Oil Futures Weighed by Demand Worries, OPEC Output

Oil futures settled lower for the third straight session, weighed by concerns over weakening demand in China and robust global production.

Futures headed lower after data released Monday showed Chinese industrial output in April came in at 9.3% above last year's level--an improvement over a tepid March reading but under the 9.5% forecast by analysts surveyed by The Wall Street Journal.

The report was the latest underscoring slowing economic growth in China, which in turn has left the oil market worried demand for crude-oil is slowing there, too. China is the world's fastest-growing large economy and the boom has fueled a rise in oil prices over the last several years.

"The Chinese data today started us off on the defensive," said Andy Lebow, senior vice president of energy futures at Jefferies Bache in New York. "We're going to really need some demand growth in the second half [of the year] to suck up the increased crude production."

Light, sweet crude for June delivery settled 87 cents, or 0.9%, lower at $95.17 a barrel on the New York Mercantile Exchange. Brent crude on the ICE futures exchange recently settled $1.09, or 1%, lower at $102.82 a barrel.

Monday's fall is the latest decline in crude prices, as signs of strong supply in the U.S. and elsewhere keep a lid on gains. Year to date, crude futures have barely budged, up just 3.65% since the start of 2013.

On Monday, the Organization of the Petroleum Exporting Countries raised its strongest concerns yet this year about weakening oil demand in China. It cut its estimate for Chinese oil demand growth in the first quarter by 20,000 barrels a day, saying weaker-than-expected economic growth in China "may dent oil demand consumption."

Research service Platts estimated OPEC raised crude output by 25,000 barrels a day to 30.5 million barrels a day in April. The increase marked the end of a recent trend of lower production. The service said output had fallen by nearly a million barrels a day between October and March.

Platts said the increase was driven by higher output from Saudi Arabia, the biggest producer, and Iraq, the No. 2 producer. The group's next meeting in Vienna scheduled for May 31

Meanwhile, many oil-market observers remained concerned about the effect of a wind-down of monetary stimulus measures at the U.S. Federal Reserve. The Wall Street Journal reported on Friday that Fed officials had mapped out a strategy for winding down its $85 billion-a-month easing program.

An end to the measure would likely entail more support for the U.S. dollar, which typically weakens oil prices by making the commodity more expensive to global buyers.

The ICE Dollar Index, which tracks the greenback against a basket of currencies, was recently up 0.1% at 83.340.

Front-month June reformulated gasoline blendstock, or RBOB, settled 3.93 cents, or 1.4%, lower at $2.8210 a gallon. June heating oil settled 1.52 cents, or 0.5%, lower at $2.8910 a gallon.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Oil Futures Weighed by Demand Worries, OPEC Output

Oil futures settled lower for the third straight session, weighed by concerns over weakening demand in China and robust global production.

Futures headed lower after data released Monday showed Chinese industrial output in April came in at 9.3% above last year's level--an improvement over a tepid March reading but under the 9.5% forecast by analysts surveyed by The Wall Street Journal.

The report was the latest underscoring slowing economic growth in China, which in turn has left the oil market worried demand for crude-oil is slowing there, too. China is the world's fastest-growing large economy and the boom has fueled a rise in oil prices over the last several years.

"The Chinese data today started us off on the defensive," said Andy Lebow, senior vice president of energy futures at Jefferies Bache in New York. "We're going to really need some demand growth in the second half [of the year] to suck up the increased crude production."

Light, sweet crude for June delivery settled 87 cents, or 0.9%, lower at $95.17 a barrel on the New York Mercantile Exchange. Brent crude on the ICE futures exchange recently settled $1.09, or 1%, lower at $102.82 a barrel.

Monday's fall is the latest decline in crude prices, as signs of strong supply in the U.S. and elsewhere keep a lid on gains. Year to date, crude futures have barely budged, up just 3.65% since the start of 2013.

On Monday, the Organization of the Petroleum Exporting Countries raised its strongest concerns yet this year about weakening oil demand in China. It cut its estimate for Chinese oil demand growth in the first quarter by 20,000 barrels a day, saying weaker-than-expected economic growth in China "may dent oil demand consumption."

Research service Platts estimated OPEC raised crude output by 25,000 barrels a day to 30.5 million barrels a day in April. The increase marked the end of a recent trend of lower production. The service said output had fallen by nearly a million barrels a day between October and March.

Platts said the increase was driven by higher output from Saudi Arabia, the biggest producer, and Iraq, the No. 2 producer. The group's next meeting in Vienna scheduled for May 31

Meanwhile, many oil-market observers remained concerned about the effect of a wind-down of monetary stimulus measures at the U.S. Federal Reserve. The Wall Street Journal reported on Friday that Fed officials had mapped out a strategy for winding down its $85 billion-a-month easing program.

An end to the measure would likely entail more support for the U.S. dollar, which typically weakens oil prices by making the commodity more expensive to global buyers.

The ICE Dollar Index, which tracks the greenback against a basket of currencies, was recently up 0.1% at 83.340.

Front-month June reformulated gasoline blendstock, or RBOB, settled 3.93 cents, or 1.4%, lower at $2.8210 a gallon. June heating oil settled 1.52 cents, or 0.5%, lower at $2.8910 a gallon.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Venezuela Oil Minister: Contracts Could Be Canceled if Output Demands Not M

CARACAS--Venezuela's government could revoke contracts of 10 small partner companies in the nationalized oil industry if they fail to meet the state's demands to increase production, Oil Minister Rafael Ramirez told reporters Friday.

