Ford Working With Numerous Cities To Ensure Readiness For Electric Vehicles
While Ford Motor Co (NYSE:F) is gearing up for the launch of its new Focus Electric car later this year and C-MAX Energi plug-in hybrid in 2012, the company is also working with cities and utility partners to identify key infrastructure building blocks that will enable metropolitan areas to be ready for electric vehicles.
Some of the cities Ford is already working with include New York, Chicago, Los Angeles, Houston, Washington D.C., San Francisco, and Boston.
Some of the key actions Ford has identified in working with cities include: utility rate structures that encourage nighttime (off-peak) charging, a streamlined permitting and inspection process to support infrastructure installation, integrated advisory committees representing a wide variety of groups, urban planning to optimize charge locations, and finally infrastructure incentives to offset a portion of customer costs.
Mike Tinskey, Ford's manager of Vehicle Electrification and Infrastructure said, "As more and more electric vehicles come to market, it's incredibly important that cities develop action plans including infrastructure development and permitting solutions to ensure these vehicles are a viable solution for citizens. Ford continues outreach with cities across the country to spread best practices and work with multiple partners including local utilities, auto manufacturers, technology companies and others to support a successful integration of electric vehicles."
Wednesday, April 13, 2011
Offshore Regulation Could Grow
Offshore Regulation Could Grow
Wednesday, April 13, 2011
Houston Chronicle
by Jennifer A. Dlouhy
The Obama administration is exploring whether to expand federal oversight of offshore drilling beyond oil and gas companies to rig suppliers, oil field services providers and other contractors now outside regulators' reach.
Michael Bromwich, the director of the Bureau of Ocean Energy Management, Regulation and Enforcement, told reporters Tuesday that the existing system imposes artificial limits on what his agency can do to make offshore drilling safer. Its enforcement power now ends with oil and gas companies that hold leases to drill in U.S. waters.
"That dramatically limits the scope of our oversight," he said. "It is very important for our regulatory oversight to extend as broadly as possible to all of the entities that are operating offshore and not for us to be artificially limited just to the individual operator that applies for permits and submits exploration plans."
Bromwich said that approach may have seemed adequate before the lethal blowout of BP's Macondo well nearly a year ago -- which killed 11 and started a multimillion-gallon oil spill -- but isn't compatible with the regulatory agenda that arose from the disaster.
"We are very interested in pushing that in an aggressive and in a responsible way," he said, "and if that requires us to extend our scope beyond the operator, that's something that needs to be seriously considered."
Last year's accident sharpened lawmakers' and regulators' focus on the broad spectrum of companies involved in offshore drilling.
According to the presidential commission that investigated the oil spill that began last April 20, the disaster was the result of a series of decisions made by BP and its contractors at the site, including Transocean, which owned the Deepwater Horizon drilling rig, and Halliburton, which did cement work.
The bureau can impose requirements on equipment used and work done by contractors, but oil and gas companies operating offshore are ultimately responsible for whether those mandates are fulfilled.
Separately, the government is reviewing how to consider companies' safety records and other factors in weighing their proposed offshore drilling projects.
Bromwich said the ocean energy bureau is evaluating the evidence "that ought to factor in as to whether a company can continue to be a player" but said it could include disciplinary records, history of violations and past fines.
The ocean energy bureau can count on a big boost in funding -- at least for a few months -- under the budget deal congressional leaders and the White House reached last week.
The legislation to keep the government running through the end of fiscal year 2011 on Sept. 30 includes $47 million more for the bureau than it got in fiscal 2010.
That's about half as much as the administration wanted to add to the agency's fiscal 2011 funding, but the boost came amid cuts totaling $40 billion in many non-defense programs.
The administration has asked Congress for $358 million in fiscal 2012, which would allow the bureau to hire 116 new offshore inspectors, triple what it has now, and 41 new permitting personnel, nearly doubling the current 50-member team. Much of the administration's planned funding increase would come from proposed new fees on oil and natural gas producers.
Wednesday, April 13, 2011
Houston Chronicle
by Jennifer A. Dlouhy
The Obama administration is exploring whether to expand federal oversight of offshore drilling beyond oil and gas companies to rig suppliers, oil field services providers and other contractors now outside regulators' reach.
Michael Bromwich, the director of the Bureau of Ocean Energy Management, Regulation and Enforcement, told reporters Tuesday that the existing system imposes artificial limits on what his agency can do to make offshore drilling safer. Its enforcement power now ends with oil and gas companies that hold leases to drill in U.S. waters.
"That dramatically limits the scope of our oversight," he said. "It is very important for our regulatory oversight to extend as broadly as possible to all of the entities that are operating offshore and not for us to be artificially limited just to the individual operator that applies for permits and submits exploration plans."
Bromwich said that approach may have seemed adequate before the lethal blowout of BP's Macondo well nearly a year ago -- which killed 11 and started a multimillion-gallon oil spill -- but isn't compatible with the regulatory agenda that arose from the disaster.
"We are very interested in pushing that in an aggressive and in a responsible way," he said, "and if that requires us to extend our scope beyond the operator, that's something that needs to be seriously considered."
Last year's accident sharpened lawmakers' and regulators' focus on the broad spectrum of companies involved in offshore drilling.
According to the presidential commission that investigated the oil spill that began last April 20, the disaster was the result of a series of decisions made by BP and its contractors at the site, including Transocean, which owned the Deepwater Horizon drilling rig, and Halliburton, which did cement work.
Opposed by GOP?
Any move to expand the ocean energy bureau's regulatory powers would probably require congressional action, according to a preliminary review by Interior Department officials. And it seems unlikely that key lawmakers would be eager to bolster the bureau's rule-making authority, especially in the House, where Republicans are moving to limit the agency's discretion.The bureau can impose requirements on equipment used and work done by contractors, but oil and gas companies operating offshore are ultimately responsible for whether those mandates are fulfilled.
No immediate position
"Even though a lot of this stuff is done by somebody else, the requirements still apply to the activity," said Erik Milito, upstream director for the American Petroleum Institute, which didn't take an immediate position on expanding the agency's authority. "As far as who is ultimately responsible for that, generally it is the operator."Separately, the government is reviewing how to consider companies' safety records and other factors in weighing their proposed offshore drilling projects.
Bromwich said the ocean energy bureau is evaluating the evidence "that ought to factor in as to whether a company can continue to be a player" but said it could include disciplinary records, history of violations and past fines.
More funding
The government imposed a swath of new safety and environmental mandates after the Deepwater Horizon disaster, including a requirement that companies prove they have the equipment and know-how to harness crude from any future deep-water well blowout.The ocean energy bureau can count on a big boost in funding -- at least for a few months -- under the budget deal congressional leaders and the White House reached last week.
The legislation to keep the government running through the end of fiscal year 2011 on Sept. 30 includes $47 million more for the bureau than it got in fiscal 2010.
That's about half as much as the administration wanted to add to the agency's fiscal 2011 funding, but the boost came amid cuts totaling $40 billion in many non-defense programs.
Hiring more inspectors
Even other units of the Interior Department didn't fare as well. For instance, funding for the Bureau of Land Management, which handles onshore oil and gas leases, would be trimmed $18 million from the fiscal 2010 level.The administration has asked Congress for $358 million in fiscal 2012, which would allow the bureau to hire 116 new offshore inspectors, triple what it has now, and 41 new permitting personnel, nearly doubling the current 50-member team. Much of the administration's planned funding increase would come from proposed new fees on oil and natural gas producers.
Devon Energy
Devon Energy
Apr 13, 2011
Devon Energy (NYSE:DVN) said that it plans to extract more natural-gas liquids and crude oil from a variety of onshore energy fields in North America following a major realignment in the past year.
The company said it sees plenty of opportunity to expand production between Alberta, Canada and southern Texas.
CEO John Richels said that the company holds a "deep inventory of oil and liquids-rich growth plays," as well as "significant exposure to emerging plays."
Shares of the company are currently trading 1.24% higher at $87.05.
Apr 13, 2011
Devon Energy (NYSE:DVN) said that it plans to extract more natural-gas liquids and crude oil from a variety of onshore energy fields in North America following a major realignment in the past year.
The company said it sees plenty of opportunity to expand production between Alberta, Canada and southern Texas.
CEO John Richels said that the company holds a "deep inventory of oil and liquids-rich growth plays," as well as "significant exposure to emerging plays."
Shares of the company are currently trading 1.24% higher at $87.05.
Musings: Are Prospects for Natural Gas Shifting to The Plus Column?
Musings: Are Prospects for Natural Gas Shifting to The Plus Column?
Wednesday, April 13, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks
"In terms of new sources of energy, we have a few different options. The first is natural gas." These were the words of President Obama in his remarks entitled A Secure Energy Future, delivered on March 30th at Georgetown University. For being the first of various energy fuel options, however, natural gas received precious little additional mention during the President's comments other than his view that "recent innovations" have given the United States "the opportunity to tap large reserves – perhaps a century's worth." Even the leader of the country has bought into the mystique of the super abundance of natural gas from shale that appears to be ubiquitous throughout North America.
The President cautioned his listeners, though, that the government needs to make sure that the oil and gas industry is tapping these shale reserves "without polluting our water supply," a bone thrown in the direction of environmentalists who seem to be losing in their efforts to restrict the burning of fossil fuels. In his comments, President Obama said he was asking Secretary of Energy Steven Chu to work with other federal agencies, various state governments, environmental specialists and the natural gas industry to "improve the safety of this process [hydraulic fracturing of gas shale formations]." President Obama made a point of mentioning that Secretary Chu has a Nobel Prize for physics. According to the President, "He likes to tinker on this stuff in his garage on the weekend." We're not sure whether that comment was to compare Secretary Chu to Bill Hewlett and David Packer who created a technology and commercial powerhouse company or to Christopher Lloyd who played Dr. Emmett "Doc" Brown in the 1985 film, Back to the Future. We must say we haven't met many physicists tinkering in the domestic oil and gas industry.
There appears to be a sort of Dr. Jekyll and Mr. Hyde outlook for natural gas. Recognized as a lower carbon, i.e., cleaner, alternative fuel choice that possesses significant energy and provides consumption flexibility to meet the multiple energy demands of modern society, natural gas should be in high demand. That demand should be further boosted by its current low price – the product of significant new supplies of gas and declines in energy markets needing it. The problem is that the financial crisis of 2008 has produced one of the most anemic economic recoveries since the Great Depression. The economic downturn and weak recovery has reduced energy demand. This, coupled with government mandates for increased use of renewable fuels in the utility sector, has created increased fuel-on-fuel price competition, in particular for coal and natural gas. But the real culprit has been the growth in supplies of new natural gas.
Exhibit 1. Oil Prices Boosted By Geopolitical Problems
Source: EIA, PPHB
At the same time gas prices were collapsing, explosive oil demand in the developing economies of the world, principally in Asia/Pacific, combined with geopolitical turmoil have driven oil prices significantly higher than where they would likely be absent the civil unrest in the Middle East and North Africa. As it appears, the political problems in Libya, and now Syria and Yemen, are not improving quickly and, in fact, could actually spread to additional Middle Eastern countries. The upward pressure on global oil prices is likely to increase in the near-term.
The price divergence between crude oil and natural gas has produced a profoundly distorted relative valuation of these fuels. The energy content of natural gas to crude oil is 5.6 to 1.0, or six to one for ease of figuring. The current West Texas Intermediate (WTI)
Exhibit 2. Oil Trading At 25-times Gas Value
Source: EIA, PPHB
crude oil price of about $112 per barrel suggests that a thousand cubic feet (Mcf) of natural gas should be valued at roughly $20. Instead, the ratio of the price of crude oil to natural gas has expanded to about 25-times. As can be seen in the chart in Exhibit 2, between 2005 and 2008, this ratio averaged around 10-times. Since the beginning of 2009, the ratio has increased to an average of about 20-times. Given the run-up in crude oil prices and the prospect of only modest increases in natural gas demand, the oil to gas ratio is now moving closer to an average of 25-times. At some point the ratio will reverse. The question is what will have to happen before that trend reverses?
Most natural gas industry observers have focused on two trends in trying to understand market sentiment – the gas-directed rig count and the monthly gas production figures. The gas rig count is reported weekly by several sources and is being sliced and diced regularly by analysts trying to discern early movements in activity that may foreshadow declines in gas production, which presumably would lead to higher natural gas prices in the future. The problem is trying to ascertain how long in the future before gas prices might rise.
