State Senate Proposes Impact Fee on Gas Drillin
Friday, April 29, 2011
Knight Ridder/Tribune Business News
by Brad Bumsted and Andrew Conte, The Pittsburgh Trib
The ranking Republican in the state Senate today proposed an impact fee on Marcellus shale gas drilling, of which an estimated 60 percent would go to counties and municipalities with deep wells as well as townships and boroughs neighboring drilling production sites.
The fee would be used to help cover damage to roads and bridges, maintenance and improvement costs for water and sewage systems and emergency responder costs, said Senate President Pro Tempore Joe Scarnati, R-Jefferson County.
The other 40 percent would be split between conservation districts statewide and environmental funds for clean up and infrastructure, Scarnati said.
The exact breakdown of revenue from the fee is still subject to negotiation in a bill that Scarnati hopes will be ready for a vote in early June. The bill could be introduced as soon as next week.
The baseline fee is $10,000 per well, but it would be adjusted based on gas volume and the price of gas. The average fee per well would be about $25,000 in 2011, according to Scarnati's office.
The fee would be retroactive for 2010 and raise $45 million for last year. It will bring in $76 million this year and will rise to at least $150 million by 2014, Scarnati said.
The legislation was much anticipated because of Scarnati's stature in legislative leadership and because Republican Gov. Tom Corbett has said flatly he will not consider a tax that brings money into the General Fund.
"I have to believe this is in the sweet spot of where I believe most legislators will be," Scarnati said.
Moreover, he said it would be difficult to pass a state budget without some sort of levy on the burgeoning industry.
"I can't see how we get a state budget done without bringing some dollars in from this industry," he said.
The fees will not be used to balance the budget, which is $4.2 billion in the red. But the political dynamic of lawmakers voting for cuts requires a fee on the industry, he said.
Statewide polls show widespread support for a tax on shale drilling -- 69-22 percent in favor in a recent Quinnipiac University poll.
Scarnati said it is a fee and not a tax because the money does not go to the General Fund. There also are no exemptions as typically exist with shale extraction taxes, he said.
"What's the difference between a fee and tax? Governor Corbett's pen," Scarnati said. "That will be the ultimate test."
He said he had lunch with Corbett on Monday.
"At this point, I have a caution light," Scarnati said today in a phone conference with reporters. "I don't have a red light. I don't have a green light."
Marcellus drillers are open to an impact fee that provides money for local communities as long as it's "clear, straightforward and competitive," Kathryn Klaber, president of the Marcellus Shale Coalition trade group, said in a statement.
"Our industry understands that, while there are tremendous financial opportunities in Marcellus Shale development, there also can be impacts felt by our host communities," Klaber said.
"We support the concept of a fee with portions for local government and conservation and most importantly strong but consistent local regulations as part of this approach," said Matt Pitzarella, a spokesman for Range Resources.
"The devil is and will always be in the details and we eagerly look forward to seeing and reviewing those particulars, but we remain supportive of the concept."
Friday, April 29, 2011
Mexico May Become Oil Importer by 2020 -Study
Mexico May Become Oil Importer by 2020 -Study
Friday, April 29, 201
Baker Institute
Without sufficient investments in upstream oil field activities utilizing new and advanced technologies, Mexico faces the prospect of becoming a net oil importer in 10 years, according to new research by Rice University's James A. Baker III Institute for Public Policy and Oxford University. The stakes of the current political stalemate over oil are quite high, the study concluded. Were Pemex, Mexico's national oil company, able to fully develop its oil in line with international standards and technology, Mexican citizens could earn $1,055 per capita per year by 2020, versus $546 if current trends continue.
The two-year study will be released April 29 at a roundtable in Mexico City, co-hosted by Mexican Council on Foreign Relations. The study consists of 14 specialized academic papers authored by scholars from Oxford University, Rice University, Centro de Investigación y Docencia Económicas, National Autonomous University, Instituto Technológico Autónomo de México, Instituto de Investigaciones, Instituto Mora and Monterrey Institute of Technology and Higher Education.
Mexican petroleum production has been falling -- more than 25 percent since its peak in 2004 of 3.9 million barrels per day. Mexico produced 2.98 million barrels per day in 2010. The giant Cantarell field, in particular, has seen a significant drop in production. Meanwhile, domestic demand for oil has grown from 500,000 barrels per day in 1971 to roughly 2.15 million barrels per day in 2010. At present, Mexico is a net oil exporter, with total net exports in 2009 running at just under 1 million barrels per day.
These two trends -- lower overall production and growing internal demand -- pose serious challenges for the Mexican government. The Baker Institute study examines three basic questions: What does Mexico want from its oil policies? What are the Mexican oil sector’s medium- to long-term prospects? And how can Mexico best manage the foreseeable obstacles to achieving its underlying goals for the future of oil in Mexico?
Mexico, the study found, has "three fundamental long-term objectives for its oil sector: to retain ownership and control of subsoil resources ('resource nationalism'); to protect the national economy from external shocks and predation ('energy security'); and to distribute any surpluses generated from this national patrimony to the benefit of the Mexican people as a whole." These goals could generate conflict, the study noted. But despite these goals, the study also concluded, a more equitable distribution of oil revenues could wipe out poverty in the country and thereby create more grassroots political backing for energy reforms. Instead, existing federal spending practices benefit the country's most wealthy citizens.
Mexican leaders are keenly aware of the potential problems caused by falling oil exports and rising public expectations. Pemex has taken steps to slow the declining production by increasing investment in two newer fields. However, the study warned, enhanced recovery techniques for both onshore and offshore oil take years to have an effect.
Moreover, the study questioned whether the Mexican leadership has the will and the ability to reach long-term energy goals. "Political decision-making in the Mexican energy sector, like in many democratic societies, can become highly captive of vested interests," the study said, "with outcomes that are less than optimum for the stakeholder, in this case, the Mexican people." The study argued that for many of those vested interests, the status quo is quite advantageous.
"The study's final determination is that the decline in Mexican oil revenues is likely to be gradual rather than rapid and reduce the chances that a sudden, deep crisis will create the political will to make hard choices or unpopular reforms. For instance, if Pemex is able to maintain production levels through new finds and better efficiency, it could postpone the export crisis for three decades. But even with this expanded time frame, it is not assured that Mexico will undertake an orderly adjustment. Rather, the study's authors concluded, "it can also generate incentives to postpone it or adjust to the fall in government revenues through the least-costly short-run solution, such as cutting public investment, which can, at the same time, generate the greatest adverse effects in the long run."
Friday, April 29, 201
Baker Institute
Without sufficient investments in upstream oil field activities utilizing new and advanced technologies, Mexico faces the prospect of becoming a net oil importer in 10 years, according to new research by Rice University's James A. Baker III Institute for Public Policy and Oxford University. The stakes of the current political stalemate over oil are quite high, the study concluded. Were Pemex, Mexico's national oil company, able to fully develop its oil in line with international standards and technology, Mexican citizens could earn $1,055 per capita per year by 2020, versus $546 if current trends continue.
The two-year study will be released April 29 at a roundtable in Mexico City, co-hosted by Mexican Council on Foreign Relations. The study consists of 14 specialized academic papers authored by scholars from Oxford University, Rice University, Centro de Investigación y Docencia Económicas, National Autonomous University, Instituto Technológico Autónomo de México, Instituto de Investigaciones, Instituto Mora and Monterrey Institute of Technology and Higher Education.
Mexican petroleum production has been falling -- more than 25 percent since its peak in 2004 of 3.9 million barrels per day. Mexico produced 2.98 million barrels per day in 2010. The giant Cantarell field, in particular, has seen a significant drop in production. Meanwhile, domestic demand for oil has grown from 500,000 barrels per day in 1971 to roughly 2.15 million barrels per day in 2010. At present, Mexico is a net oil exporter, with total net exports in 2009 running at just under 1 million barrels per day.
These two trends -- lower overall production and growing internal demand -- pose serious challenges for the Mexican government. The Baker Institute study examines three basic questions: What does Mexico want from its oil policies? What are the Mexican oil sector’s medium- to long-term prospects? And how can Mexico best manage the foreseeable obstacles to achieving its underlying goals for the future of oil in Mexico?
Mexico, the study found, has "three fundamental long-term objectives for its oil sector: to retain ownership and control of subsoil resources ('resource nationalism'); to protect the national economy from external shocks and predation ('energy security'); and to distribute any surpluses generated from this national patrimony to the benefit of the Mexican people as a whole." These goals could generate conflict, the study noted. But despite these goals, the study also concluded, a more equitable distribution of oil revenues could wipe out poverty in the country and thereby create more grassroots political backing for energy reforms. Instead, existing federal spending practices benefit the country's most wealthy citizens.
Mexican leaders are keenly aware of the potential problems caused by falling oil exports and rising public expectations. Pemex has taken steps to slow the declining production by increasing investment in two newer fields. However, the study warned, enhanced recovery techniques for both onshore and offshore oil take years to have an effect.
Moreover, the study questioned whether the Mexican leadership has the will and the ability to reach long-term energy goals. "Political decision-making in the Mexican energy sector, like in many democratic societies, can become highly captive of vested interests," the study said, "with outcomes that are less than optimum for the stakeholder, in this case, the Mexican people." The study argued that for many of those vested interests, the status quo is quite advantageous.
"The study's final determination is that the decline in Mexican oil revenues is likely to be gradual rather than rapid and reduce the chances that a sudden, deep crisis will create the political will to make hard choices or unpopular reforms. For instance, if Pemex is able to maintain production levels through new finds and better efficiency, it could postpone the export crisis for three decades. But even with this expanded time frame, it is not assured that Mexico will undertake an orderly adjustment. Rather, the study's authors concluded, "it can also generate incentives to postpone it or adjust to the fall in government revenues through the least-costly short-run solution, such as cutting public investment, which can, at the same time, generate the greatest adverse effects in the long run."
ONGC Makes New O&G Discoveries in Gujarat
ONGC Makes New O&G Discoveries in Gujarat
Friday, April 29, 201
Asia Pulse Pte. Ltd.
Indian state-owned Oil and Natural Gas Co. (ONGC) said it has made two oil and gas discoveries in Gujarat.
ONGC struck oil and gas in a well drilled block CB-ONN-2004 2 in Gujarat, the company said in a statement.
The state-owned firm has 50 percent interest in the block that it had won along with Gujarat State Petroleum (40 percent) and Sunterra (10 percent) in the seventh round of bidding under New Exploration Licensing Policy (NELP).
