Commodity Corner: Crude Up on Bernanke Comments
Wednesday, April 27, 2011
Rigzone Staff
by Saaniya Bangee
Crude oil climbed higher Wednesday after the U.S. Federal Reserve indicated there would be no change in its monetary policy.
Light, sweet crude settled at $112.76 a barrel, up 55 cents. After a two-day meeting, Federal Reserve chairman Ben Bernanke said Wednesday that the spike in inflation will be temporary, due to higher oil and gas prices, and that the economy will continue to recover at a moderate pace.
The Fed also said it will keep interest rates near zero. Lower interest rates have helped keep the dollar weak contributing to higher oil prices. Oil, which is priced in dollars, is more attractive to foreign buyers when the dollar is weak.
Crude futures for June delivery fluctuated between $110.71 and $113.40 Wednesday.
Meanwhile, crude futures were also pressured by strong gasoline prices. Front-month gasoline gained 6.22 cents, settling at $3.419 a gallon. Gasoline futures traded between $3.35 and $3.44 a gallon on Wednesday. RBOB gasoline futures ended the day's trading session at their highest in 33 months. The Energy Information Administration (EIA) reported that gasoline stockpiles fell last week for the 10th week in a row, the lowest level since Sept. 2009.
After trading between $4.37 and $4.43, May natural gas lost a penny to settle at $4.377 a gallon Wednesday.
Wednesday, April 27, 2011
BP Expects to Resume GOM Drilling by Summer
BP Expects to Resume GOM Drilling by Summer
Wednesday, April 27, 2011
The Wall Street Journal
by Guy Chazan
BP says it expects to resume drilling in the Gulf of Mexico by the summer, less than 18 months after a rig it had leased there exploded, killing 11 workers and triggering a catastrophic oil spill.
Company officials spoke as BP reported results that showed the repercussions of the Deepwater Horizon disaster continue to weigh on its balance sheet.
Fergus MacLeod, BP's head of investor relations, told analysts that BP is working toward a "phased resumption of activities [in the Gulf] in the middle of the year," subject to regulatory approvals. He said BP would only restart if it could meet or exceed new safety standards, such as tough requirements on oil-spill response capabilities and equipment such as blowout preventers.
A return to the Gulf would mark a big symbolic success for BP chief executive Bob Dudley and his efforts to rebuild a company still badly tarnished by last year's oil spill. BP is the largest producer in the deepwater Gulf of Mexico, one of its main heartlands, and it still owns more acreage there than any other company. But output from its Gulf fields has fallen sharply in the aftermath of the oil spill.
BP's replacement cost profit for the first quarter was $5.5 billion, down 2% from $5.6 billion a year ago and lower than most analysts' forecasts. The metric, which strips out changes in the value of crude inventories, is more closely watched by investors than the net profit figure, which was $7.1 billion in the first quarter, up 17% from $6.1 billion on a year ago.
BP also said it had taken an additional $400 million pretax charge for spill-related costs, bringing its total provision for the spill to $41.3 billion. Last week BP and its contractors on the blownout well, Transocean and Cameron, sued each other over the disaster.
BP's lower replacement cost profit--and the steep 11% drop in its oil and gas production--reflected the continuing impact of Deepwater Horizon. The company has had to sell billions of dollars worth of producing oil fields to cover the costs of the spill. And like other oil companies, its output was badly hit by the drilling moratorium which was imposed by the Obama administration in the wake of the Deepwater Horizon explosion and only lifted last October.
Company officials say its Gulf of Mexico production had declined by 100,000 barrels a day from 433,000 barrels a day last year--a 23% fall. BP's costs have risen, too--partly because of the huge expense of keeping its drilling rigs on standby in the Gulf waiting for the moratorium to be lifted.
Resuming operations in the Gulf has been difficult for all oil companies, not just BP. The new U.S. regulator, the Bureau of Ocean Energy Management, Regulation and Enforcement, BOEMRE, has imposed tough new safety and environmental standards on all operators, which now have to demonstrate how they would contain a subsea blowout.
Since February, BOEMRE has issued permits for the drilling of only ten wells. But allowing BP, which still faces a range of criminal and civil investigations over the Gulf spill, to resume drilling there could prove controversial. The company says it has asked regulators for permission to drill 10 development wells that were underway when the moratorium was imposed.
Wednesday, April 27, 2011
The Wall Street Journal
by Guy Chazan
BP says it expects to resume drilling in the Gulf of Mexico by the summer, less than 18 months after a rig it had leased there exploded, killing 11 workers and triggering a catastrophic oil spill.
Company officials spoke as BP reported results that showed the repercussions of the Deepwater Horizon disaster continue to weigh on its balance sheet.
Fergus MacLeod, BP's head of investor relations, told analysts that BP is working toward a "phased resumption of activities [in the Gulf] in the middle of the year," subject to regulatory approvals. He said BP would only restart if it could meet or exceed new safety standards, such as tough requirements on oil-spill response capabilities and equipment such as blowout preventers.
A return to the Gulf would mark a big symbolic success for BP chief executive Bob Dudley and his efforts to rebuild a company still badly tarnished by last year's oil spill. BP is the largest producer in the deepwater Gulf of Mexico, one of its main heartlands, and it still owns more acreage there than any other company. But output from its Gulf fields has fallen sharply in the aftermath of the oil spill.
BP's replacement cost profit for the first quarter was $5.5 billion, down 2% from $5.6 billion a year ago and lower than most analysts' forecasts. The metric, which strips out changes in the value of crude inventories, is more closely watched by investors than the net profit figure, which was $7.1 billion in the first quarter, up 17% from $6.1 billion on a year ago.
BP also said it had taken an additional $400 million pretax charge for spill-related costs, bringing its total provision for the spill to $41.3 billion. Last week BP and its contractors on the blownout well, Transocean and Cameron, sued each other over the disaster.
BP's lower replacement cost profit--and the steep 11% drop in its oil and gas production--reflected the continuing impact of Deepwater Horizon. The company has had to sell billions of dollars worth of producing oil fields to cover the costs of the spill. And like other oil companies, its output was badly hit by the drilling moratorium which was imposed by the Obama administration in the wake of the Deepwater Horizon explosion and only lifted last October.
Company officials say its Gulf of Mexico production had declined by 100,000 barrels a day from 433,000 barrels a day last year--a 23% fall. BP's costs have risen, too--partly because of the huge expense of keeping its drilling rigs on standby in the Gulf waiting for the moratorium to be lifted.
Resuming operations in the Gulf has been difficult for all oil companies, not just BP. The new U.S. regulator, the Bureau of Ocean Energy Management, Regulation and Enforcement, BOEMRE, has imposed tough new safety and environmental standards on all operators, which now have to demonstrate how they would contain a subsea blowout.
Since February, BOEMRE has issued permits for the drilling of only ten wells. But allowing BP, which still faces a range of criminal and civil investigations over the Gulf spill, to resume drilling there could prove controversial. The company says it has asked regulators for permission to drill 10 development wells that were underway when the moratorium was imposed.
Jubilant Receives Extension in Krishna Godavari Block
Jubilant Receives Extension in Krishna Godavari Block
Wednesday, April 27, 2011
Jubilant Energy N.V.
by SubseaIQ
Jubilant announced that the Management Committee for the Krishna Godavari Block (KG-OSN-2001/3), which consists of two nominees from Government of India (Ministry of Petroleum and Natural Gas and Directorate General of Hydrocarbons) has recommended the grant of an extension to the existing contract area by 20.5 km2.
The Field Development Plan ("FDP") for Deen Dayal West area ("DDW") in Krishna Godavari block, which includes wells KG-8, KG-15, KG-17 and KG-28, was approved by Government of India in November, 2009.
