Norway Plans to Raise Taxes on Oil Companies

OSLO - Norwegian Prime Minister Jens Stoltenberg, who faces an election in September, on Sunday laid out plans for a modest tax cut for mainland businesses while increasing taxes on oil companies and multinationals, as the small Nordic nation looks to maintain a competitive business climate.

Mr. Stoltenberg's plan, part of the government budget presentation on Tuesday, includes a reduction in the general corporate tax to 27% from 28% starting in 2014.

The move is expected to shave 2.4 billion kroner ($413 million) off the annual tax bill for mainland industry, as well as NOK500 million annually for those who are self-employed, the government said. Lawmakers will vote on the budget, but Mr. Stoltenberg's ruling coalition has enough votes to pass it.

Neighboring Sweden recently cut its corporate-tax rate to 22%, and Denmark plans to reach the same level by 2016. Finland, meanwhile, is aiming to take its tax rate at 20%.

Norway's oil-and-gas industry has helped keep unemployment low, public finances intact and wages rapidly growing. While this has insulated Norway from much of Europe's economic malaise, it has forced many companies outside the energy sector to be noncompetitive.

"Some sectors are performing very well, pushing prices and salaries higher," Mr. Stoltenberg said at a news conference. "At the same time, businesses that can't increase prices because they depend on global markets are squeezed by high costs and lower demand from abroad."

Norway's wage growth is expected to slow to 3.5% in 2013, but is still high enough to erode the competitiveness of companies in the international market.

Oil companies won't benefit from the tax cut, the government said, because it will be offset by an increase in the special petroleum tax to 51% from 50%.

Mr. Stoltenberg criticized oil companies for cost overruns on big projects, and said they would have to pay a bigger share of the investments from now on.

"We think we give a better signal to the oil companies when they must now bear a bigger share of the investments themselves, not the least because we need more cost awareness in that sector," he said.

The 24 oil projects under development offshore Norway have recorded cost overruns of NOK49 billion, government figures show. Mr. Stoltenberg said "90% of this is paid for by the society."

Oil companies would still be able to deduct most of their investment costs, but slightly less than before. By reducing a tax deduction called the "uplift," oil companies' tax bill was expected to increase by NOK70 billion in current value between 2013 and 2050, the government said, or slightly below NOK3 billion annually.

Norway's dominant oil company, Statoil ASA, wasn't available for comment Sunday.

The Norwegian Oil and Gas Association said it worried the changes could undermine Norway's reputation as a stable environment for oil-company investments, and warned that marginally profitable oil and gas projects could be shelved.

Amid a high oil price, some offshore projects "have a pretty high break-even price," association spokesman Erling Kvadsheim told The Wall Street Journal. "I don't think this measure in itself will necessarily affect those, but some of the more expensive projects to increase the oil recovery [on mature fields] may be impacted."

Some of the bill for the tax cuts would go to big corporations. The government said it planned to reduce multinational companies' ability to shift profit into low-tax countries from Norway through internal loans. Lowering interest deductions on such loans would increase tax revenue by NOK3 billion annually, the government said.

In addition, a higher tax rate on people who own more than one home would increase Norway's tax revenue by an additional 500 million kroner annually, the government said.

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

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Norway Plans to Raise Taxes on Oil Companies

OSLO - Norwegian Prime Minister Jens Stoltenberg, who faces an election in September, on Sunday laid out plans for a modest tax cut for mainland businesses while increasing taxes on oil companies and multinationals, as the small Nordic nation looks to maintain a competitive business climate.

Mr. Stoltenberg's plan, part of the government budget presentation on Tuesday, includes a reduction in the general corporate tax to 27% from 28% starting in 2014.

The move is expected to shave 2.4 billion kroner ($413 million) off the annual tax bill for mainland industry, as well as NOK500 million annually for those who are self-employed, the government said. Lawmakers will vote on the budget, but Mr. Stoltenberg's ruling coalition has enough votes to pass it.

Neighboring Sweden recently cut its corporate-tax rate to 22%, and Denmark plans to reach the same level by 2016. Finland, meanwhile, is aiming to take its tax rate at 20%.

Norway's oil-and-gas industry has helped keep unemployment low, public finances intact and wages rapidly growing. While this has insulated Norway from much of Europe's economic malaise, it has forced many companies outside the energy sector to be noncompetitive.

"Some sectors are performing very well, pushing prices and salaries higher," Mr. Stoltenberg said at a news conference. "At the same time, businesses that can't increase prices because they depend on global markets are squeezed by high costs and lower demand from abroad."

Norway's wage growth is expected to slow to 3.5% in 2013, but is still high enough to erode the competitiveness of companies in the international market.

Oil companies won't benefit from the tax cut, the government said, because it will be offset by an increase in the special petroleum tax to 51% from 50%.

Mr. Stoltenberg criticized oil companies for cost overruns on big projects, and said they would have to pay a bigger share of the investments from now on.

"We think we give a better signal to the oil companies when they must now bear a bigger share of the investments themselves, not the least because we need more cost awareness in that sector," he said.

The 24 oil projects under development offshore Norway have recorded cost overruns of NOK49 billion, government figures show. Mr. Stoltenberg said "90% of this is paid for by the society."