Exploratory well Vadtal-3 produced oil at a rate of 22.5 cubic meter per day and gas at a rate of 3758 cubic meter per day on testing, it said, "The oil produced is of very good quality with a gravity of 41.10 API."
This is the second discovery in block CB-ONN-2001/1.
ONGC said it made an oil discovery in a nomination block Linch Extn-1 in the western offshore.
"Development well North Kadi-461 in Linch Extn-I PML, Western Onshore Basin, was drilled to a depth of 1600 meters," it said adding oil flowed at a rate of 17 cubic meters per day during testing.
The oil is heavy oil with 25.390 API gravity.
ONGC said it produced 27.272 million tonnes of crude oil in 2010-11 fiscal, marginally higher than the target of 27 million tonnes. Gas production at 25.322 billion cubic meters was also higher than 25 bcm target.
It sold 20.297 bcm of gas and produced 3.2 million tonnes of value added products in the fiscal year.
The firm's overseas arm, ONGC Videsh Ltd produced 9.433 million tonnes of oil and oil equivalent gas, surpassing the earlier peak production of 8.87 million tons of oil and oil equivalent gas in 2009-10.
Commenting on the performance, ONGC chairman and managing director A K Hazarika said, "Considering the global average rate of production decline from matured oil fields, this performance of ONGC is commendable."
"Our performance in reserve accretion is once again laudable. However, without drawing any complacence, we are focusing on bringing all new discoveries to production at the earliest possible opportunities," he said.
ONGC said it made a total of 24 discoveries during 2010-11 financial year.
During 2010-11, ONGC said it added 236.92 million tonne oil and oil equivalent (Mtoe) gas in-place reserves. Of this "83.56 million tonnes of oil equivalent as the Ultimate Reserve surpassed the record breaking performance of previous fiscal (82.98 Mtoe) and resulting a RRR (Reserve Replacement Ratio) of 1.76."
Friday, April 29, 201
Asia Pulse Pte. Ltd.
Indian state-owned Oil and Natural Gas Co. (ONGC) said it has made two oil and gas discoveries in Gujarat.
ONGC struck oil and gas in a well drilled block CB-ONN-2004 2 in Gujarat, the company said in a statement.
The state-owned firm has 50 percent interest in the block that it had won along with Gujarat State Petroleum (40 percent) and Sunterra (10 percent) in the seventh round of bidding under New Exploration Licensing Policy (NELP).
Exploratory well Vadtal-3 produced oil at a rate of 22.5 cubic meter per day and gas at a rate of 3758 cubic meter per day on testing, it said, "The oil produced is of very good quality with a gravity of 41.10 API."
This is the second discovery in block CB-ONN-2001/1.
ONGC said it made an oil discovery in a nomination block Linch Extn-1 in the western offshore.
"Development well North Kadi-461 in Linch Extn-I PML, Western Onshore Basin, was drilled to a depth of 1600 meters," it said adding oil flowed at a rate of 17 cubic meters per day during testing.
The oil is heavy oil with 25.390 API gravity.
ONGC said it produced 27.272 million tonnes of crude oil in 2010-11 fiscal, marginally higher than the target of 27 million tonnes. Gas production at 25.322 billion cubic meters was also higher than 25 bcm target.
It sold 20.297 bcm of gas and produced 3.2 million tonnes of value added products in the fiscal year.
The firm's overseas arm, ONGC Videsh Ltd produced 9.433 million tonnes of oil and oil equivalent gas, surpassing the earlier peak production of 8.87 million tons of oil and oil equivalent gas in 2009-10.
Commenting on the performance, ONGC chairman and managing director A K Hazarika said, "Considering the global average rate of production decline from matured oil fields, this performance of ONGC is commendable."
"Our performance in reserve accretion is once again laudable. However, without drawing any complacence, we are focusing on bringing all new discoveries to production at the earliest possible opportunities," he said.
ONGC said it made a total of 24 discoveries during 2010-11 financial year.
During 2010-11, ONGC said it added 236.92 million tonne oil and oil equivalent (Mtoe) gas in-place reserves. Of this "83.56 million tonnes of oil equivalent as the Ultimate Reserve surpassed the record breaking performance of previous fiscal (82.98 Mtoe) and resulting a RRR (Reserve Replacement Ratio) of 1.76."
Drilling Commenced at Petroamerica's Las Maracas Well
Drilling Commenced at Petroamerica's Las Maracas Well
Friday, April 29, 2011
Petroamerica Oil Corp.
Petroamerica announced the April 27, 2011 spud of the Las Maracas-2 exploration well in the Los Ocarros Block, situated in the Llanos Basin of Colombia. The Las Maracas-2 well is targeting the Carbonera C7, Mirador and Une reservoir formations in a fault trap defined by 3D seismic. The well will be directionally drilled by the Parker 268 drilling rig and is expected to reach its total depth of 13,100 feet (measured depth) by end June, 2011.
The Company, pursuant to a Farmin Agreement with Talisman Oil & Gas Colombia Limited, is entitled to a 50% participating interest in the Los Ocarros Block, subject to the approval of the National Hydrocarbon Agency (ANH) and the operator of the block, Cepsa Colombia S.A., a subsidiary of the Cepsa Group.
Friday, April 29, 2011
Petroamerica Oil Corp.
Petroamerica announced the April 27, 2011 spud of the Las Maracas-2 exploration well in the Los Ocarros Block, situated in the Llanos Basin of Colombia. The Las Maracas-2 well is targeting the Carbonera C7, Mirador and Une reservoir formations in a fault trap defined by 3D seismic. The well will be directionally drilled by the Parker 268 drilling rig and is expected to reach its total depth of 13,100 feet (measured depth) by end June, 2011.
The Company, pursuant to a Farmin Agreement with Talisman Oil & Gas Colombia Limited, is entitled to a 50% participating interest in the Los Ocarros Block, subject to the approval of the National Hydrocarbon Agency (ANH) and the operator of the block, Cepsa Colombia S.A., a subsidiary of the Cepsa Group.
Southern Bay Starts Drilling in Fayette County
Southern Bay Starts Drilling in Fayette County
Friday, April 29, 2011
Eureka Energy Ltd.
Eureka announced the spudding of Blackjack Springs Unit #1H, the first well at its Pan de Azucar Eagle Ford Shale project in Fayette County, on-shore Texas USA.
As of April 27, 2011 local time, the operator, Southern Bay advised that the well had reached a depth of 2,080 ft and was drilling ahead. The well is planned to target the Eagle Ford Shale at a vertical depth of approximately 10,500 feet with a horizontal of around 6,000 feet.
The Blackjack Springs Drilling Unit is a 916 acre pooled unit to which Eureka has contributed 86 acres for its 9.4% working interest. The unit is immediately adjacent to the remaining 675 acres (EKA WI 100%) that make up the balance of the Pan de Azucar project.
The operator, Southern Bay, is a wholly owned subsidiary of GeoResources Inc.
Friday, April 29, 2011
Eureka Energy Ltd.
Eureka announced the spudding of Blackjack Springs Unit #1H, the first well at its Pan de Azucar Eagle Ford Shale project in Fayette County, on-shore Texas USA.
As of April 27, 2011 local time, the operator, Southern Bay advised that the well had reached a depth of 2,080 ft and was drilling ahead. The well is planned to target the Eagle Ford Shale at a vertical depth of approximately 10,500 feet with a horizontal of around 6,000 feet.
The Blackjack Springs Drilling Unit is a 916 acre pooled unit to which Eureka has contributed 86 acres for its 9.4% working interest. The unit is immediately adjacent to the remaining 675 acres (EKA WI 100%) that make up the balance of the Pan de Azucar project.
The operator, Southern Bay, is a wholly owned subsidiary of GeoResources Inc.
Medco Energi Wins Oil Field Proj. in Tunisia
Medco Energi Wins Oil Field Proj. in Tunisia
Friday, April 29, 2011
Asia Pulse Pte. Ltd.
Medco Energi said its subsidiary Medco Tunisia Anaguid Ltd has secured the right to produce oil from an oil field in Tunisia.
Medco Tunisia was granted last month the license by the Tunisian government to develop the Durra oil field in Anaguid.
Medco will team up with OMV Anaguid Ltd, formerly named Pioneer Natural Resources Anaguid Ltd to operate the oil field, Medco Energi project director Lukman Mahfoedz said.
The Durra field is expected to start producing 3,300 barrels of oil per day in June, Lukman told the newspaper Investor Daily yesterday.
Medco Tunisia owns a 20 percent stake in the project with OMV Anaguid holding a 30 percent share and ETAP, that represents the Tunisian government as a 50 percent shareholder.
Friday, April 29, 2011
Asia Pulse Pte. Ltd.
Medco Energi said its subsidiary Medco Tunisia Anaguid Ltd has secured the right to produce oil from an oil field in Tunisia.
Medco Tunisia was granted last month the license by the Tunisian government to develop the Durra oil field in Anaguid.
Medco will team up with OMV Anaguid Ltd, formerly named Pioneer Natural Resources Anaguid Ltd to operate the oil field, Medco Energi project director Lukman Mahfoedz said.
The Durra field is expected to start producing 3,300 barrels of oil per day in June, Lukman told the newspaper Investor Daily yesterday.
Medco Tunisia owns a 20 percent stake in the project with OMV Anaguid holding a 30 percent share and ETAP, that represents the Tunisian government as a 50 percent shareholder.
Treaty's Tx. Lease Acquisition Delayed
Treaty's Tx. Lease Acquisition Delayed
Friday, April 29, 2011
Treaty Energy Corp.
Treaty announced an update to its announced "letter of intent" of April 12, 2011 to acquire producing oil and gas leases in Shackelford County, Texas.
The closing on this acquisition has been delayed until June 7, 2011 because of issues that had to be corrected by the seller on the leases being purchased.
Stephen L. York, Vice President of Acquisitions and Operations for Treaty Energy, stated, "Although we are disappointed over the delay of this acquisition, we are very pleased that all the issues are being corrected and the new closing date is now set."
Friday, April 29, 2011
Treaty Energy Corp.
Treaty announced an update to its announced "letter of intent" of April 12, 2011 to acquire producing oil and gas leases in Shackelford County, Texas.
The closing on this acquisition has been delayed until June 7, 2011 because of issues that had to be corrected by the seller on the leases being purchased.
