011 is a $10 million deferred compensation charge relating to the quarterly value change of Noble Energy stock held in a benefit program.
Thursday, April 28, 2011
Noble Energy Inc.
Noble reported first quarter 2011 net income of $14 million, or $0.08 per share diluted, on revenues of $899 million. The Company's first quarter 2010 net income was $237 million, or $1.34 per share diluted, on revenues of $733 million. First quarter 2011 net income includes items that are not typically considered by analysts in published estimates. Excluding the impact of these items, which were primarily unrealized commodity derivative losses and a rig standby charge in the deepwater Gulf of Mexico, first quarter 2011 adjusted net income was $240 million, or $1.35 per share diluted. Adjusted net income for the first quarter of 2010 was $138 million, or $0.78 per share diluted.
Discretionary cash flow for the first quarter 2011 was $576 million, compared to $447 million for the similar quarter in 2010. Net cash provided by operating activities was $484 million, and capital expenditures were $545 million.
Key highlights for the first quarter 2011 include:
- Increased sales volumes 9 percent versus the first quarter 2010 to 215 thousand barrels of oil equivalent per day (MBoe/d)
- Drilled 12 additional horizontal Niobrara wells in the DJ basin, 9 of which were located in the Wattenberg field
- Received industry's first drilling permit post-moratorium to resume deepwater Gulf of Mexico drilling at the Santiago prospect
- Finalized field development drilling and well completions at the Aseng oil project offshore Equatorial Guinea
- Completed seismic acquisition of 3D data offshore Nicaragua and 2D data offshore France
- Issued $850 million of 30-year unsecured notes and enhanced liquidity position to over $3.5 billion between cash and available credit
Charles D. Davidson, Noble Energy's Chairman and CEO, commented, "Noble Energy's first quarter has delivered a great start to 2011. With high liquid volumes and pricing, combined with good cost control, the business generated very strong cash flow. Our balance sheet was further fortified with a successful debt offering, and as a result, the Company is in a very strong position. Operationally, we remain focused on delivering production and cash flow growth from our base of discovered resources and major project developments. We are excited to have active investment programs ongoing in all four of our core areas, including development of our major projects, as well as exploration, appraisal, and development drilling underway throughout our global portfolio."
Total sales volumes for the first quarter 2011 averaged 215 MBoe/d. Approximately 40 percent of the Company's sales volumes were liquids, with 31 percent international natural gas, and the remainder U.S. natural gas. Production volumes were 216 MBoe/d.
The Company's international sales volumes were 101 MBoe/d, a 25 percent increase versus the first quarter 2010. Lower facility maintenance downtime and higher liquid liftings in Equatorial Guinea resulted in a 15 MBoe/d increase. Natural gas sales in Israel were up 61 percent to 140 million cubic feet per day (MMcf/d), with the higher volumes attributable to increased overall demand for natural gas in power generation, as well as the impact of lower competing imports. In the North Sea, strong performance and additional deliverability at Dumbarton and Lochranza accounted for increased oil volumes. The Company's 2010 volumes included 30 MMcf/d of natural gas in Ecuador, where the Company's production sharing contract was terminated in late 2010.
Noble Energy's U.S. volumes were 114 MBoe/d for the first quarter of 2011. Winter storms reduced the Company's onshore U.S. volumes in the first quarter 2011 by nearly 2 MBoe/d on average. In addition, U.S. volumes do not include the approximately 6 MBoe/d of Mid-continent and Illinois basin oil assets which were sold in the third quarter 2010. In the DJ basin, first quarter 2011 volumes averaged over 56 MBoe/d, up 12 percent from the first quarter 2010. The increase is primarily attributed to ongoing vertical and horizontal drilling at Wattenberg, as well as the impact of the asset acquisition that closed in the first quarter last year. The Company experienced natural declines in various onshore natural gas plays and the deepwater Gulf of Mexico versus the first quarter last year.