Oil companies would still be able to deduct most of their investment costs, but slightly less than before. By reducing a tax deduction called the "uplift," oil companies' tax bill was expected to increase by NOK70 billion in current value between 2013 and 2050, the government said, or slightly below NOK3 billion annually.

Norway's dominant oil company, Statoil ASA, wasn't available for comment Sunday.

The Norwegian Oil and Gas Association said it worried the changes could undermine Norway's reputation as a stable environment for oil-company investments, and warned that marginally profitable oil and gas projects could be shelved.

Amid a high oil price, some offshore projects "have a pretty high break-even price," association spokesman Erling Kvadsheim told The Wall Street Journal. "I don't think this measure in itself will necessarily affect those, but some of the more expensive projects to increase the oil recovery [on mature fields] may be impacted."

Some of the bill for the tax cuts would go to big corporations. The government said it planned to reduce multinational companies' ability to shift profit into low-tax countries from Norway through internal loans. Lowering interest deductions on such loans would increase tax revenue by NOK3 billion annually, the government said.

In addition, a higher tax rate on people who own more than one home would increase Norway's tax revenue by an additional 500 million kroner annually, the government said.

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

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Petroceltic Plans Nine Wells over 18 Months

Junior oil and gas firm Petroceltic International outlined plans to drill a minimum of nine wells during the next 18 months when it reported its annual results Monday.

Petroceltic said that its drilling campaign would take place across Bulgaria, Egypt, Kurdistan and Romania.

In Bulgaria, where Petroceltic operates three production licenses including the Galata gas field that it brought into production in 2004, the firm said that its latest exploration well – Kamchia – was spud this month and, if successful, could be rapidly developed through existing infrastructure.

The firm said it was continuing to invest in Egypt, in spite of the high degree of political uncertainty in the country, and that the recent award to it of the onshore South Idku and offshore North Thekah blocks was evidence of its commitment to the country.

In the Kurdistan region of Iraq, a joint venture in which Petroceltic is a part plans to begin drilling two high-impact prospects during the second half of 2013. The firm said that a number of prospects within the joint venture's Shakrok and Dinarta block are assessed to contain prospective resources in excess of 500 million barrels.

During 2012, Petroceltic acquired highly-quality 3D seismic data over the Muridava and Est Cobalcescu blocks in Romania as part of the country's 10th Licensing Round. The firm said it has identified the presence of a variety of potentially material exploration leads and prospects on these blocks, and it plans to drill two of these during 2013 as part of a wider Black Sea campaign. A further four wells are scheduled for 2014.

Meanwhile, Petroceltic has resumed planning for an appraisal well in Italy on the Elsa discovery offshore Abruzzo and was recently awarded the Central Adriatic permit B.R272.EL. Onshore, the firm has made steady progress on the permitting for its Carpignano Sesia well in the western Po Valley.

Petroceltic also said that it has booked reserves for its Ain Tsila assets of 304 million barrels of oil equivalent after a Declaration of Commerciality was made in December 2012.

The firm exceed its production target of 28,000 barrels of oil equivalent per day (boepd) during 2012, with the full-year pro-forma rate coming in at 28,400 boepd.

Petroceltic Chairman Robert Adair commented in a statement:

"Petroceltic has fundamentally transformed its business over the past year. The merger with Melrose in October 2012 has created a significant, regionally focussed, full cycle, independent oil and gas company. This combination has produced a company with stable finances and excellent growth prospects. Petroceltic has the technical expertise and ambition to develop further over the next 12 months while the recent announcement of our new $500 million financing facility represents a strong technical and financial endorsement of the quality of our producing assets and longer term growth ambitions of the group.

"All key objectives set out at the end of last year have been met or exceeded. The Declaration of Commerciality, announced in December 2012, is a significant milestone in the development of our Algerian asset, this has allowed us to book reserves for the Ain Tsila asset for the first time. Looking forward, we have an exciting programme of exploration and appraisal planned over the coming 18 months with a minimum of nine wells planned across our portfolio in North Africa, the Black Sea and the Kurdistan Region of Iraq."

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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BP Reviewing Mad Dog Phase 2 Development Plans

BP plc and partners are reviewing their plans for the second phase of the Mad Dog field development in the U.S. Gulf of Mexico as current market conditions and industry inflation have made the current development scheme less attractive.

BP, Chevron Corp. and BHP Billiton Petroleum are reviewing the existing plans and other options in evaluating how to develop the project, BP's largest greenfield development in the U.S. Gulf in a decade and one of the world's largest spars.

However, BP told Rigzone it fully intends to develop the Mad Dog Phase 2 resources and is committed to moving forward with the right plan.

"It is too early to speculate when the details of the final plan will be approved by BP and its co-owners," a BP spokesperson said in an email statement.

The current plans for Mad Dog Phase 2 include a spar floating system with infield flow lines and associated subsea infrastructure to connect the subsea production and injection wells. The project also includes export pipelines connected to the existing Mardi Gras system.

The spar will have production capacity of 130,000 barrels of oil per day, 75 million cubic feet per day of total compression, and water injection capacity of 280,000 barrels per day (bopd) for waterflood of western and southern field segments. Water injection capacity can be expanded to 350,000 bopd to accommodate future injection requirements.