Wednesday, April 13, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks
"In terms of new sources of energy, we have a few different options. The first is natural gas." These were the words of President Obama in his remarks entitled A Secure Energy Future, delivered on March 30th at Georgetown University. For being the first of various energy fuel options, however, natural gas received precious little additional mention during the President's comments other than his view that "recent innovations" have given the United States "the opportunity to tap large reserves – perhaps a century's worth." Even the leader of the country has bought into the mystique of the super abundance of natural gas from shale that appears to be ubiquitous throughout North America.
The President cautioned his listeners, though, that the government needs to make sure that the oil and gas industry is tapping these shale reserves "without polluting our water supply," a bone thrown in the direction of environmentalists who seem to be losing in their efforts to restrict the burning of fossil fuels. In his comments, President Obama said he was asking Secretary of Energy Steven Chu to work with other federal agencies, various state governments, environmental specialists and the natural gas industry to "improve the safety of this process [hydraulic fracturing of gas shale formations]." President Obama made a point of mentioning that Secretary Chu has a Nobel Prize for physics. According to the President, "He likes to tinker on this stuff in his garage on the weekend." We're not sure whether that comment was to compare Secretary Chu to Bill Hewlett and David Packer who created a technology and commercial powerhouse company or to Christopher Lloyd who played Dr. Emmett "Doc" Brown in the 1985 film, Back to the Future. We must say we haven't met many physicists tinkering in the domestic oil and gas industry.
There appears to be a sort of Dr. Jekyll and Mr. Hyde outlook for natural gas. Recognized as a lower carbon, i.e., cleaner, alternative fuel choice that possesses significant energy and provides consumption flexibility to meet the multiple energy demands of modern society, natural gas should be in high demand. That demand should be further boosted by its current low price – the product of significant new supplies of gas and declines in energy markets needing it. The problem is that the financial crisis of 2008 has produced one of the most anemic economic recoveries since the Great Depression. The economic downturn and weak recovery has reduced energy demand. This, coupled with government mandates for increased use of renewable fuels in the utility sector, has created increased fuel-on-fuel price competition, in particular for coal and natural gas. But the real culprit has been the growth in supplies of new natural gas.
Exhibit 1. Oil Prices Boosted By Geopolitical Problems
Source: EIA, PPHB
At the same time gas prices were collapsing, explosive oil demand in the developing economies of the world, principally in Asia/Pacific, combined with geopolitical turmoil have driven oil prices significantly higher than where they would likely be absent the civil unrest in the Middle East and North Africa. As it appears, the political problems in Libya, and now Syria and Yemen, are not improving quickly and, in fact, could actually spread to additional Middle Eastern countries. The upward pressure on global oil prices is likely to increase in the near-term.
The price divergence between crude oil and natural gas has produced a profoundly distorted relative valuation of these fuels. The energy content of natural gas to crude oil is 5.6 to 1.0, or six to one for ease of figuring. The current West Texas Intermediate (WTI)
Exhibit 2. Oil Trading At 25-times Gas Value
Source: EIA, PPHB
crude oil price of about $112 per barrel suggests that a thousand cubic feet (Mcf) of natural gas should be valued at roughly $20. Instead, the ratio of the price of crude oil to natural gas has expanded to about 25-times. As can be seen in the chart in Exhibit 2, between 2005 and 2008, this ratio averaged around 10-times. Since the beginning of 2009, the ratio has increased to an average of about 20-times. Given the run-up in crude oil prices and the prospect of only modest increases in natural gas demand, the oil to gas ratio is now moving closer to an average of 25-times. At some point the ratio will reverse. The question is what will have to happen before that trend reverses?
Most natural gas industry observers have focused on two trends in trying to understand market sentiment – the gas-directed rig count and the monthly gas production figures. The gas rig count is reported weekly by several sources and is being sliced and diced regularly by analysts trying to discern early movements in activity that may foreshadow declines in gas production, which presumably would lead to higher natural gas prices in the future. The problem is trying to ascertain how long in the future before gas prices might rise.
Pemex Evacuates 638 Workers from Leaning Dorm Platform
Pemex Evacuates 638 Workers from Leaning Dorm Platform
Wednesday, April 13, 2011
Dow Jones Newswires
by Laurence Iliff
Pemex said Tuesday it evacuated 638 workers from a semi-submersible dormitory platform after it began to lean to one side when water entered a pontoon.
Pemex said in a statement there were no injuries as a result of the sudden inclination of the Flotel Jupiter platform housing the workers about 80 kilometers (48 miles) off the coast of Ciudad de Carmen, Campeche state.
Since the platform is used only for housing and not for production, Pemex added, the morning incident didn't cause any leakage of hydrocarbons. "Pemex reiterates that neither production nor other activities in the area were affected," the statement said.
Since the platform is used only for housing and not for production, Pemex added, the morning incident didn't cause any leakage of hydrocarbons. "Pemex reiterates that neither production nor other activities in the area were affected," the statement said.
The evacuated workers, Pemex said, were taken by transport ships to the Abkatun-Alfa platform. Divers were sealing the affected pontoon on the Jupiter and Pemex said it expected the platform to be stabilized shortly and moved to an inspection area.
Wednesday, April 13, 2011
Dow Jones Newswires
by Laurence Iliff
Pemex said Tuesday it evacuated 638 workers from a semi-submersible dormitory platform after it began to lean to one side when water entered a pontoon.
Pemex said in a statement there were no injuries as a result of the sudden inclination of the Flotel Jupiter platform housing the workers about 80 kilometers (48 miles) off the coast of Ciudad de Carmen, Campeche state.
Since the platform is used only for housing and not for production, Pemex added, the morning incident didn't cause any leakage of hydrocarbons. "Pemex reiterates that neither production nor other activities in the area were affected," the statement said.
Leaning Flotel Jupiter Platform
Since the platform is used only for housing and not for production, Pemex added, the morning incident didn't cause any leakage of hydrocarbons. "Pemex reiterates that neither production nor other activities in the area were affected," the statement said.
The evacuated workers, Pemex said, were taken by transport ships to the Abkatun-Alfa platform. Divers were sealing the affected pontoon on the Jupiter and Pemex said it expected the platform to be stabilized shortly and moved to an inspection area.
Va. Dem Bucks Administration on Offshore Leasing
Va. Dem Bucks Administration on Offshore Leasing
Wednesday, April 13, 2011
Daily Press, Newport News, Va.
by Cory Nealon
There's nothing like a politician not seeking re-election.
Case in point: U.S. Sen. Jim Webb, D-Va.
Since announcing in February he would not seek re-election, Webb has bucked President Barack Obama, a fellow Democrat, on a handful of issues.
First, he criticized Obama's handling of the turmoil in Libya. Next, he backed a bill that would've halted the U.S. Environmental Protection Agency from regulating greenhouse gases, which Obama favors because the Senate didn't pass energy legislation in 2009.
Now he's calling on Obama to open Virginia's coast to oil and natural gas exploration.
"As gas prices rise, in part due to America's dependence on foreign oil, we must pursue robust energy policies that include the expansion of our domestic energy resources in a safe and secure manner, as well as conservation and clean energy measures," Webb said in a statement issued by his office last week.
He also asked Obama to expand the 2.9-million acre tract -- slightly larger than Delaware -- located 50 miles off Virginia's shore that was previously considered for drilling.
The request comes a little more than a year after Obama announced he would open much of the East Coast, including Virginia, to drilling. Obama scrapped the plan, however, after last year's Gulf of Mexico oil spill, which killed 11 and caused untold damage to the gulf's ecosystem.
For those of you keeping tabs at home, the offshore drilling bill that Webb supports comes from Rep. Bob Goodlatte, R-Roanoke -- the same lawmaker trying to curtail the EPA's aggressive Chesapeake Bay Restoration plan.
Who says the House and Senate can't work together?
Global warming
I got a fair amount of feedback -- most of it critical -- about an article last week concerning global warming skeptic Roy W. Spencer.
Spencer spoke at the Environment Virginia Symposium at the request of Gov. Bob McDonnell's administration.
Spencer said that he agrees with most of what the Intergovernmental Panel on Climate Change -- the body of scientists that shared the 2007 Nobel Peace Prize with former Vice President Al Gore -- has to say about global warming.
However, he highlighted gaps in the panel's data and questioned whether mankind is causing the Earth to warm through its use of fossil fuels.
The view is not popular among environmental activists and scientists, both of whom have criticized the media for giving Spencer and similar-minded scientists a platform to expound their views.
What I haven't heard is anyone complaining that Spencer said something false or inaccurate. Instead, the gripes centered on his conservative and evangelical affiliations, which were pointed out in the article.
If you still feel he doesn't deserve a seat at the table, my phone number and email are below. As always, comments are welcomed.
Wednesday, April 13, 2011
Daily Press, Newport News, Va.
by Cory Nealon
There's nothing like a politician not seeking re-election.
Case in point: U.S. Sen. Jim Webb, D-Va.
Since announcing in February he would not seek re-election, Webb has bucked President Barack Obama, a fellow Democrat, on a handful of issues.
First, he criticized Obama's handling of the turmoil in Libya. Next, he backed a bill that would've halted the U.S. Environmental Protection Agency from regulating greenhouse gases, which Obama favors because the Senate didn't pass energy legislation in 2009.
Now he's calling on Obama to open Virginia's coast to oil and natural gas exploration.
"As gas prices rise, in part due to America's dependence on foreign oil, we must pursue robust energy policies that include the expansion of our domestic energy resources in a safe and secure manner, as well as conservation and clean energy measures," Webb said in a statement issued by his office last week.
He also asked Obama to expand the 2.9-million acre tract -- slightly larger than Delaware -- located 50 miles off Virginia's shore that was previously considered for drilling.
The request comes a little more than a year after Obama announced he would open much of the East Coast, including Virginia, to drilling. Obama scrapped the plan, however, after last year's Gulf of Mexico oil spill, which killed 11 and caused untold damage to the gulf's ecosystem.
For those of you keeping tabs at home, the offshore drilling bill that Webb supports comes from Rep. Bob Goodlatte, R-Roanoke -- the same lawmaker trying to curtail the EPA's aggressive Chesapeake Bay Restoration plan.
Who says the House and Senate can't work together?
Global warming
I got a fair amount of feedback -- most of it critical -- about an article last week concerning global warming skeptic Roy W. Spencer.
Spencer spoke at the Environment Virginia Symposium at the request of Gov. Bob McDonnell's administration.
Spencer said that he agrees with most of what the Intergovernmental Panel on Climate Change -- the body of scientists that shared the 2007 Nobel Peace Prize with former Vice President Al Gore -- has to say about global warming.
However, he highlighted gaps in the panel's data and questioned whether mankind is causing the Earth to warm through its use of fossil fuels.
The view is not popular among environmental activists and scientists, both of whom have criticized the media for giving Spencer and similar-minded scientists a platform to expound their views.
What I haven't heard is anyone complaining that Spencer said something false or inaccurate. Instead, the gripes centered on his conservative and evangelical affiliations, which were pointed out in the article.
If you still feel he doesn't deserve a seat at the table, my phone number and email are below. As always, comments are welcomed.
Veolia Environmental Awarded Water Treatment Contract
Veolia Environmental Awarded Water Treatment Contract
Apr 13, 2011
Veolia Environmental (NYSE:VE) has signed a deal with the Plains Exploration & Production Company for a Produced Water Reclamation Facility at its Arroyo Grande Oilfield in San Luis Obispo County, California.
The treatment system will utilize Veolia Water's OPUS II technology to generate high quality water.
Veolia will design, build, and operate the 45,000-barrel per day facility under a 12-year agreement. Veolia will provide operations and maintenance services as well as performance guarantees on a fixed-fee basis to ensure design performance and recycled water of high quality.
Kirk Schwab, general manager of the Veolia Water Solutions & Technologies said, "This project uses world-class technology that treats produced water to generate high-quality water. As a result, our partnership is creating societal and environmental benefits that we can all be proud of. This approach demonstrates a shared commitment to responsible development of resources."
Veolia Environmental has a potential upside of 9% based on a current price of $32.19 and an average consensus analyst price target of $35.1.