The hydrocarbon plays encountered in discovery wells KG-8 and KG-15 extend towards South/South West of the original block boundary. As per the Production Sharing Contract ("PSC"), the Management Committee has recommended the enlargement of the DDW development area in this direction. The previously approved development area for DDW is 17 km2.
As disclosed in CPR at time of the Company's IPO, this extended area of 20.5 km2 will increase the existing 2P reserves and 2C resources for KG block.
Jubilant holds a 10% participating interest in this block through its subsidiary Jubilant Offshore Drilling Private Limited in India. Gujarat State Petroleum Corporation Limited, with an 80% participating interest, is the Operator for the block.
Wednesday, April 27, 2011
Jubilant Energy N.V.
by SubseaIQ
Jubilant announced that the Management Committee for the Krishna Godavari Block (KG-OSN-2001/3), which consists of two nominees from Government of India (Ministry of Petroleum and Natural Gas and Directorate General of Hydrocarbons) has recommended the grant of an extension to the existing contract area by 20.5 km2.
The Field Development Plan ("FDP") for Deen Dayal West area ("DDW") in Krishna Godavari block, which includes wells KG-8, KG-15, KG-17 and KG-28, was approved by Government of India in November, 2009.
The hydrocarbon plays encountered in discovery wells KG-8 and KG-15 extend towards South/South West of the original block boundary. As per the Production Sharing Contract ("PSC"), the Management Committee has recommended the enlargement of the DDW development area in this direction. The previously approved development area for DDW is 17 km2.
As disclosed in CPR at time of the Company's IPO, this extended area of 20.5 km2 will increase the existing 2P reserves and 2C resources for KG block.
Jubilant holds a 10% participating interest in this block through its subsidiary Jubilant Offshore Drilling Private Limited in India. Gujarat State Petroleum Corporation Limited, with an 80% participating interest, is the Operator for the block.
KKR to Buy Barnett Shale Properties from Carrizo
KKR to Buy Barnett Shale Properties from Carrizo
Wednesday, April 27, 2011
Kohlberg Kravis Roberts & Co. L.P.
Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, KKR) announced that KKR has entered into a definitive agreement to acquire certain Barnett Shale properties from Carrizo O&G for $104 million. The transaction, which is expected to close in mid-May, is being made through KKR Natural Resources (KNR), KKR's partnership with Premier Natural to pursue investments in North American oil and gas properties. The transaction is the third investment made by KNR and, following the acquisition of certain properties from ConocoPhillips in January, the second investment made by KNR in the Barnett Shale.
Located in North Central Texas and producing out of the Barnett Shale formation, the Assets contain 122.4bcfe of total net proved reserves (based on a third party estimate) and comprise 75 gross (58.5 net) wells currently producing at a gross rate of 15.7mmcfe/d (8.3 mmcfe/d net).
"With their significant proved developed producing reserve component in a reservoir we know well through our current operations in the region, the assets are a great fit for our KKR Natural Resources platform. We are pleased to add these assets to our oil and gas portfolio and remain excited about the opportunity to grow the KNR platform through the acquisition of additional oil and gas properties in North America," said Jonathan Smidt, a Member at KKR and a senior member of KKR's Energy and Infrastructure business.
KKR announced its partnership with Premier in February, 2010. Founded in June 2006 by former executives of Vintage Petroleum, Inc., Premier currently operates a portfolio of assets located in the Barnett Shale, the Texas Gulf Coast and the Permian Basin and has experience operating assets in most of the major producing basins in the United States.
Wednesday, April 27, 2011
Kohlberg Kravis Roberts & Co. L.P.
Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, KKR) announced that KKR has entered into a definitive agreement to acquire certain Barnett Shale properties from Carrizo O&G for $104 million. The transaction, which is expected to close in mid-May, is being made through KKR Natural Resources (KNR), KKR's partnership with Premier Natural to pursue investments in North American oil and gas properties. The transaction is the third investment made by KNR and, following the acquisition of certain properties from ConocoPhillips in January, the second investment made by KNR in the Barnett Shale.
Located in North Central Texas and producing out of the Barnett Shale formation, the Assets contain 122.4bcfe of total net proved reserves (based on a third party estimate) and comprise 75 gross (58.5 net) wells currently producing at a gross rate of 15.7mmcfe/d (8.3 mmcfe/d net).
"With their significant proved developed producing reserve component in a reservoir we know well through our current operations in the region, the assets are a great fit for our KKR Natural Resources platform. We are pleased to add these assets to our oil and gas portfolio and remain excited about the opportunity to grow the KNR platform through the acquisition of additional oil and gas properties in North America," said Jonathan Smidt, a Member at KKR and a senior member of KKR's Energy and Infrastructure business.
KKR announced its partnership with Premier in February, 2010. Founded in June 2006 by former executives of Vintage Petroleum, Inc., Premier currently operates a portfolio of assets located in the Barnett Shale, the Texas Gulf Coast and the Permian Basin and has experience operating assets in most of the major producing basins in the United States.
Inpex: Agreement Signed for Vladivostok LNG Joint Study
Wednesday, April 27, 2011
Inpex Corp.
Inpex announced that the Company Japan Far East Gas Co., Ltd., newly established by INPEX, ITOCHU, Japan Petroleum Exploration Co., Ltd. (hereinafter JAPEX), Marubeni and ITOCHU (hereinafter CIECO), has signed an agreement on the implementation of a joint study for the natural gas utilization project in Vladivostok area with Russia's Gazprom. The Agreement was signed on April 25, 2011 in Moscow, Russia.
The Joint Study consists of a Pre-FEED for the construction of a liquefied natural gas (LNG) plant with production capacity of 10 million tons per year, a preliminary feasibility study on the compressed natural gas (CNG) pilot project and a preliminary study on gas-chemical complex project. The Joint Study is scheduled to be completed by the end of 2011.
The Agency for Natural Resources and Energy of Japan's Ministry of Economy, Trade and Industry, ITOCHU, JAPEX and Gazprom implemented a preliminary feasibility study (Pre-FS) from May 2009 to July 2010. Following the result on the Pre-FS as well as the discussions between the related parties, an agreement was signed between the Agency and Gazprom in January 2011 on the framework and cooperation for the Joint Study. This Agreement was hereby signed on the details of the Joint Study in furtherance of the above-mentioned agreement between the Agency and Gazprom.
On March 19, 2011 at the meeting on the comprehensive development of the fuel and energy industry in Eastern Siberia and the Far East held in Sakhalin Oblast, Prime Minister Putin revealed his intentions to increase LNG supply to Japan and alluded to the construction of a new LNG plant in that area. This Joint Study and realization of its future potential projects are considered to be very important for Russia-Japan relations, as well as for the stable LNG supply to not only Japan but also to the Far East and other Asian countries, and will contribute to the diversification of Russia's gas (LNG) export sources.
KBR Lands Contract at Chevron Facility
Wednesday, April 27, 2011
KBR Inc.
KBR has been awarded a $65 million contract by Chevron Products Company to execute a Base Oil expansion project at Chevron's refinery in Pascagoula, MS. The construction project includes building a new lubes hydrocracker and a lube dewaxing / hydrofinishing unit. KBR intends to hire staff locally for the execution of this project. Work is expected to begin in May, and upon completion, the facility is expected to be one of the largest premium base oil plants in the world.
"We are proud to have been selected to execute the delivery of this project, helping Chevron become one of the world's largest producers of premium base oil," said David Zimmerman, President, KBR Services. "KBR has a long history of executing major construction projects in this region and at this refinery. We look forward to continuing this tradition, using local resources to deliver a project that meets schedule and cost targets while maintaining KBR's absolute commitment to safety excellence."