The government, which has laid out ambitious plans to raise production capacity over the next several years, wrote to all of its partners in November 2010 calling on them to boost output.

"At this moment we have identified 10 companies with problems, four of which are very critical," Mr. Ramirez said. "I'm going to make the call again. If they don't complete the plans then I will have to go to the National Assembly and say that these companies are not fulfilling what they promised," he said, warning that those not meeting their targets could have their contracts canceled.

The minister declined to name the companies but said that "they are very small" and include some that produce no more than 30 barrels a day.

"Time is up. I hope that the companies come and talk to us," Mr. Ramirez said.

He added that large partners like U.S. oil major Chevron Corp. (CVX) and China National Petroleum Corp. (CNPC.YY) have already responded to the government's demands and now he is waiting for the smaller companies to follow suit.

Under late President Hugo Chavez, who died in March, Venezuela's government revised contract terms with its oil partners to give the state a larger claim on oil projects. Some companies like ConocoPhillips (COP) and Exxon Mobil Corp. (XOM) rejected the new terms and are now seeking billions in compensation from Venezuela through international arbitration courts.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Total Confirms Output Targets, Sees Further Growth After 2017

SHETLAND, Scotland - French company Total SA still expects its oil and gas output to grow 3% on average on an annual basis between 2011 and 2015, and then sees accelerated growth after 2017 as new projects come on stream, the head of the exploration and production division Yves-Louis Darricarrere said, ahead of the group's release of its first-quarter earnings later this week.

By 2017, the group expects to have increased its production capacity potential to 3 million barrels of oil equivalent per day, from currently around 2.3 mboe/d, Mr. Darricarrere said during a press presentation there Monday.

The group is strongly competing with peers to find more oil and gas as energy demand keeps growing in emerging markets and while most conventional hydrocarbon reservoirs around the world are believed now to be depleting. Total has engaged in a strategic change and has become more aggressive in terms of exploration, allowing it to recently make substantial discoveries, notably in risky areas also called "frontier basins," such as the rough seas of West Shetlands and the Barents Sea, at the most northern tip of Europe.

Total even sees its output growth accelerating after 2017, as "already 90% of the 2017 potential is either in production or in development," Mr. Darricarrere said.

"We're seeing the results of our revitalized exploration strategy. Accepting to take more risks and looking for larger projects are our new focuses," Mr. Darricarrere said, adding the group's potential resources has doubled in the last three years to six billion barrels of oil equivalent.

In the North Sea alone, the group plans to invest as much as $20 billion over the five coming years, he said.

The strategy has allowed Total's production decline rate to remain steady, at around 3%, he said.

"We're able to control the decline, but this is because attention has been brought to existing fields and all our projects must be on time... Any delay of a project is a destruction of growth," he added.

Total has currently 15 projects under development, four of which are located in the North Sea and the Barents Sea. Mr. Darricarrere said "these projects, for the time being, are on time" and should add around 175,000 boe/d to Total's production.

The group will release its first-quarter earnings on Friday at 0600 GMT. Analysts polled by Dow Jones Newswires expect Total's first-quarter output to have dropped 2.1% from a year earlier to 2.323 mboe/d from 2.372 mboe/d.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Total Confirms Output Targets, Sees Further Growth After 2017

SHETLAND, Scotland - French company Total SA still expects its oil and gas output to grow 3% on average on an annual basis between 2011 and 2015, and then sees accelerated growth after 2017 as new projects come on stream, the head of the exploration and production division Yves-Louis Darricarrere said, ahead of the group's release of its first-quarter earnings later this week.

By 2017, the group expects to have increased its production capacity potential to 3 million barrels of oil equivalent per day, from currently around 2.3 mboe/d, Mr. Darricarrere said during a press presentation there Monday.

The group is strongly competing with peers to find more oil and gas as energy demand keeps growing in emerging markets and while most conventional hydrocarbon reservoirs around the world are believed now to be depleting. Total has engaged in a strategic change and has become more aggressive in terms of exploration, allowing it to recently make substantial discoveries, notably in risky areas also called "frontier basins," such as the rough seas of West Shetlands and the Barents Sea, at the most northern tip of Europe.

Total even sees its output growth accelerating after 2017, as "already 90% of the 2017 potential is either in production or in development," Mr. Darricarrere said.

"We're seeing the results of our revitalized exploration strategy. Accepting to take more risks and looking for larger projects are our new focuses," Mr. Darricarrere said, adding the group's potential resources has doubled in the last three years to six billion barrels of oil equivalent.

In the North Sea alone, the group plans to invest as much as $20 billion over the five coming years, he said.

The strategy has allowed Total's production decline rate to remain steady, at around 3%, he said.

"We're able to control the decline, but this is because attention has been brought to existing fields and all our projects must be on time... Any delay of a project is a destruction of growth," he added.

Total has currently 15 projects under development, four of which are located in the North Sea and the Barents Sea. Mr. Darricarrere said "these projects, for the time being, are on time" and should add around 175,000 boe/d to Total's production.