The development concept includes 33 wet wells, 19 production and 14 injection wells.

BP is operator of Mad Dog Phase 2 with 60.5 percent working interest. BHP Petroleum holds 23.9 percent interest and Chevron owns 15.6 percent.

Mad Dog Phase 2 was one of seven projects BP anticipated would be in the post-final investment decision stage in the 2015-2020 timeframe. BP expected to kick off construction of the Mad Dog 2 infrastructure around the end of 2013, according to a BP December 2012 presentation.

Mad Dog Phase 2 is one of 11 BP megaprojects that will each require a gross investment of over $10 billion.  Located in the southern Green Canyon area of the U.S. Gulf in water depths of 4,500 to 6,800 feet (1,372 to 2,073 meters), Mad Dog is estimated to contain reserves ranging from 200 to 450 million barrels of oil equivalent.

The company reported late last year it was on track to deliver 15 projects from 2012-2014. BP started up three of those projects in 2012, including the Galapagos project in the U.S. Gulf, Clochas Mavacola in Angola and Devenick in the North Sea.  

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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BP Reviewing Mad Dog Phase 2 Development Plans

BP plc and partners are reviewing their plans for the second phase of the Mad Dog field development in the U.S. Gulf of Mexico as current market conditions and industry inflation have made the current development scheme less attractive.

BP, Chevron Corp. and BHP Billiton Petroleum are reviewing the existing plans and other options in evaluating how to develop the project, BP's largest greenfield development in the U.S. Gulf in a decade and one of the world's largest spars.

However, BP told Rigzone it fully intends to develop the Mad Dog Phase 2 resources and is committed to moving forward with the right plan.

"It is too early to speculate when the details of the final plan will be approved by BP and its co-owners," a BP spokesperson said in an email statement.

The current plans for Mad Dog Phase 2 include a spar floating system with infield flow lines and associated subsea infrastructure to connect the subsea production and injection wells. The project also includes export pipelines connected to the existing Mardi Gras system.

The spar will have production capacity of 130,000 barrels of oil per day, 75 million cubic feet per day of total compression, and water injection capacity of 280,000 barrels per day (bopd) for waterflood of western and southern field segments. Water injection capacity can be expanded to 350,000 bopd to accommodate future injection requirements.

The development concept includes 33 wet wells, 19 production and 14 injection wells.

BP is operator of Mad Dog Phase 2 with 60.5 percent working interest. BHP Petroleum holds 23.9 percent interest and Chevron owns 15.6 percent.

Mad Dog Phase 2 was one of seven projects BP anticipated would be in the post-final investment decision stage in the 2015-2020 timeframe. BP expected to kick off construction of the Mad Dog 2 infrastructure around the end of 2013, according to a BP December 2012 presentation.

Mad Dog Phase 2 is one of 11 BP megaprojects that will each require a gross investment of over $10 billion.  Located in the southern Green Canyon area of the U.S. Gulf in water depths of 4,500 to 6,800 feet (1,372 to 2,073 meters), Mad Dog is estimated to contain reserves ranging from 200 to 450 million barrels of oil equivalent.

The company reported late last year it was on track to deliver 15 projects from 2012-2014. BP started up three of those projects in 2012, including the Galapagos project in the U.S. Gulf, Clochas Mavacola in Angola and Devenick in the North Sea.  

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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Media shines a light on Colorado BLM leasing plans

News stories last week show that BLM Colorado State Director Helen Hankins is up to her old tricks. According to stories in E&E News’ Energywire, the Durango Herald, and the Denver Business Journal, Dir. Hankins is following her consistent pattern of offering to auction off controversial land for oil and gas, even after major public outcry. This time, Dir. Hankins’ plans to offer more than 10,000 acres near Mesa Verde National Park – worsening air pollution problems the park is already experiencing from existing nearby drilling operations and coal-fired power plants.

It’s worth noting that bringing these oil and gas proposals back puts Dir. Hankins in direct conflict with the balanced approach to public land use that Interior Sec. Sally Jewell spent her weekend endorsing to Western governors.

You may remember that in early 2013, Dir. Hankins deferred the Mesa Verde parcels after the National Park Service, landowners, and community groups protested the threat posed to the park from drilling pollution. Her reversal demonstrates why Sec. Jewell should rein in the Colorado BLM office and ensure that Dir. Hankins is using innovative 2010 oil and gas leasing reforms such as “Master Leasing Plans” which allow a more balanced approach to energy development and look at on-the-ground impacts, including threats to air quality and tourism and recreation. Instead, Dir. Hankins continues ignore the balanced approach Westerners want and plays her part as the oil and gas industry’s real estate agent.

In the Durango Herald, Emery Cowan reported that the La Plata County Commissioners sent a letter to Dir. Hankins asking her to implement the Obama administration’s oil and gas leasing reforms.

County asks for delay in gas and oil lease

“However, by making the decision to lease (the La Plata County parcels in November), the BLM appears to be shutting the door on a (master plan) and a smart approach to protect the treasures that are so important to our local community and economy,” the letter said.

Scott Streater, writing for E&E News, noted that former park rangers weighed in on the original lease sale with concerns of how oil and gas leasing would affect one of the nation’s most iconic parks, Mesa Verde National Park.