Apr 13, 2011
Veolia Environmental (NYSE:VE) has signed a deal with the Plains Exploration & Production Company for a Produced Water Reclamation Facility at its Arroyo Grande Oilfield in San Luis Obispo County, California.
The treatment system will utilize Veolia Water's OPUS II technology to generate high quality water.
Veolia will design, build, and operate the 45,000-barrel per day facility under a 12-year agreement. Veolia will provide operations and maintenance services as well as performance guarantees on a fixed-fee basis to ensure design performance and recycled water of high quality.
Kirk Schwab, general manager of the Veolia Water Solutions & Technologies said, "This project uses world-class technology that treats produced water to generate high-quality water. As a result, our partnership is creating societal and environmental benefits that we can all be proud of. This approach demonstrates a shared commitment to responsible development of resources."
Veolia Environmental has a potential upside of 9% based on a current price of $32.19 and an average consensus analyst price target of $35.1.
Contsellation To Build Solar Plant In Holyoke, Mass.
Contsellation To Build Solar Plant In Holyoke, Mass.
Apr 13, 2011
Constellation Energy (NYSE:CEG) and the Holyoke Gas & Electric Department announced today the development of a new 4.5-megawatt solar installation that will generate electricity for 18,000 customers in Holyoke, Massachusetts.
The system is scheduled for completion this summer, and will be among the largest solar installations in New England.
Constellation will build, own, and maintain the system while HG&E will purchase all of the electricity generated from the plant under a 20-year power purchase agreement at a fixed cost that is less than projected market electricity rates.
Michael D. Smith, senior vice president of green initiatives for Constellation Energy's retail business said, "Large-scale solar generation is an attractive option for municipal utilities to manage volatile energy costs for their customers and meet renewable energy goals. In states like Massachusetts with strong market-based incentive programs, Constellation can provide solar power to municipal utilities at a rate that is significantly less than electricity from other generation sources, which benefits both the environment and power customers' bottom lines."
Constellation Energy has a potential upside of 5.1% based on a current price of $33.18 and an average consensus analyst price target of $34.86.
Apr 13, 2011
Constellation Energy (NYSE:CEG) and the Holyoke Gas & Electric Department announced today the development of a new 4.5-megawatt solar installation that will generate electricity for 18,000 customers in Holyoke, Massachusetts.
The system is scheduled for completion this summer, and will be among the largest solar installations in New England.
Constellation will build, own, and maintain the system while HG&E will purchase all of the electricity generated from the plant under a 20-year power purchase agreement at a fixed cost that is less than projected market electricity rates.
Michael D. Smith, senior vice president of green initiatives for Constellation Energy's retail business said, "Large-scale solar generation is an attractive option for municipal utilities to manage volatile energy costs for their customers and meet renewable energy goals. In states like Massachusetts with strong market-based incentive programs, Constellation can provide solar power to municipal utilities at a rate that is significantly less than electricity from other generation sources, which benefits both the environment and power customers' bottom lines."
Constellation Energy has a potential upside of 5.1% based on a current price of $33.18 and an average consensus analyst price target of $34.86.
Consol Energy Raises Its 2011 Coal Production Target, Shares Up 3.5%
Consol Energy Raises Its 2011 Coal Production Target, Shares Up 3.5%
Apr 13, 2011
Consol Energy Inc (NYSE:CNX) reported its coal business had a "very good" Q1, leading to a boost in its 2011 production target to 60 to 62 million tons, up from its earlier target of 59 to 61 million tons.
Consol also said it had drilled 13 horizontal wells in the Marcellus shale in the first quarter, putting it ahead of schedule for a total of 70 wells for the year.
The first two wells it drilled on acreage acquired from Dominion "appear to be very substantial," the company said.
Consol Energy has a potential upside of 17.6% based on a current price of $50.70 and an average consensus analyst price target of $59.62.
Apr 13, 2011
Consol Energy Inc (NYSE:CNX) reported its coal business had a "very good" Q1, leading to a boost in its 2011 production target to 60 to 62 million tons, up from its earlier target of 59 to 61 million tons.
Consol also said it had drilled 13 horizontal wells in the Marcellus shale in the first quarter, putting it ahead of schedule for a total of 70 wells for the year.
The first two wells it drilled on acreage acquired from Dominion "appear to be very substantial," the company said.
Consol Energy has a potential upside of 17.6% based on a current price of $50.70 and an average consensus analyst price target of $59.62.
Atlantic to Farm-In to Orchid Prospect
Atlantic to Farm-In to Orchid Prospect
Wednesday, April 13, 2011
P/F Atlantic Petroleum
Atlantic Petroleum has reached an agreement to acquire a 10% stake in P.1556, Block 29/1c containing the Orchid Prospect from Summit Petroleum in return for carrying a share of the cost of the initial exploration well.
The Orchid Prospect is a four-way dip closure in the Tertiary and Chalk and is located in the Central North Sea surrounded by the producing Banff, Kyle, Bittern and Gannet fields. The Orchid prospect is located close to acreage awarded to Atlantic Petroleum in the 26th Round.
Summit, the operator, is currently seeking a semi-submersible rig to drill the prospect in the second half of this year.
Ben Arabo, CEO, commented, "This is an important addition to our 2011 program. We are pleased to join Summit in the Central North Sea which is an area of growth for Atlantic Petroleum. We look forward to working with this new partner group on the Orchid project."
Wednesday, April 13, 2011
P/F Atlantic Petroleum
Atlantic Petroleum has reached an agreement to acquire a 10% stake in P.1556, Block 29/1c containing the Orchid Prospect from Summit Petroleum in return for carrying a share of the cost of the initial exploration well.
The Orchid Prospect is a four-way dip closure in the Tertiary and Chalk and is located in the Central North Sea surrounded by the producing Banff, Kyle, Bittern and Gannet fields. The Orchid prospect is located close to acreage awarded to Atlantic Petroleum in the 26th Round.
Summit, the operator, is currently seeking a semi-submersible rig to drill the prospect in the second half of this year.
Ben Arabo, CEO, commented, "This is an important addition to our 2011 program. We are pleased to join Summit in the Central North Sea which is an area of growth for Atlantic Petroleum. We look forward to working with this new partner group on the Orchid project."
Mainland Locates Multiple Pay Zones at Burkley-Phillips Well
Mainland Locates Multiple Pay Zones at Burkley-Phillips Well
Wednesday, April 13, 2011
Mainland Resources Inc.
Mainland reported that further review and analysis of the Core results and Log data for the Burkley-Phillips #1 well indicates that the well hosts multiple potential pay zones including the Bossier Shale, Knowles Lime, Cotton Valley and Haynesville shale intercepts, and in addition has the potential for oil within the Tuscaloosa sandstones.
Mike Newport, President of Mainland Resources stated, "This new data is vitally important to Mainland as we design the production plan at Buena Vista. For instance, this new data revealing what we know as the Deep Bossier Shale is very important as it demonstrates the Burkley-Phillips has a strong potential to be an economically viable project for us."
"Deep Bossier Shales generally have high production rates, so that we can expect greater longevity in the wells that have strong potential for production from other zones, such as the Knowles and Cotton Valley," Newport added.
The analysis of the data has indicated that the primary pay zone is a Deep Bossier Shale, which is within a greater than 2000 foot Bossier Formation interval that was encountered at approximately 19,960 feet. Special Core analysis performed on core cut within the Bossier in the well, suggests that the rock properties of the shales are similar to high productivity Bossier wells in Northwest Louisiana and East Texas. These observations, combined with natural fracturing and very high pressures in excess of 20,000 psi, suggest that the well could have very strong production rates in the Bossier Zone.
The Bossier Section consists of interbedded sandstones, siltstones and shales within a naturally fractured, high-pressure environment. Petrophysical analysis suggests that some of the sandstones have very good conventional porosity. Typical, in these types of formations, production rates are high.
Good porosity is also observed within approximately 70 feet of the overlying Knowles Lime in the Burkley-Phillips #1 well. Petrophysical analysis, as well as exceptional mud gas shows observed while drilling this unit, indicate the potential for excellent gas production within this interval.
Mainland and its working interest partners control in excess of 17,800 net acres or 28 sections on the Buena Vista prospect area where the Burkley-Phillips #1 well was drilled to 22,000 feet, cored and logged. Upon successful completion of its proposed merger with American Exploration, Mainland would own 92% of the 28 sections in the Buena Vista prospect. As recently announced, core analysis has determined that gas in place in the Buena Vista prospect could be up to 500 BCF/section based on the cored interval.
Wednesday, April 13, 2011
Mainland Resources Inc.
Mainland reported that further review and analysis of the Core results and Log data for the Burkley-Phillips #1 well indicates that the well hosts multiple potential pay zones including the Bossier Shale, Knowles Lime, Cotton Valley and Haynesville shale intercepts, and in addition has the potential for oil within the Tuscaloosa sandstones.
Mike Newport, President of Mainland Resources stated, "This new data is vitally important to Mainland as we design the production plan at Buena Vista. For instance, this new data revealing what we know as the Deep Bossier Shale is very important as it demonstrates the Burkley-Phillips has a strong potential to be an economically viable project for us."
"Deep Bossier Shales generally have high production rates, so that we can expect greater longevity in the wells that have strong potential for production from other zones, such as the Knowles and Cotton Valley," Newport added.
The analysis of the data has indicated that the primary pay zone is a Deep Bossier Shale, which is within a greater than 2000 foot Bossier Formation interval that was encountered at approximately 19,960 feet. Special Core analysis performed on core cut within the Bossier in the well, suggests that the rock properties of the shales are similar to high productivity Bossier wells in Northwest Louisiana and East Texas. These observations, combined with natural fracturing and very high pressures in excess of 20,000 psi, suggest that the well could have very strong production rates in the Bossier Zone.
The Bossier Section consists of interbedded sandstones, siltstones and shales within a naturally fractured, high-pressure environment. Petrophysical analysis suggests that some of the sandstones have very good conventional porosity. Typical, in these types of formations, production rates are high.
Good porosity is also observed within approximately 70 feet of the overlying Knowles Lime in the Burkley-Phillips #1 well. Petrophysical analysis, as well as exceptional mud gas shows observed while drilling this unit, indicate the potential for excellent gas production within this interval.
Mainland and its working interest partners control in excess of 17,800 net acres or 28 sections on the Buena Vista prospect area where the Burkley-Phillips #1 well was drilled to 22,000 feet, cored and logged. Upon successful completion of its proposed merger with American Exploration, Mainland would own 92% of the 28 sections in the Buena Vista prospect. As recently announced, core analysis has determined that gas in place in the Buena Vista prospect could be up to 500 BCF/section based on the cored interval.
LNG Energy to Sell Ok. Acreage
LNG Energy to Sell Ok. Acreage
Wednesday, April 13, 2011
LNG Energy Ltd.
LNG Energy's subsidiary, BWB Exploration, has entered into an agreement to sell all of its working interest in approximately 2,800 net acres of oil and gas lease holdings in Carter County, Oklahoma to an undisclosed buyer for approximately US $5,180,000 in cash subject to final adjustments. The sale is expected to close on or before May 2, 2011.
"We continue to focus on our core areas in Poland and Papua New Guinea. This disposition follows our recent acquisition in Poland where we acquired about 180,000 net acres and now have exposure to a 1.1 million acre gross position in the Polish Baltic Basin," commented Dave Afseth, President & CEO of LNG.
Poland Operational Update
The second well being drilled, Lebork S-1 on the Slupsk Concession has been drilled to 3,517m, with 227m of open hole core already taken. It is anticipated that the drilling and logging will be completed in the next week. The core will be analyzed over the coming weeks. The majority of the analysis of the sidewall cores from the Wytowno S-1 well are expected to be received back from the subcontractor in May 2011. The 1st well on the Starogard concession is expected to be spudded in June 2011.
LNG is a Canadian exploration and development company focused on developing oil and gas reserves in Papua New Guinea, Poland and the US. LNG holds a 100% interest in approximately 5.5 million acres of prospective oil and gas properties in Papua New Guinea. LNG has a 50% net interest in approximately 360,000 gross acres of prospective shales in Poland together with Realm Energy (BVI). LNG also has a 20% net interest in approximately 734,000 gross acres of prospective shales in Poland together with BNK Petroleum Inc., Sorgenia E&P S.p.A., and Rohol-Aufsuchungs Aktiengesellschaft, and a 100% net interest in BWB Exploration, LLC ("BWB"), which holds approximately 2,800 acres of oil and gas leases in Carter County, Oklahoma and an estimated 28,757 acres of leases in the Black Warrior Basin of Mississippi and Alabama. LNG shares trade on the TSX Venture Exchange under the symbol "LNG".