Global crude oil pricing averaged $97.15 per barrel for the first quarter 2011, up 31 percent from the same period last year. Natural gas realizations in the U.S. averaged $4.07 per thousand cubic feet (Mcf), down from $5.46 per Mcf in the first quarter 2010. In Israel, natural gas realizations continue to benefit from strong global liquid markets, with pricing averaging $4.19 per Mcf. Natural gas liquid pricing in the U.S. averaged $47.80 per barrel, or 52 percent of the Company's average U.S. crude oil realization.
Total production costs per barrel of oil equivalent (Boe), including lease operating expenses, production and ad valorem taxes, and transportation were down 6 percent from the first quarter of 2010 to $7.34 per Boe. Lease operating expense was $4.75 per Boe and depreciation, depletion, and amortization was $11.42 per Boe. The Company's mix of production, with higher volumes in low-cost areas such as Equatorial Guinea and Israel, contributed to lower per unit rates versus the first quarter last year.
Exploration expense for the first quarter 2011 included $26 million of seismic expenditures, including data acquisitions in the DJ basin, offshore Nicaragua and offshore France. General and administrative expenses were up primarily related to increased staffing for the development of the Company's major development projects. The Company's adjusted effective tax rate and deferred portion were both 34 percent for the first quarter 2011.
Other operating income/expense includes an $18 million rig standby charge incurred as a result of the time required to obtain deepwater Gulf of Mexico drilling permits post the moratorium. Included in other income/expense for the first quarter 2011 is a $10 million deferred compensation charge relating to the quarterly value change of Noble Energy stock held in a benefit program.
Exxon Mobil 1Q Profit Soars 69% on Higher Oil Prices
Thursday, April 28, 2011
Dow Jones Newswires
by Tess Stynes
ExxonMobil's first-quarter earnings surged a bigger-than-expected 69% as the company benefited from high oil prices and stronger refining margins.
The world's largest publicly traded oil company by market value has reported stronger results in recent quarters due to rising oil profits and improved refining industry profitability. The growth was a reflection of a recovery from the recession for the broader energy sector, which appears poised for a return toward the boom days that preceded the financial collapse in 2008.
Exxon's $25 billion takeover of natural-gas producer XTO Energy Inc. acquisition last year boosted its production and reserves, though prices have remained soft. The move is anticipated to be highly profitable in the long term, on expectations that natural-gas consumption will grow.
Exxon Mobil reported a profit of $10.65 billion, or $2.14 a share, up from $6.3 billion, or $1.33 a share, a year earlier. Revenue climbed 26% to $114 billion after climbing 41% a year earlier.
Analysts polled by Thomson Reuters most recently forecast earnings of $2.07 on revenue of $114.85 billion.
Exploration and production earnings rose 49%. Exxon Mobil's production rose 10%, boosted by its acquisition last year of XTO Energy Inc., which boosted its natural gas production by 24%.
Refining and distribution business earnings soared amid stronger refining margins and sales of petroleum products.
Exxon Mobil said it spent $5.7 billion for stock repurchases, buying back 69 million shares. The total included $5 billion of buybacks to reduce shares outstanding.
Shares were down 0.5% at $87.32 in premarket trading. The stock through Thursday's close is up 27% in the past year.
Shell Reports $6.9B in 1Q11
Shell Reports $6.9B in 1Q11
Thursday, April 28, 2011
Royal Dutch Shell plc
Shell's first quarter 2011 earnings, on a current cost of supplies (CCS) basis, were $6.9 billion compared with $4.9 billion a year ago. Basic CCS earnings per share increased by 40% versus the same quarter a year ago.
Royal Dutch Shell Chief Executive Officer Peter Voser commented, "Our first quarter 2011 earnings have risen from year-ago levels, driven by higher industry margins and our own operating performance.
"We continue to make good progress in implementing our strategy; improving near-term performance, delivering a new wave of production growth, and maturing the next generation of growth options for shareholders.