BLM to put deferred parcels near Colo. national park back on the block

Among those that protested against leasing the parcels was the Coalition of National Park Service Retirees, which wrote a letter in February to Salazar complaining that development of the eight parcels “could further impair the already degraded air quality at Mesa Verde, harm important scenic values within the surrounding landscape and negatively affect the local economy, which depends greatly on the national park’s protected status.”

Writing in the Denver Business Journal, Cathy Proctor noted that Mesa Verde attracts more than half a million visitors annually.

Denver Business Journal: Feds to re-offer oil and gas leases near Mesa Verde National Park

The federal Bureau of Land Management is moving forward with a controversial plan to offer about 12,000 acres of mineral rights in southwest Colorado for oil and gas drilling at its November auction — including parcels near the entrance to Mesa Verde National Park.

As public outcry continues to grow, we’ll be watching to see if Dir. Hankins is allowed to continue making the Administration’s reforms into a broken promise for Western communities.

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Woodside Halts Pluto Expansion Plans

Woodside Petroleum Ltd. has revealed there are longer discussions with other major oil and gas companies regarding an expansion of the Pluto liquefied natural gas (LNG) project in Western Australia.

Pluto, a $15 billion project that was launched about a year ago, has contributed significantly to Woodside's production profile in recent months.

The operation was a key factor behind Woodside reporting Thursday in its quarterly update a 55 percent jump in production compared to a year earlier for the three months to end-March.

Woodside had previously said it was looking to work with partners on the expansion of Pluto; however, those intentions were also dismissed in the update.

"At present, there are no discussions with other resource owners with regard to Pluto expansion," the Perth-based company said.

"Woodside is continuing its efforts in the pursuit of expansion gas and has exploration activities scheduled in the region over the coming years."

Only a week ago Woodside shelved its development plans for the Browse LNG project, in which the company is majority owner and operator. Woodside said that decision was due to commercial factors.

Despite expansion at Pluto and the development of Browse being currently off the agenda for Woodside, the company recorded several improvements for first quarter 2013 against the corresponding period a year ago.

The increase in production saw Woodside report first quarter output of 21.9 million barrels, which was in line with the company's guidance for 2013. Sales revenue increased by 21 percent to $1.445 billion.

Woodside explained that Pluto, along with the ongoing success of the North West Shelf operation, were major reasons for a lift in production.

However, compared to the previous quarter, to end-December 2012, production was down 10 percent and sales revenue was 18 percent lower.

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

Woodside Halts Pluto Expansion Plans

Woodside Petroleum Ltd. has revealed there are longer discussions with other major oil and gas companies regarding an expansion of the Pluto liquefied natural gas (LNG) project in Western Australia.

Pluto, a $15 billion project that was launched about a year ago, has contributed significantly to Woodside's production profile in recent months.

The operation was a key factor behind Woodside reporting Thursday in its quarterly update a 55 percent jump in production compared to a year earlier for the three months to end-March.

Woodside had previously said it was looking to work with partners on the expansion of Pluto; however, those intentions were also dismissed in the update.

"At present, there are no discussions with other resource owners with regard to Pluto expansion," the Perth-based company said.

"Woodside is continuing its efforts in the pursuit of expansion gas and has exploration activities scheduled in the region over the coming years."

Only a week ago Woodside shelved its development plans for the Browse LNG project, in which the company is majority owner and operator. Woodside said that decision was due to commercial factors.

Despite expansion at Pluto and the development of Browse being currently off the agenda for Woodside, the company recorded several improvements for first quarter 2013 against the corresponding period a year ago.

The increase in production saw Woodside report first quarter output of 21.9 million barrels, which was in line with the company's guidance for 2013. Sales revenue increased by 21 percent to $1.445 billion.

Woodside explained that Pluto, along with the ongoing success of the North West Shelf operation, were major reasons for a lift in production.

However, compared to the previous quarter, to end-December 2012, production was down 10 percent and sales revenue was 18 percent lower.

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

Woodside Halts Pluto Expansion Plans

Woodside Petroleum Ltd. has revealed there are longer discussions with other major oil and gas companies regarding an expansion of the Pluto liquefied natural gas (LNG) project in Western Australia.

Pluto, a $15 billion project that was launched about a year ago, has contributed significantly to Woodside's production profile in recent months.

The operation was a key factor behind Woodside reporting Thursday in its quarterly update a 55 percent jump in production compared to a year earlier for the three months to end-March.

Woodside had previously said it was looking to work with partners on the expansion of Pluto; however, those intentions were also dismissed in the update.

"At present, there are no discussions with other resource owners with regard to Pluto expansion," the Perth-based company said.

"Woodside is continuing its efforts in the pursuit of expansion gas and has exploration activities scheduled in the region over the coming years."

Only a week ago Woodside shelved its development plans for the Browse LNG project, in which the company is majority owner and operator. Woodside said that decision was due to commercial factors.

Despite expansion at Pluto and the development of Browse being currently off the agenda for Woodside, the company recorded several improvements for first quarter 2013 against the corresponding period a year ago.

The increase in production saw Woodside report first quarter output of 21.9 million barrels, which was in line with the company's guidance for 2013. Sales revenue increased by 21 percent to $1.445 billion.