Fed Lowers 2011 GDP Growth Estimate, Raises Core Inflation Expectation
Fed Lowers 2011 GDP Growth Estimate, Raises Core Inflation Expectation
Apr 27, 2011
The US Federal Reserve on Wednesday lowered its expected rate of growth for the US economy in 2011, citing a slower pace than anticipated for the start of the year. In an unprecedented press conference after a meeting of the Fed's Board of Governors, Chairman Ben Bernanke said that the employment picture appears to be better than expected. January's unemployment rate forecast of 8.8- 9% was lowered to 8.4-8.7% for the end of the year.
Apr 27, 2011
The US Federal Reserve on Wednesday lowered its expected rate of growth for the US economy in 2011, citing a slower pace than anticipated for the start of the year. In an unprecedented press conference after a meeting of the Fed's Board of Governors, Chairman Ben Bernanke said that the employment picture appears to be better than expected. January's unemployment rate forecast of 8.8- 9% was lowered to 8.4-8.7% for the end of the year.
Husky's 1QHercules Offshore, Seahawk Drilling Finalize Asset Sale
Wednesday, April 27, 2011
Hercules Offshore Inc.
Hercules Offshore and Seahawk Drilling announced the completion of the asset purchase and sale previously disclosed on February 11, 2011. In accordance with the terms of the Asset Purchase Agreement, Hercules Offshore will acquire 20 jackup rigs located in the U.S. Gulf of Mexico and related assets, accounts receivable, cash, accounts payables, and certain contractual rights from Seahawk Drilling. The total consideration paid to Seahawk Drilling consists of approximately 22.3 million shares of Hercules Offshore common stock and $25.0 million in cash. Following this transaction, there will be a total of approximately 137.2 million outstanding shares of Hercules Offshore, Inc.
Chevron Raises Its Quarterly Dividend To $0.78
Chevron Raises Its Quarterly Dividend To $0.78
Apr 27, 2011
Chevron Corp (NYSE:CVX) said Wednesday its board of directors has raised the company's quarterly dividend to $0.78, an 8.3% increase from the previous dividend of $0.72.
The dividend will be paid June 10th to shareholders of record as of May 19th.
The dividend represents an annual yield of 2.9% based on the company's closing price of $108.75 on Tuesday, April 26th.
Apr 27, 2011
Chevron Corp (NYSE:CVX) said Wednesday its board of directors has raised the company's quarterly dividend to $0.78, an 8.3% increase from the previous dividend of $0.72.
The dividend will be paid June 10th to shareholders of record as of May 19th.
The dividend represents an annual yield of 2.9% based on the company's closing price of $108.75 on Tuesday, April 26th.
Exxon Mobil Increases Quarterly Dividend To $0.47
Exxon Mobil Increases Quarterly Dividend To $0.47
Apr 27, 2011
Exxon Mobil Corp (NYSE:XOM) said Wednesday its board of directors had increased the company's 2nd quarter dividend to $0.47 from $0.44.
That represents an annual yield of 2.1% based on the stock's closing price on Tuesday of $87.42.
The dividend will be paid out June 10th to shareholders of record on May 13th.
Shares of Exxon Mobil are trading down 0.69% at $86.82.
Apr 27, 2011
Exxon Mobil Corp (NYSE:XOM) said Wednesday its board of directors had increased the company's 2nd quarter dividend to $0.47 from $0.44.
That represents an annual yield of 2.1% based on the stock's closing price on Tuesday of $87.42.
The dividend will be paid out June 10th to shareholders of record on May 13th.
Shares of Exxon Mobil are trading down 0.69% at $86.82.
Husky's 1Q Profit Leaps on Higher Output, Prices
Husky's 1Q Profit Leaps on Higher Output, Prices
Wednesday, April 27, 2011
Husky Energy Inc.
Husky achieved strong earnings and cash flow growth in the first quarter of 2011 compared to the same quarter of 2010. Performance was driven primarily by increased production volumes, higher realized crude oil prices for the Atlantic Region and South East Asia, and higher throughput rates and margins within the downstream segment.
"Our first quarter results are in accordance with our execution plan," said CEO Asim Ghosh. "Actions undertaken to grow near-term production have achieved the intended result during a period of strengthening prices. At the same time, our downstream refining segment posted strong performance, with higher throughput enabling us to capitalize on improving market conditions."
"In addition, we have made steady progress in advancing our mid and long-term growth initiatives. Steps taken in the quarter have enabled Husky to achieve important milestones towards progressing the Liwan Gas Project offshore China. This project will create shareholder value by tapping into the fast growing energy markets in Hong Kong and mainland China."
A summary of first quarter results, together with recent key highlights, follows:
First quarter production averaged 310,400 boe/day in line with guidance. Volumes compare positively with 280,500 boe/day in the fourth quarter of 2010 and 295,900 boe/day in first quarter of 2010. Production volumes were driven higher by the February closing of the Western Canada asset acquisition and good performance from White Rose and North Amethyst.
First quarter cash flow and earnings growth were driven by higher upstream production volumes, higher realized light crude oil prices for the Atlantic Region and South East Asia, and stronger throughput rates and margins within the downstream segment. These were partially offset by the impact on Western Canada realized crude oil pricing of higher discounts to WTI, the impact of a strong Canadian dollar, lower throughput at the Lloydminster Upgrader and weak natural gas prices.
Light crude oil prices averaged U.S. $104.97 per barrel for the quarter, 38 percent higher compared to same period of 2010. Of the Company's total production, approximately 20 percent is priced and sold relative to light crude prices (North Sea Brent). U.S. refining market crack spreads were stronger during the quarter with the average Chicago 3:2:1 crack spread at U.S. $16.58 per barrel, compared to U.S. $6.23 in the same period of 2010.
"We continue to prudently manage our financial position and exercise discipline in all aspects of our capital and operating expenditures," said Alister Cowan, CFO.
KEY AREA SUMMARY AND GROWTH UPDATE:
Western Canada - Unconventional and Conventional
The Company continues to maintain production levels from Western Canada and has accelerated development drilling.
Oil Resource Plays
Within the oil resource portfolio, the Company is focused on developing its opportunities in the Lower Shaunavon and Bakken zones in Southern Saskatchewan along with the Viking zone in Southwest Saskatchewan and central Alberta. Husky has approximately 500,000 net acres in its oil resource portfolio. Seventeen wells were drilled during the period with six placed on production.
Gas Resource Plays
Husky advanced development drilling of its liquids-rich gas assets in the Alberta Deep Basin. In the Ansell area, four rigs were active and a total of 20 Cardium formation wells were drilled during the quarter and an additional six exploration and development wells were drilled in Kakwa, Bivouac, the Horn River Basin and on the Cypress acreage.
Through a combination of crown land sales and private purchases, Husky increased its land holdings in its gas resource portfolio during the first quarter by 29,000 acres.
Heavy Oil
Husky is amongst the industry leaders in heavy oil production and has a significant land and resource portfolio along with a solid integrated infrastructure position. Within its heavy oil operations, the Company's strategy is focused on maintaining production levels, being a low cost producer and continuing to drive new enhanced recovery techniques to sustain production volumes.
Construction of the 8,000 bbl/day South Pikes Peak project was approximately 58 percent complete at the end of the first quarter with production expected in mid 2012. The project continues to progress as expected.
The 3,000 bbl/day Paradise Hill project activity commenced in the first quarter, and will utilize the existing Bolney infrastructure. Production is anticipated in late 2012.
Oil Sands
The Company advanced the recently sanctioned Phase I Sunrise Energy Project. Twelve horizontal wells were spud and seven drilled during the quarter. The Company made several significant equipment orders that included the steam generators, vessels, water treating plant and a camp to support the project.
Tucker contributed positive earnings in the quarter with an average production volume of 6,200 bbls/day. Further wells will be brought on production in the second quarter.
Atlantic Region
Through the first quarter, North Amethyst performed well with average production of 21,400 bbls/day net to Husky. In 2011, Husky expects to tie-in an additional producer and one more injector well.