Wednesday, April 13, 2011
LNG Energy Ltd.
LNG Energy's subsidiary, BWB Exploration, has entered into an agreement to sell all of its working interest in approximately 2,800 net acres of oil and gas lease holdings in Carter County, Oklahoma to an undisclosed buyer for approximately US $5,180,000 in cash subject to final adjustments. The sale is expected to close on or before May 2, 2011.
"We continue to focus on our core areas in Poland and Papua New Guinea. This disposition follows our recent acquisition in Poland where we acquired about 180,000 net acres and now have exposure to a 1.1 million acre gross position in the Polish Baltic Basin," commented Dave Afseth, President & CEO of LNG.
Poland Operational Update
The second well being drilled, Lebork S-1 on the Slupsk Concession has been drilled to 3,517m, with 227m of open hole core already taken. It is anticipated that the drilling and logging will be completed in the next week. The core will be analyzed over the coming weeks. The majority of the analysis of the sidewall cores from the Wytowno S-1 well are expected to be received back from the subcontractor in May 2011. The 1st well on the Starogard concession is expected to be spudded in June 2011.
LNG is a Canadian exploration and development company focused on developing oil and gas reserves in Papua New Guinea, Poland and the US. LNG holds a 100% interest in approximately 5.5 million acres of prospective oil and gas properties in Papua New Guinea. LNG has a 50% net interest in approximately 360,000 gross acres of prospective shales in Poland together with Realm Energy (BVI). LNG also has a 20% net interest in approximately 734,000 gross acres of prospective shales in Poland together with BNK Petroleum Inc., Sorgenia E&P S.p.A., and Rohol-Aufsuchungs Aktiengesellschaft, and a 100% net interest in BWB Exploration, LLC ("BWB"), which holds approximately 2,800 acres of oil and gas leases in Carter County, Oklahoma and an estimated 28,757 acres of leases in the Black Warrior Basin of Mississippi and Alabama. LNG shares trade on the TSX Venture Exchange under the symbol "LNG".
Petro Vista Reaches TD at Morichito Well
Petro Vista Reaches TD at Morichito Well
Wednesday, April 13, 2011
Petro Vista Energy Corp.
Petro Vista announced that the Morichito-5B well in Colombia has reached total depth and production casing is being run to evaluate oil and gas shows encountered in the Tertiary Carbonera and Mirador and Cretaceous Guadalupe, Gacheta, and Ubaque formations.
This Morichito-5B was drilled from the Company's original M-5 (2010 discovery) drilling pad and deviated approximately 1200 feet to the southwest of the original well. The well was drilled to a total depth of 6855 feet in the Paleozoic. During drilling mud-log shows were encountered in the Carbonera C7, Mirador, Guadalupe, Gacheta, and Ubaque formations. Subsequent petrophysical analysis of electric logs indicated multiple potential pay zones.
The Carbonera C7 zone is equivalent to and six feet structurally high to the 5900 foot zone in the Morichito M-5 well which swabbed at a rate of 375 barrels of oil per day of 23 degree API oil with no water cut (see news release dated March 25, 2010).
A decision has been taken with partners Green Power Corporation and Golden Oil Corp. to run 7" production casing and test at least two zones. The Company expects testing to commence approximately May 1st and take 15-20 days to complete. Assuming success and the receipt of necessary permits, this well will be placed on a long-term production test along with the existing M5 discovery well on which a work-over rig is being mobilized with testing to commence approximately April 28.
The Morichito-5B well was drilled as a deeper pool wildcat and fulfills the company's Phase V contract commitment with the Colombian National Hydrocarbon Agency (ANH).
Wednesday, April 13, 2011
Petro Vista Energy Corp.
Petro Vista announced that the Morichito-5B well in Colombia has reached total depth and production casing is being run to evaluate oil and gas shows encountered in the Tertiary Carbonera and Mirador and Cretaceous Guadalupe, Gacheta, and Ubaque formations.
This Morichito-5B was drilled from the Company's original M-5 (2010 discovery) drilling pad and deviated approximately 1200 feet to the southwest of the original well. The well was drilled to a total depth of 6855 feet in the Paleozoic. During drilling mud-log shows were encountered in the Carbonera C7, Mirador, Guadalupe, Gacheta, and Ubaque formations. Subsequent petrophysical analysis of electric logs indicated multiple potential pay zones.
The Carbonera C7 zone is equivalent to and six feet structurally high to the 5900 foot zone in the Morichito M-5 well which swabbed at a rate of 375 barrels of oil per day of 23 degree API oil with no water cut (see news release dated March 25, 2010).
A decision has been taken with partners Green Power Corporation and Golden Oil Corp. to run 7" production casing and test at least two zones. The Company expects testing to commence approximately May 1st and take 15-20 days to complete. Assuming success and the receipt of necessary permits, this well will be placed on a long-term production test along with the existing M5 discovery well on which a work-over rig is being mobilized with testing to commence approximately April 28.
The Morichito-5B well was drilled as a deeper pool wildcat and fulfills the company's Phase V contract commitment with the Colombian National Hydrocarbon Agency (ANH).
Oil Flows at Breezer's Tx. Well
Oil Flows at Breezer's Tx. Well
Wednesday, April 13, 2011
Breezer Ventures Inc.
Breezer announced that their first well of a ten well rehabilitation and production development program in Callahan County, Texas, has successfully established oil flow in Jackson #6 Well. The drilling program was able to re-open Well #6 and discovered a considerable amount of free oil and oil pressure build-up.
The Company's field operator, Whitt Oil and Gas, and project manager, Firecreek Global Inc., both stated: "we've re-entered and deepened Well #6 (the former Magnolia/Mobil Oil well) and we are very encouraged by the amount of free oil encountered while drilling deeper into the Moran Sand."
The Company plans to utilize modern oil stimulation techniques, which will enhance the production rate of Well #6 once in full production. The field operator, Whitt Oil and Gas, will complete the final stage of drilling and completion phase and start production testing of Well #6 later this week. The well also has proven Tannehill, Cisco, Cook and Palo Pinto oil and gas formations, which the Company plans to develop in the future.
Breezer Ventures Inc. has ten (10) existing oil and gas wells that are currently in for rehabilitation and reactivation on the Jackson Lease, which contains 870 acres, and is situated on the western side of the Bend Arch in the Fort Worth Basin. The lease is situated 5 miles north of Baird, Texas.
The Company's objective is to develop stable long-term oil and gas production from the proven formations located on the Jackson Lease at very low capital costs. This project is expected to yield stable cash flow for years and will be profitable especially with oil prices at current record levels.
Wednesday, April 13, 2011
Breezer Ventures Inc.
Breezer announced that their first well of a ten well rehabilitation and production development program in Callahan County, Texas, has successfully established oil flow in Jackson #6 Well. The drilling program was able to re-open Well #6 and discovered a considerable amount of free oil and oil pressure build-up.
The Company's field operator, Whitt Oil and Gas, and project manager, Firecreek Global Inc., both stated: "we've re-entered and deepened Well #6 (the former Magnolia/Mobil Oil well) and we are very encouraged by the amount of free oil encountered while drilling deeper into the Moran Sand."
The Company plans to utilize modern oil stimulation techniques, which will enhance the production rate of Well #6 once in full production. The field operator, Whitt Oil and Gas, will complete the final stage of drilling and completion phase and start production testing of Well #6 later this week. The well also has proven Tannehill, Cisco, Cook and Palo Pinto oil and gas formations, which the Company plans to develop in the future.
Breezer Ventures Inc. has ten (10) existing oil and gas wells that are currently in for rehabilitation and reactivation on the Jackson Lease, which contains 870 acres, and is situated on the western side of the Bend Arch in the Fort Worth Basin. The lease is situated 5 miles north of Baird, Texas.
The Company's objective is to develop stable long-term oil and gas production from the proven formations located on the Jackson Lease at very low capital costs. This project is expected to yield stable cash flow for years and will be profitable especially with oil prices at current record levels.
Brigham Exceeds Records at ND, Montana Bakken Wells
Brigham Exceeds Records at ND, Montana Bakken Wells
Wednesday, April 13, 2011
Brigham Exploration Co.
Brigham announced that its Sorenson 29-32 #2H Bakken well produced a North Dakota Bakken record 5,330 barrels of oil equivalent during its early 24-hour peak flow back period. Brigham also announced that its Johnson 30-19 #1H Bakken well, which is located in Richland County, Montana, produced a Montana Bakken record early 24-hour peak flow back rate of approximately 2,962 barrels of oil equivalent. Brigham announced the completion of four additional North Dakota Bakken wells and, as a result, has completed 56 consecutive long lateral high frac stage wells in North Dakota at an average early 24-hour peak flow back rate of approximately 2,884 barrels of oil equivalent. Finally, Brigham provided an update on its drilling and completion activities in the Williston Basin.
The Sorenson 29-32 #2H represents Brigham's first infill well completion in its Ross project area and was drilled, on average, approximately 1,720' from the Sorenson 29-32 #1H well, which was completed in April 2010. The Sorenson 29-32 #2H was completed with 38 frac stages.
The Sorenson 29-32 #2H and the Cvancara 20-17 #1H, which produced approximately 4,402 barrels of oil equivalent during its early 24-hour peak flow back period, were the first wells drilled and completed using Brigham's smart pad design. The smart pad design allows wells to be drilled from the same pad and simultaneously fracture stimulated. It is estimated that approximately 10% to 20% in cost savings can be achieved with implementation of smart pad drilling and completion techniques.
In North Dakota, Brigham will spud its second Three Forks well in its Rough Rider project area in Williams County before the end of the month. An additional Three Forks well is anticipated to be spud in early summer in McKenzie County.
In Montana, Brigham recently completed drilling operations on the Beck 15-10 #1H, which is located in Roosevelt County, and will drill three consecutive additional wells in Montana, two of which are in Roosevelt County and one in Richland County. Later this month, Brigham will begin the fracture stimulation of the Voss 21-11H, which was purchased from another operator who drilled and completed the well in August 2007 with a single fracture stimulation. Brigham successfully removed the old liner from the wellbore and replaced it with a new liner with swell packers. Brigham expects to use 28 fracture stimulation stages to complete the Voss 21-11H.
Brigham currently has two wells flowing back, two wells fracing and 15 wells waiting on completion.
Later this month, Brigham expects to add additional fracture stimulation capacity thereby providing access to two fully dedicated frac crews focused on completing Brigham operated horizontal wells in the basin. At that time, Brigham estimates that it will be capable of fracture stimulating and bringing on line to production a minimum of eight wells per month due to the efficiencies gained by simultaneous stimulations.
Bud Brigham continued, "The extremely positive results of our Johnson 30-19 #1H, which is located in Richland County, further de-risks part of our Montana acreage for the Bakken. Our de-risking should continue based on the results of the fracture stimulation of the Voss 21-11H, which is expected to occur later this month. Plans are to continue to work towards de-risking larger parts of our Montana acreage by drilling a total of four additional wells over the next several months."
Bud Brigham concluded, "Importantly, our acceleration in the Williston Basin continues to be on schedule as we expect to begin operating two fully dedicated frac crews this month and expect our next dedicated operated rig to arrive in May. Our core acreage position combined with our operational expertise and accelerated development is anticipated to set us up for a very positive 2011 in terms of net asset value growth. Looking ahead, given the remarkably consistent results associated with our 56 consecutive long lateral high frac stage completions in North Dakota, it's likely that we will no longer release individual well early 24-hour peak rates, except in certain circumstances, such as where results provide specific information with respect to de-risking our non-core acreage and the resulting net asset value accretion."
Wednesday, April 13, 2011
Brigham Exploration Co.