Stephen L. York, Vice President of Acquisitions and Operations for Treaty Energy, stated, "Although we are disappointed over the delay of this acquisition, we are very pleased that all the issues are being corrected and the new closing date is now set."
FairfieldNodal Assists Apache Tame Alaskan Challenge
FairfieldNodal Assists Apache Tame Alaskan Challenge
Friday, April 29, 2011
FairfieldNodal
FairfieldNodal announced the successful employment of ZLand and Z700 cable-freeequipment on an Apache Corporation seismic test survey in the extremely challenging onshore and shallow-water region of Cook Inlet, Alaska.
Due to restrictive state and federal permits, the test took place on a condensed timeline from mid-March to early April of this year. Unpredictable ice and ground conditions in the area put additional demands on the operations.
Apache contracted NES to organize and test a variety of seismic recording and source systems to determine optimum equipment and acquisition parameters for potential future exploration over their lease holdings in the area.
FairfieldNodal contributed to the test by organizing and assembling its own true cable-free ZLand and Z700 recording systems, and installing a Z700 deployment/retrieval system on a local vessel. For the limited test, FairfieldNodal supplied 725 ZLand nodes and 200 Z700 nodes, plus support and operations personnel.
Operationally, FairfieldNodal components and support performed nearly flawlessly, a tribute to the team's efficient organization as well as the suitability of both ZLand and Z700 equipment for work in harsh environments; in this case, one of the world's most challenging regions for seismic operations.
Friday, April 29, 2011
FairfieldNodal
FairfieldNodal announced the successful employment of ZLand and Z700 cable-freeequipment on an Apache Corporation seismic test survey in the extremely challenging onshore and shallow-water region of Cook Inlet, Alaska.
Due to restrictive state and federal permits, the test took place on a condensed timeline from mid-March to early April of this year. Unpredictable ice and ground conditions in the area put additional demands on the operations.
Apache contracted NES to organize and test a variety of seismic recording and source systems to determine optimum equipment and acquisition parameters for potential future exploration over their lease holdings in the area.
FairfieldNodal contributed to the test by organizing and assembling its own true cable-free ZLand and Z700 recording systems, and installing a Z700 deployment/retrieval system on a local vessel. For the limited test, FairfieldNodal supplied 725 ZLand nodes and 200 Z700 nodes, plus support and operations personnel.
Operationally, FairfieldNodal components and support performed nearly flawlessly, a tribute to the team's efficient organization as well as the suitability of both ZLand and Z700 equipment for work in harsh environments; in this case, one of the world's most challenging regions for seismic operations.
Gulf Island Fabrication Signs LOI for GOM Hull Fabrication Proj.
Gulf Island Fabrication Signs LOI for GOM Hull Fabrication Proj.
Friday, April 29, 2011
Gulf Island Fabrication Inc.
Gulf Island Fabrication announced that through its subsidiary Gulf Marine Fabricators, it has signed a Letter of Award for the fabrication of a hull for a Williams deep-water Gulf of Mexico project. Revenue and man-hour backlog is included in the Company's consolidated backlog reported when the Company announced its earnings results for the quarter ended March 31, 2011.
Friday, April 29, 2011
Gulf Island Fabrication Inc.
Gulf Island Fabrication announced that through its subsidiary Gulf Marine Fabricators, it has signed a Letter of Award for the fabrication of a hull for a Williams deep-water Gulf of Mexico project. Revenue and man-hour backlog is included in the Company's consolidated backlog reported when the Company announced its earnings results for the quarter ended March 31, 2011.
Baker Hughes Names New Executive Chairman
Baker Hughes Names New Executive Chairman
Friday, April 29, 2011
Baker Hughes Inc.
Baker Hughes has approved the transition of Chad C. Deaton, Chairman of the Board and Chief Executive Officer, to the new role of Executive Chairman beginning January 1, 2012. At that time Martin S. Craighead will assume the position of Chief Executive Officer in addition to his role as President of Baker Hughes.
Mr. Deaton said, "In October 2011, I will have served seven years as the leader of Baker Hughes. We have accomplished the major objectives I had when I joined the company in the fall of 2004 and I am very proud to have shared this success with our outstanding employees, management team and Board of Directors. We have expanded and refocused the company, building its competitive strengths while maintaining financial discipline and improving our returns. We have established a strong culture based on our Core Values of Integrity, Performance, Learning and Teamwork.
"I have tremendous respect for Martin's abilities and confidence in his leadership. As an experienced operations executive, Martin has an exceptional background for the CEO role. He has been with the company for over 25 years, including management roles in both the United States and other countries. He is one of the veterans of the company's management team who has effectively mobilized our people and technology into a new geographic alignment as a leading global supplier of oilfield services."
H. John Riley, Lead Director of the company's Board of Directors, said that "The entire board is extremely appreciative of Chad Deaton's outstanding leadership and significant contributions to the success of Baker Hughes over the past several years. He has implemented a strategy for growth and improved performance that has re-energized and broadened the horizons for the company. We look forward to Chad's active involvement in his new role as Executive Chairman.
"The Board joins me in congratulating Martin for earning the opportunity to lead Baker Hughes in the future as the company continues its growth as a leader in our industry. Baker Hughes is extremely well positioned for the future."
Friday, April 29, 2011
Baker Hughes Inc.
Baker Hughes has approved the transition of Chad C. Deaton, Chairman of the Board and Chief Executive Officer, to the new role of Executive Chairman beginning January 1, 2012. At that time Martin S. Craighead will assume the position of Chief Executive Officer in addition to his role as President of Baker Hughes.
Mr. Deaton said, "In October 2011, I will have served seven years as the leader of Baker Hughes. We have accomplished the major objectives I had when I joined the company in the fall of 2004 and I am very proud to have shared this success with our outstanding employees, management team and Board of Directors. We have expanded and refocused the company, building its competitive strengths while maintaining financial discipline and improving our returns. We have established a strong culture based on our Core Values of Integrity, Performance, Learning and Teamwork.
"I have tremendous respect for Martin's abilities and confidence in his leadership. As an experienced operations executive, Martin has an exceptional background for the CEO role. He has been with the company for over 25 years, including management roles in both the United States and other countries. He is one of the veterans of the company's management team who has effectively mobilized our people and technology into a new geographic alignment as a leading global supplier of oilfield services."
H. John Riley, Lead Director of the company's Board of Directors, said that "The entire board is extremely appreciative of Chad Deaton's outstanding leadership and significant contributions to the success of Baker Hughes over the past several years. He has implemented a strategy for growth and improved performance that has re-energized and broadened the horizons for the company. We look forward to Chad's active involvement in his new role as Executive Chairman.
"The Board joins me in congratulating Martin for earning the opportunity to lead Baker Hughes in the future as the company continues its growth as a leader in our industry. Baker Hughes is extremely well positioned for the future."
Duncan Energy to Merge with Enterprise Products
Duncan Energy to Merge with Enterprise Products
Apr 29, 2011
Duncan Energy and Enterprise Products announced today that both companies are planning a definitive merger agreement. In the merger Duncan Energy will become a wholly-owned subsidiary of Enterprise Products' operating partnership through a unit-for-unit exchange. Based on the cash distributions to be paid on May 6 by both companies, the merger would result in a 32% increase in per unit cash distributions for the unitholders of Duncan Energy. The merger is expected to be immediately accretive in terms of distributable cash flow per common unit of Enterprise PRoducts. Shares of Duncan Energy are up 5.67% to $43.05 while Enterprise Products shares are down 2.53% to $48.25.
Apr 29, 2011
Duncan Energy and Enterprise Products announced today that both companies are planning a definitive merger agreement. In the merger Duncan Energy will become a wholly-owned subsidiary of Enterprise Products' operating partnership through a unit-for-unit exchange. Based on the cash distributions to be paid on May 6 by both companies, the merger would result in a 32% increase in per unit cash distributions for the unitholders of Duncan Energy. The merger is expected to be immediately accretive in terms of distributable cash flow per common unit of Enterprise PRoducts. Shares of Duncan Energy are up 5.67% to $43.05 while Enterprise Products shares are down 2.53% to $48.25.
Shale Boom, Gas Demand to Make North America LNG Exports Reality
Shale Boom, Gas Demand to Make North America LNG Exports Reality
Friday, April 29, 2011
Rigzone Staff
by Karen Boman
The increase in North American natural gas due to the shale gas boom and a projected increase in global gas demand mean that North America will become a liquefied natural gas (LNG) exporter within the next few years.
The recovery in global LNG consumption in 2010, combined with anticipated gas demand growth in emerging economies of China and India presents opportunities for LNG exports, as does growing demand in Europe, where gas production is expected to decline and demand for gas-fired power generation is expected to grow. Near-term LNG demand also will be impacted by Japan, where the earthquake and tsunami damaged nuclear power facilities, resulting in strong demand for natural gas to fire electric power plants. However, it is too early to tell how this will impact Japan's long-term plans.
North American LNG exports should be sustained as long as North American shale gas production remains at existing levels, said Zach Allen, publisher of PanEurasian Enterprises NATS report, which tracks global LNG markets. Cheniere Energy's Sabine Pass in Louisiana and Freeport LNG in Texas are two existing LNG regasification facilities that will have liquefaction capacity added to allow for LNG exports.
Sabine Pass's liquefaction facilities are scheduled to begin operations in 2015, drawing from onshore Gulf Coast conventional gas plays as well as the Barnett, Haynesville, Bossier, and Eagle Ford shale gas plays. Freeport LNG's liquefaction facility also is expected to be in service in 2015, and will draw its supply from the Eagle Ford, Barnett and Haynesville shale plays as well.
Cheniere noted that adding liquefaction infrastructure to Sabine Pass will allow the company arbitrage opportunities for Henry Hub versus oil prices. Worldwide LNG prices are predominately based on oil prices, or between $10-$25/MMBtu, while Cheniere estimates the cost of delivering gas from Sabine Pass to Europe and Asia at between $7 - $12/MMbtu. The project also has the advantage of having significant infrastructure already in place, including storage, marine and pipeline interconnection facilities, which means lower capital costs.
The Cove Point LNG regasification facility near Baltimore, Maryland could potentially serve as an export facility for Marcellus shale gas, Allen noted. He sees Marcellus gas as a stranded asset, as it's difficult to move gas south from the Marcellus region. "Through displacement, you can move a certain amount of it to the north and east, but that precipitates a price war," said Allen, who also speculates that Sempra Energy's Cameron LNG facility in Louisiana might also be another possible LNG liquefaction facility.