The West White Rose satellite pilot development is progressing on schedule. These wells will provide additional information on the reservoir to refine understanding of the best development scheme for the full West White Rose field. First production from the pilot is anticipated in the third quarter of 2011.
Husky holds exploration rights to nineteen parcels of land in the area. In 2011, the Company plans to participate in the drilling of an appraisal well at the Mizzen discovery and an exploration well to the south of Terra Nova.
South East Asia
Development of the Liwan Gas Project is progressing in accordance with the Heads of Agreement signed with China National Offshore Oil Corporation (CNOOC) in December 2010. Under the Heads of Agreement, Husky will operate the deepwater portion of the project involving development drilling and completions, subsea equipment and controls, and subsea tie-backs to a shallow water platform. CNOOC will operate the shallow water portion of the project including a shallow water platform, approximately 270 km of subsea pipeline to shore, and the onshore gas processing plant.
Development of the Liwan Gas Project comprises three discoveries on Block 29/26; Liwan 3-1, Liuhua 34-2 and Liuhua 29-1, with first gas production expected in late 2013, ramping up through 2014. Official project sanction is expected later in 2011. It is anticipated the natural gas will be sold under a long-term contract at competitive prices in the Guangdong and Hong Kong markets.
The partnership has made considerable progress in advancing the Liwan Gas Project as the Overall Development Plan (ODP) for Liwan 3-1 has been prepared and is undergoing final reviews with submission to authorities scheduled in the second quarter. Development of the Liwan 3-1 and Liuhua 34-2 fields are proceeding in parallel and will share infrastructure. The ODP for the Liuhua 34-2 field is in preparation and planned for submission to authorities mid-2011. Liuhua 29-1 is expected to be fully delineated later this year with an ODP submission targeted before year end.
All nine development wells for the Liwan 3-1 field have been successfully drilled confirming the quality and extent of the reservoir. Fabrication and construction has begun, and long lead time items ordered in accordance with the schedule. Deepwater installation and pipe lay work are planned to take place in 2012 and 2013.
CNOOC is progressing with the development of the shallow water portion of the project. The infrastructure is designed to allow for the tie-in of incremental wells and fields. Gas from the Liuhua 29-1 field will be processed through the same shallow water platform and onshore gas plant as the other two fields and is expected to come on stream in late 2014.
In Indonesia, Husky and its partners continue to progress and plan for the development of the BD and MDA gas fields with first gas production expected in 2014. The long lead time items for the BD field, including the FPSO, are set to go to tender by mid-year. An appraisal well for the MDA field will be drilled later this year as well as a nearby low risk exploratory well targeting the same type of reservoir.
Wednesday, April 27, 2011
Husky Energy Inc.
Husky achieved strong earnings and cash flow growth in the first quarter of 2011 compared to the same quarter of 2010. Performance was driven primarily by increased production volumes, higher realized crude oil prices for the Atlantic Region and South East Asia, and higher throughput rates and margins within the downstream segment.
"Our first quarter results are in accordance with our execution plan," said CEO Asim Ghosh. "Actions undertaken to grow near-term production have achieved the intended result during a period of strengthening prices. At the same time, our downstream refining segment posted strong performance, with higher throughput enabling us to capitalize on improving market conditions."
"In addition, we have made steady progress in advancing our mid and long-term growth initiatives. Steps taken in the quarter have enabled Husky to achieve important milestones towards progressing the Liwan Gas Project offshore China. This project will create shareholder value by tapping into the fast growing energy markets in Hong Kong and mainland China."
A summary of first quarter results, together with recent key highlights, follows:
- Net earnings of $626 million, or $0.70 per share (diluted), including an after-tax gain of $143 million on the sale of non-core assets, an increase of 70 percent from a year ago.
- Cash flow from operations of $1,164 million, or $1.30 per share (diluted), an increase of 36 percent from a year ago.
- Total production before royalties for the quarter averaged 310,400 boe/day, 5 percent above the same quarter of last year and 11 percent higher than the fourth quarter of 2010.
- Progressed the Liwan Gas Project as the Company expects to submit the Overall Development Plan for Liwan 3-1 to the Chinese authorities in the second quarter. The Liwan Gas Project includes several fields; Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 with first gas anticipated from Liwan 3-1 and Liuhua 34-2 in late 2013, ramping up through 2014. Liuhua 29-1 production is anticipated late 2014. Husky's production share is 49 percent.
- Liwan gas is expected to be sold under a long-term contract at competitive prices in the Guangdong and Hong Kong markets.
- Phase I of the Sunrise Energy Project progressed on schedule as development drilling commenced in early 2011 with 12 horizontal wells spud and seven drilled in the quarter.
- In the Atlantic Region, the Company continued to ramp up North Amethyst volumes.
- The Lloydminster Upgrader resumed normal operations in April at which time repairs were completed.
- Closed the previously announced Western Canada asset acquisition on February 4th.
- Closed a $300 million preferred share financing to enhance our liquidity and financial flexibility.
First quarter production averaged 310,400 boe/day in line with guidance. Volumes compare positively with 280,500 boe/day in the fourth quarter of 2010 and 295,900 boe/day in first quarter of 2010. Production volumes were driven higher by the February closing of the Western Canada asset acquisition and good performance from White Rose and North Amethyst.
First quarter cash flow and earnings growth were driven by higher upstream production volumes, higher realized light crude oil prices for the Atlantic Region and South East Asia, and stronger throughput rates and margins within the downstream segment. These were partially offset by the impact on Western Canada realized crude oil pricing of higher discounts to WTI, the impact of a strong Canadian dollar, lower throughput at the Lloydminster Upgrader and weak natural gas prices.
Light crude oil prices averaged U.S. $104.97 per barrel for the quarter, 38 percent higher compared to same period of 2010. Of the Company's total production, approximately 20 percent is priced and sold relative to light crude prices (North Sea Brent). U.S. refining market crack spreads were stronger during the quarter with the average Chicago 3:2:1 crack spread at U.S. $16.58 per barrel, compared to U.S. $6.23 in the same period of 2010.
"We continue to prudently manage our financial position and exercise discipline in all aspects of our capital and operating expenditures," said Alister Cowan, CFO.
KEY AREA SUMMARY AND GROWTH UPDATE:
Western Canada - Unconventional and Conventional
The Company continues to maintain production levels from Western Canada and has accelerated development drilling.
Oil Resource Plays
Within the oil resource portfolio, the Company is focused on developing its opportunities in the Lower Shaunavon and Bakken zones in Southern Saskatchewan along with the Viking zone in Southwest Saskatchewan and central Alberta. Husky has approximately 500,000 net acres in its oil resource portfolio. Seventeen wells were drilled during the period with six placed on production.
Gas Resource Plays
Husky advanced development drilling of its liquids-rich gas assets in the Alberta Deep Basin. In the Ansell area, four rigs were active and a total of 20 Cardium formation wells were drilled during the quarter and an additional six exploration and development wells were drilled in Kakwa, Bivouac, the Horn River Basin and on the Cypress acreage.
Through a combination of crown land sales and private purchases, Husky increased its land holdings in its gas resource portfolio during the first quarter by 29,000 acres.
Heavy Oil
Husky is amongst the industry leaders in heavy oil production and has a significant land and resource portfolio along with a solid integrated infrastructure position. Within its heavy oil operations, the Company's strategy is focused on maintaining production levels, being a low cost producer and continuing to drive new enhanced recovery techniques to sustain production volumes.
Construction of the 8,000 bbl/day South Pikes Peak project was approximately 58 percent complete at the end of the first quarter with production expected in mid 2012. The project continues to progress as expected.
The 3,000 bbl/day Paradise Hill project activity commenced in the first quarter, and will utilize the existing Bolney infrastructure. Production is anticipated in late 2012.
Oil Sands
The Company advanced the recently sanctioned Phase I Sunrise Energy Project. Twelve horizontal wells were spud and seven drilled during the quarter. The Company made several significant equipment orders that included the steam generators, vessels, water treating plant and a camp to support the project.