Woodside explained that Pluto, along with the ongoing success of the North West Shelf operation, were major reasons for a lift in production.

However, compared to the previous quarter, to end-December 2012, production was down 10 percent and sales revenue was 18 percent lower.

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.

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MOG Details Ombrina Mare Drilling Plans

Italy-focused Mediterranean Oil & Gas (MOG) highlighted its drilling plans for its Ombrina Mare and Maltese assets as the firm reported a first quarter update Friday.

After a positive ruling on MOG's submission of its environment impact assessment (EIA) for Ombrina Mare offshore development, the company has commissioned ERC Equipoise to complete by June a competent persons report detailing the reserves and resources in the field. MOG then plans to drill a pilot development well in the first half of 2014.

Meanwhile, MOG has made progress in Malta with the completion of its farm out to Genel Energy and the appointment of AGR Well Management for the drilling of the Hagar Qim 1 well.

MOG achieved net gas production of some 3.9 million cubic feet of gas per day during the first quarter, with 3.34 million cubic feet per day coming from its offshore Guendelina field. Guendelina well GUE-2ss – which accounts for 30 percent of the field's production – was taken offline on March 5 in order to find out what had caused an influx of water. MOG and its partner Eni (the operator) are analyzing possible remedial work so that the well can be restarted.

Analysts at London-based investment bank Liberum Capital commented that the shut-in "appears temporary and recoverable reserves should be unaffected".

Commenting on the update Friday, MOG Chief Executive Dr Bill Higgs said in a statement:

"We have had a busy start to what is going to be an important year for MOG as we gear up for the drilling program in Malta in Q4 2013 and as Ombrina Mare appraisal drilling draws nearer. We are financially strong and continue to build our cash position from production."

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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ConocoPhillips Suspends 2014 Alaska Drilling Plans

ConocoPhillips will place on hold its 2014 drilling plans for Alaska's Chukchi Sea due to the uncertainties of evolving federal regulatory requirements and operational permitting standards.

While the company is confident in its expertise and ability to safely conduct offshore Arctic operations, ConocoPhillips believes it needs more time to ensure that all regulatory stakeholders are aligned, said ConocoPhillips Alaska President Trond-Erik Johansen in a statement.

"We welcome the opportunity to work with the federal government and other leaseholders to further define and clarify the requirements for drilling offshore Alaska," Johansen commented. "Once those requirements are understood, we will reevaluate our Chukchi Sea drilling plans. We believe this is a reasonable and responsible approach given the huge investments required to operate offshore in the Arctic."

ConocoPhillips in 1998 was awarded 98 exploration lease tracts in the Chukchi Sea Outer Continental Shelf. The company is Alaska's largest oil producer and is operator of the Kuparuk and Alpine fields. ConocoPhillips' leases will expire in 2019. As of year-end 2012, the company had invested $650 million net in its Chukchi Sea operations, including leases, seismic, biological studies and well planning, a ConocoPhillips spokesperson told Rigzone in an email.

Royal Dutch Shell plc in February suspended its 2014 offshore Alaska drilling plans, saying it needed more time to ensure the readiness of its equipment and employees for future drilling.

Last month, the U.S. Department of the Interior (DOI) concluded that Shell failed to finalize key components of its 2012 Alaska Arctic drilling program. DOI called on the industry and government to collaborate to develop an Arctic-specific model for offshore Alaska oil and gas exploration.

DOI Secretary Ken Salazar said the agency would proceed with ConocoPhillips using the same regime it did with Shell. While the Obama administration is interested in pursuing Arctic resources, Salazar said they wouldn't allow shortcuts in terms of requirements, and that exploration would only be carried out with the "utmost safety."

Greenpeace International called decisions by ConocoPhillips and Norway-based Statoil ASA to shelve Arctic drilling plans on admission that the oil industry is still not capable of meeting the enormous challenges posed by operating in the world's most extreme environment.

"The time has come for governments around the world to call for a permanent halt to the reckless exploitation of the far north," said Greenpeace International Arctic campaigner Ben Wycliffe in a statement.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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ExxonMobil Plans World's Biggest FLNG Facility

SYDNEY - ExxonMobil Corp. laid out plans for a development using the world's biggest floating natural gas processing plant, in a technically challenging move that underscores its bullish view on Asian demand for the fuel.

Exxon and partner BHP Billiton Ltd. want to anchor a vessel extending 495 meters--the equivalent of around five football pitches--at sea to tap into the remote Scarborough natural gas field offshore Western Australia. They're seeking government approval for the multibillion dollar project, and targeting first production as early as 2020.

Floating liquefied natural gas technology, known as FLNG, is untried but has captured the attention of some of the world's biggest energy companies seeking to access gas fields that are too small or remote to develop using pipelines and onshore facilities. Royal Dutch Shell PLC is a leading proponent of FLNG vessels, which it plans to deploy in Australia and possibly elsewhere.

The relative calm of the waters off Australia's northeastern coastline make the country a strong candidate to accommodate the world's first FLNG vessels. Its stable political environment and proximity to Asian markets that have a growing appetite for fuels that are cleaner than coal when burnt are also drawcards. According to the International Energy Agency, China's natural gas demand alone will more than quadruple to 545 billion cubic meters between 2011 and 2035.