The group will release its first-quarter earnings on Friday at 0600 GMT. Analysts polled by Dow Jones Newswires expect Total's first-quarter output to have dropped 2.1% from a year earlier to 2.323 mboe/d from 2.372 mboe/d.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

WPX's Niobrara Well Hits Output Milestone

WPX Energy announced Monday that its Niobrara Shale discovery well in the Piceance Basin exceeded 1 billion cubic feet of natural gas production in just over 100 days of operation.

At this rate, WPX expects the Niobrara well to produce in its first four months what a typical well in the Piceance Basin's Williams Fork formation produces over its estimated lifecycle of 25 to 30 years.

The Niobrara well is located on WPX's acreage in Western Colorado, where the company has the lease rights to approximately 180,000 net acres of the Niobrara/Mancos shale play.

The discovery well initially produced 16 million cubic feet per day at a flowing pressure of 7,300 pounds per square inch. It registered an average production rate of almost 10 million cubic feet per day over its first 90 days, despite being choked back substantially.

"We're very pleased with what we're seeing," said Ralph A. Hill, WPX's president and chief executive officer. "This well is demonstrating tremendous strength. It's a large discovery that has significant upside potential for creating shareholder value."

Over time, WPX believes that its Niobrara discovery has the potential to more than double the company's proved, probable and possible (3P) reserves, which were approximately 18 trillion cubic feet at year-end 2012.

WPX started drilling its second Niobrara well Wednesday, April 3. The company expects to begin completion activities in June.

As previously announced, WPX plans to drill a total of four horizontal Niobrara wells in 2013. The drilling plan is designed to prove up adjacent acreage and test the repeatability of the play on additional acreage the company owns.

WPX already has extensive processing and takeaway capacity under contract in the Piceance to support Niobrara production.

The Niobrara and Mancos shales are generally located at depths of 10,000 to 13,000 feet. The Williams Fork is a shallower formation, generally located at depths of 6,000 to 9,000 feet. In the Piceance Basin, WPX holds an average working interest of 66 percent in the Niobrara and Mancos shales.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Egypt Says It Will Invest To Raise Oil Output

DUBAI - Cash-strapped Egypt will spend $18 billion over coming years to build new refineries and modify existing plants in a move to increase its annual fuel output, the country's oil minister said in an interview with Al Tahrir Television.

"There are some urgent measures to be taken this fiscal year to operate some refineries safely ... and there are measures in the next couple of years to lift the output of the existing refineries from the current 25-26 metric tons a year to more than 30 million tons," Osama Kamal told the Egyptian channel.

Overall "we have decided in November to invest $18 billion until 2017 to build new refineries and upgrade the existing refineries we have," he said.

Egypt has been paying hefty premiums for its crude deliveries for its refineries due to a weaker pound and difficulties in securing letters of credit for its transactions, while a shortage of state-subsided diesel has paralyzed transportation in many parts of the country.

Continuing unrest in the country since the ousting of former President Hosni Mubarak has led to a risky economic mix of dwindling foreign-exchange reserves, declining tourism revenue and costly price subsidies, economists said. To prop up the Egyptian currency, the central bank has gone through nearly two-thirds of its foreign-currency reserves, pushing the country to the brink of a liquidity crisis.

Egypt is trying to secure a $4.8 billion loan from the International Monetary Fund, a move viewed as critical to rescuing its economy and mending its reputation as a place to do business.

The IMF wants Egypt to reduce its subsidy spending, as part of a reform plan for the loan, say those close to the talks. But any subsidy changes would likely only enrage the legions of poor who rely on cheap fuel.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Egypt Says It Will Invest To Raise Oil Output

DUBAI - Cash-strapped Egypt will spend $18 billion over coming years to build new refineries and modify existing plants in a move to increase its annual fuel output, the country's oil minister said in an interview with Al Tahrir Television.

"There are some urgent measures to be taken this fiscal year to operate some refineries safely ... and there are measures in the next couple of years to lift the output of the existing refineries from the current 25-26 metric tons a year to more than 30 million tons," Osama Kamal told the Egyptian channel.

Overall "we have decided in November to invest $18 billion until 2017 to build new refineries and upgrade the existing refineries we have," he said.

Egypt has been paying hefty premiums for its crude deliveries for its refineries due to a weaker pound and difficulties in securing letters of credit for its transactions, while a shortage of state-subsided diesel has paralyzed transportation in many parts of the country.

Continuing unrest in the country since the ousting of former President Hosni Mubarak has led to a risky economic mix of dwindling foreign-exchange reserves, declining tourism revenue and costly price subsidies, economists said. To prop up the Egyptian currency, the central bank has gone through nearly two-thirds of its foreign-currency reserves, pushing the country to the brink of a liquidity crisis.

Egypt is trying to secure a $4.8 billion loan from the International Monetary Fund, a move viewed as critical to rescuing its economy and mending its reputation as a place to do business.

The IMF wants Egypt to reduce its subsidy spending, as part of a reform plan for the loan, say those close to the talks. But any subsidy changes would likely only enrage the legions of poor who rely on cheap fuel.

Copyright (c) 2013 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Sea Dragon Boosts Output in Egypt

Sea Dragon Energy Inc. announced the following operational update for its recent work activities in Egypt.