"We have announced new asset sales and cost savings programs, as part of Shell's focus on continuous improvement, to enhance our profitability and performance. Shell sold $3.2 billion of non-core positions, including tight gas assets in South Texas, in the quarter. Exits from non-core positions continue, with the announcements of further disposals, with proceeds mainly expected during 2011-2012. These additional disposals include refining capacity in the United Kingdom, and marketing positions in Chile and several African countries. This will enhance our competitive performance, and improve our customer and partner focus.
"Shell started commercial production at two new projects during the quarter; the 20 thousand boe/d Schoonebeek Enhanced Oil Recovery project in the Netherlands, and Qatargas 4 LNG, with a capacity of 7.8 million tonnes per year. Together, in an industry that needs sustained investment in diverse energy sources to meet customer demand, these projects are expected to add 90 thousand boe/d of peak production for Shell. These projects are part of a sequence of over 20 new Upstream start-ups planned for 2011-14, as we deliver on our plans for sustainable growth. The first gas flowed from Qatar's North Field into the new Pearl Gas-to-Liquids project during the quarter, where Shell's value-added technology is underpinning the development of the world's largest GTL facility.
"We continue to crystallize new investment options for medium-term growth, including the confirmation of the Geronggong discovery in deep water Brunei, and new LNG potential in the Wheatstone development in Australia, where our gas discoveries have been included in a new partner-operated LNG project, which is under study."
Voser concluded, "We are making good progress against our targets, to deliver a more competitive performance."
First quarter 2011 portfolio developments
Upstream
In Qatar, Shell and Qatargas announced delivery of the first cargo of LNG from the Qatargas 4 project (Shell share 30%). Production is expected to ramp up to 1.4 billion standard cubic feet of gas per day (scf/d), delivering 7.8 million tonnes per annum (mtpa) of LNG and 70 thousand barrels per day (b/d) of condensate and liquefied petroleum gas.
In the Netherlands, Shell produced its first oil from the Schoonebeek Enhanced Oil Recovery (EOR) project (Shell share 30%). The field is expected to ramp up to produce some 20 thousand barrels of oil equivalent per day (boe/d).
Shell sold non-core Upstream assets, with proceeds totalling $2.4 billion in the quarter. As previously announced, Shell completed the sale of a group of predominately mature tight gas fields in South Texas in the USA, producing some 200 million scf/d (Shell share), for some $1.8 billion. In addition, Shell sold various other non-core assets in Canada, Pakistan, the United Kingdom and the USA (combined Shell share of production of some 25 thousand boe/d) as well as exploration acreage in Colombia.
During the first quarter 2011, Shell confirmed a significant oil and gas discovery, Geronggong, drilled in 2010 in deep water Brunei.
Key features of the FIRST quarter 2011
Production in the first quarter 2011 increased by some 230 thousand boe/d from new field start-ups and the continuing ramp-up of fields, which more than offset the impact of field declines.
First quarter Upstream earnings excluding identified items were $4,638 million compared with $4,305 million a year ago. Identified items were a net gain of $1,120 million, compared with a net gain of $110 million in the first quarter 2011.
Upstream earnings excluding identified items, compared with the first quarter 2010, reflected the effect of higher crude oil and natural gas realizations on revenues, higher dividends from an LNG venture and increased realized LNG prices. These items were partly offset by lower crude oil and natural gas production volumes, higher production taxes, lower trading contributions, and higher operating expenses, mainly related to the start-up of new projects.
Global liquids realizations were 32% higher than in the first quarter 2010. Global natural gas realizations were 11% higher than in the same quarter a year ago. Natural gas realizations in the Americas decreased by 25%, whereas natural gas realizations outside the Americas increased by 20%.
First quarter 2011 production was 3,504 thousand boe/d compared with 3,594 thousand boe/d a year ago. Crude oil production was down 3% and natural gas production decreased by 2% compared with the first quarter 2010. Excluding the impact of divestments, the first quarter 2011 production was in line with the same period last year.
New field start-ups and the continuing ramp-up of fields contributed to the production in the first quarter 2011 by some 230 thousand boe/d, in particular from the ramp-up of Gbaran Ubie in Nigeria, the start-up of the Qatargas 4 project in Qatar, and the ramp-up of the Jackpine Mine at the Athabasca Oil Sands Project in Canada, which more than offset the impact of field declines.