Allen sees Gulf Coast liquefaction facilities as primarily serving the European market, while the Kitimat LNG plant in British Columbia has a competitive advantage in serving northeast Asian markets due to its proximity to Asia. The terminal would also provide a market for Canadian gas, as incremental demand in northern Washington, Oregon and northern California does not provide enough market for gas supply in the region.
Last month, Kitimat partners Apache Canada Ltd., and EOG Resources Canada said Encana Corporation would acquire a 30 percent working interest in the planned facility. The three companies have a significant presence in the Horn River Basin. According to a report by Scotiabank Group, demand for Kitimat LNG is expected to be boosted in the medium-term outlook as shifting to gas-fired power generation occurs in the U.S and parts of Europe and Japan shifts from nuclear energy to imported LNG.
One challenge facing North American LNG exporters is the lack of liquidity and transparency in the European LNG market. Since LNG traded on power exchanges in Europe can be done privately, with no price information disclosed, "we have no idea what LNG prices really are," Allen noted. The market is at best opaque, said Allen, but market forces will eventually push for more transparency.
North American exports of LNG have the potential to compete in cost terms in the global LNG market, Barclays Capital noted in an April 19 report. However, the successful development of liquefaction terminals will depend not only on economics, but ability of project sponsors to secure long term off-take agreements, access to capital and regulatory permits. The higher oil price environment anticipated by Barclays will help make North American LNG exports competitive; however, they are likely to come at the higher end of the LNG supply cost curve.
Solid credit is key for a company developing a North American liquefaction project due to the fact that U.S. and Canadian gas not stranded, as it usually is with liquefaction projects. In a traditional stranded gas project, the project developer would have to ensure that the sale price, with a known floor price, covered the break-even cost of the integrated facility and secured a certain return on the investment.
Both the U.S. and Canada have deep and liquid domestic gas markets that offer an alternative for feed gas; these alternatives make the all-in cost of LNG production a moving target. "It would take an enormous balance sheet to shoulder the risk of buying gas at Henry Hub and selling it at oil equivalents in Europe or Asia over a 20-year time-frame," Barclays noted.
Shale gas development around the world also could dampen LNG consumption, including China. However, Barclays estimated in a March 22 report that the effect of shale gas on Chinese LNG imports would be limited to about 1 Bcf/d over the next decade, given the constraints China faces in developing its shale gas. Shale gas exploration and development in other countries is still in the early stages, but worldwide success of shale gas development "could pose a significant downside risk to LNG import needs."
Friday, April 29, 2011
Rigzone Staff
by Karen Boman
The increase in North American natural gas due to the shale gas boom and a projected increase in global gas demand mean that North America will become a liquefied natural gas (LNG) exporter within the next few years.
The recovery in global LNG consumption in 2010, combined with anticipated gas demand growth in emerging economies of China and India presents opportunities for LNG exports, as does growing demand in Europe, where gas production is expected to decline and demand for gas-fired power generation is expected to grow. Near-term LNG demand also will be impacted by Japan, where the earthquake and tsunami damaged nuclear power facilities, resulting in strong demand for natural gas to fire electric power plants. However, it is too early to tell how this will impact Japan's long-term plans.
North American LNG exports should be sustained as long as North American shale gas production remains at existing levels, said Zach Allen, publisher of PanEurasian Enterprises NATS report, which tracks global LNG markets. Cheniere Energy's Sabine Pass in Louisiana and Freeport LNG in Texas are two existing LNG regasification facilities that will have liquefaction capacity added to allow for LNG exports.
Cheniere noted that adding liquefaction infrastructure to Sabine Pass will allow the company arbitrage opportunities for Henry Hub versus oil prices. Worldwide LNG prices are predominately based on oil prices, or between $10-$25/MMBtu, while Cheniere estimates the cost of delivering gas from Sabine Pass to Europe and Asia at between $7 - $12/MMbtu. The project also has the advantage of having significant infrastructure already in place, including storage, marine and pipeline interconnection facilities, which means lower capital costs.
The Cove Point LNG regasification facility near Baltimore, Maryland could potentially serve as an export facility for Marcellus shale gas, Allen noted. He sees Marcellus gas as a stranded asset, as it's difficult to move gas south from the Marcellus region. "Through displacement, you can move a certain amount of it to the north and east, but that precipitates a price war," said Allen, who also speculates that Sempra Energy's Cameron LNG facility in Louisiana might also be another possible LNG liquefaction facility.
Allen sees Gulf Coast liquefaction facilities as primarily serving the European market, while the Kitimat LNG plant in British Columbia has a competitive advantage in serving northeast Asian markets due to its proximity to Asia. The terminal would also provide a market for Canadian gas, as incremental demand in northern Washington, Oregon and northern California does not provide enough market for gas supply in the region.
Last month, Kitimat partners Apache Canada Ltd., and EOG Resources Canada said Encana Corporation would acquire a 30 percent working interest in the planned facility. The three companies have a significant presence in the Horn River Basin. According to a report by Scotiabank Group, demand for Kitimat LNG is expected to be boosted in the medium-term outlook as shifting to gas-fired power generation occurs in the U.S and parts of Europe and Japan shifts from nuclear energy to imported LNG.
North American exports of LNG have the potential to compete in cost terms in the global LNG market, Barclays Capital noted in an April 19 report. However, the successful development of liquefaction terminals will depend not only on economics, but ability of project sponsors to secure long term off-take agreements, access to capital and regulatory permits. The higher oil price environment anticipated by Barclays will help make North American LNG exports competitive; however, they are likely to come at the higher end of the LNG supply cost curve.
Solid credit is key for a company developing a North American liquefaction project due to the fact that U.S. and Canadian gas not stranded, as it usually is with liquefaction projects. In a traditional stranded gas project, the project developer would have to ensure that the sale price, with a known floor price, covered the break-even cost of the integrated facility and secured a certain return on the investment.
Both the U.S. and Canada have deep and liquid domestic gas markets that offer an alternative for feed gas; these alternatives make the all-in cost of LNG production a moving target. "It would take an enormous balance sheet to shoulder the risk of buying gas at Henry Hub and selling it at oil equivalents in Europe or Asia over a 20-year time-frame," Barclays noted.
Chevron Reports Mixed Q1, Beats EPS By $0.05, Revenue Up 23% But Huge Miss
Chevron Reports Mixed Q1, Beats EPS By $0.05, Revenue Up 23% But Huge Miss
Apr 29, 2011
Chevron (NYSE:CVX) reported Q1 EPS of $3.09 today, just above the consensus estimate for $3.04 per share. Revenue for the quarter was up 23.4%% year-over-year to $58.41 billion, well below the consensus estimate for $66.62 billion.
Chairman and CEO John Watson said, "Our first quarter financial performance was strong. Current quarter earnings from upstream operations benefited from higher prices for crude oil, while downstream operations benefited from improved margins on refined petroleum products. We continue to operate safely, advance our major capital projects and restructure our downstream portfolio."
Apr 29, 2011
Chevron (NYSE:CVX) reported Q1 EPS of $3.09 today, just above the consensus estimate for $3.04 per share. Revenue for the quarter was up 23.4%% year-over-year to $58.41 billion, well below the consensus estimate for $66.62 billion.
Chairman and CEO John Watson said, "Our first quarter financial performance was strong. Current quarter earnings from upstream operations benefited from higher prices for crude oil, while downstream operations benefited from improved margins on refined petroleum products. We continue to operate safely, advance our major capital projects and restructure our downstream portfolio."
March Consumer Spending Grows 0.6%, Personal Income Up 0.5%
March Consumer Spending Grows 0.6%, Personal Income Up 0.5%
Apr 29, 2011
March consumer spending was better than many had feared, showing a 0.6% rise in current dollar terms according to the Commerce Department, slightly higher than the 0.5% increase economists' had expected.
When adjusted for inflation, spending increased 0.2% in the month after rising 0.5% in January.
Consumer spending in both January and February was revised higher, with February spending getting bumped to 0.9% from 0.7%, and January spending to 0.5% from an initially estimated 0.3% increase.
It was feared higher energy prices could more severely slow consumers' spending. The personal consumption index (PCE) rose 0.4% in March after an increase of the same amount in February. Year-over-year the PCE is up 1.8%.
Core PCE, which excludes food and fuel, was up only 0.1% in March, after rising 0.2% in February, and is up 0.9% year-over-year.
Personal income for the month rose 0.5% in March, beating the expectation for a 0.3% gain.
Apr 29, 2011
March consumer spending was better than many had feared, showing a 0.6% rise in current dollar terms according to the Commerce Department, slightly higher than the 0.5% increase economists' had expected.
When adjusted for inflation, spending increased 0.2% in the month after rising 0.5% in January.
Consumer spending in both January and February was revised higher, with February spending getting bumped to 0.9% from 0.7%, and January spending to 0.5% from an initially estimated 0.3% increase.
It was feared higher energy prices could more severely slow consumers' spending. The personal consumption index (PCE) rose 0.4% in March after an increase of the same amount in February. Year-over-year the PCE is up 1.8%.
Core PCE, which excludes food and fuel, was up only 0.1% in March, after rising 0.2% in February, and is up 0.9% year-over-year.
Personal income for the month rose 0.5% in March, beating the expectation for a 0.3% gain.
Lukoil Enters Offshore Project in Vietnam
Lukoil Enters Offshore Project in Vietnam
Friday, April 29, 2011
Dow Jones Newswires
by Alexander Kolyandr
Lukoil has acquired 50% of the Vietnam offshore Hanoi Trough-02 oil project from privately-owned Quad Energy S.A., which still keep the other half of the project.
The production share agreement project offshore Vietnam at the South China Sea will be operated by Lukoil Overseas, a Lukoil subsidiary.
The field's resource is estimated at 180 millions metric tons of oil equivalent, Lukoil said.
Friday, April 29, 2011
Dow Jones Newswires
by Alexander Kolyandr
Lukoil has acquired 50% of the Vietnam offshore Hanoi Trough-02 oil project from privately-owned Quad Energy S.A., which still keep the other half of the project.
The production share agreement project offshore Vietnam at the South China Sea will be operated by Lukoil Overseas, a Lukoil subsidiary.
The field's resource is estimated at 180 millions metric tons of oil equivalent, Lukoil said.