The company's net production in Egypt averaged 1,526 barrels of oil per day (bopd) in the month of January 2013 and has now reached 1,840 barrels of oil equivalent per day (boepd) or 1,720 bopd and 120 boepd in gas and NGL's. In NW Gemsa, oil production is averaging 9,900 bopd gross (990 bopd net), while gas and NGL's are adding another 1,200 boepd gross (120 boepd net). In Kom Ombo, production is averaging 500 bopd gross (250 bopd net); while in Shukhier Marine the company is producing 480 bopd.

Over the past two months, Sea Dragon has also been able to collect a significant percentage of its aging receivables thus enabling it to reduce the receivables amount to $4.63 million and the age of its receivables to two months based on current production.

Current production from the Al Amir SE and Geyad fields is approximately 9,900 bopd gross (990 bopd net). Total production, including solution gas and natural gas liquids, is approximately 11,100 boepd gross (1,110 boepd net). The concession has eight current oil producers at Al Amir SE field, two at Al Ola and five at Geyad. Cumulative production from the NW Gemsa Concession has now exceeded 10.6 million barrels of 42 degree API Crude oil.

Water injection is ongoing with three injectors currently operating at Al Amir SE Field and one injector at Geyad Field. Current total injection rates are approximately 17,800 bopd. Cumulative injection to date is 6.9 million barrels at Al Amir SE and 1.7 million barrels at Geyad.

Al Amir SE-16 Well

This well is now being completed as a Shagar water injector. The well was spud Feb. 28 and successfully drilled to its total depth of 11,000 feet in the Upper Rudeis Formation. It encountered 27 feet of good quality wet sand in the shagar member of the Karim Formation in the interval 10,807.5 to 10,834.5 feet. This well will add another water injection point in the field, which will improve sweep efficiency and maximize oil recovery.

Future Plans

Beyond the completion of Al Amir SE-16, future plans at NW Gemsa include the drilling of two additional water injectors, one producer and one exploration well in 2013.

The NW Gemsa concession is located onshore on the west side of the Gulf of Suez, approximately 186 miles (300 kilometers) southeast of Cairo. Two main oil fields are producing light oil, the Al Amir SE field along with the Al Ola extension to the south and the Geyad field to the north. Sea Dragon has a 10 percent working interest in the NW Gemsa Concession with Vegas oil and gas at 50 percent, as operator and Circle Oil PLC with 40 percent.

The Shukheir Marine Concession contains both the Shukheir Bay and Gamma development leases.

Current production from the concession is 480 bopd. Sea Dragon is the sole owner and operator of the concession.

Shukheir Bay #5 Well Work-Over

Following the successful completion of work-over operations on this well, it has now recovered its kill fluid and restored its pre work-over production of 380 bopd. The SHB-5 well produces from the Upper and Lower Rudeis sands within the Shukheir Bay field. The well began production in 2006 and has produced over 1.1 million barrels of oil to date.

Future Plans

The company continues to plan an acid stimulation treatment in the Gamma #1 well which may add 100 bopd.

Exploratory drilling opportunities also exist in the Gamma lease, prospecting the prolific Nubia Formation and in the Shukheir Bay lease in the Upper and Lower Rudeis Formations. The Company is currently re-mapping its 3-D seismic coverage in the area to evaluate these opportunities.

The Shukheir Marine Concession is located in the shallow offshore waters of the Gulf of Suez approximately 186 miles (300 kilometers) southeast of Cairo. Following the acquisition of 100 percent interest in the concession which contains both the Shukheir Bay and Gamma oil fields, Sea Dragon began a comprehensive review of the upside potential believed to still exist in both fields.

Current production from the Al Baraka field is approximately 500 gross (250 net) bopd.

Future Plans

Plans are to monitor production from West Al Baraka-2 and then if warranted commence an appraisal/development drilling program which could involve the drilling of up to three new wells.

The Kom Ombo Concession is located onshore in the southern part of Egypt some 621 miles (1,000 kilometers) south of Cairo. It contains the Al Baraka and the newly discovered W. Al Baraka oilfields, producing light oil from multiple reservoirs. Sea Dragon owns a 50 percent working interest and is a joint operator of the Kom Ombo Concession with Dana Gas owning the remaining 50 percent.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Sea Dragon Boosts Output in Egypt

Sea Dragon Energy Inc. announced the following operational update for its recent work activities in Egypt.

The company's net production in Egypt averaged 1,526 barrels of oil per day (bopd) in the month of January 2013 and has now reached 1,840 barrels of oil equivalent per day (boepd) or 1,720 bopd and 120 boepd in gas and NGL's. In NW Gemsa, oil production is averaging 9,900 bopd gross (990 bopd net), while gas and NGL's are adding another 1,200 boepd gross (120 boepd net). In Kom Ombo, production is averaging 500 bopd gross (250 bopd net); while in Shukhier Marine the company is producing 480 bopd.

Over the past two months, Sea Dragon has also been able to collect a significant percentage of its aging receivables thus enabling it to reduce the receivables amount to $4.63 million and the age of its receivables to two months based on current production.

Current production from the Al Amir SE and Geyad fields is approximately 9,900 bopd gross (990 bopd net). Total production, including solution gas and natural gas liquids, is approximately 11,100 boepd gross (1,110 boepd net). The concession has eight current oil producers at Al Amir SE field, two at Al Ola and five at Geyad. Cumulative production from the NW Gemsa Concession has now exceeded 10.6 million barrels of 42 degree API Crude oil.

