EC225: On Target for 2013 Return?

When a Super Puma helicopter with 19 people on board was forced to ditch in the North Sea, west of Shetland, last October the incident was another reminder of 2009's fatal crash that saw 16 people killed – the biggest loss of life in a helicopter incident in the North Sea in two decades.

The April 2009 crash also involved a Super Puma, and given that October's incident was the second ditching of a Super Puma in 2012, a major question was raised as to the continuing safety of the aircraft for use in offshore transfers.

While Bond Aviation operated the helicopters involved in the 2009 crash and the May 2012 ditching, the Super Puma in October's incident was operated by a separate company: CHC Helicopter. No lives were lost in either of 2012's ditching incidents, but having Super Pumas ditching into the sea has not exactly inspired confidence in a particular variant of the aircraft: the EC225 made by Eurocopter.

Flights of the EC225 variant were soon suspended after the October incident, with certain exceptions for what CHC CEO William Amelio described as "life-or-death search-and-rescue missions".

The EC225 Super Puma (courtesy of Eurocopter)

At the time of the October incident, preliminary investigations by the UK's Air Accidents Investigations Branch (AAIB) indicated that the controlled ditching of the EC225 – in which all 17 passengers and two crew were evacuated safely – showed strong similarities to May's ditching incident. This was because a problem with a particular critical gearbox component appeared to be the trigger for both incidents.

In May's incident, the crew ditched the helicopter after a warning that the main gearbox lubrication system had failed and a subsequent attempt to operate the emergency system on the aircraft also caused a failure warning.

In the October incident, the main gearbox lubrication system was lost after the complete failure of the helicopter's bevel-gear vertical shaft. Just as with the May incident a 360-degree crack had been found in the bevel-gear vertical shaft, with the fracture causing the gears operating the main oil pump on the helicopter to fail.

Although the October incident saw the emergency system operating correctly, it gave a false warning of failure which led the crew to decide to ditch the helicopter.

To find out how the firm is progressing in working out a solution to the problems with the EC225, Rigzone recently spoke to Eurocopter. This was after the firm's CEO Lutz Bertling, said in mid-April that he was confident that the helicopter would be able to return to service during the third quarter of this year after the firm identified both an interim fix and what it thinks might be the final solution to the gearbox problem.

A third test campaign by the company has seen significant progress made regarding the root cause of the crack initiation in the gear box, according to a Eurocopter spokesman. The company believes a combination of factors led to weakened fatigue strength in the vertical shaft and it added that it has replicated the crack initiation in scenarios conducted on test benches.

Meanwhile, a flight test is currently in progress to demonstrate the crack-propagation scenario. The firm has been working with Georgia Technology Research Institute and Shainin Engineering, which was involved in identifying the wing crack issues that dogged the Airbus A380 fleet during the first half of last year.

"We believe we have found the root cause at Eurocopter. That has to be verified by all the regulatory authorities," the spokesman said. "It's only our opinion in finding what the root cause is at this moment in time. So what we're saying is that the long-term fix will be a new shaft and interim solutions will be put in place, but only [when] cleared by the operators and all the regulatory bodies."

This means that the 3Q 2013 deadline for a return to service of the EC225 could prove optimistic.

"We can't give dates specifically and [Bertling] has given the third quarter as a reasonable period of time. So we'll work as close to that as we can," added the spokesman.

How soon the Scottish oil and gas industry will see a return of the EC225 will depend on what the interim fix is and if the regulators allow them to employ it to get the aircraft back in the air, according to Jake Molloy – the Aberdeen-based organizer for the RMT Union.

"There are too many ifs and buts at this minute in time to say with any authority whether or not they will be back. They've also got to satisfy the Helicopter Safety Steering Group, which is a broad church of employers' associations, trade unions, workforce representatives and others," said Molloy, whose union's offshore energy branch represents thousands of workers in the UK North Sea.

"So, there's a long, long way before we get to that question of whether or not we're happy. It's really got to be decided, in the first instance, whether Eurocopter is happy, the regulators are happy, the HSSG is happy and then the question will come to whether or not we as workforce representatives and, moreover, the workforce are happy."