Brigham announced that its Sorenson 29-32 #2H Bakken well produced a North Dakota Bakken record 5,330 barrels of oil equivalent during its early 24-hour peak flow back period. Brigham also announced that its Johnson 30-19 #1H Bakken well, which is located in Richland County, Montana, produced a Montana Bakken record early 24-hour peak flow back rate of approximately 2,962 barrels of oil equivalent. Brigham announced the completion of four additional North Dakota Bakken wells and, as a result, has completed 56 consecutive long lateral high frac stage wells in North Dakota at an average early 24-hour peak flow back rate of approximately 2,884 barrels of oil equivalent. Finally, Brigham provided an update on its drilling and completion activities in the Williston Basin.
Record North Dakota Bakken Well
Brigham announced that the Sorenson 29-32 #2H produced a North Dakota Bakken record 5,330 barrels of oil equivalent (4,661 barrels of oil and 4.01 MMcf of natural gas) during its early 24-hour peak flow back period. The Sorenson 29-32 #2H, which is located in Brigham's Ross project area in Mountrail County, North Dakota, supplants Brigham's Sorenson 29-32 #1H as the record initial rate Bakken well. To date, based on publically available information, Brigham has the four highest initial rate Bakken wells and seven of the top 10 initial rate Bakken wells in the Williston Basin.The Sorenson 29-32 #2H represents Brigham's first infill well completion in its Ross project area and was drilled, on average, approximately 1,720' from the Sorenson 29-32 #1H well, which was completed in April 2010. The Sorenson 29-32 #2H was completed with 38 frac stages.
The Sorenson 29-32 #2H and the Cvancara 20-17 #1H, which produced approximately 4,402 barrels of oil equivalent during its early 24-hour peak flow back period, were the first wells drilled and completed using Brigham's smart pad design. The smart pad design allows wells to be drilled from the same pad and simultaneously fracture stimulated. It is estimated that approximately 10% to 20% in cost savings can be achieved with implementation of smart pad drilling and completion techniques.
Record Montana Bakken Well
Brigham announced that the Johnson 30-19 #1H, which is located in Richland County, produced approximately 2,962 barrels of oil equivalent (2,684 barrels of oil and 1.67 MMcf of natural gas) during its early 24-hour peak flow back period. The well was completed with 36 fracture stimulation stages, and based on publically available information, is the record initial rate Bakken well in Montana.North Dakota Operated Well Result Update
Brigham has now completed 56 consecutive long lateral high frac stage wells in North Dakota with an average early 24-hour peak flow back rate of approximately 2,884 barrels of oil equivalent.Williston Basin Operated Drilling and Completion Update
Brigham's accelerated development of its acreage in North Dakota and Montana is proceeding with four operated rigs drilling in Rough Rider, two operated rigs drilling in Ross and one operated rig drilling in Montana. Brigham's eighth dedicated operated rig is expected to arrive in May.In North Dakota, Brigham will spud its second Three Forks well in its Rough Rider project area in Williams County before the end of the month. An additional Three Forks well is anticipated to be spud in early summer in McKenzie County.
In Montana, Brigham recently completed drilling operations on the Beck 15-10 #1H, which is located in Roosevelt County, and will drill three consecutive additional wells in Montana, two of which are in Roosevelt County and one in Richland County. Later this month, Brigham will begin the fracture stimulation of the Voss 21-11H, which was purchased from another operator who drilled and completed the well in August 2007 with a single fracture stimulation. Brigham successfully removed the old liner from the wellbore and replaced it with a new liner with swell packers. Brigham expects to use 28 fracture stimulation stages to complete the Voss 21-11H.
Brigham currently has two wells flowing back, two wells fracing and 15 wells waiting on completion.
Later this month, Brigham expects to add additional fracture stimulation capacity thereby providing access to two fully dedicated frac crews focused on completing Brigham operated horizontal wells in the basin. At that time, Brigham estimates that it will be capable of fracture stimulating and bringing on line to production a minimum of eight wells per month due to the efficiencies gained by simultaneous stimulations.
Management Comments
Bud Brigham, the Chairman, President and CEO, commented, "Our team continues to deliver outstanding operational results with record setting Bakken wells in North Dakota and Montana. The impressive results of the Sorenson 29-32 #2H, which was drilled approximately one year after the Sorenson 29-32 #1H, clearly demonstrates the substantial net asset value attributable to our infill drilling locations."Bud Brigham continued, "The extremely positive results of our Johnson 30-19 #1H, which is located in Richland County, further de-risks part of our Montana acreage for the Bakken. Our de-risking should continue based on the results of the fracture stimulation of the Voss 21-11H, which is expected to occur later this month. Plans are to continue to work towards de-risking larger parts of our Montana acreage by drilling a total of four additional wells over the next several months."
Bud Brigham concluded, "Importantly, our acceleration in the Williston Basin continues to be on schedule as we expect to begin operating two fully dedicated frac crews this month and expect our next dedicated operated rig to arrive in May. Our core acreage position combined with our operational expertise and accelerated development is anticipated to set us up for a very positive 2011 in terms of net asset value growth. Looking ahead, given the remarkably consistent results associated with our 56 consecutive long lateral high frac stage completions in North Dakota, it's likely that we will no longer release individual well early 24-hour peak rates, except in certain circumstances, such as where results provide specific information with respect to de-risking our non-core acreage and the resulting net asset value accretion."
Tesoro Logistics LP Sets Estimated IPO Price Range
Tesoro Logistics LP Sets Estimated IPO Price Range
Apr 13, 2011
Tesoro Logistics LP, the refined oil terminal, pipeline and tank storage unit of refiner Tesoro Corp (NYSE:TSO) set an estimate price range for its IPO of $19 to $21 a common unit.
The Delaware Limited Partnership will offer 12.5 million common units, and plans to raise about $250 million dollars.
A large part of the proceeds will be distributed to Tesoro Corp to reimburse the company for certain capital expenditures incurred.
Tesoro Logistics LP plans to trade under the symbol TLLP on the New York Stock Exchange.
Apr 13, 2011
Tesoro Logistics LP, the refined oil terminal, pipeline and tank storage unit of refiner Tesoro Corp (NYSE:TSO) set an estimate price range for its IPO of $19 to $21 a common unit.
The Delaware Limited Partnership will offer 12.5 million common units, and plans to raise about $250 million dollars.
A large part of the proceeds will be distributed to Tesoro Corp to reimburse the company for certain capital expenditures incurred.
Tesoro Logistics LP plans to trade under the symbol TLLP on the New York Stock Exchange.
Beach Discovers Oil at Butlers Well
Beach Discovers Oil at Butlers Well
Wednesday, April 13, 2011
Beach Energy Ltd.
Beach had its third success from as many wells in its 16 well operated program in the Western Flank of the Cooper Basin with the Butlers-2 well encountering a five meter oil column. The Butlers-2 well is located 950 meters NE of the Butlers-1 discovery well.
The Butlers-2 oil column was encountered in the Namur Sandstone reservoir and was consistent with pre-drill expectations. The large step-out will result in an upgrade of recoverable oil reserves from the Butlers Field of approximately 1.5 million barrels (gross), subject to remapping and a detailed review of the well data. Beach will announce a firmer reserve assessment as appropriate data becomes available.
Butlers-2 is is expected to be on-line around mid-July after completion of the new Butlers oil facility. Oil from the Butlers Field is transported from the Western Flank by flowline to Moomba. The success at Butlers-2 is likely to lead to additional development drilling in the Butlers Field. The Ensign#30 rig will now be moved to the Butlers-3 development well location which is located about 320 meters to the NW of Butlers-1.
Participants in PEL 92 are:
* Beach 75% (Operator)
* Cooper Energy Limited 25%
Wednesday, April 13, 2011
Beach Energy Ltd.
Beach had its third success from as many wells in its 16 well operated program in the Western Flank of the Cooper Basin with the Butlers-2 well encountering a five meter oil column. The Butlers-2 well is located 950 meters NE of the Butlers-1 discovery well.
The Butlers-2 oil column was encountered in the Namur Sandstone reservoir and was consistent with pre-drill expectations. The large step-out will result in an upgrade of recoverable oil reserves from the Butlers Field of approximately 1.5 million barrels (gross), subject to remapping and a detailed review of the well data. Beach will announce a firmer reserve assessment as appropriate data becomes available.
Butlers-2 is is expected to be on-line around mid-July after completion of the new Butlers oil facility. Oil from the Butlers Field is transported from the Western Flank by flowline to Moomba. The success at Butlers-2 is likely to lead to additional development drilling in the Butlers Field. The Ensign#30 rig will now be moved to the Butlers-3 development well location which is located about 320 meters to the NW of Butlers-1.
Participants in PEL 92 are:
* Beach 75% (Operator)
* Cooper Energy Limited 25%
Tower Resources Notes Seismic Ops in Namibia, Uganda Licenses
Tower Resources Notes Seismic Ops in Namibia, Uganda Licenses
Wednesday, April 13, 2011
Tower Resources plc
Tower Resources provided an update on its current operations in each country, managed by wholly-owned subsidiaries Neptune Petroleum (Namibia) Limited and Neptune Petroleum (Uganda) Limited.
Namibia
In License 0010, offshore Namibia, where Neptune Petroleum (Namibia) Limited has a 15% carried interest, interpretation of the 3-D seismic is well advanced with initial conclusions delivered from all of the specialist consultants. Clear structural closure, sustained reservoir thickness and direct hydrocarbon indicators - AVO anomalies and pock marks - have been confirmed at the main Maastrichtian prospect level. Additional potential is confirmed at the Palaeocene horizon (defined as a lead in the Competent Persons Report (CPR)) but also at two other formations deeper than the Maastrichtian. The very large structural closures are confirmed and, therefore, the indicated additional reservoir horizons substantially increase the resource upside potential.
Arcadia Petroleum Limited, operator of License 0010, which is funding Tower for the cost of the first well, is making progress with its program to put in place funding and to contract a deep water drilling rig with a view to drilling around the end of 2011. At present, there appear to be suitable rigs available during the target period. A CPR is currently being updated with a targeted publication early in June 2011.
Uganda
A letter of intent in advance of a contract for the 2-D seismic program of 150-200 kms has been signed with TESLA-IMC International Limited and line clearance is expected to begin by late April. Completion is targeted for end June 2011, by which time a well location can be selected. A high density geochemical survey, conducted by GORE Geochemical Surveys, is also underway over the prospect area together with focused sampling around the two existing wells and an oil-bearing well in EA1. The Environmental Impact Assessment and early operational planning for a third well have begun. Now that the political uncertainty with respect to long term development planning in Uganda appears to have been resolved, a final phase of the farm out program has been initiated. The Tower Board has raised the additional equity capital required to undertake the seismic program on schedule and a well can still be drilled in October 2011, subject to rig availability. If the cost of seismic is subsequently met by a third party, the funds will be deployed on new projects.
Peter Kingston, Executive Chairman of Tower Resources, commented, "I am pleased to confirm that the first well in Namibia, to test the huge potential of the Delta prospect, remains a target within a year. The 3-D seismic interpretation has confirmed the 2-D seismic interpretation but has also opened up significant potential from additional reservoirs. I am also pleased that the Uganda seismic and well program is still on schedule."
Wednesday, April 13, 2011
Tower Resources plc
Tower Resources provided an update on its current operations in each country, managed by wholly-owned subsidiaries Neptune Petroleum (Namibia) Limited and Neptune Petroleum (Uganda) Limited.
Namibia
In License 0010, offshore Namibia, where Neptune Petroleum (Namibia) Limited has a 15% carried interest, interpretation of the 3-D seismic is well advanced with initial conclusions delivered from all of the specialist consultants. Clear structural closure, sustained reservoir thickness and direct hydrocarbon indicators - AVO anomalies and pock marks - have been confirmed at the main Maastrichtian prospect level. Additional potential is confirmed at the Palaeocene horizon (defined as a lead in the Competent Persons Report (CPR)) but also at two other formations deeper than the Maastrichtian. The very large structural closures are confirmed and, therefore, the indicated additional reservoir horizons substantially increase the resource upside potential.
Arcadia Petroleum Limited, operator of License 0010, which is funding Tower for the cost of the first well, is making progress with its program to put in place funding and to contract a deep water drilling rig with a view to drilling around the end of 2011. At present, there appear to be suitable rigs available during the target period. A CPR is currently being updated with a targeted publication early in June 2011.