Water injection is ongoing with three injectors currently operating at Al Amir SE Field and one injector at Geyad Field. Current total injection rates are approximately 17,800 bopd. Cumulative injection to date is 6.9 million barrels at Al Amir SE and 1.7 million barrels at Geyad.

Al Amir SE-16 Well

This well is now being completed as a Shagar water injector. The well was spud Feb. 28 and successfully drilled to its total depth of 11,000 feet in the Upper Rudeis Formation. It encountered 27 feet of good quality wet sand in the shagar member of the Karim Formation in the interval 10,807.5 to 10,834.5 feet. This well will add another water injection point in the field, which will improve sweep efficiency and maximize oil recovery.

Future Plans

Beyond the completion of Al Amir SE-16, future plans at NW Gemsa include the drilling of two additional water injectors, one producer and one exploration well in 2013.

The NW Gemsa concession is located onshore on the west side of the Gulf of Suez, approximately 186 miles (300 kilometers) southeast of Cairo. Two main oil fields are producing light oil, the Al Amir SE field along with the Al Ola extension to the south and the Geyad field to the north. Sea Dragon has a 10 percent working interest in the NW Gemsa Concession with Vegas oil and gas at 50 percent, as operator and Circle Oil PLC with 40 percent.

The Shukheir Marine Concession contains both the Shukheir Bay and Gamma development leases.

Current production from the concession is 480 bopd. Sea Dragon is the sole owner and operator of the concession.

Shukheir Bay #5 Well Work-Over

Following the successful completion of work-over operations on this well, it has now recovered its kill fluid and restored its pre work-over production of 380 bopd. The SHB-5 well produces from the Upper and Lower Rudeis sands within the Shukheir Bay field. The well began production in 2006 and has produced over 1.1 million barrels of oil to date.

Future Plans

The company continues to plan an acid stimulation treatment in the Gamma #1 well which may add 100 bopd.

Exploratory drilling opportunities also exist in the Gamma lease, prospecting the prolific Nubia Formation and in the Shukheir Bay lease in the Upper and Lower Rudeis Formations. The Company is currently re-mapping its 3-D seismic coverage in the area to evaluate these opportunities.

The Shukheir Marine Concession is located in the shallow offshore waters of the Gulf of Suez approximately 186 miles (300 kilometers) southeast of Cairo. Following the acquisition of 100 percent interest in the concession which contains both the Shukheir Bay and Gamma oil fields, Sea Dragon began a comprehensive review of the upside potential believed to still exist in both fields.

Current production from the Al Baraka field is approximately 500 gross (250 net) bopd.

Future Plans

Plans are to monitor production from West Al Baraka-2 and then if warranted commence an appraisal/development drilling program which could involve the drilling of up to three new wells.

The Kom Ombo Concession is located onshore in the southern part of Egypt some 621 miles (1,000 kilometers) south of Cairo. It contains the Al Baraka and the newly discovered W. Al Baraka oilfields, producing light oil from multiple reservoirs. Sea Dragon owns a 50 percent working interest and is a joint operator of the Kom Ombo Concession with Dana Gas owning the remaining 50 percent.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

ExxonMobil to Boost Output at Iraq West Qurna-1 by Mid 2013

U.S. energy giant Exxon Mobil Corp. and its partners are planning to increase crude oil production from West Qurna-1 oil field in southern Iraq to 530,000 barrels a day by July, from 495,000 barrels a day now, a senior Iraqi oil official said Monday.

Mahdi Abdul Razzaq al-Maliki, head of the field's joint management committee, said the consortium, which also includes Royal Dutch Shell PLC and Iraq, is planning to raise output from West Qurna-1 to 600,000 barrels a day by the end of 2013.

"According to this year's plan which has been approved by the oil ministry, the consortium will invest some $1.65 billion compared with $1 billion invested last year," Mr. al-Maliki told Dow Jones Newswires.

Iraq, a member of the Organization of the Petroleum Exporting Countries, is targeting a total output of 4.5 million barrels a day next year from 3.3 million barrels a day now, the Iraqi prime minister's top energy advisor, Thamir Ghadhban, said.

New oil fields, being developed by some of the world's largest oil companies will come on stream this year such as Majnoon, which is being developed by Shell, West Qurna-2 being developed by OAO Lukoil Holdings and Garraf oil field, which is being upgraded by a consortium led by Malaysia's Petronas and Japan Petroleum Exploration Co., or Japex.

Exxon is in a row with the Iraqi government over deals it signed with the semi-autonomous region of Kurdistan in northern Iraq. The Baghdad government says that Exxon should choose between its southern oil field and its deal in the north. Baghdad and Kurdistan are at logger heads over who should control oil resources in the Kurdish region.

Copyright (c) 2012 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Musings: Natural Gas Output Falls In December; Start Of A Trend?

This opinion piece presents the opinions of the author.
It does not necessarily reflect the views of Rigzone.