LNG sales volumes of 4.42 million tonnes were 4% higher than in the same quarter a year ago, reflecting higher volumes from Nigeria LNG and the Sakhalin II project as well as the successful start-up of the Qatargas 4 project.
Thursday, April 28, 2011
Royal Dutch Shell plc
Shell's first quarter 2011 earnings, on a current cost of supplies (CCS) basis, were $6.9 billion compared with $4.9 billion a year ago. Basic CCS earnings per share increased by 40% versus the same quarter a year ago.
- First quarter 2011 CCS earnings, excluding identified items, were $6.3 billion compared with $4.8 billion in the first quarter 2010, an increase of 30%. Basic CCS earnings per share, excluding identified items, increased by 29% versus the same quarter a year ago.
- Cash flow from operating activities for the first quarter 2011 was $8.6 billion. Excluding net working capital movements, cash flow from operating activities in the first quarter 2011 was $13.1 billion, compared with $10.4 billion in the same quarter last year.
- Net capital investment for the quarter was $1.7 billion. Total cash dividends paid to shareholders during the first quarter 2011 were $1.6 billion. Some 31.1 million Class A shares, equivalent to $1.1 billion, were issued under the Scrip Dividend Programme for the fourth quarter 2010.
- Gearing at the end of the first quarter 2011 was 14.0%.
- A first quarter 2011 dividend has been announced of $0.42 per ordinary share, unchanged from the US dollar dividend per share for the same period in 2010.
Royal Dutch Shell Chief Executive Officer Peter Voser commented, "Our first quarter 2011 earnings have risen from year-ago levels, driven by higher industry margins and our own operating performance.
"We continue to make good progress in implementing our strategy; improving near-term performance, delivering a new wave of production growth, and maturing the next generation of growth options for shareholders.
"We have announced new asset sales and cost savings programs, as part of Shell's focus on continuous improvement, to enhance our profitability and performance. Shell sold $3.2 billion of non-core positions, including tight gas assets in South Texas, in the quarter. Exits from non-core positions continue, with the announcements of further disposals, with proceeds mainly expected during 2011-2012. These additional disposals include refining capacity in the United Kingdom, and marketing positions in Chile and several African countries. This will enhance our competitive performance, and improve our customer and partner focus.
"Shell started commercial production at two new projects during the quarter; the 20 thousand boe/d Schoonebeek Enhanced Oil Recovery project in the Netherlands, and Qatargas 4 LNG, with a capacity of 7.8 million tonnes per year. Together, in an industry that needs sustained investment in diverse energy sources to meet customer demand, these projects are expected to add 90 thousand boe/d of peak production for Shell. These projects are part of a sequence of over 20 new Upstream start-ups planned for 2011-14, as we deliver on our plans for sustainable growth. The first gas flowed from Qatar's North Field into the new Pearl Gas-to-Liquids project during the quarter, where Shell's value-added technology is underpinning the development of the world's largest GTL facility.
"We continue to crystallize new investment options for medium-term growth, including the confirmation of the Geronggong discovery in deep water Brunei, and new LNG potential in the Wheatstone development in Australia, where our gas discoveries have been included in a new partner-operated LNG project, which is under study."
Voser concluded, "We are making good progress against our targets, to deliver a more competitive performance."
First quarter 2011 portfolio developments
Upstream
In Qatar, Shell and Qatargas announced delivery of the first cargo of LNG from the Qatargas 4 project (Shell share 30%). Production is expected to ramp up to 1.4 billion standard cubic feet of gas per day (scf/d), delivering 7.8 million tonnes per annum (mtpa) of LNG and 70 thousand barrels per day (b/d) of condensate and liquefied petroleum gas.
In the Netherlands, Shell produced its first oil from the Schoonebeek Enhanced Oil Recovery (EOR) project (Shell share 30%). The field is expected to ramp up to produce some 20 thousand barrels of oil equivalent per day (boe/d).