However, companies like Exxon need to ensure their vessels can withstand stormy seas. One main concern is that the forces generated by liquefied gas sloshing in partially filled containers can damage the storage system. That issue is being addressed with containers designed to minimize sloshing and with elaborate anchoring systems that limit the movement of vessels in the water.

Exxon's proposed facility would produce between 6 million and 7 million metric tons of liquefied natural gas, or LNG, a year for several decades. The Scarborough resource was discovered in 1979 and is estimated to hold up to 10 trillion cubic feet of gas--equal to more than a third of the U.S.'s annual gas consumption.

Early design work would begin next year, ahead of a final investment decision in 2014-15, Exxon said in a filing to the federal government's environment department. A Melbourne-based spokeswoman for Exxon said FLNG has "the capacity to reduce our capital costs by removing the need for infrastructure" and has a smaller environmental footprint.

With close to a dozen natural-gas export terminals planned for its coastline, Australia is poised to leapfrog Qatar as the world's top exporter of LNG by the end of the decade. LNG is natural gas chilled to a liquid so that it can be shipped by tanker.

The industry, however, is facing increasing cost headwinds driven by a strong local currency and a shortage of skilled labor. Underscoring these challenges, Chevron Corp. and smaller joint venture partners including Exxon and Shell said in December the cost of building their giant Gorgon LNG project on the Western Australian coast had blown out by a fifth to 52 billion Australian dollars (US$54.4 billion).

The budget overruns come as Australia becomes increasingly likely to face rising competition from emerging gas-export industries in North America and Africa, which could make it tougher to secure customers.

FLNG is often touted by company executives as a means of mitigating cost pressures because much of the construction process occurs offshore in countries with cheaper sources of labor. Companies also don't have to pay for acquiring and clearing land.

"For some of the more economically challenged gas resources out there, floating LNG is going to take on a much higher profile," said Andrew Williams, a Melbourne-based energy analyst at RBC Capital Markets.

In 2011, Shell committed to use a FLNG vessel to process natural gas from its Prelude field in the Browse Basin offshore northwestern Australia. The vessel is due to begin producing 3.6 million tons of LNG each year from 2017.

Shell estimated that its project would cost between US$3 billion and US$3.5 billion for every 1 million tons of production capacity, or between US$10.8 billion and US$12.6 billion.

In its filing Tuesday, Exxon didn't estimate a cost for its Scarborough development.

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

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ExxonMobil Plans World's Biggest FLNG Facility

SYDNEY - ExxonMobil Corp. laid out plans for a development using the world's biggest floating natural gas processing plant, in a technically challenging move that underscores its bullish view on Asian demand for the fuel.

Exxon and partner BHP Billiton Ltd. want to anchor a vessel extending 495 meters--the equivalent of around five football pitches--at sea to tap into the remote Scarborough natural gas field offshore Western Australia. They're seeking government approval for the multibillion dollar project, and targeting first production as early as 2020.

Floating liquefied natural gas technology, known as FLNG, is untried but has captured the attention of some of the world's biggest energy companies seeking to access gas fields that are too small or remote to develop using pipelines and onshore facilities. Royal Dutch Shell PLC is a leading proponent of FLNG vessels, which it plans to deploy in Australia and possibly elsewhere.

The relative calm of the waters off Australia's northeastern coastline make the country a strong candidate to accommodate the world's first FLNG vessels. Its stable political environment and proximity to Asian markets that have a growing appetite for fuels that are cleaner than coal when burnt are also drawcards. According to the International Energy Agency, China's natural gas demand alone will more than quadruple to 545 billion cubic meters between 2011 and 2035.

However, companies like Exxon need to ensure their vessels can withstand stormy seas. One main concern is that the forces generated by liquefied gas sloshing in partially filled containers can damage the storage system. That issue is being addressed with containers designed to minimize sloshing and with elaborate anchoring systems that limit the movement of vessels in the water.

Exxon's proposed facility would produce between 6 million and 7 million metric tons of liquefied natural gas, or LNG, a year for several decades. The Scarborough resource was discovered in 1979 and is estimated to hold up to 10 trillion cubic feet of gas--equal to more than a third of the U.S.'s annual gas consumption.

Early design work would begin next year, ahead of a final investment decision in 2014-15, Exxon said in a filing to the federal government's environment department. A Melbourne-based spokeswoman for Exxon said FLNG has "the capacity to reduce our capital costs by removing the need for infrastructure" and has a smaller environmental footprint.

With close to a dozen natural-gas export terminals planned for its coastline, Australia is poised to leapfrog Qatar as the world's top exporter of LNG by the end of the decade. LNG is natural gas chilled to a liquid so that it can be shipped by tanker.

The industry, however, is facing increasing cost headwinds driven by a strong local currency and a shortage of skilled labor. Underscoring these challenges, Chevron Corp. and smaller joint venture partners including Exxon and Shell said in December the cost of building their giant Gorgon LNG project on the Western Australian coast had blown out by a fifth to 52 billion Australian dollars (US$54.4 billion).

The budget overruns come as Australia becomes increasingly likely to face rising competition from emerging gas-export industries in North America and Africa, which could make it tougher to secure customers.