Uganda
A letter of intent in advance of a contract for the 2-D seismic program of 150-200 kms has been signed with TESLA-IMC International Limited and line clearance is expected to begin by late April. Completion is targeted for end June 2011, by which time a well location can be selected. A high density geochemical survey, conducted by GORE Geochemical Surveys, is also underway over the prospect area together with focused sampling around the two existing wells and an oil-bearing well in EA1. The Environmental Impact Assessment and early operational planning for a third well have begun. Now that the political uncertainty with respect to long term development planning in Uganda appears to have been resolved, a final phase of the farm out program has been initiated. The Tower Board has raised the additional equity capital required to undertake the seismic program on schedule and a well can still be drilled in October 2011, subject to rig availability. If the cost of seismic is subsequently met by a third party, the funds will be deployed on new projects.
Peter Kingston, Executive Chairman of Tower Resources, commented, "I am pleased to confirm that the first well in Namibia, to test the huge potential of the Delta prospect, remains a target within a year. The 3-D seismic interpretation has confirmed the 2-D seismic interpretation but has also opened up significant potential from additional reservoirs. I am also pleased that the Uganda seismic and well program is still on schedule."
Reef Resources Encounters Oil Pay at Ontario Well
Reef Resources Encounters Oil Pay at Ontario Well
Wednesday, April 13, 2011
Solo Oil plc
Reef Resources reported that petrophysical analysis has been finalized on its Ausable #5 well. Log analysis indicates 72 meters net pay of oil, natural gas liquids (NGL's) and natural gas in the Guelph and A2 formations in Ontario, Canada.
Log analysis in the Guelph indicates net oil and gas liquids pay zone is 57 meters with porosity averaging 9.7%. Evidence of hydrocarbons was evident on core and logs throughout the Guelph formation.
Additionally, the shallower A2 formation was identified as a potential gas producer with net pay of 15 meters and 7% porosity.
The Company will now undertake a work program in order to complete the hole and flow test the well, with the intent of bringing the Ausable #5 well on production.
A comprehensive core analysis will be conducted in the near future to determine cap rock integrity for future gas storage, permeability of the producing zones and provide useful information for the upcoming completion program.
Arnie Hansen, President, stated, "The Ausable #5 well has exceeded our expectations. The log and core results confirm the notion the Ausable reef is an underutilized and undervalued asset. Findings on the Ausable #5 well confirm the Company logic to accelerate the Enhanced Oil Recovery (EOR) and Natural Gas Liquids program."
Reef will be announcing test results after completion and next development steps in the EOR, NGL program.
The Ausable reef is currently on production and is generating revenue from the initial Enhanced Oil Recovery Natural Gas Liquids Recycling program which commenced in 4th quarter 2010.
Solo Executive Director, Neil Ritson, commented, "These results, with over 70 metres of net hydrocarbon pay, are extremely encouraging and the Ausable #5 well has a high probability of being productive. This result contributes significantly to the field development plan and to the knowledge necessary to successfully optimize the EOR scheme. The well, financed by Solo's participating loan, adds further encouragement that the EOR scheme will be commercially successful."
Wednesday, April 13, 2011
Solo Oil plc
Reef Resources reported that petrophysical analysis has been finalized on its Ausable #5 well. Log analysis indicates 72 meters net pay of oil, natural gas liquids (NGL's) and natural gas in the Guelph and A2 formations in Ontario, Canada.
Log analysis in the Guelph indicates net oil and gas liquids pay zone is 57 meters with porosity averaging 9.7%. Evidence of hydrocarbons was evident on core and logs throughout the Guelph formation.
Additionally, the shallower A2 formation was identified as a potential gas producer with net pay of 15 meters and 7% porosity.
The Company will now undertake a work program in order to complete the hole and flow test the well, with the intent of bringing the Ausable #5 well on production.
A comprehensive core analysis will be conducted in the near future to determine cap rock integrity for future gas storage, permeability of the producing zones and provide useful information for the upcoming completion program.
Arnie Hansen, President, stated, "The Ausable #5 well has exceeded our expectations. The log and core results confirm the notion the Ausable reef is an underutilized and undervalued asset. Findings on the Ausable #5 well confirm the Company logic to accelerate the Enhanced Oil Recovery (EOR) and Natural Gas Liquids program."
Reef will be announcing test results after completion and next development steps in the EOR, NGL program.
The Ausable reef is currently on production and is generating revenue from the initial Enhanced Oil Recovery Natural Gas Liquids Recycling program which commenced in 4th quarter 2010.
Solo Executive Director, Neil Ritson, commented, "These results, with over 70 metres of net hydrocarbon pay, are extremely encouraging and the Ausable #5 well has a high probability of being productive. This result contributes significantly to the field development plan and to the knowledge necessary to successfully optimize the EOR scheme. The well, financed by Solo's participating loan, adds further encouragement that the EOR scheme will be commercially successful."
Toyota to cut back production in the U.K.
Toyota to cut back production in the U.K.
Apr 13, 2011
Toyota (TM) is cutting production in the U.K. as a result of the March 11 earthquake and tsunami in Japan. The automaker will suspend production at its vehicle factory in Burnaston, Derbyshire and at its engine plant in north Wales over the Easter holiday period in an effort to conserve parts. Additionally, the automaker is planning reduced production volumes in May.
Apr 13, 2011
Toyota (TM) is cutting production in the U.K. as a result of the March 11 earthquake and tsunami in Japan. The automaker will suspend production at its vehicle factory in Burnaston, Derbyshire and at its engine plant in north Wales over the Easter holiday period in an effort to conserve parts. Additionally, the automaker is planning reduced production volumes in May.
Leni Briefs Final Details for Spanish Work-Over Ops
Leni Briefs Final Details for Spanish Work-Over Ops
Wednesday, April 13, 2011
Leni Gas & Oil plc
Leni announced final details regarding its planned work-over operations at its 100% owned Ayoluengo and Hontomin Oilfields in Northern Spain.
The Company's Spanish subsidiary Compania Petrolifera de Sedano S.L. has signed contracts and agreed work scopes with both the Société de Maintenance Pétrolière ("SMP") and Services Pétrolièrs Schlumberger ("Schlumberger"). The Company has also received all outstanding permits and authorizations from the Spanish authorities in order to commence the planned work-over program announced on March 17, 2011.
Schlumberger will provide all necessary wireline logging and perforating services, as well as cementing services if required, and SMP will supply their 80-tonne "SMP-2" drilling unit which will be used in conjunction with the Company owned Cardwell 45-tonne rig to ensure overall smooth operations. Mobilization to the field will commence shortly and the program is expected to get underway on April 26, 2011.
As announced in March, work will initially focus on six high productivity wells in the crestal area of the Ayoluengo Field (Ayo-4, 5, 32, 36, 37and 46) and the perforation of approximately 45 meters of previously untapped reservoir in the Hontomin-2 well on the nearby Hontomin Field. Each Ayoluengo well will be cleaned out, re-perforated over existing intervals, some new intervals will be perforated and the casing and production tubulars will be repaired. Additional cementing operations will be selectively undertaken to improve water shut-off where this is required. A progressive cavitation pump (PCP) will be installed in well Ayo-37 to increase the production and reliability of that well. Depending on initial results up to four additional wells (Ayo-18, 35, 38 and 44) may be added to the program at Ayoluengo.
The estimated production capacity from the work-over program ranges from 300 to over 500 barrels oil per day. The initial seven well program is expected to be completed within 60 days.
Neil Ritson, LGO Chief Executive commented, "We are very pleased to be undertaking this work which will immediately benefit both the production levels and cash flow from our Spanish operations. This is of course especially beneficial at a time of high oil prices. Successful results from this initial program will lead to further investment in the field facilities and the completion of additional wells."
Wednesday, April 13, 2011
Leni Gas & Oil plc
Leni announced final details regarding its planned work-over operations at its 100% owned Ayoluengo and Hontomin Oilfields in Northern Spain.
The Company's Spanish subsidiary Compania Petrolifera de Sedano S.L. has signed contracts and agreed work scopes with both the Société de Maintenance Pétrolière ("SMP") and Services Pétrolièrs Schlumberger ("Schlumberger"). The Company has also received all outstanding permits and authorizations from the Spanish authorities in order to commence the planned work-over program announced on March 17, 2011.
Schlumberger will provide all necessary wireline logging and perforating services, as well as cementing services if required, and SMP will supply their 80-tonne "SMP-2" drilling unit which will be used in conjunction with the Company owned Cardwell 45-tonne rig to ensure overall smooth operations. Mobilization to the field will commence shortly and the program is expected to get underway on April 26, 2011.
As announced in March, work will initially focus on six high productivity wells in the crestal area of the Ayoluengo Field (Ayo-4, 5, 32, 36, 37and 46) and the perforation of approximately 45 meters of previously untapped reservoir in the Hontomin-2 well on the nearby Hontomin Field. Each Ayoluengo well will be cleaned out, re-perforated over existing intervals, some new intervals will be perforated and the casing and production tubulars will be repaired. Additional cementing operations will be selectively undertaken to improve water shut-off where this is required. A progressive cavitation pump (PCP) will be installed in well Ayo-37 to increase the production and reliability of that well. Depending on initial results up to four additional wells (Ayo-18, 35, 38 and 44) may be added to the program at Ayoluengo.
The estimated production capacity from the work-over program ranges from 300 to over 500 barrels oil per day. The initial seven well program is expected to be completed within 60 days.
Neil Ritson, LGO Chief Executive commented, "We are very pleased to be undertaking this work which will immediately benefit both the production levels and cash flow from our Spanish operations. This is of course especially beneficial at a time of high oil prices. Successful results from this initial program will lead to further investment in the field facilities and the completion of additional wells."
Seadrill Sells West Juno Rig
Seadrill Sells West Juno Rig
Wednesday, April 13, 201
Seadrill Ltd.
Seadrill has entered into an agreement to sell the newly built jack-up drilling rig West Juno to an undisclosed buyer incorporated in the UK for a total consideration of US $248.5 million.
Seadrill expects to record a gain on sale of approximately US $18 million on closing. Closing of the agreement and the transfer of ownership of the unit is scheduled upon completion of the rig's present drilling assignment late second quarter or early third quarter 2011. Seadrill expects to have an EBITDA contribution from the rig in the period up to closing of approximately US $6 million.
Alf C Thorkildsen, CEO of Seadrill Management AS, said, "We are continuously evaluating sale and purchase opportunities in order to maximize the long term return for our shareholders. This dynamic approach can from time to time lead to divestments and reallocation of capital. We have through the sale of West Juno at an attractive price been able to monetize the underlying strength of the jack up market. Although we remain optimistic on the market outlook for premium jack-up rigs, we have decided to relocate the proceeds to fund investment in other new unit as we since October 2010 have committed to investing US $4.7 billion in newbuildings."
Seadrill's fleet of jack-up rigs remains the world largest modern jack-up fleet with a total of 19 units built after 2006. Furthermore Seadrill has options for construction of further six units at attractive prices compared to going market prices.
Wednesday, April 13, 201
Seadrill Ltd.
Seadrill has entered into an agreement to sell the newly built jack-up drilling rig West Juno to an undisclosed buyer incorporated in the UK for a total consideration of US $248.5 million.
Seadrill expects to record a gain on sale of approximately US $18 million on closing. Closing of the agreement and the transfer of ownership of the unit is scheduled upon completion of the rig's present drilling assignment late second quarter or early third quarter 2011. Seadrill expects to have an EBITDA contribution from the rig in the period up to closing of approximately US $6 million.
Alf C Thorkildsen, CEO of Seadrill Management AS, said, "We are continuously evaluating sale and purchase opportunities in order to maximize the long term return for our shareholders. This dynamic approach can from time to time lead to divestments and reallocation of capital. We have through the sale of West Juno at an attractive price been able to monetize the underlying strength of the jack up market. Although we remain optimistic on the market outlook for premium jack-up rigs, we have decided to relocate the proceeds to fund investment in other new unit as we since October 2010 have committed to investing US $4.7 billion in newbuildings."
Seadrill's fleet of jack-up rigs remains the world largest modern jack-up fleet with a total of 19 units built after 2006. Furthermore Seadrill has options for construction of further six units at attractive prices compared to going market prices.