Harvest Natural Spins Bit Offshore Gabon
Harvest Natural Spins Bit Offshore Gabon
Friday, April 29, 201
Harvest Natural Resources Inc.
Harvest Natural Resources announced the commencement of drilling operations on the Ruche Marin-A exploration well located in the offshore waters of Gabon, West Africa. This exploration well will be drilled utilizing the Transocean Sedneth 701 semi-submersible drilling unit.
The Ruche Marin-A well will be drilled in a water depth of 380 feet to test multiple stacked pre-salt targets to a planned total measured depth of approximately 10,100 feet. Drilling is anticipated to require approximately 28 days. In the event of success, additional time will be required to test and evaluate the well.
Friday, April 29, 201
Harvest Natural Resources Inc.
Harvest Natural Resources announced the commencement of drilling operations on the Ruche Marin-A exploration well located in the offshore waters of Gabon, West Africa. This exploration well will be drilled utilizing the Transocean Sedneth 701 semi-submersible drilling unit.
The Ruche Marin-A well will be drilled in a water depth of 380 feet to test multiple stacked pre-salt targets to a planned total measured depth of approximately 10,100 feet. Drilling is anticipated to require approximately 28 days. In the event of success, additional time will be required to test and evaluate the well.
Breitling Spuds Tx. Well
Breitling Spuds Tx. Well
Friday, April 29, 2011
Breitling O&G Corp.
Breitling has spud the Breitling-Salsa #1 in San Patricio County, Texas as it continues to develop its Gulf Coast Onshore Initiative that began in May 2010.
The Breitling-Salsa #1 Prospect is expected to be drilled to 4800 feet to test Upper Frio-aged oil and gas sands. The drill site is near two fields that together have produced 210 million BO and 314 BCF. The prospect is targeting stacked Frio objectives in a four-way closure (anticline) updip to oil production in the Plymouth Field (125 million BO and 134 BCF). The primary objectives of the Breitling-Salsa Prospect are 3 proven productive zones in the Greta Stringer formation and 2 zones in the Greta Massive formation. The anticlinal structure is generally defined by subsurface well control with the interpretation and proposed location confirmed by integrating 3D Seismic.
Management anticipates the well will reach total depth in about 8 days. Well completion and testing on the Breitling-Salsa #1 well should begin during the third week of May 2011.
Breitling Oil and Gas CEO Chris Faulkner stated, "You have huge surrounding production from the Frio, Miocene and Vicksburg-aged sandstone reservoirs in this area." Faulkner added, "The Breitling-Salsa has great potential to IP above 200 barrels of oil per day and show us cumulative production above 700,000 barrels."
Friday, April 29, 2011
Breitling O&G Corp.
Breitling has spud the Breitling-Salsa #1 in San Patricio County, Texas as it continues to develop its Gulf Coast Onshore Initiative that began in May 2010.
The Breitling-Salsa #1 Prospect is expected to be drilled to 4800 feet to test Upper Frio-aged oil and gas sands. The drill site is near two fields that together have produced 210 million BO and 314 BCF. The prospect is targeting stacked Frio objectives in a four-way closure (anticline) updip to oil production in the Plymouth Field (125 million BO and 134 BCF). The primary objectives of the Breitling-Salsa Prospect are 3 proven productive zones in the Greta Stringer formation and 2 zones in the Greta Massive formation. The anticlinal structure is generally defined by subsurface well control with the interpretation and proposed location confirmed by integrating 3D Seismic.
Management anticipates the well will reach total depth in about 8 days. Well completion and testing on the Breitling-Salsa #1 well should begin during the third week of May 2011.
Breitling Oil and Gas CEO Chris Faulkner stated, "You have huge surrounding production from the Frio, Miocene and Vicksburg-aged sandstone reservoirs in this area." Faulkner added, "The Breitling-Salsa has great potential to IP above 200 barrels of oil per day and show us cumulative production above 700,000 barrels."
Bontan Updates on Sara, Myra Licenses
Bontan Updates on Sara, Myra Licenses
Friday, April 29, 2011
ontan Corp. Inc.
Bontan issued following update with respect to its indirect working interest of 5.23% in the Israeli project comprising Sara and Myra licenses located in the Levantine Basin:
Israel Rig Contract - Myra and Sara Licenses
The operator of the consortium of the Licenses has entered into an Assignment Agreement with a third party, whereby, the operator has taken assignment of a third party's rights and obligations to an existing Drill Rig and Associated Services Contract for a Semisubmersible Drilling Rig, subject to certain terms and conditions.
Additional Information about the Offshore Israel Project
The rights in the Licenses for the Offshore Israel Project are held by a group consisting of IPC Israel, Emanuelle Energy Ltd, Modiin Energy Limited Partnership, Emanuelle Energy Oil and Gas Limited Partnership and other entities including the operator, GeoGlobal Resources (India) Inc.
Bontan's share of the Working Interest in the Licenses is 5.23% through the holding of 50% equity in IPC Israel by Bontan's subsidiary, IPC Cayman.
Friday, April 29, 2011
ontan Corp. Inc.
Bontan issued following update with respect to its indirect working interest of 5.23% in the Israeli project comprising Sara and Myra licenses located in the Levantine Basin:
Israel Rig Contract - Myra and Sara Licenses
The operator of the consortium of the Licenses has entered into an Assignment Agreement with a third party, whereby, the operator has taken assignment of a third party's rights and obligations to an existing Drill Rig and Associated Services Contract for a Semisubmersible Drilling Rig, subject to certain terms and conditions.
Additional Information about the Offshore Israel Project
The rights in the Licenses for the Offshore Israel Project are held by a group consisting of IPC Israel, Emanuelle Energy Ltd, Modiin Energy Limited Partnership, Emanuelle Energy Oil and Gas Limited Partnership and other entities including the operator, GeoGlobal Resources (India) Inc.
Bontan's share of the Working Interest in the Licenses is 5.23% through the holding of 50% equity in IPC Israel by Bontan's subsidiary, IPC Cayman.
Enbridge to Expand Haynesville Shale Infrastructure
Enbridge to Expand Haynesville Shale Infrastructure
Friday, April 29, 2011
Enbridge Energy Partners L.P.
Enbridge announced that it plans to invest an additional $175 million to expand its East Texas system. The Partnership has signed long-term agreements with several major natural gas producers on the Texas side of the Haynesville shale to provide gathering, treating and transmission services in Shelby, Sabine, San Augustine and Nacogdoches counties. The projects involve construction of gathering and related market outlet pipelines and related treating facilities in the Texas Haynesville shale.
"We are pleased to announce these new projects for our customers in the Texas Haynesville shale region. Our East Texas system is well positioned with substantial infrastructure and unmatched access to numerous intrastate and interstate connecting pipelines. We envision additional infrastructure development for our customers beyond what we've already committed in this region," said Mark Maki, president of the Partnership's management company. "We consider the Texas Haynesville to be one of the best natural gas plays in North America and expect long-term fundamentals to support development of this resource well into the future. These projects will support continued growth in cash flow and distributions for our unit holders."
Friday, April 29, 2011
Enbridge Energy Partners L.P.
Enbridge announced that it plans to invest an additional $175 million to expand its East Texas system. The Partnership has signed long-term agreements with several major natural gas producers on the Texas side of the Haynesville shale to provide gathering, treating and transmission services in Shelby, Sabine, San Augustine and Nacogdoches counties. The projects involve construction of gathering and related market outlet pipelines and related treating facilities in the Texas Haynesville shale.
"We are pleased to announce these new projects for our customers in the Texas Haynesville shale region. Our East Texas system is well positioned with substantial infrastructure and unmatched access to numerous intrastate and interstate connecting pipelines. We envision additional infrastructure development for our customers beyond what we've already committed in this region," said Mark Maki, president of the Partnership's management company. "We consider the Texas Haynesville to be one of the best natural gas plays in North America and expect long-term fundamentals to support development of this resource well into the future. These projects will support continued growth in cash flow and distributions for our unit holders."
ExxonMobil Files Development Plans for Hebron
ExxonMobil Files Development Plans for Hebron
Friday, April 29, 2011
Rigzone Staff
ExxonMobil has filed a development application with the Newfoundland and Labrador regulatory board for the Hebron project. The Board is in the process of reviewing the application. Once the application has gone through the review process, the Board will begin a public review period.
A review of the merits of the project will not commence until the Board is satisfied that it has received a complete application. ExxonMobil and its partners have yet to file a benefits plan and other supporting documentation in connection to the application. These documents are expected to be provided to the Board by early May.
The Hebron Project is located offshore St. John's Newfoundland and Labrador in the Jeanne d'Arc Basin in the North Atlantic Ocean. Production is expected to begin no later than the end of 2017. This will be the fourth stand-along development project on the Grand Banks. Oil from Hebron will be produced from a concrete gravity base structure (GBS). The scope of the project is expected to span over 30 years from the initial development phase, through installation and operations, decommissioning and abandonment. The facility will be designed to handle an estimated production rate of approximately 150,000 barrels of oil per day, which can potentially increase to 180,000 barrels of oil per day.
Friday, April 29, 2011
Rigzone Staff
ExxonMobil has filed a development application with the Newfoundland and Labrador regulatory board for the Hebron project. The Board is in the process of reviewing the application. Once the application has gone through the review process, the Board will begin a public review period.
A review of the merits of the project will not commence until the Board is satisfied that it has received a complete application. ExxonMobil and its partners have yet to file a benefits plan and other supporting documentation in connection to the application. These documents are expected to be provided to the Board by early May.
The Hebron Project is located offshore St. John's Newfoundland and Labrador in the Jeanne d'Arc Basin in the North Atlantic Ocean. Production is expected to begin no later than the end of 2017. This will be the fourth stand-along development project on the Grand Banks. Oil from Hebron will be produced from a concrete gravity base structure (GBS). The scope of the project is expected to span over 30 years from the initial development phase, through installation and operations, decommissioning and abandonment. The facility will be designed to handle an estimated production rate of approximately 150,000 barrels of oil per day, which can potentially increase to 180,000 barrels of oil per day.
Rosneft Net Profit Up 58% at $3.94B, Beats Expectations
Rosneft Net Profit Up 58% at $3.94B, Beats Expectations
Friday, April 29, 2011
Dow Jones Newswires
by Jacob Gronholt-Pedersen
Rosneft said first-quarter net profit rose 58% from last year on higher oil prices and crude output as well as tax breaks on its Vankor field.