Tucker contributed positive earnings in the quarter with an average production volume of 6,200 bbls/day. Further wells will be brought on production in the second quarter.
Atlantic Region
Through the first quarter, North Amethyst performed well with average production of 21,400 bbls/day net to Husky. In 2011, Husky expects to tie-in an additional producer and one more injector well.
The West White Rose satellite pilot development is progressing on schedule. These wells will provide additional information on the reservoir to refine understanding of the best development scheme for the full West White Rose field. First production from the pilot is anticipated in the third quarter of 2011.
Husky holds exploration rights to nineteen parcels of land in the area. In 2011, the Company plans to participate in the drilling of an appraisal well at the Mizzen discovery and an exploration well to the south of Terra Nova.
South East Asia
Development of the Liwan Gas Project is progressing in accordance with the Heads of Agreement signed with China National Offshore Oil Corporation (CNOOC) in December 2010. Under the Heads of Agreement, Husky will operate the deepwater portion of the project involving development drilling and completions, subsea equipment and controls, and subsea tie-backs to a shallow water platform. CNOOC will operate the shallow water portion of the project including a shallow water platform, approximately 270 km of subsea pipeline to shore, and the onshore gas processing plant.
Development of the Liwan Gas Project comprises three discoveries on Block 29/26; Liwan 3-1, Liuhua 34-2 and Liuhua 29-1, with first gas production expected in late 2013, ramping up through 2014. Official project sanction is expected later in 2011. It is anticipated the natural gas will be sold under a long-term contract at competitive prices in the Guangdong and Hong Kong markets.
The partnership has made considerable progress in advancing the Liwan Gas Project as the Overall Development Plan (ODP) for Liwan 3-1 has been prepared and is undergoing final reviews with submission to authorities scheduled in the second quarter. Development of the Liwan 3-1 and Liuhua 34-2 fields are proceeding in parallel and will share infrastructure. The ODP for the Liuhua 34-2 field is in preparation and planned for submission to authorities mid-2011. Liuhua 29-1 is expected to be fully delineated later this year with an ODP submission targeted before year end.
All nine development wells for the Liwan 3-1 field have been successfully drilled confirming the quality and extent of the reservoir. Fabrication and construction has begun, and long lead time items ordered in accordance with the schedule. Deepwater installation and pipe lay work are planned to take place in 2012 and 2013.
CNOOC is progressing with the development of the shallow water portion of the project. The infrastructure is designed to allow for the tie-in of incremental wells and fields. Gas from the Liuhua 29-1 field will be processed through the same shallow water platform and onshore gas plant as the other two fields and is expected to come on stream in late 2014.
In Indonesia, Husky and its partners continue to progress and plan for the development of the BD and MDA gas fields with first gas production expected in 2014. The long lead time items for the BD field, including the FPSO, are set to go to tender by mid-year. An appraisal well for the MDA field will be drilled later this year as well as a nearby low risk exploratory well targeting the same type of reservoir.
National Oilwell Varco Reports 1Q Income for 2011
Wednesday, April 27, 2011
National Oilwell Varco Inc.
National Oilwell Varco reported that for its first quarter ended March 31, 2011 it earned net income of $407 million, or $0.96 per fully diluted share, compared to fourth quarter ended December 31, 2010 net income of $440 million, or $1.05 per fully diluted share. The first quarter 2011 results included charges related to Libya asset write-downs and the Company's acquisition of APL totaling $19 million pre-tax, or $0.04 per share after-tax. Net income for the first quarter of 2011 excluding the Libya and APL charges was $422 million, or $1.00 per fully diluted share.
Reported revenues for the first quarter of 2011 were $3.15 billion, a decrease of one percent from the fourth quarter of 2010 and an increase of four percent from the first quarter of 2010. Operating profit for the quarter, excluding the Libya and APL charges, was $628 million or 20 percent of sales.
Capital equipment orders for the Company's Rig Technology segment increased significantly, both sequentially and year-over-year, to $2.28 billion during the first quarter, reflecting higher demand for drilling equipment for new build offshore rigs. At March 31, 2011 the segment's backlog was $6.16 billion, up 23 percent from the end of the fourth quarter.
Pete Miller, Chairman, President and CEO of National Oilwell Varco, remarked, "Our Company got off to a good start in the first quarter of 2011. Our Petroleum Services & Supplies segment performed exceptionally well, and helped offset expected lower revenues from new rig projects. The high levels of oilfield activity are spurring demand for all our products and services, serving to reload our backlog of Rig Technology capital equipment, and enabling our Distribution Services team to put up very solid revenues and margins once again.
"We are very excited that bookings into our capital equipment backlog were more than double our shipments this quarter. Overall, efficient execution of orders in our backlog, our leading technologies, great service, and, most importantly, the best workforce in the industry, led to solid earnings this quarter.
"Gradually recovering economies, high oil prices, a pressing need for modern, efficient drilling and well stimulation equipment, and rising consumption of drillpipe, downhole tools, and other critical oilfield products provide a great outlook for National Oilwell Varco."
Rig Technology
First quarter revenues for the Rig Technology segment were $1.61 billion, a decrease of eight percent from the fourth quarter of 2010 and a decrease of 15 percent from the first quarter of 2010. Operating profit for this segment was $422 million, or 26.2 percent of sales. Revenue out of backlog for the segment declined 25 percent year-over-year, and was down 12 percent from the fourth quarter of 2010, to $1.1 billion for the first quarter of 2011, reflecting the completion of many new offshore rig projects which were won in preceding years.
Petroleum Services & Supplies
Revenues for the first quarter of 2011 for the Petroleum Services & Supplies segment were $1.27 billion, up 11 percent compared to fourth quarter 2010 results and up 37 percent from the first quarter of 2010. Operating profit was $246 million, or 19.4 percent of revenue, an increase of 45 percent from the fourth quarter of 2010. Operating profit flow-through, or the change in operating profit divided by the change in revenue, was 59 percent sequentially and 39 percent from the first quarter of 2010 to the first quarter of 2011.
Distribution Services
The Distribution Services segment generated first quarter revenues of $410 million, which were down three percent from the fourth quarter of 2010 and represented a 23 percent increase from the first quarter of 2010. First quarter operating profit was $28 million or 6.8 percent of sales. Operating profit flow-through was 22 percent from the first quarter of 2010 to the first quarter of 2011.
Xtreme O&G Acquires Stake in Producing Well
Wednesday, April 27, 2011
Xtreme O&G Inc.
Xtreme O&G has acquired a minor working interest in a well producing initially over 400 barrels of oil per day and over 950,000 cubic feet of gas per day. Xtreme agreed to purchase the working interest for 15,000 shares of restricted common stock from one of its partners, further strengthening their relationship.
This newest project verifies their recent geologic studies in the area and they expect this well to produce 200,000 barrels of oil and 500 Million cubic feet of gas during its lifetime. Xtreme and its partners will continue to seek additional working interest and to participate in leasing acreage in the area to continue to exploit these resources.
Willard G. McAndrew III, CEO of Xtreme, commented, "This acquisition represents another step in our expending relationships and gives us a new series of leases to explore in what we hope to be a prolific formation that responds well to today's drilling and recovery technologies."
ExxonMobil Declares Dividend for 2Q
Wednesday, April 27, 2011
ExxonMobil Corp.
ExxonMobil declared a cash dividend of 47 cents per share on the Common Stock, payable on June 10, 2011 to shareholders of record of Common Stock at the close of business on May 13, 2011.
This second quarter dividend compares with 44 cents per share paid in the first quarter of 2011.
Through its dividends, the corporation has shared its success with its shareholders for more than 100 years and has increased its annual dividend payment to shareholders for twenty-nine consecutive years.