The Energy Information Administration's (EIA) survey of natural gas production from the Lower 48 states for the month of December 2012 showed the first decline in output since March of that year. With the continued decline in drilling rigs targeting natural gas formations, analysts are encouraged that possibly we are witnessing the first results of the drilling slowdown. The EIA's commentary associated with the release of the data, however, mentioned weather related factors impacting gas output, especially in the associated gas production from the Bakken where an early and severe winter caused a drilling and well completion slowdown. Additionally, many producers ran out of budget money before the end of the year and were forced to slow activity. If nothing else, however, the slowdown in gas output reinforces the phenomenon the industry may soon be confronting, which is the need to ramp up drilling activity to offset the steep decline in existing well production due to the nature of shale gas wells.

Overall, the initial estimate of gross natural gas production for the entire United States fell just about 1 billion cubic feet (Bcf) in December. Alaskan gas production actually rose about 0.2 Bcf while output in the Gulf of Mexico fell almost as much (-0.14 Bcf), meaning that virtually the entirety of the production decline occurred in Lower 48 basins. If we examine the revision to the prior monthly's initial production estimate, there was a reduction of 0.32 Bcf, which suggests the December production decline may only have been about 0.7 Bcf, but of sufficient size to be meaningful. Before analysts get too excited about this potential change in trend and what it might mean for natural gas prices, a new report from natural gas research firm, Bentek Energy, suggests that 2013 and 2014 will be a replay of the past several years – growth in production rather than a decline. The firm's forecast, however, calls for a slowing in the rate of increase in gas production during the next two years compared to the rate of growth experienced in the prior two years.

According to Bentek, natural gas production in the U.S. rose 3.6%, or by 1.6 Bcf per day in 2010 and increased by an average of 3.5
Bcf/d in 2011-2012. They are projecting that overall gas output will grow by 2 Bcf/d in 2013, as nine key shale basins will grow by 4.9 Bcf/d, which will be offset by other production falling by 2.9 Bcf/d. In 2014, the firm sees production increasing by 3.4 Bcf/d. An interesting point in the historical data is that in 2011 offshore gas output fell by 1.2 Bcf/d and then by another 0.9 Bcf/d in 2012. Bentek sees offshore production declining by only about 0.3 Bcf/d in 2013 and reaching steady output in 2014. If we were to exclude the impact of the decline in offshore production in 2011-12, the average annual output increase was about 4.3 Bcf/d, or nearly 0.8 Bcf/d more coming from onshore basins. By the end of 2014, Bentek foresees gas output above 70 Bcf/d, up from current production of slightly be low 65 Bcf/d.

Bentek's forecast for output is based on three primary factors. These include: debottlenecking of geographic regions where output has been constrained by a lack of infrastructure; operators continuing to focus on wet gas and associated gas from oil plays; and continued improvement in drilling rig efficiencies. The impact of the last two factors is shown in several charts from the Bentek forecast report that crystalize their views.

The chart in Exhibit 11 shows the impact of wet gas (green) output on total incremental natural gas production beginning in 2010 and continuing through the 2014 forecast period. As the chart shows, associated wet gas was only a minor contributor to gas output in 2010 but grew in 2011 as the impact of low natural gas prices drove operators to emphasize oil and wet gas formations. With natural gas prices continuing to languish in 2012, that trend became more pronounced with expected results. Because of the strong focus on natural gas liquids (NGLs) and crude oil due to high world oil prices and better investment returns for operators, Bentek sees wet gas production growing as we move through 2013 and 2014. Part of the strength in NGL and oil demand and their prices is due to debottlenecking Bentek assumes will occur based on the list of new pipeline and gas processing facilities either being built or planned to be built in the coming months.

The last major trend is the impact on shale gas costs from improvements in drilling. Exhibit 12 contains a chart showing the number of horizontal wells drilled since 2008 (blue columns), the number of horizontal rigs working (red line) and the average number of wells drilled per rig per month (black dotted line). The wells per month line in most impressive showing how after about a three-year downward trend between 2008 and 2010, the number rose in 2011 and remained essentially stable throughout the year but then started a steady upward climb throughout 2012. This rise in rig performance reflects not only improved knowledge about how and where to drill and the greater use of pad drilling facilities, but also the impact from the growing fleet of new AC (electric) rigs that bring greater capabilities for drilling deeper and longer horizontal wells.

Improvements in drilling in the Bakken have been meaningful as shown in Exhibit 13. Since the first quarter of 2010, the average time to drill a well has declined roughly 15%, although from the fourth quarter of 2010 the decline is much more significant – off nearly 40%! As the average rig can drill more wells per year and more rigs are moving into the Bakken, wells drilled have jumped in the past several quarters - from around 375 wells per quarter to 500 wells and then to a 600-wells per quarter rate for the final three quarters of 2012. The question is can the industry operate more drilling rigs in the region and will those rigs be capable of continuing to drill wells in fewer days in the future?

Last summer, the North Dakota Department of Mineral Resources presented an expected case for the future number of drilling rigs (red columns) working in the state's Bakken formation and the number of producing wells (green columns). As can be seen in Exhibit 14, the forecast calls for a small increase in the number of drilling rigs for 2013 and again in 2014, with rigs remaining flat in 2015 before spiking to a peak of just over 250 rigs in 2016. From that point the rig count begins a modest downward stepping pattern until it reaches a low point of 50 rigs in 2036 where it remains through the balance of the 2050 forecast period. As a result of the boom in drilling between 2010 and 2024, the total number of Bakken wells rises sharply from 5,000 to about 35,000. Thereafter, due to the decline in the active drilling rig count, the climb in the number of producing wells is modest reaching almost 40,000 wells in 2050.