Shell sold non-core Upstream assets, with proceeds totalling $2.4 billion in the quarter. As previously announced, Shell completed the sale of a group of predominately mature tight gas fields in South Texas in the USA, producing some 200 million scf/d (Shell share), for some $1.8 billion. In addition, Shell sold various other non-core assets in Canada, Pakistan, the United Kingdom and the USA (combined Shell share of production of some 25 thousand boe/d) as well as exploration acreage in Colombia.
During the first quarter 2011, Shell confirmed a significant oil and gas discovery, Geronggong, drilled in 2010 in deep water Brunei.
Key features of the FIRST quarter 2011
- First quarter 2011 CCS earnings were $6,925 million, 41% higher than in the same quarter a year ago.
- First quarter 2011 CCS earnings excluding identified items, were $6,288 million compared with $4,822 million in the first quarter 2010.
- Basic CCS earnings per share increased by 40% versus the same quarter a year ago.
- Basic CCS earnings per share excluding identified items increased by 29% versus the same quarter a year ago.
- Cash flow from operating activities for the first quarter 2011 was $8.6 billion, compared with $4.8 billion in the same quarter last year. Excluding net working capital movements, cash flow from operating activities in the first quarter 2011 was $13.1 billion, compared with $10.4 billion in the same quarter last year.
- Total cash dividends paid to shareholders during the first quarter 2011 were $1.6 billion. During the first quarter 2011, some 31.1 million Class A shares, equivalent to $1.1 billion, were issued under the Scrip Dividend Program for the fourth quarter 2010.
- Net capital investment for the first quarter 2011 was $1.7 billion. Capital investment for the first quarter 2011 was $4.9 billion.
- Return on average capital employed (ROACE) at the end of the first quarter 2011, on a reported income basis, was 12.9%.
- Gearing was 14.0% at the end of the first quarter 2011 versus 17.1% at the end of the first quarter 2010.
Upstream
- Oil and gas production for the first quarter 2011 was 3,504 thousand boe/d, 3% lower than in the first quarter 2010. Production for the first quarter 2011 excluding the impact of divestments was in line with the same period last year.
Production in the first quarter 2011 increased by some 230 thousand boe/d from new field start-ups and the continuing ramp-up of fields, which more than offset the impact of field declines.
- LNG sales volumes of 4.42 million tonnes in the first quarter 2011 were 4% higher than in the same quarter a year ago.
First quarter Upstream earnings excluding identified items were $4,638 million compared with $4,305 million a year ago. Identified items were a net gain of $1,120 million, compared with a net gain of $110 million in the first quarter 2011.
Upstream earnings excluding identified items, compared with the first quarter 2010, reflected the effect of higher crude oil and natural gas realizations on revenues, higher dividends from an LNG venture and increased realized LNG prices. These items were partly offset by lower crude oil and natural gas production volumes, higher production taxes, lower trading contributions, and higher operating expenses, mainly related to the start-up of new projects.
Global liquids realizations were 32% higher than in the first quarter 2010. Global natural gas realizations were 11% higher than in the same quarter a year ago. Natural gas realizations in the Americas decreased by 25%, whereas natural gas realizations outside the Americas increased by 20%.
First quarter 2011 production was 3,504 thousand boe/d compared with 3,594 thousand boe/d a year ago. Crude oil production was down 3% and natural gas production decreased by 2% compared with the first quarter 2010. Excluding the impact of divestments, the first quarter 2011 production was in line with the same period last year.
New field start-ups and the continuing ramp-up of fields contributed to the production in the first quarter 2011 by some 230 thousand boe/d, in particular from the ramp-up of Gbaran Ubie in Nigeria, the start-up of the Qatargas 4 project in Qatar, and the ramp-up of the Jackpine Mine at the Athabasca Oil Sands Project in Canada, which more than offset the impact of field declines.
LNG sales volumes of 4.42 million tonnes were 4% higher than in the same quarter a year ago, reflecting higher volumes from Nigeria LNG and the Sakhalin II project as well as the successful start-up of the Qatargas 4 project.
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