Husky Posts Quarterly Dividend
Husky Posts Quarterly Dividend
Wednesday, April 27, 2011
Husky Energy Inc.
Husky has declared a quarterly dividend of $0.30 (Canadian) per share on its common shares for the three month period ended March 31, 2011. The dividend will be payable on July 5, 2011 to shareholders of record at the close of business on May 20, 2011.
On February 28, 2011, the Company announced that shareholders had approved an amendment to the corporation's articles, which allows shareholders to accept dividends in cash or in common shares.
Wednesday, April 27, 2011
Husky Energy Inc.
Husky has declared a quarterly dividend of $0.30 (Canadian) per share on its common shares for the three month period ended March 31, 2011. The dividend will be payable on July 5, 2011 to shareholders of record at the close of business on May 20, 2011.
On February 28, 2011, the Company announced that shareholders had approved an amendment to the corporation's articles, which allows shareholders to accept dividends in cash or in common shares.
Chevron Increases Quarterly Dividend by 8.3%
Wednesday, April 27, 2011
Chevron Corp.
Chevron declared a quarterly dividend of seventy-eight cents ($0.78) per share, payable June 10, 2011, to holders of common stock as shown on the transfer records of the Corporation at the close of business on May 19, 2011. The amount represents an 8.3 percent increase in the company’s quarterly dividend.
Dron & Dickson Bags Talisman Contract
Dron & Dickson Bags Talisman Contract
Wednesday, April 27, 2011
Dron & Dickson
Dron & Dickson has secured a multi-million pound contract with Talisman Energy (UK) Limited.
The three-year deal, with two one-year extension options, will see Dron & Dickson provide a wide range of electrical consumables in support of Talisman's North Sea assets.
Dron & Dickson operations director Colin Maver said, "Talisman is an extremely important client for Dron & Dickson and we are delighted to be working with them.
"Winning this long-term contract underpins our reputation for providing cost-effective, high-quality products that help our customers reduce risk and comply with the latest legislation.
"Building strong relationships with our customers is extremely important to us as a company and we very much look forward to developing the relationship with Talisman over the coming months and years."
Wednesday, April 27, 2011
Dron & Dickson
Dron & Dickson has secured a multi-million pound contract with Talisman Energy (UK) Limited.
The three-year deal, with two one-year extension options, will see Dron & Dickson provide a wide range of electrical consumables in support of Talisman's North Sea assets.
Dron & Dickson operations director Colin Maver said, "Talisman is an extremely important client for Dron & Dickson and we are delighted to be working with them.
"Winning this long-term contract underpins our reputation for providing cost-effective, high-quality products that help our customers reduce risk and comply with the latest legislation.
"Building strong relationships with our customers is extremely important to us as a company and we very much look forward to developing the relationship with Talisman over the coming months and years."
Total Confirms Gas Discovery in Bolivia
Total Confirms Gas Discovery in Bolivia
Wednesday, April 27, 2011
Dow Jones Newswires
by Geraldine Amiel
French oil major Total Wednesday confirmed it made a new gas discovery in Bolivia but declined to give further detail about the discovery and its potential.
Earlier Thursday, Bolivia's state news agency ABI reported that Total and Argentina's Tecpetrol, a unit of the Techint group, had struck gas in the Bolivian lowlands.
ABI also said that Bolivian president Evo Morales is slated to announce the results later Wednesday at an event to celebrate the find at the Aquio block in Santa Cruz province.
The companies have invested $70 million over the past 16 months to drill to a depth of 6,300 meters in search of the fuel, according to ABI.
Production capacity at the Aquio and Ipati blocs is currently estimated at 6.5 million cubic meters a day, which is likely to be doubled or to even reach 18 million cubic meters a day, also according to ABI.
Wednesday, April 27, 2011
Dow Jones Newswires
by Geraldine Amiel
French oil major Total Wednesday confirmed it made a new gas discovery in Bolivia but declined to give further detail about the discovery and its potential.
Earlier Thursday, Bolivia's state news agency ABI reported that Total and Argentina's Tecpetrol, a unit of the Techint group, had struck gas in the Bolivian lowlands.
ABI also said that Bolivian president Evo Morales is slated to announce the results later Wednesday at an event to celebrate the find at the Aquio block in Santa Cruz province.
The companies have invested $70 million over the past 16 months to drill to a depth of 6,300 meters in search of the fuel, according to ABI.
Production capacity at the Aquio and Ipati blocs is currently estimated at 6.5 million cubic meters a day, which is likely to be doubled or to even reach 18 million cubic meters a day, also according to ABI.
Eni's Earning Soars on Higher Oil Prices
Eni's Earning Soars on Higher Oil Prices
Wednesday, April 27, 2011
Eni S.p.A.
Eni, the international oil and gas company, today announces its group results for the first quarter of 20111 (unaudited).
Paolo Scaroni, Chief Executive Officer, commented, "In the first quarter of 2011, marked by the Libyan events, Eni delivered a solid set of financial results on the back of a favorable oil price environment. In spite of ongoing uncertainties regarding resumption of our activities in Libya, the profitability and growth outlook for our Company has remained positive underpinned by a sound financial position, the quality of our asset portfolio, and a strong projects pipeline."
Adjusted operating profit
Adjusted operating profit was €5.13 billion, up 18.4% from the first quarter of 2010. This was due to a better operating performance reported by the Exploration & Production Division (up 32.1%) on the back of stronger oil prices. The Engineering & Construction Division reported a strong performance. The Petrochemical Division also improved versus a year ago as operating losses were substantially cut. These positive trends were partially offset by poor performance reported by the Refining & Marketing Division due to high costs for oil feedstock which were only partially transferred to refined product prices and the Gas & Power Division which was affected by weaker margins on gas sales.
Adjusted Net Profit
Adjusted net profit was €2.22 billion, up 21.6% compared with a year ago, as a result of better operating performance and a decreased adjusted tax rate (from 53% to 50.5%).
Capital expenditure
Capital expenditure for the quarter amounted to €2.87 billion mainly related to continuing development of oil and gas reserves, the construction of rigs and offshore vessels in the Engineering & Construction segment and the upgrading of gas transport infrastructure.
Cash flow
Net cash generated by operating activities amounted to €4.19 billion and were used to fund capital expenditure (€2.87 billion) as well as pay down net borrowings2 which was down by €1.17 billion from December 31, 2010, to €24.95 billion. Cash flow from operating activities was negatively affected by a lower cash inflow of €347 million associated with transferring trade receivables due beyond end of 2010 to factoring institutions amounting to €1,279 million in the fourth quarter 2010, while the current quarter benefitted from transferring €932 million of trade receivables due beyond March 31, 2011 to those institutions.
Financial Ratios
Return on Average Capital Employed (ROACE)3 calculated on an adjusted basis for the twelve-month period ending on March 31, 2011, was 11.4%. The ratio of net borrowings to shareholders' equity including non-controlling interest – leverage3 – decreased to 0.44 at March 31, 2011, from 0.47 as of December 31, 2010. This change was due to profit for the period and reduced net borrowings, notwithstanding the appreciation of the euro against the US dollar as recorded at March 31, 2011, vs. December 31, 2010 (up 6.4%) which reduced shareholders' equity by €1.9 billion.
Exploration & Production
Eni reported liquids and gas production of 1,684 kboe/d for the first quarter of 2011, down by 8.6% from the first quarter of 2010 (down 158 kboe/d). The magnitude of this reduction was the result of the shutdown of activities at several of Eni's producing sites in Libya and the closure of the GreenStream pipeline transporting gas from Libya to Italy which occurred on February 22, 2011, as a result of ongoing political instability and conflict in the Country. From April 2011, Eni production in Libya has been flowing at a level of 50-55 kboe/d and with the full supply supporting local production of electricity. Performance in the quarter was negatively impacted by lower entitlements in the Company's PSAs due to higher oil prices with an overall effect of 32 kboe/d compared to the year-earlier quarter, in addition to the above mentioned Libyan shutdown that caused a production loss of 129 kboe/d compared to the first quarter of 2010. These negatives were partly offset by continuing production ramp-up in Egypt, Iraq and Italy.