Molloy added that his union is not putting any timeline on when it expects to see the EC225 back in service.

Commenting on the 3Q 2013 deadline set by Bertling, he said:

"If that's what Eurocopter think then they are entitled to their opinion on that, but we're not putting any timeline on it. It will be done when it's done.

"As things stand, the helicopter providers are doing a sterling job in providing a service and getting people in and off shore. We'd like to see the full fleet back, and operating safely obviously, because it would get a lot of people back to work who are currently sitting at home."

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Chesapeake Executive: No Target Date to Find Permanent CEO

Chesapeake Energy Corp.'s acting chief executive declined to say Monday when the company expects to have a permanent chief executive to succeed Aubrey McClendon.

Mr. McClendon officially stepped down as chief executive Monday. Chesapeake, the second-largest U.S. natural-gas producer after Exxon Mobil Corp., has been searching for a new chief executive since January after Mr. McClendon agreed to leave the company he helped found, citing "philosophical differences" with board members installed by activist shareholders.

Chesapeake had been close to landing a new chief executive before an agreement fell apart in late negotiations, a person familiar with the company's inner workings had said. Chesapeake then named Chief Operating Officer Steve Dixon as acting chief executive, working in tandem with Chief Financial Officer Domenic J. Dell'Osso and Chairman Archie W. Dunham in a newly established office of the chairman.

Speaking with investment analysts Monday morning, Mr. Dixon declined to say when Chesapeake might have a permanent chief executive in place. He also declined to address reports that Chesapeake's negotiations with an unnamed candidate fell apart last week.

"Those are speculations and we won't addresses that," he said.

The board's delay in announcing a new chief executive doesn't bode ill for the company, which will have to find someone with experience running a large oil and gas production business and who will agree to move to the company's Oklahoma City headquarters, said Morningstar analyst Mark Hanson.

"I don't think it's a negative for Chesapeake investors that a CEO hasn't been found," Mr. Hanson said. "Being prudent is a good thing."

Chesapeake holds drilling rights to some of the most prolific sources of oil and gas in the U.S. But it has been battered by natural-gas prices that last year sank to their lowest level in more than a decade, forcing the company to sell assets to pay for its operations.

Chesapeake has since resorted to selling assets to keep itself afloat. The company is now focusing on selling smaller packages of acres than on blockbuster, multimillion-dollar deals that had been announced under Mr. McClendon's stewardship.

Chesapeake has already announced $1.5 billion in asset sales this year and says more deals will follow as rising natural-gas prices have made its acres more attractive to potential buyers.

Natural-gas prices settled above $4 a million British thermal units last week, the first time they have done so since August 2011.

"There's certainly sentiment in the market that gas has bottomed and is on the way up," Mr. Dixon said Monday.

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

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Faroe Still on Target to Drill 5 Wells in 2013

Faroe Petroleum remains on target to drill five fully-funded exploration wells during the remainder of this year, the company said as it released its annual results Tuesday.

Faroe said its capital expenditure plans for 2013 "will be significant" with it earmarking some GBP 170 million ($258 million) to be spent during the year. GBP 120 million ($182 million) of this will be spent on exploration, with the remainder spent on producing fields.

Four wells are planned in Norway (Darwin, Snilehorn, Novus and Butch East) while one appraisal well is planned in the UK (Perth).

In its results for 2012, Faroe said that its 2P (proved and probable) reserves stood at 20.1 million barrels of oil equivalent at the end of December. 95 percent of this is associated with fields currently on production.

2012 total average production was approximately 6,900 barrels of oil equivalent per day (boepd), compared with 2,500 boepd in 2011.

Faroe noted that the Hyme field came on stream in February this year, with net production from the well during 2013 expected to be approximately 1,200 boepd. In addition, several infill wells are planned for 2013 on the Njord, Brage, Ringhorne East and Schooner fields.

In total, 2013 production is expected to be between 7,000 and 9,000 boepd.

Oil sector analysts at London-based investment bank Peel Hunt commented in a statement:

"Success at the drill bit has been modest with two key discoveries, namely Butch and Rodriguez (post year-end). However, Faroe's growth initiatives have remained robust with its successful participation in the UK (seven awards) and the Norwegian (eight awards) licencing rounds and its entry into Iceland."