BP Races to Save Deal With Rosneft
BP Races to Save Deal With Rosneft
Wednesday, April 13, 2011
The Wall Street Journal
by Guy Chazan & Gregory L. White
As a bruising fight between BP and some of Russia's most powerful oligarchs intensifies, BP is now weighing a previously unthinkable step to end the battle: possibly pulling out of its lucrative Russian joint venture with the oligarchs, TNK-BP.
BP is considering the move as part of its scramble to salvage a separate, proposed alliance with Russia's state oil company, Rosneft, before a crucial deadline for that deal -- which is opposed by its TNK-BP partners -- expires Thursday.
The U.K. oil company is considering a range of options to rescue the Rosneft partnership, some of which would have been inconceivable before the deal ran into trouble in February. One of them is to divest its 50% stake in TNK-BP, according to a person familiar with the matter.
Selling its half of a company that accounts for one quarter of BP's global oil-and-gas production and close to one-fifth of its reserves is seen as unlikely. But it is a sign of BP's desperation as the countdown begins to Thursday's deadline that it is even considering such an option.
In January, BP and Rosneft said they would swap shares in each other and jointly explore for oil and gas in the Russian Arctic, an area previously off limits to foreign oil companies, as part of a groundbreaking strategic partnership.
But BP's partners in TNK-BP, a consortium of Soviet-born billionaires collectively known as AAR, claimed the Rosneft deal violated their shareholder agreement, which stipulated that TNK-BP should be the main vehicle for both partners' investments in Russia. In February, AAR won a court injunction blocking the deal.
Last Friday a panel of independent arbitrators left the injunction in place until further notice but gave BP permission to seek to extend the April 14 deadline for the share swap.
The company is now pursuing a number of solutions to its dispute with AAR. Yet even now, it isn't clear which path it will take to extricate itself from the mess.
The options under consideration include allowing TNK-BP to participate in the Arctic venture, possibly through an equity interest, or compensating AAR financially to win its assent to the deal, according to the person familiar with the matter. However, some people close to BP think AAR is likely to demand a level of compensation that is far beyond what BP could accept.
Alternatively, Rosneft, BP or a third party could buy out AAR's stake in TNK-BP; or Rosneft or a third party could buy out BP's stake, the person familiar with the matter said.
Most of those options are considered extremely difficult to execute, according to analysts. AAR's 50% stake in TNK-BP is thought to be worth at least $25 billion, and it would be hard for BP or Rosneft to raise that kind of capital. The Russian government, opposed to foreign ownership of its strategic natural resources, may also balk at BP taking full ownership of one of Russia's largest oil producers.
On the other hand, BP would be loath to divest TNK-BP, whose rich dividend flow quickly exceeded BP's original investment, industry observers say.
In addition, it is unclear who would buy its stake. Most other Western oil companies are too risk-averse to make such a big bet on Russia.
"I think BP selling out of TNK-BP is the least likely option," said a Russian banker with knowledge of the firms. "It's a cash machine." He expects BP to offer AAR compensation, "a considerable payout, running into the billions of dollars."
There is little sign Rosneft will agree to an extension of the share-swap deadline, given its doubts about whether BP would be able to prevail in arbitration with AAR. "[Rosneft] seem to be frustrated," one person close to BP said. A spokesman for the Russian company said it had received no proposals from BP.
Meanwhile, people close to TNK-BP said the company was planning lawsuits against BP and its managers to claim compensation for damages the venture allegedly suffered from missing out on the Rosneft deal. People close to BP dismissed the leaks as a pressure tactic, apparently aimed at signaling BP won't be able to restore the status quo inside TNK-BP that existed before it announced its tie-up with Rosneft. Media reports about the planned lawsuits helped push BP shares lower Tuesday.
Wednesday, April 13, 2011
The Wall Street Journal
by Guy Chazan & Gregory L. White
As a bruising fight between BP and some of Russia's most powerful oligarchs intensifies, BP is now weighing a previously unthinkable step to end the battle: possibly pulling out of its lucrative Russian joint venture with the oligarchs, TNK-BP.
BP is considering the move as part of its scramble to salvage a separate, proposed alliance with Russia's state oil company, Rosneft, before a crucial deadline for that deal -- which is opposed by its TNK-BP partners -- expires Thursday.
The U.K. oil company is considering a range of options to rescue the Rosneft partnership, some of which would have been inconceivable before the deal ran into trouble in February. One of them is to divest its 50% stake in TNK-BP, according to a person familiar with the matter.
Selling its half of a company that accounts for one quarter of BP's global oil-and-gas production and close to one-fifth of its reserves is seen as unlikely. But it is a sign of BP's desperation as the countdown begins to Thursday's deadline that it is even considering such an option.
In January, BP and Rosneft said they would swap shares in each other and jointly explore for oil and gas in the Russian Arctic, an area previously off limits to foreign oil companies, as part of a groundbreaking strategic partnership.
But BP's partners in TNK-BP, a consortium of Soviet-born billionaires collectively known as AAR, claimed the Rosneft deal violated their shareholder agreement, which stipulated that TNK-BP should be the main vehicle for both partners' investments in Russia. In February, AAR won a court injunction blocking the deal.
Last Friday a panel of independent arbitrators left the injunction in place until further notice but gave BP permission to seek to extend the April 14 deadline for the share swap.
The company is now pursuing a number of solutions to its dispute with AAR. Yet even now, it isn't clear which path it will take to extricate itself from the mess.
The options under consideration include allowing TNK-BP to participate in the Arctic venture, possibly through an equity interest, or compensating AAR financially to win its assent to the deal, according to the person familiar with the matter. However, some people close to BP think AAR is likely to demand a level of compensation that is far beyond what BP could accept.
Alternatively, Rosneft, BP or a third party could buy out AAR's stake in TNK-BP; or Rosneft or a third party could buy out BP's stake, the person familiar with the matter said.
Most of those options are considered extremely difficult to execute, according to analysts. AAR's 50% stake in TNK-BP is thought to be worth at least $25 billion, and it would be hard for BP or Rosneft to raise that kind of capital. The Russian government, opposed to foreign ownership of its strategic natural resources, may also balk at BP taking full ownership of one of Russia's largest oil producers.
On the other hand, BP would be loath to divest TNK-BP, whose rich dividend flow quickly exceeded BP's original investment, industry observers say.
In addition, it is unclear who would buy its stake. Most other Western oil companies are too risk-averse to make such a big bet on Russia.
"I think BP selling out of TNK-BP is the least likely option," said a Russian banker with knowledge of the firms. "It's a cash machine." He expects BP to offer AAR compensation, "a considerable payout, running into the billions of dollars."
There is little sign Rosneft will agree to an extension of the share-swap deadline, given its doubts about whether BP would be able to prevail in arbitration with AAR. "[Rosneft] seem to be frustrated," one person close to BP said. A spokesman for the Russian company said it had received no proposals from BP.
Meanwhile, people close to TNK-BP said the company was planning lawsuits against BP and its managers to claim compensation for damages the venture allegedly suffered from missing out on the Rosneft deal. People close to BP dismissed the leaks as a pressure tactic, apparently aimed at signaling BP won't be able to restore the status quo inside TNK-BP that existed before it announced its tie-up with Rosneft. Media reports about the planned lawsuits helped push BP shares lower Tuesday.
ONGC to Buy 25% Stake in Kazakh Exploration Block
ONGC to Buy 25% Stake in Kazakh Exploration Block
Wednesday, April 13, 2011
Dow Jones Newswires
by Rakesh Sharma
Oil & Natural Gas Corp. will sign an agreement Saturday to purchase a 25% stake in the Satpayev exploration block in Kazakhstan, the chairman of India's biggest explorer said Wednesday.
"The government [of India] has approved a total investment plan of $400 million. This includes a signature bonus of $13 million and $80 million as a fee for taking the stake in the block," A. K. Hazarika told Dow Jones Newswires.
"The rest will be spent on exploration activities."
The deal will mark another success by ONGC in its attempts to buy oil and gas assets overseas to secure energy supplies for the world's fastest-growing major economy after China. The state-run company, which has been witnessing a decline in production at its aging fields in India, has in the past missed out on several overseas oil and gas asset acquisitions, especially to cash-rich Chinese companies in western Africa.
Kazakhstan's Satpayev exploration block is located in a hydrocarbon-rich region of the North Caspian Sea, off the country's south-western coast.
KazMunaiGas, Kazakhstan's national oil company, will hold the remaining 75% stake in the block.
The initial agreement for the stake sale was signed in 2009, but the governments haven't so far disclosed the valuation for the stake transfer.
ONGC had originally sought the 25% stake in association with Lakshmi Niwas Mittal's Mittal Investments Sarl, but the billionaire, who owns a steel mill in the central Asian nation, pulled out of the venture in November 2009, leaving ONGC to pursue the deal on its own.
ONGC will likely purchase the stake in the Satpayev block via its overseas investment unit, ONGC Videsh Ltd.
Hazarika said the agreement will be signed during Indian Prime Minister Manmohan Singh's visit to Kazakhstan for bilateral meetings. Singh will visit Kazakhstan Friday and Saturday.
The Indian government is pushing state-run explorers to expedite acquisitions of overseas exploration and producing assets as a possible hedge against fluctuations in global crude oil prices and save on precious foreign exchange. The South Asian country imports four-fifths of its crude oil requirements.
Earlier Wednesday, the Hindustan Times reported that a peak output of 287,000 barrels per day is envisaged from the 256 million tons of reserves in the Satpayev field.
Hazarika declined give details on the reserves. "That has to be seen," he said.
Wednesday, April 13, 2011
Dow Jones Newswires
by Rakesh Sharma
Oil & Natural Gas Corp. will sign an agreement Saturday to purchase a 25% stake in the Satpayev exploration block in Kazakhstan, the chairman of India's biggest explorer said Wednesday.
"The government [of India] has approved a total investment plan of $400 million. This includes a signature bonus of $13 million and $80 million as a fee for taking the stake in the block," A. K. Hazarika told Dow Jones Newswires.
"The rest will be spent on exploration activities."
The deal will mark another success by ONGC in its attempts to buy oil and gas assets overseas to secure energy supplies for the world's fastest-growing major economy after China. The state-run company, which has been witnessing a decline in production at its aging fields in India, has in the past missed out on several overseas oil and gas asset acquisitions, especially to cash-rich Chinese companies in western Africa.
Kazakhstan's Satpayev exploration block is located in a hydrocarbon-rich region of the North Caspian Sea, off the country's south-western coast.
KazMunaiGas, Kazakhstan's national oil company, will hold the remaining 75% stake in the block.
The initial agreement for the stake sale was signed in 2009, but the governments haven't so far disclosed the valuation for the stake transfer.
ONGC had originally sought the 25% stake in association with Lakshmi Niwas Mittal's Mittal Investments Sarl, but the billionaire, who owns a steel mill in the central Asian nation, pulled out of the venture in November 2009, leaving ONGC to pursue the deal on its own.
ONGC will likely purchase the stake in the Satpayev block via its overseas investment unit, ONGC Videsh Ltd.
Hazarika said the agreement will be signed during Indian Prime Minister Manmohan Singh's visit to Kazakhstan for bilateral meetings. Singh will visit Kazakhstan Friday and Saturday.
The Indian government is pushing state-run explorers to expedite acquisitions of overseas exploration and producing assets as a possible hedge against fluctuations in global crude oil prices and save on precious foreign exchange. The South Asian country imports four-fifths of its crude oil requirements.
Earlier Wednesday, the Hindustan Times reported that a peak output of 287,000 barrels per day is envisaged from the 256 million tons of reserves in the Satpayev field.
Hazarika declined give details on the reserves. "That has to be seen," he said.
Tullow IDs Gas Finds at Tano License
Tullow IDs Gas Finds at Tano License
Wednesday, April 13, 2011
Tullow Oil plc
The Tweneboa-4 appraisal well in the Deepwater Tano license offshore Ghana has successfully encountered gas condensate in good quality sandstone reservoirs. Results of drilling, wireline logs and samples of reservoir fluids have confirmed the western extent of the Tweneboa gas condensate accumulation.
The well, located 3.9 kilometres southwest of the Tweneboa-2 appraisal well was drilled in the western flank of the accumulation to complete the appraisal of the Tweneboa gas-condensate discovery. The well encountered 18 meters of net gas condensate pay in high quality stacked reservoir sandstones which are in static pressure communication with both the Tweneboa-1 and Tweneboa-2 wells.