London-listed Rosneft said net profit under U.S. Generally Accepted Accounting Principles rose to $3.94 billion from $2.49 billion in the first quarter of 2010, above a forecast of $3.72 billion in a Dow Jones Newswires survey of eight analysts.
Revenue increased 36% to $20.12 billion from $14.76 billion a year earlier, boosted by a surge in global crude prices as well as higher output, helped by a ramp-up of production at the huge East Siberian Vankor field. Analysts had expected revenue of $20.3 billion.
Earnings before interest, taxes, depreciation and amortization, or Ebitda, rose 50% to $6.65 billion from $4.44 billion and were above analysts' expectation of $6.42 billion.
Rosneft said it produced 2.564 million barrels of oil equivalent per day during the quarter, and lowered net debt by 19% in the three months to $11.1 billion.
Friday, April 29, 2011
Dow Jones Newswires
by Jacob Gronholt-Pedersen
Rosneft said first-quarter net profit rose 58% from last year on higher oil prices and crude output as well as tax breaks on its Vankor field.
London-listed Rosneft said net profit under U.S. Generally Accepted Accounting Principles rose to $3.94 billion from $2.49 billion in the first quarter of 2010, above a forecast of $3.72 billion in a Dow Jones Newswires survey of eight analysts.
Revenue increased 36% to $20.12 billion from $14.76 billion a year earlier, boosted by a surge in global crude prices as well as higher output, helped by a ramp-up of production at the huge East Siberian Vankor field. Analysts had expected revenue of $20.3 billion.
Earnings before interest, taxes, depreciation and amortization, or Ebitda, rose 50% to $6.65 billion from $4.44 billion and were above analysts' expectation of $6.42 billion.
Rosneft said it produced 2.564 million barrels of oil equivalent per day during the quarter, and lowered net debt by 19% in the three months to $11.1 billion.
Entergy Reports Mixed Q1 Results, EPS Beats By $0.05, Revenue Down 8% YoY
Entergy Reports Mixed Q1 Results, EPS Beats By $0.05, Revenue Down 8% YoY
Apr 29, 2011
Entergy Corporation (NYSE:ETR) reported Q1 EPS of $1.38 today, beating the consensus estimate for $1.33 per share. Revenue for the quarter was down 8% year-over-year to $2.54 billion, below the consensus estimate for $2.79 billion.
J. Wayne Leonard, Entergy's chairman and chief executive officer said, "Results for the quarter reflect the continued benefits of constructive regulatory decisions. The quarter also brought challenges to the business climate for the nuclear industry with the tragic events at the Fukushima Daiichi plant in Japan. As always, we will continue our intense focus on safety and operational excellence in all aspects of our business. Whatever learning may come from the Fukushima event will be quickly applied to our own emergency preparation and processes."
The company affirmed its 2011 EPS guidance in the range of $6.35 to $6.85, in-line with the consensus estimate of $6.55 per share.
Apr 29, 2011
Entergy Corporation (NYSE:ETR) reported Q1 EPS of $1.38 today, beating the consensus estimate for $1.33 per share. Revenue for the quarter was down 8% year-over-year to $2.54 billion, below the consensus estimate for $2.79 billion.
J. Wayne Leonard, Entergy's chairman and chief executive officer said, "Results for the quarter reflect the continued benefits of constructive regulatory decisions. The quarter also brought challenges to the business climate for the nuclear industry with the tragic events at the Fukushima Daiichi plant in Japan. As always, we will continue our intense focus on safety and operational excellence in all aspects of our business. Whatever learning may come from the Fukushima event will be quickly applied to our own emergency preparation and processes."
The company affirmed its 2011 EPS guidance in the range of $6.35 to $6.85, in-line with the consensus estimate of $6.55 per share.
Chevron Reports $6.2B in 1Q11 Earnings
Chevron Reports $6.2B in 1Q11 Earnings
Friday, April 29, 2011
Chevron Corp.
Chevron reported earnings of $6.2 billion ($3.09 per share – diluted) for the first quarter 2011, compared with $4.6 billion ($2.27 per share – diluted) in the 2010 first quarter.
Sales and other operating revenues in the first quarter 2011 were $58 billion, up from $47 billion in the year-ago period, mainly due to higher prices for crude oil and refined products.
"Our first quarter financial performance was strong," said Chairman and CEO John Watson. "Current quarter earnings from upstream operations benefited from higher prices for crude oil, while downstream operations benefited from improved margins on refined petroleum products. We continue to operate safely, advance our major capital projects and restructure our downstream portfolio."
Watson continued, "We are aggressively investing in affordable supplies of new energy to meet the needs of a growing economy. Our combined capital outlays and investments during the quarter amounted to over $8 billion." The company completed the acquisition of Atlas Energy, Inc., which provides a premier position in the Marcellus Shale in southwestern Pennsylvania, and strengthens the company's global position in developing unconventional gas resources. The company continues to advance its major capital projects, including deepwater projects in the Gulf of Mexico and multiple LNG projects in Angola and Australia. The Gorgon Project in Australia continues on pace, and the company finalized agreements to bring another major participant into the Australian Wheatstone Project as both a natural gas supplier and equity participant.
Watson continued, "We recently received our first deepwater exploratory drilling permit in the Gulf of Mexico following the moratorium, and have resumed work on our Moccasin well that was suspended in June of last year. The resumption of deepwater drilling activity in the Gulf of Mexico is vital to improving our nation's energy security and supporting the economic recovery. We are working with the government to improve the efficiency and transparency of the permitting process."
"In the downstream business, we made further progress on streamlining our asset portfolio," Watson added. The company announced an agreement to sell its 220,000-barrels-per-day Pembroke Refinery and other downstream assets in the United Kingdom and Ireland for $730 million, plus additional proceeds estimated at $1 billion for the company's inventory and other working capital. The transaction is expected to close in the second-half 2011. The company also announced an agreement to sell its fuels, finished lubricants and aviation fuels businesses in Spain, and completed the sale of its fuels-marketing and aviation businesses in nine eastern Caribbean countries as well as its fuels-marketing businesses in two African countries.
Also in the first quarter, the company announced the final investment decision on a $1.4 billion project to construct a lubricants base oil manufacturing facility at the Pascagoula, Mississippi, refinery. The facility is designed to manufacture 25,000 barrels per day of premium base oil. Project completion is expected by year-end 2013.
The company purchased $750 million of its common stock in the first quarter 2011.
UPSTREAM
Worldwide net oil-equivalent production was 2.76 million barrels per day in the first quarter 2011, down from 2.78 million barrels per day in the 2010 first quarter. Production increases in Brazil, Nigeria, Thailand and Canada were more than offset by normal field declines, a one percent negative volume effect of higher prices on cost-recovery volumes and other contractual provisions as well as decreases due to weather- and maintenance-related downtime.
U.S. upstream earnings of $1.45 billion in the first quarter 2011 were up $293 million from a year earlier. The benefit of higher crude oil realizations was partly offset by decreased net oil-equivalent production and lower natural gas realizations.
The company's average sales price per barrel of crude oil and natural gas liquids was approximately $89 in the 2011 quarter, compared with $71 a year ago. The average sales price of natural gas was $4.04 per thousand cubic feet, down from $5.29 in last year's first quarter.
Net oil-equivalent production of 694,000 barrels per day in the first quarter 2011 was down 40,000 barrels per day, or about 5 percent, from a year earlier. The decrease in production was associated with normal field declines and weather- and maintenance-related downtime. Partially offsetting this decrease was new production at both Perdido in the Gulf of Mexico and from the acquisition of Atlas Energy, Inc. The net liquids component of oil-equivalent production decreased approximately 5 percent in the 2011 first quarter to 482,000 barrels per day, while net natural gas production declined about 8 percent to 1.27 billion cubic feet per day.
International upstream earnings of $4.53 billion increased $960 million from the first quarter 2010. Higher prices and sales volumes for crude oil increased earnings between quarters. This benefit was partly offset by higher operating expenses, including fuel, and tax items. Depreciation expenses were also higher between periods. Foreign currency effects decreased earnings by $116 million in the 2011 quarter, compared with a decrease of $102 million a year earlier.
The average sales price for crude oil and natural gas liquids in the 2011 quarter was $95 per barrel, compared with $70 a year earlier. The average price of natural gas was $5.03 per thousand cubic feet, up from $4.61 in last year's first quarter.
Net oil-equivalent production of 2.07 million barrels per day in the first quarter 2011 was up approximately 17,000 barrels per day from a year ago. The increase included 73,000 barrels per day associated with higher production in Brazil, Nigeria, Thailand and Canada. Partially offsetting this increase were a negative effect of higher prices on cost-recovery volumes and other contractual provisions as well as decreases due to weather- and maintenance-related downtime and normal field declines. The net liquids component of oil-equivalent production remained flat at 1.43 million barrels per day, while net natural gas production was up about 3 percent to 3.83 billion cubic feet per day.
CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures in the first quarter 2011 were $5.0 billion, compared with $4.4 billion in the first quarter 2010. The amounts included approximately $200 million in 2011 and $300 million in 2010 for the company's share of expenditures by affiliates, which did not require cash outlays by the company. Expenditures for upstream projects represented 92 percent of the companywide total in the first quarter 2011. These amounts exclude the acquisition of Atlas Energy, Inc.
Friday, April 29, 2011
Chevron Corp.
Chevron reported earnings of $6.2 billion ($3.09 per share – diluted) for the first quarter 2011, compared with $4.6 billion ($2.27 per share – diluted) in the 2010 first quarter.
Sales and other operating revenues in the first quarter 2011 were $58 billion, up from $47 billion in the year-ago period, mainly due to higher prices for crude oil and refined products.
"Our first quarter financial performance was strong," said Chairman and CEO John Watson. "Current quarter earnings from upstream operations benefited from higher prices for crude oil, while downstream operations benefited from improved margins on refined petroleum products. We continue to operate safely, advance our major capital projects and restructure our downstream portfolio."
Watson continued, "We are aggressively investing in affordable supplies of new energy to meet the needs of a growing economy. Our combined capital outlays and investments during the quarter amounted to over $8 billion." The company completed the acquisition of Atlas Energy, Inc., which provides a premier position in the Marcellus Shale in southwestern Pennsylvania, and strengthens the company's global position in developing unconventional gas resources. The company continues to advance its major capital projects, including deepwater projects in the Gulf of Mexico and multiple LNG projects in Angola and Australia. The Gorgon Project in Australia continues on pace, and the company finalized agreements to bring another major participant into the Australian Wheatstone Project as both a natural gas supplier and equity participant.