FLNG is often touted by company executives as a means of mitigating cost pressures because much of the construction process occurs offshore in countries with cheaper sources of labor. Companies also don't have to pay for acquiring and clearing land.

"For some of the more economically challenged gas resources out there, floating LNG is going to take on a much higher profile," said Andrew Williams, a Melbourne-based energy analyst at RBC Capital Markets.

In 2011, Shell committed to use a FLNG vessel to process natural gas from its Prelude field in the Browse Basin offshore northwestern Australia. The vessel is due to begin producing 3.6 million tons of LNG each year from 2017.

Shell estimated that its project would cost between US$3 billion and US$3.5 billion for every 1 million tons of production capacity, or between US$10.8 billion and US$12.6 billion.

In its filing Tuesday, Exxon didn't estimate a cost for its Scarborough development.

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Perupetro Plans Auction for Offshore Concessions

LIMA, Peru - Peru's state agency for hydrocarbon exploration, Perupetro, said Monday it plans to auction off nine concessions in the fourth quarter of this year.

Perupetro President Luis Ortigas said all of the nine concessions are offshore. He said the concessions should attract investments of $450 million.

Mr. Ortigas said Perupetro will start a roadshow in the coming weeks to promote the auction.

He said investments in offshore concessions totaled about $2 billion in recent years, and he expects these investments to double in the next five years.

Perupetro had previously said it planned to auction off more than 30 concessions this year, with most of those concessions located in Peru's Amazon region. However, that plan has been delayed several times as the agency awaits information needed to carry out prior consultation for indigenous groups living in the Amazon.

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Perupetro Plans Auction for Offshore Concessions

LIMA, Peru - Peru's state agency for hydrocarbon exploration, Perupetro, said Monday it plans to auction off nine concessions in the fourth quarter of this year.

Perupetro President Luis Ortigas said all of the nine concessions are offshore. He said the concessions should attract investments of $450 million.

Mr. Ortigas said Perupetro will start a roadshow in the coming weeks to promote the auction.

He said investments in offshore concessions totaled about $2 billion in recent years, and he expects these investments to double in the next five years.

Perupetro had previously said it planned to auction off more than 30 concessions this year, with most of those concessions located in Peru's Amazon region. However, that plan has been delayed several times as the agency awaits information needed to carry out prior consultation for indigenous groups living in the Amazon.

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Iraq Plans to Invest $130B in Oil, Gas Over 5 Years

Iraq plans to invest some $130 billion over the next five years in order to triple the country's output, which is currently stood at 3.25 million barrels a day, the country's oil minister said Saturday.

Abdul Kareem Luaiby said that his country would allocate $18 billion to raise natural gas output and $25 billion to upgrade refinery capacity. Iraq expects to earn some $600 billion in revenue from these oil expansion plans, Mr. Luaiby told an energy conference held in Basra.

Iraq has boosted its crude oil production last year by 24%, thanks to several oil deals Iraq signed with international oil companies such as Royal Dutch Shell PLC, BP PLC, Exxon Mobil Corp., Eni SpA, OAO Lukoil Holdings and China National Petroleum Corp.

Iraq's crude oil exports have, over the last few months, surpassed those of Iran and became the Organization of the Petroleum Exporting Countries' second-largest producer.

Iraq's crude oil exports in February rose by 7.5%, to 2.536 million barrels a day on month, compared with 2.359 million barrels a day in January, according to figures released by the State Oil Marketing Organization, or SOMO. Iraq plans to raise exports to 2.9 million barrels a day this year.

Production from Iraq's super-giant Majnoon oil field, which is being developed by Shell, will reach 100,000 barrels a day in May and 200,000 barrels a day by the end of the year, Luaiby told the conference.

Last year, the Paris-based International Energy Agency estimated that Iraq would be able to pump up to 6.1 million barrels a day in 2020 and 8.3 million barrels a day in 2035. Iraq said it would be able to reach 8 million to 9 million barrels a day in 2020.

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UK Explorer Cuadrilla Delays Fracking Plans Until 2014

LONDON - U.K. shale gas explorer Cuadrilla Resources Ltd. said Wednesday it was delaying its plans to begin hydraulic fracturing at its Bowland shale project in Lancashire, England, to 2014 while it conducts an environmental impact assessment for the site of each exploration well.

Cuadrilla had planned to start hydraulic fracturing, a controversial process used to release natural gas from the rock, this summer. The delay will be a setback for U.K. government ambitions to replicate the North American shale gas revolution that has transformed the U.S. energy market.

"We recognize that within the complex U.K. regulatory framework governing planning this process can prove lengthy but we are determined to spare no effort in meeting our exploration targets in an environmentally and socially sustainable manner," Cuadrilla Chief Executive Francis Egan said.

At the end of last year, the U.K. government lifted a moratorium on hydraulic fracturing, or fracking, as part of plans to stimulate renewed investment in Britain's energy sector and reduce dependence on gas imports as its aging North Sea oil and gas fields start to run dry.

Exploration is still at an early stage in the U.K., making a reliable estimate of the country's reserves difficult. There has been no commercial shale gas production in the U.K. so far.

Cuadrilla said that technical analysis of the Bowland Shale confirms the company's previous estimate that the license area holds at least 200 trillion cubic feet of gas resources.