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Faroe Still on Target to Drill 5 Wells in 2013

Faroe Petroleum remains on target to drill five fully-funded exploration wells during the remainder of this year, the company said as it released its annual results Tuesday.

Faroe said its capital expenditure plans for 2013 "will be significant" with it earmarking some GBP 170 million ($258 million) to be spent during the year. GBP 120 million ($182 million) of this will be spent on exploration, with the remainder spent on producing fields.

Four wells are planned in Norway (Darwin, Snilehorn, Novus and Butch East) while one appraisal well is planned in the UK (Perth).

In its results for 2012, Faroe said that its 2P (proved and probable) reserves stood at 20.1 million barrels of oil equivalent at the end of December. 95 percent of this is associated with fields currently on production.

2012 total average production was approximately 6,900 barrels of oil equivalent per day (boepd), compared with 2,500 boepd in 2011.

Faroe noted that the Hyme field came on stream in February this year, with net production from the well during 2013 expected to be approximately 1,200 boepd. In addition, several infill wells are planned for 2013 on the Njord, Brage, Ringhorne East and Schooner fields.

In total, 2013 production is expected to be between 7,000 and 9,000 boepd.

Oil sector analysts at London-based investment bank Peel Hunt commented in a statement:

"Success at the drill bit has been modest with two key discoveries, namely Butch and Rodriguez (post year-end). However, Faroe's growth initiatives have remained robust with its successful participation in the UK (seven awards) and the Norwegian (eight awards) licencing rounds and its entry into Iceland."

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Cairn Continues to Target North Sea Plays

Cairn Energy will continue to target new plays within the UK North Sea and Norwegian continental shelf, the firm said Tuesday as it outlined plans to explore frontier basins in the Atlantic Margin and Mediterranean in its annual results statement.

Cairn will use cash generated from its share in various producing North Sea assets to fund several operated exploration wells offshore Morocco and Senegal, West Africa, during 2013 and 2014. It is also planning a 3D seismic campaign in the Gulf of Lion, offshore Spain, as well as conducting geological studies into opportunities offshore Malta.

The company also announced Tuesday farm-in into three blocks offshore Senegal. Cairn is taking a 65-percent working interest and operatorship of three blocks – Rufisque, Sangomar and Sangomar Deep – that are currently operated by Far Limited with Petrosen (the Senegalese national oil company) as a joint venture partner. In return it has agreed to fully fund the costs of one exploration well and to fund 72.2 percent of subsequent exploration costs.

In the UK and Norway, Cairn is involved in four non-operated exploration and appraisal wells during 2013, two of which are underway. It also has new interests in 10 licenses that have been acquired in recent licensing rounds.

Meanwhile, work continues on the North Sea's Greater Catcher area (where Cairn has a 30-percent, non-operated interest) and the Kraken oil field (25 percent). These fields are now a late pre-development stage and are expected to lead to first oil and cash flows in sometime around 2016/2017.

"With a strong cash position and a disciplined approach to capital expenditure, we look forward to the start of our multi-well, multi-year operated exploration programme commencing in Q4 2013 targeting more than 3.5 billion barrels of oil equivalent," Cairn Chief Executive Simon Thomson commented in a company statement.

Oil analysts at London-based investment bank FirstEnergy was positive about Cairn's announcements Tuesday, noting that the farm-in offshore Senegal adds "further high-impact exploration potential to the portfolio".

Cairn reported a pre-tax loss for 2012 of $194.2 million (2011: $1.2 billion loss) and stated that it had cash at the end of December amounting to $1.6 billion. The firm also retains an approximately 10 percent residual shareholding in Cairn India.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Cairn Continues to Target North Sea Plays

Cairn Energy will continue to target new plays within the UK North Sea and Norwegian continental shelf, the firm said Tuesday as it outlined plans to explore frontier basins in the Atlantic Margin and Mediterranean in its annual results statement.