Watson continued, "We recently received our first deepwater exploratory drilling permit in the Gulf of Mexico following the moratorium, and have resumed work on our Moccasin well that was suspended in June of last year. The resumption of deepwater drilling activity in the Gulf of Mexico is vital to improving our nation's energy security and supporting the economic recovery. We are working with the government to improve the efficiency and transparency of the permitting process."
"In the downstream business, we made further progress on streamlining our asset portfolio," Watson added. The company announced an agreement to sell its 220,000-barrels-per-day Pembroke Refinery and other downstream assets in the United Kingdom and Ireland for $730 million, plus additional proceeds estimated at $1 billion for the company's inventory and other working capital. The transaction is expected to close in the second-half 2011. The company also announced an agreement to sell its fuels, finished lubricants and aviation fuels businesses in Spain, and completed the sale of its fuels-marketing and aviation businesses in nine eastern Caribbean countries as well as its fuels-marketing businesses in two African countries.
Also in the first quarter, the company announced the final investment decision on a $1.4 billion project to construct a lubricants base oil manufacturing facility at the Pascagoula, Mississippi, refinery. The facility is designed to manufacture 25,000 barrels per day of premium base oil. Project completion is expected by year-end 2013.
The company purchased $750 million of its common stock in the first quarter 2011.
UPSTREAM
Worldwide net oil-equivalent production was 2.76 million barrels per day in the first quarter 2011, down from 2.78 million barrels per day in the 2010 first quarter. Production increases in Brazil, Nigeria, Thailand and Canada were more than offset by normal field declines, a one percent negative volume effect of higher prices on cost-recovery volumes and other contractual provisions as well as decreases due to weather- and maintenance-related downtime.
U.S. upstream earnings of $1.45 billion in the first quarter 2011 were up $293 million from a year earlier. The benefit of higher crude oil realizations was partly offset by decreased net oil-equivalent production and lower natural gas realizations.
The company's average sales price per barrel of crude oil and natural gas liquids was approximately $89 in the 2011 quarter, compared with $71 a year ago. The average sales price of natural gas was $4.04 per thousand cubic feet, down from $5.29 in last year's first quarter.
Net oil-equivalent production of 694,000 barrels per day in the first quarter 2011 was down 40,000 barrels per day, or about 5 percent, from a year earlier. The decrease in production was associated with normal field declines and weather- and maintenance-related downtime. Partially offsetting this decrease was new production at both Perdido in the Gulf of Mexico and from the acquisition of Atlas Energy, Inc. The net liquids component of oil-equivalent production decreased approximately 5 percent in the 2011 first quarter to 482,000 barrels per day, while net natural gas production declined about 8 percent to 1.27 billion cubic feet per day.
International upstream earnings of $4.53 billion increased $960 million from the first quarter 2010. Higher prices and sales volumes for crude oil increased earnings between quarters. This benefit was partly offset by higher operating expenses, including fuel, and tax items. Depreciation expenses were also higher between periods. Foreign currency effects decreased earnings by $116 million in the 2011 quarter, compared with a decrease of $102 million a year earlier.
The average sales price for crude oil and natural gas liquids in the 2011 quarter was $95 per barrel, compared with $70 a year earlier. The average price of natural gas was $5.03 per thousand cubic feet, up from $4.61 in last year's first quarter.
Net oil-equivalent production of 2.07 million barrels per day in the first quarter 2011 was up approximately 17,000 barrels per day from a year ago. The increase included 73,000 barrels per day associated with higher production in Brazil, Nigeria, Thailand and Canada. Partially offsetting this increase were a negative effect of higher prices on cost-recovery volumes and other contractual provisions as well as decreases due to weather- and maintenance-related downtime and normal field declines. The net liquids component of oil-equivalent production remained flat at 1.43 million barrels per day, while net natural gas production was up about 3 percent to 3.83 billion cubic feet per day.
CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures in the first quarter 2011 were $5.0 billion, compared with $4.4 billion in the first quarter 2010. The amounts included approximately $200 million in 2011 and $300 million in 2010 for the company's share of expenditures by affiliates, which did not require cash outlays by the company. Expenditures for upstream projects represented 92 percent of the companywide total in the first quarter 2011. These amounts exclude the acquisition of Atlas Energy, Inc.
Total Reports Q1 Earnings Up 51% To $5.86 Billion
Total Reports Q1 Earnings Up 51% To $5.86 Billion
Apr 29, 2011
Total (NYSE:TOT) reported Q1 earnings of $5.86 billion, up 51% from the $3.87 billion the company earned in Q1 of 2010. Revenue for the quarter was up 22% year-over-year to $68.29 billion.
Chief Executive Christophe de Margerie said, "Growing geopolitical tensions and the aftermath of the earthquake in Japan will shift the balance of the global energy markets. In the face of these new challenges, Total confirms its strategy of investing to increase its production to better respond to changes in energy demand and in the energy mix."
Total announced Thursday night a $1.37 billion proposal to take 60% of SunPower Corp. (NASDAQ:SPWRA), a U.S. solar manufacturer, in an effort to boost its renewable-energy portfolio.
Apr 29, 2011
Total (NYSE:TOT) reported Q1 earnings of $5.86 billion, up 51% from the $3.87 billion the company earned in Q1 of 2010. Revenue for the quarter was up 22% year-over-year to $68.29 billion.
Chief Executive Christophe de Margerie said, "Growing geopolitical tensions and the aftermath of the earthquake in Japan will shift the balance of the global energy markets. In the face of these new challenges, Total confirms its strategy of investing to increase its production to better respond to changes in energy demand and in the energy mix."
Total announced Thursday night a $1.37 billion proposal to take 60% of SunPower Corp. (NASDAQ:SPWRA), a U.S. solar manufacturer, in an effort to boost its renewable-energy portfolio.
IHS: Niobrara Resource Potential Not Yet Proven
IHS: Niobrara Resource Potential Not Yet Proven
Friday, April 29, 2011
Rigzone Staff
Despite enthusiasm by exploration and production (E&P) companies and investors, successful development efforts to unlock the Niobrara horizontal oil play's resource potential has been limited, and more time is needed to further delineate its true potential as a resource play, according to a special report by IHS.
IHS studied the performance of a few modern horizontal oil wells present in the Niobrara and compared initial production rates of these wells against initial production rates for median-producing oil wells in the core of the Bakken/Three Forks shale play.
According to IHS, the median Bakken horizontal well completed since 2009 in the play's core averaged about 230 b/d of oil in its six month online. Two modern Niobrara horizontal wells matched or exceeded that oil production level, with the remaining 10 wells producing between 10 b/d and 190 b/d. In their sixth month, five of these wells produced 70 b/d of oil or less; three produced between 100 b/d and 125 b/d; and the remaining two wells produced approximately 185 b/d.
While enthusiasm for the Niobrara is likely tied to the success of the Bakken/Three Forks play, study author and IHS principal energy equity analyst Sven Del Pozzo noted that definitive conclusions of the Niobrara potential can't be made at this early stage, since fewer than 20 modern horizontal Niobrara wells in the DJ and North Park basins have 365 days of IHS production history, "and just 10 of those have a meaningful oil cut."
The author said he doesn't necessarily disagree with the expectations of E&P companies that experience will enhance both well performance and predictability in the Niobrara. However, Del Pozzo said those who have cited the Niobrara play's best wells as indicative of future results are being a bit premature due the variability and lack of production data.
"The Niobrara is situated at various depths and has diverse rock properties as it spans multiple basins, making it very risky to generalize about its prospectivity at this stage," Del Pozzo said. In comparison, the Bakken's production is predictable over a wide area, compared with the Niobrara, where well performance still varies considerably, even in the same field.
The Niobrara play extends from Wyoming and Colorado into Nebraska and Kansas.
Horizontal Drilling Boosts 2010 Oil Production
Horizontal drilling activity in the Bakken and other U.S. oil shale formations helped boost U.S. oil production. The U.S. Energy Information Administration (EIA) reported this week that U.S. oil production grew in 2009 and 2010 after experiencing declines in all but one year from 1986 to 2008.
While the 2009 production increase resulted from deepwater Gulf of Mexico activity, EIA attributed the 2010 growth to oil shale drilling. "Operators are combining horizontal wells and hydraulic fracturing – the same technologies used to significantly boost shale gas production – to do the same for oil," EIA said.
Total oil production in North Dakota has approximately tripled since 2005 thanks to development of the Bakken play, which extends into Montana and parts of Canada. North Dakota Bakken production has increased from less than 3,000 b/d in 2005 to over 230,000 b/d in 2010, and the Bakken's share of North Dakota oil production rose from about three percent to about 75 percent during the same period of time.
Shale plays known primarily for gas production also are seeing an acceleration of oil-focused drilling as strong oil prices has prompted producers to switch their focus from shale gas to shale oil. In Texas, oil production from the Barnett shale play has more than tripled from 2005 to 2010, while Woodford shale oil production in Oklahoma passed the 4,000 b/d mark in 2010, up 42 percent from 2009 and nearly three times 2008 volumes.
The Eagle Ford oil shale play in Texas, which had negligible production in 2005, approached 30,000 b/d in 2010. Oil production from Appalachia's Marcellus shale more than doubled in 2010 from a year earlier and has grown nearly thirteen-fold since 2007.
The Baker Hughes rig count currently shows more active oil-directed rigs than gas-directed rigs. Natural gas rigs generally accounted for between 80 percent and 90 percent of the total weekly rig count during most of the 2000s. However, the number of rigs targeting oil deposits climbing began climbing significantly in mid-2009.
The importance of horizontal drilling to increasing oil production is also underscored by the Baker Hughes rig count data, EIA noted. Horizontal rigs comprised less than one-third of oil-directed rigs in September 2008; since then, the number of horizontal oil rigs has tripled, increasing that share to about 46 percent.
The increase in crude oil prices relative to gas prices is one factor responsible for the shift towards oil-focused drilling. The crude oil-to-natural gas price ratio, which through mid-2009 averaged over eight from 2000 through mid-2009, has since risen considerably. EIA noted that, when the Brent crude spot price in dollars per barrel is divided by the Henry Hub spot price of gas in dollars per MMBtu, oil is five times more valuable than gas on an energy-equivalent basis.