A big challenge for producers in the Bakken is the lack of pipeline infrastructure to move associated natural gas production from the
region. Many people are familiar with the NASA photo of the United States at night showing the gas flaring in the Bakken (red) compared to the lights of Minneapolis, Minnesota on the right hand side of the picture. This picture rivals ones from the past showing the huge volumes of gas being burned in Nigeria and Russia that could be seen from space.

A chart from the North Dakota Department of Mineral Resources shows how the percentage of natural gas produced in the state is
burned. As the chart in Exhibit 16 shows, gas flaring was relatively minor until about 2005 and then it grew to about 24% in 2008 before falling 10 percentage points as a pipeline was opened up. From about 14% in 2009, the percentage of gas burned rose to the 35% area where it remains today awaiting more pipeline capacity and liquids-processing plants being built.

The Bentek natural gas production forecast relies on the continuation of the triumvirate of factors that have made oil shale plays as successful as they have been to date. Debottlenecking of various key producing basins appears a safe bet since it is based on projects already approved and in many cases already under construction with attractive returns. A continuation of improvements in drilling efficiency appears less secure as it depends on the drilling industry converting the balance of its old, conventional rig fleet into a new, AC-based one. That means higher day rates for working rigs in order for contractors to justify the investment in new rigs. What will higher dayrates mean for well economics? What happens to these oil and wet gas plays should oil prices fall from their current lofty levels? These latter considerations could impact the economics of shale drilling and thus gas output that would negatively impact the Bentek forecast since it is based on economic models employing 12-month forward strip pricing for crude oil and NGLs. The one offset to this logic is the dedication of large integrated and independent producers to drill through the period of poor economic returns because they believe in the eventual recovery of oil and natural gas prices that will reward them for their strategy.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Rosneft Expects 2013 Output to Increase by 1%-2%

MOSCOW - OAO Rosneft expects to increase its output by between 1% and 2% in 2013 mainly due to production growth at its giant Vankor field in Siberia, the company said Friday as it reported its 2102 full year earnings.

In a conference call Dmitry Avdeev, the vice president for finance and economics, said he expects crude oil production from Vankor to reach between 430,000 barrels and 440,000 barrels per day, although he neither confirmed nor denied that oil production at the company's other main fields could decline.

Vankor was the main contributor to Rosneft's oil output growth of 2.5% to 2,43 million barrels a day in 2012 amid declining output at the company's other main fields.

Higher output and higher oil prices led to a 13% rise in revenue for the year to 3.08 trillion rubles ($102 billion) and a 7.2% rise in net profit to RUB342 billion.

However, the profit figure fell well below market expectations. "Reasons for such results are not exactly clear. There is an item called 'other expenditures' which unfortunately the company does not disclose," said Alexander Kornilov, an analyst with Alfa Bank, who called the results "disappointing".

The market is also worried by a sharp drop in free cash flow, which dropped to RUB45 billion for the full year from RUB99 billion a year before, partly due to increased investment and lower income from operations. Shares in the company closed down 2.1% RUB261.5 in Moscow, underperforming the wider index which was flat on the day.

Rosneft is buying competitor TNK-BP from BP PLC and its partners in a deal worth $50 billion that will create the world's largest traded oil producer. BP will increase its stake in Rosneft to 19.8% as part of the deal.

Mr. Avdeev said antitrust bodies in Russia and Ukraine have already approved the deal, and that the purchase, which is fully funded, is going ahead as planned.

To finance the purchase of the stake from BP, Rosneft has agreed to borrow $16.7 billion from international banks, the company said in its earnings report.

Mr. Avdeev added that the oil giant may also place a Eurobond later this year, as last year's debut issue showed "a very strong demand". He added that the company would hit the international bond market after considering the attraction of this instrument compared to domestic bonds, direct loans, or contracts with trading companies.

The company's net debt stood at RUB581 billion at the end of the fourth quarter compared to RUB542 billion at the end of the previous quarter, as Rosneft is yet to draw the agreed loans.

However, the acquisition of TNK-BP dented Rosneft's Earnings before interest, taxation, depreciation and amortization, or Ebitda, due to an increase in spending on audit and consulting services.

The company's Ebitda margin, the measure used to judge a company's profitability, dropped to 19.8% in 2012 from 24.4% in the previous year.

Mr. Avdeev said the company is aiming at paying dividend at 25% of its full-year profit, as announced before.

Copyright (c) 2012 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Rosneft Expects 2013 Output to Increase by 1%-2%

MOSCOW - OAO Rosneft expects to increase its output by between 1% and 2% in 2013 mainly due to production growth at its giant Vankor field in Siberia, the company said Friday as it reported its 2102 full year earnings.

In a conference call Dmitry Avdeev, the vice president for finance and economics, said he expects crude oil production from Vankor to reach between 430,000 barrels and 440,000 barrels per day, although he neither confirmed nor denied that oil production at the company's other main fields could decline.

Vankor was the main contributor to Rosneft's oil output growth of 2.5% to 2,43 million barrels a day in 2012 amid declining output at the company's other main fields.