Cairn will use cash generated from its share in various producing North Sea assets to fund several operated exploration wells offshore Morocco and Senegal, West Africa, during 2013 and 2014. It is also planning a 3D seismic campaign in the Gulf of Lion, offshore Spain, as well as conducting geological studies into opportunities offshore Malta.

The company also announced Tuesday farm-in into three blocks offshore Senegal. Cairn is taking a 65-percent working interest and operatorship of three blocks – Rufisque, Sangomar and Sangomar Deep – that are currently operated by Far Limited with Petrosen (the Senegalese national oil company) as a joint venture partner. In return it has agreed to fully fund the costs of one exploration well and to fund 72.2 percent of subsequent exploration costs.

In the UK and Norway, Cairn is involved in four non-operated exploration and appraisal wells during 2013, two of which are underway. It also has new interests in 10 licenses that have been acquired in recent licensing rounds.

Meanwhile, work continues on the North Sea's Greater Catcher area (where Cairn has a 30-percent, non-operated interest) and the Kraken oil field (25 percent). These fields are now a late pre-development stage and are expected to lead to first oil and cash flows in sometime around 2016/2017.

"With a strong cash position and a disciplined approach to capital expenditure, we look forward to the start of our multi-well, multi-year operated exploration programme commencing in Q4 2013 targeting more than 3.5 billion barrels of oil equivalent," Cairn Chief Executive Simon Thomson commented in a company statement.

Oil analysts at London-based investment bank FirstEnergy was positive about Cairn's announcements Tuesday, noting that the farm-in offshore Senegal adds "further high-impact exploration potential to the portfolio".

Cairn reported a pre-tax loss for 2012 of $194.2 million (2011: $1.2 billion loss) and stated that it had cash at the end of December amounting to $1.6 billion. The firm also retains an approximately 10 percent residual shareholding in Cairn India.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Exillon Well Ahead of Growth Target for 2P Reserves

Onshore Russia-focused junior Exillon Energy reported an update Friday in which the firm highlighted that it was well ahead target when it comes to both production and reserves.

In the statement, Exillon CEO Mark Martin said:

"The three components of our growth strategy are to increase our production, EBITDA and reserves. Our production during 2012 grew by 45 percent, our EBITDA by 137 percent and our 2P reserves by 96 percent.

"Our target was to double our 2P reserves within three years. We have done this in one year."

Exillon reported that its total proved (1P) reserves increased by 56 percent in 2012 to 196 million barrels, while its proved plus probable (2P) reserves almost doubled to 520 million barrels from 265 million barrels at the end of 2011.

At Exillon's ETP II-III field at Timan-Pechora in northern Russia, 2P reserves increased by 110 percent to 107 million barrels. At the firm's EWS I field in Western Siberia, 2P reserves increased 75 percent to 180 million barrels.

Recent acquisitions by Exillon in Timan-Pechora added seven million barrels of 2P reserves, although they also added 95 million barrels of 3P reserves, said the firm.

Exillon said that it plans to drill 24 wells this year, which represents a 50-percent increase on the firm's 2012 drilling activity.

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Exillon Well Ahead of Growth Target for 2P Reserves

Onshore Russia-focused junior Exillon Energy reported an update Friday in which the firm highlighted that it was well ahead target when it comes to both production and reserves.

In the statement, Exillon CEO Mark Martin said:

"The three components of our growth strategy are to increase our production, EBITDA and reserves. Our production during 2012 grew by 45 percent, our EBITDA by 137 percent and our 2P reserves by 96 percent.

"Our target was to double our 2P reserves within three years. We have done this in one year."

Exillon reported that its total proved (1P) reserves increased by 56 percent in 2012 to 196 million barrels, while its proved plus probable (2P) reserves almost doubled to 520 million barrels from 265 million barrels at the end of 2011.

At Exillon's ETP II-III field at Timan-Pechora in northern Russia, 2P reserves increased by 110 percent to 107 million barrels. At the firm's EWS I field in Western Siberia, 2P reserves increased 75 percent to 180 million barrels.

Recent acquisitions by Exillon in Timan-Pechora added seven million barrels of 2P reserves, although they also added 95 million barrels of 3P reserves, said the firm.

Exillon said that it plans to drill 24 wells this year, which represents a 50-percent increase on the firm's 2012 drilling activity.