Gas & Power
Eni's worldwide natural gas sales recovered from the first quarter of 2010 (up 6% to 32.33 bcm). Sales on the Italian market increased by 10.2% due to client additions in the industrial, power generation and wholesale segments as well as higher volumes supplied. In Europe, Eni sales showed growth in all of the Company's major markets (up by 14.2% on average), excluding Belgium as a result of strong competitive pressures. Turkey, France, the Iberian Peninsula and Germany/Austria were the markets posting the largest increases. Sales to shippers which import gas to Italy decreased by 42.5%. This was due to lower availability of Libyan production and lower volumes purchased.
Portfolio developments
Ukraine
In April 2011, Eni reached an agreement with Cadogan Petroleum plc for the acquisition of an interest in two exploration and development licenses located in the Dniepr-Donetz basin, in Ukraine. This agreement is part of the development of cooperation initiatives in hydrocarbon exploration and production in the Country also reaffirmed in a Memorandum of Understanding with the Ukrainian Ministry of Ecology and Natural Resources.
Alaska
In February 2011, production start-up was achieved at the Nikaitchuq operated field (Eni 100%), located in the North Slope basins offshore Alaska, with resources of 220 million barrels. Production is expected to peak at 28 kbbl/d.
China
In January 2011, Eni signed a Memorandum of Understanding with CNPC/PetroChina to promote common opportunities to jointly expand operations in conventional and unconventional hydrocarbons in China and outside China. The parties will also cooperate in the field of advanced technology, with a special focus on the exploitation of unconventional oil and gas resources.
Angola
In January 2011, Eni was awarded rights to explore and the operatorship of offshore Block 35 in Angola, with a 30% interest. The agreement foresees drilling 2 wells and 3D seismic surveys to be carried out in the first 5 years of exploration. This deal is subject to the approval of the relevant authorities.
Exploration activities
In the first quarter of 2011, significant exploratory success was achieved in:
Outlook
Management expects that the global economic recovery will progressively strengthen across the year 2011. Nonetheless, the 2011 outlook is characterized by a certain degree of uncertainty and volatility also in light of ongoing political instability and conflict in Libya. Eni forecasts an upward trend for Brent crude oil prices supported by healthier global oil demand. For short-term economic and financial projections, Eni assumes an average Brent price of 101 $/bbl for the full year 2011. Management expects that the European gas market will remain weak as sluggish demand growth is insufficient to absorb current oversupplies. Refining margins are expected to remain unprofitable due to weak underlying fundamentals and high feedstock costs. Against this backdrop, management expectations about the main trends in the Company's businesses for 2011 and beyond are disclosed below.
In 2011, management plans to make capital expenditures broadly in line with 2010 (€13.87 billion was invested in 2010) and will mainly be directed to developing giant fields and starting production at new important fields in the Exploration & Production Division, refinery upgrading related in particular to the realization of the EST project, completing the program of enhancing Saipem's fleet of vessels and rigs, and upgrading the natural gas transport infrastructure. Assuming a Brent price of $101/barrel and the planned divestment of certain assets, management forecasts that the ratio of net borrowings to total equity (leverage) at year-end will be lower than in 2010.
Wednesday, April 27, 2011
Eni S.p.A.
Eni, the international oil and gas company, today announces its group results for the first quarter of 20111 (unaudited).
- Financial Highlights
- Adjusted operating profit: up 18.4% to € 5.13 billion
- Adjusted net profit: up 21.6% to € 2.22 billion
- Net profit: up 14.6% to € 2.55 billion
- Cash flow: € 4.19 billion
- Operational Highlights
- Oil and natural gas production for the quarter was down by 8.6% due to the shutdown of activities in Libya
- Natural gas sales for the quarter rebounded from a year ago, up by 6%
- Acquisition of two important exploration and development leases in Ukraine
- Continuing exploration success with the Perla 4 appraisal well and offshore discoveries in Ghana, the Barents Sea and the UK North Sea
Paolo Scaroni, Chief Executive Officer, commented, "In the first quarter of 2011, marked by the Libyan events, Eni delivered a solid set of financial results on the back of a favorable oil price environment. In spite of ongoing uncertainties regarding resumption of our activities in Libya, the profitability and growth outlook for our Company has remained positive underpinned by a sound financial position, the quality of our asset portfolio, and a strong projects pipeline."
Adjusted operating profit
Adjusted operating profit was €5.13 billion, up 18.4% from the first quarter of 2010. This was due to a better operating performance reported by the Exploration & Production Division (up 32.1%) on the back of stronger oil prices. The Engineering & Construction Division reported a strong performance. The Petrochemical Division also improved versus a year ago as operating losses were substantially cut. These positive trends were partially offset by poor performance reported by the Refining & Marketing Division due to high costs for oil feedstock which were only partially transferred to refined product prices and the Gas & Power Division which was affected by weaker margins on gas sales.
Adjusted Net Profit
Adjusted net profit was €2.22 billion, up 21.6% compared with a year ago, as a result of better operating performance and a decreased adjusted tax rate (from 53% to 50.5%).
Capital expenditure
Capital expenditure for the quarter amounted to €2.87 billion mainly related to continuing development of oil and gas reserves, the construction of rigs and offshore vessels in the Engineering & Construction segment and the upgrading of gas transport infrastructure.
Cash flow
Net cash generated by operating activities amounted to €4.19 billion and were used to fund capital expenditure (€2.87 billion) as well as pay down net borrowings2 which was down by €1.17 billion from December 31, 2010, to €24.95 billion. Cash flow from operating activities was negatively affected by a lower cash inflow of €347 million associated with transferring trade receivables due beyond end of 2010 to factoring institutions amounting to €1,279 million in the fourth quarter 2010, while the current quarter benefitted from transferring €932 million of trade receivables due beyond March 31, 2011 to those institutions.
Financial Ratios
Return on Average Capital Employed (ROACE)3 calculated on an adjusted basis for the twelve-month period ending on March 31, 2011, was 11.4%. The ratio of net borrowings to shareholders' equity including non-controlling interest – leverage3 – decreased to 0.44 at March 31, 2011, from 0.47 as of December 31, 2010. This change was due to profit for the period and reduced net borrowings, notwithstanding the appreciation of the euro against the US dollar as recorded at March 31, 2011, vs. December 31, 2010 (up 6.4%) which reduced shareholders' equity by €1.9 billion.
Exploration & Production
Eni reported liquids and gas production of 1,684 kboe/d for the first quarter of 2011, down by 8.6% from the first quarter of 2010 (down 158 kboe/d). The magnitude of this reduction was the result of the shutdown of activities at several of Eni's producing sites in Libya and the closure of the GreenStream pipeline transporting gas from Libya to Italy which occurred on February 22, 2011, as a result of ongoing political instability and conflict in the Country. From April 2011, Eni production in Libya has been flowing at a level of 50-55 kboe/d and with the full supply supporting local production of electricity. Performance in the quarter was negatively impacted by lower entitlements in the Company's PSAs due to higher oil prices with an overall effect of 32 kboe/d compared to the year-earlier quarter, in addition to the above mentioned Libyan shutdown that caused a production loss of 129 kboe/d compared to the first quarter of 2010. These negatives were partly offset by continuing production ramp-up in Egypt, Iraq and Italy.