The Deepwater Millennium dynamically positioned drillship drilled Tweneboa-4 to a total depth of 4,007 meters in water depths of 1,436 meters. On completion of operations, the well will be suspended for future use in field appraisal and development. The rig will then move to perform drill stem tests on the Tweneboa-2 oil and gas-condensate accumulations.
Tullow (49.95%) operates the Deepwater Tano license and is partnered by Kosmos Energy Ghana (18%), Anadarko Petroleum (18%), Sabre Oil & Gas (4.05%) and the Ghana National Petroleum Corporation (GNPC) (10% carried interest).
Uganda exploration and appraisal campaign commences
Following the signing of the SPAs for the farmdown to CNOOC and Total on March 29, 2011, the exploration and appraisal program has been reactivated and two wells are expected to commence drilling in Exploration Area 1 (EA 1) within the next two weeks. The OGEC 600 rig is preparing to spud the high-impact Jobi-East prospect and the OGEC 750 rig is getting ready to drill the first Mpyo exploratory appraisal well to test its upside potential. These wells are the start of a major program of exploration and appraisal drilling, seismic acquisition, and well testing to access the significant remaining upside potential in the basin and further expand the resource base for development.
Commenting, Angus McCoss, Exploration Director, said, "Tweneboa-4 is an important milestone as it is the final well to be drilled in the Tweneboa appraisal program. The upcoming program of well testing in the Tweneboa field, along with drilling and well testing in the Enyenra field, will provide essential information on well deliverability, dynamic reservoir connectivity and hydrocarbon volumes, which will be used to optimize our development plans for these major fields. We are also delighted to be starting drilling activities again in EA 1 in Uganda and are now gearing up for a five-rig drill-out campaign in the second half of the year."
Wednesday, April 13, 2011
Tullow Oil plc
The Tweneboa-4 appraisal well in the Deepwater Tano license offshore Ghana has successfully encountered gas condensate in good quality sandstone reservoirs. Results of drilling, wireline logs and samples of reservoir fluids have confirmed the western extent of the Tweneboa gas condensate accumulation.
The well, located 3.9 kilometres southwest of the Tweneboa-2 appraisal well was drilled in the western flank of the accumulation to complete the appraisal of the Tweneboa gas-condensate discovery. The well encountered 18 meters of net gas condensate pay in high quality stacked reservoir sandstones which are in static pressure communication with both the Tweneboa-1 and Tweneboa-2 wells.
The Deepwater Millennium dynamically positioned drillship drilled Tweneboa-4 to a total depth of 4,007 meters in water depths of 1,436 meters. On completion of operations, the well will be suspended for future use in field appraisal and development. The rig will then move to perform drill stem tests on the Tweneboa-2 oil and gas-condensate accumulations.
Tullow (49.95%) operates the Deepwater Tano license and is partnered by Kosmos Energy Ghana (18%), Anadarko Petroleum (18%), Sabre Oil & Gas (4.05%) and the Ghana National Petroleum Corporation (GNPC) (10% carried interest).
Uganda exploration and appraisal campaign commences
Following the signing of the SPAs for the farmdown to CNOOC and Total on March 29, 2011, the exploration and appraisal program has been reactivated and two wells are expected to commence drilling in Exploration Area 1 (EA 1) within the next two weeks. The OGEC 600 rig is preparing to spud the high-impact Jobi-East prospect and the OGEC 750 rig is getting ready to drill the first Mpyo exploratory appraisal well to test its upside potential. These wells are the start of a major program of exploration and appraisal drilling, seismic acquisition, and well testing to access the significant remaining upside potential in the basin and further expand the resource base for development.
Commenting, Angus McCoss, Exploration Director, said, "Tweneboa-4 is an important milestone as it is the final well to be drilled in the Tweneboa appraisal program. The upcoming program of well testing in the Tweneboa field, along with drilling and well testing in the Enyenra field, will provide essential information on well deliverability, dynamic reservoir connectivity and hydrocarbon volumes, which will be used to optimize our development plans for these major fields. We are also delighted to be starting drilling activities again in EA 1 in Uganda and are now gearing up for a five-rig drill-out campaign in the second half of the year."
Eni Takes Stake in Cadogan's Ukrainian Licenses
Eni Takes Stake in Cadogan's Ukrainian Licenses
Wednesday, April 13, 2011
Cadogan Petroleum plc
Cadogan has reached agreement with Eni for the acquisition of an interest in the Company's Pokrovskoe and Zagoryanska licenses in the east of Ukraine.
Eni will initially acquire a 30% interest in the Pokrovskoe license, with the option to acquire a further 30% interest in the future. Eni will also acquire a 60% interest in the Zagoryanska license. The initial consideration will comprise 100% funding of a work program of approximately $30 million (excluding VAT), including drilling and seismic re-processing, plus a $38 million payment. Subject to successful results from the above programs and award of production licenses, Eni will pay the Company further amounts of up to $90 million.
The transaction, which is a class one transaction under the UKLA Listing Rules, is subject to Cadogan shareholder and Ukrainian Anti-Monopoly Commission approval. The Company plans to issue a circular to shareholders in May 2011, giving full details of the proposed transaction and convening a general meeting of the Company prior to mid June 2011. Other Conditions Precedent to completion of the deal include satisfactory conclusion of an internal re-structuring within the Company, no material adverse effects between signature of the agreement and completion and all representations and warranties of the Company and Eni being true at completion. It is planned that the transaction will complete on or around June 30, 2011.
The $30 million work program on Pokrovska will be used to fulfill the work obligations on the license and will test the potential of the Upper and Lower Visean intervals which had strong indications of hydrocarbons in wells on the license. The cash proceeds arising from the transaction will be applied to finance any future Zagoryanska work programs and fund development of the Company's other assets. Additional future cash proceeds from successful operational results and the award of production licenses will further strengthen the Company's financial position, enabling it to finance its share of future development activities and to invest in new business opportunities.
Commenting on the proposed transaction Simon Duffy, Chairman, stated, "The announcement of this major transaction signifies a turning point for Cadogan. With Eni as a strategic partner, the Company can more rapidly develop the potential in these licenses and can embark on other significant oil & gas opportunities that are present in Ukraine."
Ian Baron, Chief Executive Officer commented, "The investment by Eni in two of our Ukrainian assets vindicates the Board's view, not only of the value of these particular assets, but also the scale and substance of the opportunity in the country. We strongly believe that Ukraine offers significant opportunity for Cadogan and Eni, which we can develop through combining the expertise of Cadogan's staff with the resources of a major oil company."
Wednesday, April 13, 2011
Cadogan Petroleum plc
Cadogan has reached agreement with Eni for the acquisition of an interest in the Company's Pokrovskoe and Zagoryanska licenses in the east of Ukraine.
Eni will initially acquire a 30% interest in the Pokrovskoe license, with the option to acquire a further 30% interest in the future. Eni will also acquire a 60% interest in the Zagoryanska license. The initial consideration will comprise 100% funding of a work program of approximately $30 million (excluding VAT), including drilling and seismic re-processing, plus a $38 million payment. Subject to successful results from the above programs and award of production licenses, Eni will pay the Company further amounts of up to $90 million.
The transaction, which is a class one transaction under the UKLA Listing Rules, is subject to Cadogan shareholder and Ukrainian Anti-Monopoly Commission approval. The Company plans to issue a circular to shareholders in May 2011, giving full details of the proposed transaction and convening a general meeting of the Company prior to mid June 2011. Other Conditions Precedent to completion of the deal include satisfactory conclusion of an internal re-structuring within the Company, no material adverse effects between signature of the agreement and completion and all representations and warranties of the Company and Eni being true at completion. It is planned that the transaction will complete on or around June 30, 2011.
The $30 million work program on Pokrovska will be used to fulfill the work obligations on the license and will test the potential of the Upper and Lower Visean intervals which had strong indications of hydrocarbons in wells on the license. The cash proceeds arising from the transaction will be applied to finance any future Zagoryanska work programs and fund development of the Company's other assets. Additional future cash proceeds from successful operational results and the award of production licenses will further strengthen the Company's financial position, enabling it to finance its share of future development activities and to invest in new business opportunities.
Commenting on the proposed transaction Simon Duffy, Chairman, stated, "The announcement of this major transaction signifies a turning point for Cadogan. With Eni as a strategic partner, the Company can more rapidly develop the potential in these licenses and can embark on other significant oil & gas opportunities that are present in Ukraine."
Ian Baron, Chief Executive Officer commented, "The investment by Eni in two of our Ukrainian assets vindicates the Board's view, not only of the value of these particular assets, but also the scale and substance of the opportunity in the country. We strongly believe that Ukraine offers significant opportunity for Cadogan and Eni, which we can develop through combining the expertise of Cadogan's staff with the resources of a major oil company."
Nexen Drills Dry Well in North Sea
Nexen Drills Dry Well in North Sea
Wednesday, April 13, 2011
Norwegian Petroleum Directorate
Nexen, operator of production license 434, has completed the drilling of wildcat well 6507/8-8.
The well was drilled about seven kilometers southeast of the Heidrun field.
The purpose of the well was to prove petroleum in Lower Jurassic reservoir rocks (the Tilje and Åre formations).
Reservoir rocks of expected thickness and of good quality were encountered in the Tilje and Åre formations. Data acquisition and sampling were carried out. The well is dry.
This is the first exploration well in production license 434. The production license was awarded in APA 2006.
The well was drilled to a vertical depth of 2525 meters below sea level, and was terminated in the Åre formation in the Lower Jurassic. The water depth is 329 meters. The well has now been permanently plugged and abandoned.
Well 6507/8-8 was drilled by the drilling facility Songa Delta, which will proceed to production license 378 in the North Sea to drill appraisal well 35/12-4, where Wintershall Norge ASA is the operator.
Wednesday, April 13, 2011
Norwegian Petroleum Directorate
Nexen, operator of production license 434, has completed the drilling of wildcat well 6507/8-8.
The well was drilled about seven kilometers southeast of the Heidrun field.
The purpose of the well was to prove petroleum in Lower Jurassic reservoir rocks (the Tilje and Åre formations).
Reservoir rocks of expected thickness and of good quality were encountered in the Tilje and Åre formations. Data acquisition and sampling were carried out. The well is dry.
This is the first exploration well in production license 434. The production license was awarded in APA 2006.
The well was drilled to a vertical depth of 2525 meters below sea level, and was terminated in the Åre formation in the Lower Jurassic. The water depth is 329 meters. The well has now been permanently plugged and abandoned.
Well 6507/8-8 was drilled by the drilling facility Songa Delta, which will proceed to production license 378 in the North Sea to drill appraisal well 35/12-4, where Wintershall Norge ASA is the operator.
McMoRan Runs at Rate of 54 MMcf/d at Laphroaig Well
McMoRan Runs at Rate of 54 MMcf/d at Laphroaig Well
Wednesday, April 13, 2011
McMoRan Exploration Co.
McMoRan announced a successful production test at the Laphroaig No. 2 well in St. Mary Parish, Louisiana. The production test indicated a gross rate of approximately 54 million cubic feet of natural gas per day (MMcf/d) (approximately 15 MMcf/d net to McMoRan) and zero barrels of water on a 30/64th choke with flowing tubing pressure of 9,989 pounds per square inch (PSI). McMoRan will use the results of the production test to determine the optimal flow rate for the well. The well is expected to commence production in the second quarter of 2011 using facilities in the immediate area. McMoRan has a 37.3 percent working interest and a 28.5 percent net revenue interest in the Laphroaig field. EXXI holds an 18.6 percent working interest.
Wednesday, April 13, 2011
McMoRan Exploration Co.
McMoRan announced a successful production test at the Laphroaig No. 2 well in St. Mary Parish, Louisiana. The production test indicated a gross rate of approximately 54 million cubic feet of natural gas per day (MMcf/d) (approximately 15 MMcf/d net to McMoRan) and zero barrels of water on a 30/64th choke with flowing tubing pressure of 9,989 pounds per square inch (PSI). McMoRan will use the results of the production test to determine the optimal flow rate for the well. The well is expected to commence production in the second quarter of 2011 using facilities in the immediate area. McMoRan has a 37.3 percent working interest and a 28.5 percent net revenue interest in the Laphroaig field. EXXI holds an 18.6 percent working interest.
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