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Exillon Well Ahead of Growth Target for 2P Reserves

Onshore Russia-focused junior Exillon Energy reported an update Friday in which the firm highlighted that it was well ahead target when it comes to both production and reserves.

In the statement, Exillon CEO Mark Martin said:

"The three components of our growth strategy are to increase our production, EBITDA and reserves. Our production during 2012 grew by 45 percent, our EBITDA by 137 percent and our 2P reserves by 96 percent.

"Our target was to double our 2P reserves within three years. We have done this in one year."

Exillon reported that its total proved (1P) reserves increased by 56 percent in 2012 to 196 million barrels, while its proved plus probable (2P) reserves almost doubled to 520 million barrels from 265 million barrels at the end of 2011.

At Exillon's ETP II-III field at Timan-Pechora in northern Russia, 2P reserves increased by 110 percent to 107 million barrels. At the firm's EWS I field in Western Siberia, 2P reserves increased 75 percent to 180 million barrels.

Recent acquisitions by Exillon in Timan-Pechora added seven million barrels of 2P reserves, although they also added 95 million barrels of 3P reserves, said the firm.

Exillon said that it plans to drill 24 wells this year, which represents a 50-percent increase on the firm's 2012 drilling activity.

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TNK-BP to Target US Tight Oil

MOSCOW - Russian oil producer TNK-BP Ltd. wants to gain access to U.S. tight oil projects in order to get expertise that can be used on deposits in Russia, the company's senior vice president for international projects, Boris Zilbermints, said Wednesday.

Russia has potentially huge tight oil resources in Western Siberia, where output at its main Soviet-era fields is waning.

TNK-BP, a joint venture between BP plc and a group of Soviet-born tycoons, is being taken over by Russian state-controlled oil giant OAO Rosneft.

Mr. Zilbermints said he'd had no contact with Rosneft on integration. He said the integration process would begin after the takeover closed, expected in the first half of this year.

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

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Jimbolia-100 Well Reaches Target Depth

Romania-focused Zeta Petroleum announced Thursday that the Jimbolia-100 appraisal well has reached its target depth of 8,500 feet.

Spud Dec. 31, the well is located on the Jimbolia concession near the Romanian-Serbian border. It is targeting the Jimbolia Veche oil discovery, which has two hydrocarbon-bearing intervals and a current contingent resource of 1.7 million barrels.

Now that it has reached target depth, the well will be logged and a seven-inch liner will be run into the bottom section of the hole. A decision to test the well will be made on receipt of the logging results, said Zeta.

Zeta holds a 39-percent interest in the Jimbolia-100 well. The well is operated by NIS Petrol SRL, which holds a 51-percent stake.

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Santos Confident on Achieving Production Target despite Profit Drop

Santos' full year net profit dropped by nearly a third, but the oil and gas producer remains optimistic about its ability to meet its production targets this year.

The company's net profit for the full year to Dec. 31, 2012, fell to $534.8 million (AUD 519 million), from $776.5 million (AUD 753 million). Santos explained in its earnings disclosure that in 2011, it made an exceptional gain on an asset sale.

Underlying net profit rose 34 percent to $625 million (AUD 606 million), driven by higher liquid volumes and gas prices.

Meanwhile, the company's oil production volume is up ten percent to 52.1 million barrels of oil equivalent.

"Production in 2012 was driven by new assets in Western Australia and Vietnam, and strong Cooper oil production. We expect a further lift in production this year," Santos' CEO, David Knox, said in a statement.

"Our liquefied natural gas (LNG) projects are poised to deliver significant shareholder value and remain on schedule with Papua New Guinea LNG on track for first LNG in 2014 and Gladstone LNG (GLNG) in 2015. Cost estimates for both projects are unchanged," Knox noted.

The company's main LNG project is the $19 billion (AUD18.5 billion) GLNG development on Queensland, which utilizes coal seam gas to LNG technology.

Santos disclosed in January this year that the production cost associated with GLNG blew out $53 million (AUD 50 million). At that time, Santos said GLNG’s production costs for 2012 were expected to be at $694 million (AUD 660 million), much higher than its previous cost guidance – issued in October last year – of $641 million to $673 million (AUD 610 million to AUD 640 million).

Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.

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Zeta Expects Jimbolia-100 Well to Hit Target Depth in 5 Days

Romania-focused Zeta Petroleum reported Thursday that the operator of the Jimbolia oil concession in Romania, NIS Petrol SRL, has advised it that the Jimbolia-100 appraisal well has now been drilled to its second casing point depth of 7,887 feet (2,404 meters). Casing has been run and cemented to a depth of 7,845 feet (2,391 meters).

Zeta said that, subject to confirmation of a successful cementing job, the well will be logged before drilling through the targeted oil reservoir and ahead to the target depth of 8,497 feet (2,590 meters). It is expected that the target depth will be reached within the next five days, with a further 15 days required to complete logging and testing operations. If successful, Jimbolia-100 will be completed as a production well.

The well is targeting the Jimbolia Veche oil discovery, which has two hydrocarbon-bearing intervals and a current mean contingent resource of 1.7 million barrels.

Zeta holds a 39-percent stake in the concession.

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Target Drills Ahead in the Sydney-1 Well, Progresses Fairway Project

Target Energy said Wednesday that it is drilling ahead in the Sydney-1 well, after having successfully addressed a technical issue relating to a loss in circulation at 5,915 feet.

The company will be drilling ahead in the sidetrack well; it is aiming to reach a target depth of 7,415 feet.

Target revealed in January that it was experiencing problems with progressing in the Sydney-1 well. The company said in an earlier disclosure that it experienced issues with swelling shales and gravels in the shallower of the well section.

Sydney-1 is part of Target's onshore Fairway four-well program. The other three wells in the project are the Darwin-1, Darwin-2 and Darwin-3 wells.

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BG Group to Miss 1 MMboepd Target

BG Group warned Tuesday that previous guidance given by the company that it would produce in excess of one million barrels of oil equivalent per day (boepd) in 2015 will not now be achieved.

BG Group indicated that the continuing uncertainty about the timing for the resumption of production at the Total-operated Elgin/Franklin field was partially to blame for the revision of its guidance. BG Group had already warned in October that its production was being held back by the shutdown of Elgin/Franklin, where a major gas leak occurred in March last year. The firm's production for 2012 of 658,000 boepd was in line with the revised guidance it gave in its 3Q 2012 results.

BG Group also pointed out that production during the first half of 2013 will be slightly down on 1H 2012 and even lower during 3Q 2013, when the firm performs most of its maintenance program. However, the firm added that it expects production growth to be strong during 4Q 2013 thanks to the planned ramp up of two FPSO vessels in Brazil and significant volumes from its Jasmine and Margarita fields.

The company also saw first production achieved from the 120,000 bopd FPSO vessel on the Sapinhoá field, operated by Petrobras, in January.

For 2013 as a whole, BG Group expects to produce at a rate of between 630,000 boepd and 660,000 boepd.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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BG Group to Miss 1 MMboepd Target

BG Group warned Tuesday that previous guidance given by the company that it would produce in excess of one million barrels of oil equivalent per day (boepd) in 2015 will not now be achieved.

BG Group indicated that the continuing uncertainty about the timing for the resumption of production at the Total-operated Elgin/Franklin field was partially to blame for the revision of its guidance. BG Group had already warned in October that its production was being held back by the shutdown of Elgin/Franklin, where a major gas leak occurred in March last year. The firm's production for 2012 of 658,000 boepd was in line with the revised guidance it gave in its 3Q 2012 results.

BG Group also pointed out that production during the first half of 2013 will be slightly down on 1H 2012 and even lower during 3Q 2013, when the firm performs most of its maintenance program. However, the firm added that it expects production growth to be strong during 4Q 2013 thanks to the planned ramp up of two FPSO vessels in Brazil and significant volumes from its Jasmine and Margarita fields.

The company also saw first production achieved from the 120,000 bopd FPSO vessel on the Sapinhoá field, operated by Petrobras, in January.

For 2013 as a whole, BG Group expects to produce at a rate of between 630,000 boepd and 660,000 boepd.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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