Friday, April 29, 2011
Rigzone Staff
Despite enthusiasm by exploration and production (E&P) companies and investors, successful development efforts to unlock the Niobrara horizontal oil play's resource potential has been limited, and more time is needed to further delineate its true potential as a resource play, according to a special report by IHS.
IHS studied the performance of a few modern horizontal oil wells present in the Niobrara and compared initial production rates of these wells against initial production rates for median-producing oil wells in the core of the Bakken/Three Forks shale play.
According to IHS, the median Bakken horizontal well completed since 2009 in the play's core averaged about 230 b/d of oil in its six month online. Two modern Niobrara horizontal wells matched or exceeded that oil production level, with the remaining 10 wells producing between 10 b/d and 190 b/d. In their sixth month, five of these wells produced 70 b/d of oil or less; three produced between 100 b/d and 125 b/d; and the remaining two wells produced approximately 185 b/d.
While enthusiasm for the Niobrara is likely tied to the success of the Bakken/Three Forks play, study author and IHS principal energy equity analyst Sven Del Pozzo noted that definitive conclusions of the Niobrara potential can't be made at this early stage, since fewer than 20 modern horizontal Niobrara wells in the DJ and North Park basins have 365 days of IHS production history, "and just 10 of those have a meaningful oil cut."
The author said he doesn't necessarily disagree with the expectations of E&P companies that experience will enhance both well performance and predictability in the Niobrara. However, Del Pozzo said those who have cited the Niobrara play's best wells as indicative of future results are being a bit premature due the variability and lack of production data.
"The Niobrara is situated at various depths and has diverse rock properties as it spans multiple basins, making it very risky to generalize about its prospectivity at this stage," Del Pozzo said. In comparison, the Bakken's production is predictable over a wide area, compared with the Niobrara, where well performance still varies considerably, even in the same field.
The Niobrara play extends from Wyoming and Colorado into Nebraska and Kansas.
Horizontal Drilling Boosts 2010 Oil Production
Horizontal drilling activity in the Bakken and other U.S. oil shale formations helped boost U.S. oil production. The U.S. Energy Information Administration (EIA) reported this week that U.S. oil production grew in 2009 and 2010 after experiencing declines in all but one year from 1986 to 2008.
While the 2009 production increase resulted from deepwater Gulf of Mexico activity, EIA attributed the 2010 growth to oil shale drilling. "Operators are combining horizontal wells and hydraulic fracturing – the same technologies used to significantly boost shale gas production – to do the same for oil," EIA said.
Total oil production in North Dakota has approximately tripled since 2005 thanks to development of the Bakken play, which extends into Montana and parts of Canada. North Dakota Bakken production has increased from less than 3,000 b/d in 2005 to over 230,000 b/d in 2010, and the Bakken's share of North Dakota oil production rose from about three percent to about 75 percent during the same period of time.
Shale plays known primarily for gas production also are seeing an acceleration of oil-focused drilling as strong oil prices has prompted producers to switch their focus from shale gas to shale oil. In Texas, oil production from the Barnett shale play has more than tripled from 2005 to 2010, while Woodford shale oil production in Oklahoma passed the 4,000 b/d mark in 2010, up 42 percent from 2009 and nearly three times 2008 volumes.
The Eagle Ford oil shale play in Texas, which had negligible production in 2005, approached 30,000 b/d in 2010. Oil production from Appalachia's Marcellus shale more than doubled in 2010 from a year earlier and has grown nearly thirteen-fold since 2007.
The Baker Hughes rig count currently shows more active oil-directed rigs than gas-directed rigs. Natural gas rigs generally accounted for between 80 percent and 90 percent of the total weekly rig count during most of the 2000s. However, the number of rigs targeting oil deposits climbing began climbing significantly in mid-2009.
The importance of horizontal drilling to increasing oil production is also underscored by the Baker Hughes rig count data, EIA noted. Horizontal rigs comprised less than one-third of oil-directed rigs in September 2008; since then, the number of horizontal oil rigs has tripled, increasing that share to about 46 percent.
The increase in crude oil prices relative to gas prices is one factor responsible for the shift towards oil-focused drilling. The crude oil-to-natural gas price ratio, which through mid-2009 averaged over eight from 2000 through mid-2009, has since risen considerably. EIA noted that, when the Brent crude spot price in dollars per barrel is divided by the Henry Hub spot price of gas in dollars per MMBtu, oil is five times more valuable than gas on an energy-equivalent basis.
Petrobras Strikes Oil in Campos Basin
Petrobras Strikes Oil in Campos Basin
Friday, April 29, 2011
Petrobras
Petrobras announced the discovery of a new oil accumulation in the Campos Basin pre-salt, through well 6-AB-119D-RJS drilled in the Albacora field, 107 km off the coast and only 3.2km from the FPSO P-31, by semisub Ocean Concord.
Preliminary volume estimates indicate an economically recoverable volume potential of approximately 350 million barrels of good quality oil (light).
Drilled at a water depth of 380m, it reached the total depth of 4835m, where an oil column of 241m was found, of which 104m are from the carbonate reservoirs of the Macabu Formation, with porosity around 10%.
This discovery will be the object of the Assessment Plan to be opportunely submitted to the ANP. The execution of the Long Duration Test to investigate the production behavior of this new accumulation will be decided after the assessment of the cased-hole drill-stem tests (CHDST) programmed for two selected intervals.
Friday, April 29, 2011
Petrobras
Petrobras announced the discovery of a new oil accumulation in the Campos Basin pre-salt, through well 6-AB-119D-RJS drilled in the Albacora field, 107 km off the coast and only 3.2km from the FPSO P-31, by semisub Ocean Concord.
Preliminary volume estimates indicate an economically recoverable volume potential of approximately 350 million barrels of good quality oil (light).
Drilled at a water depth of 380m, it reached the total depth of 4835m, where an oil column of 241m was found, of which 104m are from the carbonate reservoirs of the Macabu Formation, with porosity around 10%.
This discovery will be the object of the Assessment Plan to be opportunely submitted to the ANP. The execution of the Long Duration Test to investigate the production behavior of this new accumulation will be decided after the assessment of the cased-hole drill-stem tests (CHDST) programmed for two selected intervals.
Coastal Energy Hits Net Pay at Bua Ban North
Coastal Energy Hits Net Pay at Bua Ban North
Friday, April 29, 2011
Coastal Energy Co.
Coastal Energy announced the successful results of the Bua Ban North B-01 exploration well.
The Bua Ban North B-01 well was drilled to 7,960 feet TVD and encountered 28 feet of net pay in the Upper Oligocene with 23% average porosity and 29 feet of net pay in the Lower Oligocene with 16% average porosity. Net pay estimates are based on log analysis, shows and MDT analysis; the well has not been flow tested. The Company estimates that this fault block contains a total of 13 million barrels of oil in place across these two intervals.
The B-01 well also encountered good oil shows in three zones in the Miocene; however, this interval was not targeted in this well and the Miocene was not encountered in an optimal structural position. There was also an oil show in the Eocene interval.
The Company has spudded the Bua Ban North B-02 well, which will test two Miocene intervals in an optimal structural position. The B-02 well will also test Oligocene and Eocene targets. Although high gas readings were encountered throughout the Eocene and an oil show was observed, the top of the Eocene reservoir was penetrated at 7170 feet, below our interpreted threshold for development of reservoir quality sands.
Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The B-01 well delivered positive results for the Bua Ban North B prospect. We saw good oil shows throughout all of our targeted intervals which support further drilling to test the Miocene and Eocene intervals at this location. The shallow shows continue to support the potential for shallower Miocene and Upper Oligocene targets along the entire western margin of the Songkhla basin. The Eocene interval is predicted to be of reservoir quality at 6,500 feet and shallower; it was encountered in this well at 7,170 feet. We plan to test Eocene targets further up the terrace at shallower depths.
"The drilling results from Bua Ban North continue to be positive. We also remain on target to begin production testing of the multiple discoveries at Bua Ban North A in mid-May."
Randy Bartley, President and Chief Executive Officer of the Company and a member of the Society of Petroleum Engineering and Jerry Moon, Vice President, Technical & Business Development, a member of the American Association of Petroleum Geologists, a Licensed Professional Geoscientist and a Certified Petroleum Geologist in the state of Texas, have reviewed the contents of this announcement.
Friday, April 29, 2011
Coastal Energy Co.
Coastal Energy announced the successful results of the Bua Ban North B-01 exploration well.
The Bua Ban North B-01 well was drilled to 7,960 feet TVD and encountered 28 feet of net pay in the Upper Oligocene with 23% average porosity and 29 feet of net pay in the Lower Oligocene with 16% average porosity. Net pay estimates are based on log analysis, shows and MDT analysis; the well has not been flow tested. The Company estimates that this fault block contains a total of 13 million barrels of oil in place across these two intervals.
The B-01 well also encountered good oil shows in three zones in the Miocene; however, this interval was not targeted in this well and the Miocene was not encountered in an optimal structural position. There was also an oil show in the Eocene interval.
The Company has spudded the Bua Ban North B-02 well, which will test two Miocene intervals in an optimal structural position. The B-02 well will also test Oligocene and Eocene targets. Although high gas readings were encountered throughout the Eocene and an oil show was observed, the top of the Eocene reservoir was penetrated at 7170 feet, below our interpreted threshold for development of reservoir quality sands.
Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The B-01 well delivered positive results for the Bua Ban North B prospect. We saw good oil shows throughout all of our targeted intervals which support further drilling to test the Miocene and Eocene intervals at this location. The shallow shows continue to support the potential for shallower Miocene and Upper Oligocene targets along the entire western margin of the Songkhla basin. The Eocene interval is predicted to be of reservoir quality at 6,500 feet and shallower; it was encountered in this well at 7,170 feet. We plan to test Eocene targets further up the terrace at shallower depths.
"The drilling results from Bua Ban North continue to be positive. We also remain on target to begin production testing of the multiple discoveries at Bua Ban North A in mid-May."
Randy Bartley, President and Chief Executive Officer of the Company and a member of the Society of Petroleum Engineering and Jerry Moon, Vice President, Technical & Business Development, a member of the American Association of Petroleum Geologists, a Licensed Professional Geoscientist and a Certified Petroleum Geologist in the state of Texas, have reviewed the contents of this announcement.
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