Cuadrilla, which is the only company using the controversial technology to explore for shale gas onshore in the U.K., halted fracking in May 2011 after two small seismic tremors were detected near their operations.

Cuadrilla is jointly owned by U.S. private-equity firm Riverstone LLC and Australian mining group AJ Lucas and management.

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UK Explorer Cuadrilla Delays Fracking Plans Until 2014

LONDON - U.K. shale gas explorer Cuadrilla Resources Ltd. said Wednesday it was delaying its plans to begin hydraulic fracturing at its Bowland shale project in Lancashire, England, to 2014 while it conducts an environmental impact assessment for the site of each exploration well.

Cuadrilla had planned to start hydraulic fracturing, a controversial process used to release natural gas from the rock, this summer. The delay will be a setback for U.K. government ambitions to replicate the North American shale gas revolution that has transformed the U.S. energy market.

"We recognize that within the complex U.K. regulatory framework governing planning this process can prove lengthy but we are determined to spare no effort in meeting our exploration targets in an environmentally and socially sustainable manner," Cuadrilla Chief Executive Francis Egan said.

At the end of last year, the U.K. government lifted a moratorium on hydraulic fracturing, or fracking, as part of plans to stimulate renewed investment in Britain's energy sector and reduce dependence on gas imports as its aging North Sea oil and gas fields start to run dry.

Exploration is still at an early stage in the U.K., making a reliable estimate of the country's reserves difficult. There has been no commercial shale gas production in the U.K. so far.

Cuadrilla said that technical analysis of the Bowland Shale confirms the company's previous estimate that the license area holds at least 200 trillion cubic feet of gas resources.

Cuadrilla, which is the only company using the controversial technology to explore for shale gas onshore in the U.K., halted fracking in May 2011 after two small seismic tremors were detected near their operations.

Cuadrilla is jointly owned by U.S. private-equity firm Riverstone LLC and Australian mining group AJ Lucas and management.

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ONGC Plans Oil Exploration in Bengal

Oil and Natural Gas Corp (ONGC) is set to start its maiden exploratory drilling on an onshore oil block in West Bengal.

"We have decided to dig two exploratory wells in villages Ladhi and Dangi near Chakaliya in Uttar Dinajpur district of West Bengal for which we have just applied to the state government for necessary approval," an official of the state-owned oil and gas explorer told DNA Money.

The area in Uttar Dinajpur falls under Block PA-ONN-2005/1 of the Purnea basin, which ONGC bagged under the seventh round of auction under the New Exploration Licensing Policy, or Nelp VII, in 2008. The production sharing contract was signed in December 2008, while the exploration licence was granted a year later. The block covers an area of 1,069 square km.

Bharat Heavy Electrical Ltd's Pollution Control Research Institute at Haridwar has already completed the environment impact assessment on behalf of ONGC for this onshore block.

The environmental approval for exploration would be given following a public hearing of the project to be held in April. Exploratory drilling is undertaken to establish the presence of hydrocarbons indicated by seismic survey and interpretation of data. "This activity would take around 3-4 months under normal conditions," the official said.

The drilling site is surrounded by agricultural field and ONGC has assured the state government that the well head facilities would be located in such a manner avoiding settlements.

According to the petroleum ministry, gas discovery in Salbanhat, Bangladesh, close to the Indo-Bangladesh border, up to which the Purnea block extends suggests that the equivalent sediments would be prospective in this part also.

Focus on exploring the Purnea onshore block covering West Bengal and Bihar comes at a time when ONGC has not been quite successful in striking any major oil and gas find in the country in recent times at a scale achieved by private sector rival Reliance and when some of its own onshore blocks in the north-east basin is set to peak in two years.

This article was originally published on March 7.

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Petrobras Confirms Plans to Start Platform Work in China

RIO DE JANEIRO - Brazilian state-run energy giant Petroleo Brasileiro, or Petrobras, confirmed late Monday that it will start building four oil platforms in China instead of Brazil, but denied that the shift means the company will not meet strict requirements to use local goods and services.

Petrobras said that work to convert oil tankers into the P-67, P-75, P-76 and P-77 platforms would start in China, but that the work represented less than 3% of the value of the contracts to build the floating production, storage and offloading vessels, or FPSOs. The conversion, however, will be completed in Brazil, Petrobras said. The P-67 platform is part of an order for eight replicated FPSOs, while the other three platforms will be used to produce oil from areas transferred to the company from the government.

Earlier Monday, the local O Estado de S. Paulo newspaper had reported that Petrobras shifted construction of the FPSOs overseas amid concerns that local shipyards would not meet deadlines to complete construction and cause production delays. Petrobras is currently struggling with stagnant oil production because of maintenance shutdowns at aging offshore platforms and declining output at mature fields.

Concession contracts in Brazil require companies to use a certain percentage of local goods and services, part of a government strategy aimed at creating a robust oilfield-services sector to accompany development of recently discovered offshore oilfields. Petrobras plans to spend $237 billion through 2016 to develop the fields, where oil was discovered under a thick layer of salt miles under the seabed off Brazil's southeast coast.

"The index of contracted local content is immutable, and Petrobras is not trying to alter it," the company said.

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