Higher output and higher oil prices led to a 13% rise in revenue for the year to 3.08 trillion rubles ($102 billion) and a 7.2% rise in net profit to RUB342 billion.

However, the profit figure fell well below market expectations. "Reasons for such results are not exactly clear. There is an item called 'other expenditures' which unfortunately the company does not disclose," said Alexander Kornilov, an analyst with Alfa Bank, who called the results "disappointing".

The market is also worried by a sharp drop in free cash flow, which dropped to RUB45 billion for the full year from RUB99 billion a year before, partly due to increased investment and lower income from operations. Shares in the company closed down 2.1% RUB261.5 in Moscow, underperforming the wider index which was flat on the day.

Rosneft is buying competitor TNK-BP from BP PLC and its partners in a deal worth $50 billion that will create the world's largest traded oil producer. BP will increase its stake in Rosneft to 19.8% as part of the deal.

Mr. Avdeev said antitrust bodies in Russia and Ukraine have already approved the deal, and that the purchase, which is fully funded, is going ahead as planned.

To finance the purchase of the stake from BP, Rosneft has agreed to borrow $16.7 billion from international banks, the company said in its earnings report.

Mr. Avdeev added that the oil giant may also place a Eurobond later this year, as last year's debut issue showed "a very strong demand". He added that the company would hit the international bond market after considering the attraction of this instrument compared to domestic bonds, direct loans, or contracts with trading companies.

The company's net debt stood at RUB581 billion at the end of the fourth quarter compared to RUB542 billion at the end of the previous quarter, as Rosneft is yet to draw the agreed loans.

However, the acquisition of TNK-BP dented Rosneft's Earnings before interest, taxation, depreciation and amortization, or Ebitda, due to an increase in spending on audit and consulting services.

The company's Ebitda margin, the measure used to judge a company's profitability, dropped to 19.8% in 2012 from 24.4% in the previous year.

Mr. Avdeev said the company is aiming at paying dividend at 25% of its full-year profit, as announced before.

Copyright (c) 2012 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

UK Oil Output Fell by Record 28% in September-November

LONDON - The extent of the oil-production outage that contributed to tipping the U.K. economy into a fourth-quarter contraction was laid bare Thursday, as official statistics showed production of crude fell nearly 30% in the three months to November.

Production of petroleum fell a record 27.9% compared with the same period the previous year, according to energy department data, with output particularly hit by a lengthy outage at Buzzard, the largest producing field in the North Sea.

Last week, the U.K. statistics office said the closure of Buzzard, operated by Canada's Nexen Inc., was a big reason for the 0.3% contraction in the final three months of 2012. The field, which was shut for maintenance, produces up to 220,000 barrels of oil a day.

Production of natural gas also fell sharply from September through November--20.6% to be exact. This was mainly due to a continued outage at the Elgin natural gas field and to maintenance at the St. Fergus terminal, which processes gas from over 20 North Sea fields providing around 20% of the U.K.'s daily needs.

Separately Thursday, the statistics office said weak output from U.K. mines and quarries--mostly comprising North Sea oil and gas--reflects the longer-term decline in reserves. Output in the sector is now less than 40% of its 1999 peak, equivalent to an annual rate of decline of more than 6%, the office said.

Production at Buzzard has now resumed, according to oil traders. Barring more severe disruptions in the North Sea, oil and gas output should recover in the first three months of 2013, potentially boosting economic activity overall.

Total production of U.K. indigenous primary fuels in the third quarter fell 17.7%. Electricity from nuclear and from wind and hydro sources both increased.

Jason Douglas and Cassie Werber contributed to this item

Copyright (c) 2012 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

UK Oil Output Fell by Record 28% in September-November

LONDON - The extent of the oil-production outage that contributed to tipping the U.K. economy into a fourth-quarter contraction was laid bare Thursday, as official statistics showed production of crude fell nearly 30% in the three months to November.

Production of petroleum fell a record 27.9% compared with the same period the previous year, according to energy department data, with output particularly hit by a lengthy outage at Buzzard, the largest producing field in the North Sea.

Last week, the U.K. statistics office said the closure of Buzzard, operated by Canada's Nexen Inc., was a big reason for the 0.3% contraction in the final three months of 2012. The field, which was shut for maintenance, produces up to 220,000 barrels of oil a day.

Production of natural gas also fell sharply from September through November--20.6% to be exact. This was mainly due to a continued outage at the Elgin natural gas field and to maintenance at the St. Fergus terminal, which processes gas from over 20 North Sea fields providing around 20% of the U.K.'s daily needs.

Separately Thursday, the statistics office said weak output from U.K. mines and quarries--mostly comprising North Sea oil and gas--reflects the longer-term decline in reserves. Output in the sector is now less than 40% of its 1999 peak, equivalent to an annual rate of decline of more than 6%, the office said.

Production at Buzzard has now resumed, according to oil traders. Barring more severe disruptions in the North Sea, oil and gas output should recover in the first three months of 2013, potentially boosting economic activity overall.

Total production of U.K. indigenous primary fuels in the third quarter fell 17.7%. Electricity from nuclear and from wind and hydro sources both increased.

Jason Douglas and Cassie Werber contributed to this item

Copyright (c) 2012 Dow Jones & Company, Inc.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here