Gas & Power
Eni's worldwide natural gas sales recovered from the first quarter of 2010 (up 6% to 32.33 bcm). Sales on the Italian market increased by 10.2% due to client additions in the industrial, power generation and wholesale segments as well as higher volumes supplied. In Europe, Eni sales showed growth in all of the Company's major markets (up by 14.2% on average), excluding Belgium as a result of strong competitive pressures. Turkey, France, the Iberian Peninsula and Germany/Austria were the markets posting the largest increases. Sales to shippers which import gas to Italy decreased by 42.5%. This was due to lower availability of Libyan production and lower volumes purchased.
Portfolio developments
Ukraine
In April 2011, Eni reached an agreement with Cadogan Petroleum plc for the acquisition of an interest in two exploration and development licenses located in the Dniepr-Donetz basin, in Ukraine. This agreement is part of the development of cooperation initiatives in hydrocarbon exploration and production in the Country also reaffirmed in a Memorandum of Understanding with the Ukrainian Ministry of Ecology and Natural Resources.
Alaska
In February 2011, production start-up was achieved at the Nikaitchuq operated field (Eni 100%), located in the North Slope basins offshore Alaska, with resources of 220 million barrels. Production is expected to peak at 28 kbbl/d.
China
In January 2011, Eni signed a Memorandum of Understanding with CNPC/PetroChina to promote common opportunities to jointly expand operations in conventional and unconventional hydrocarbons in China and outside China. The parties will also cooperate in the field of advanced technology, with a special focus on the exploitation of unconventional oil and gas resources.
Angola
In January 2011, Eni was awarded rights to explore and the operatorship of offshore Block 35 in Angola, with a 30% interest. The agreement foresees drilling 2 wells and 3D seismic surveys to be carried out in the first 5 years of exploration. This deal is subject to the approval of the relevant authorities.
Exploration activities
In the first quarter of 2011, significant exploratory success was achieved in:
- Ghana with the appraisal well Sankofa-2 in the offshore license Cape Three Points (Eni 47.22% , operator);
- the Norwegian sector of the Barents Sea with the Skrugard oil and gas discovery in the PL532 license (Eni 30% );
- Venezuela with the Perla 4 appraisal well of the homonymous discovery in the Cardon IV offshore block (Eni 50%, operator);
- United Kingdom with the appraisal of the Culzean discovery (Eni 16.95%).
Outlook
Management expects that the global economic recovery will progressively strengthen across the year 2011. Nonetheless, the 2011 outlook is characterized by a certain degree of uncertainty and volatility also in light of ongoing political instability and conflict in Libya. Eni forecasts an upward trend for Brent crude oil prices supported by healthier global oil demand. For short-term economic and financial projections, Eni assumes an average Brent price of 101 $/bbl for the full year 2011. Management expects that the European gas market will remain weak as sluggish demand growth is insufficient to absorb current oversupplies. Refining margins are expected to remain unprofitable due to weak underlying fundamentals and high feedstock costs. Against this backdrop, management expectations about the main trends in the Company's businesses for 2011 and beyond are disclosed below.
- Production of liquids and natural gas is forecast to decline from 2010 (1.815 million boe/d was the actual level in 2010 at 80 $/bbl) at the Company's pricing scenario of 101 dollar a Brent barrel for the full year. The decline is expected as a result of volumes losses in Libya following the shutdown of almost all of the Company's production facilities. Better production performance at the Company's assets elsewhere in the world will help offset the impact associated with rising crude oil prices on PSAs entitlements. The magnitude of the Libyan production loss will depend on how long the situation lasts, which management cannot predict for the time being. From April 2011, Eni's production in Libya has been flowing at the rate of 50-55 kboe/d, down from the expected level of 280 kboe/d for the year. Management estimates that each day in which production remains at current levels will cause a reduction of approximately 600 boe/d in the full-year average daily production. Management has been implementing its plans to target production growth in the Company' assets by ramping up fields that were started in 2010, growing the production plateau at the giant Zubair oilfield in Iraq, starting up new fields in Australia, Algeria and the US, as well as executing production optimizations in particular in Nigeria, Egypt, Angola and the United Kingdom;
- Worldwide gas sales are expected to grow from 2010 (in 2010 actual sales amounted to 97.06 bcm), in spite of sales losses to certain Italian importers due to lower availability of gas from Libya. Management plans to drive volume growth in Italy leveraging clients additions in the power generation, industrial and wholesale segments, as well as organic growth in key European markets. Considering mounting competitive pressure in the gas market, the achievement of the planned volumes target will be underpinned by strengthening the Company's leadership on the European market; marketing actions intended to strengthen the customer base in the domestic market and renegotiating the Company's long-term gas purchase contracts. The cash flow impact associated with lower sales to Italian shippers will be offset by expected lower cash outflows associated with the Company's take-or-pay gas purchase contracts as the Company is planning to meet lower availability of Libyan gas with gas from other sources in its portfolio;
- Regulated businesses in Italy will benefit from the pre-set regulatory return on new capital expenditures and continuing efficiency actions;
- Refining throughputs on Eni's account are expected to slightly decline compared to 2010 (actual throughputs in 2010 were 34.8 mmtonnes). The decline is mainly expected at the Venice refinery due to difficulties in supplying Libyan crude oil. Higher volumes are expected to be processed on more competitive refineries and the optimization of refinery cycles, as well as efficiency actions, are expected to be implemented in response to a volatile trading environment;
- Retail sales of refined products in Italy and the rest of Europe are expected to be substantially in line with 2010 (11.73 mmtonnes in 2010) against the backdrop of weaker demand. Management plans to improve sales leveraging selective pricing and marketing initiatives, starting new service stations, developing the "non-oil" business and service upgrade;
- The Engineering & Construction business confirms solid results due to increasing turnover and a robust order backlog.
In 2011, management plans to make capital expenditures broadly in line with 2010 (€13.87 billion was invested in 2010) and will mainly be directed to developing giant fields and starting production at new important fields in the Exploration & Production Division, refinery upgrading related in particular to the realization of the EST project, completing the program of enhancing Saipem's fleet of vessels and rigs, and upgrading the natural gas transport infrastructure. Assuming a Brent price of $101/barrel and the planned divestment of certain assets, management forecasts that the ratio of net borrowings to total equity (leverage) at year-end will be lower than in 2010.
Butlers Well Delivers for Beach Energy
Butlers Well Delivers for Beach Energy
Wednesday, April 27, 2011
Cooper Energy Ltd.
Cooper Energy announced that Butlers-3 was drilled to a total depth of 1,365 meters and wireline logs have confirmed that it has intersected a 3 meter oil column in excellent quality Namur sandstone reservoir. This result confirms the northern extent of the field, as mapped. Butlers-3 is the fourth well in the 2011 PEL92 area drilling campaign and is the second development well of the Butlers oil field.
The well has been cased and suspended, and the rig is preparing to move. The well will be tied-back to the Butlers production facilities at a later date and will provide an additional drainage point for the Namur oil reservoir to the northwest of the Butlers-1 discovery well.
The impact on production rates and reserves will be assessed once the full results of the current Butlers appraisal/development drilling program have been evaluated and production rates from the new development wells have been established.
The next well in the eleven well drilling program is Parham-1, an exploration well located about 1 km to the southwest of the Butlers-1 discovery well. The details pertaining to Parham-1 will be announced when the well spuds.
Joint Venture Participants are Cooper Energy (25%) and Beach Energy (75% and Operator).
Wednesday, April 27, 2011
Cooper Energy Ltd.
Cooper Energy announced that Butlers-3 was drilled to a total depth of 1,365 meters and wireline logs have confirmed that it has intersected a 3 meter oil column in excellent quality Namur sandstone reservoir. This result confirms the northern extent of the field, as mapped. Butlers-3 is the fourth well in the 2011 PEL92 area drilling campaign and is the second development well of the Butlers oil field.
The well has been cased and suspended, and the rig is preparing to move. The well will be tied-back to the Butlers production facilities at a later date and will provide an additional drainage point for the Namur oil reservoir to the northwest of the Butlers-1 discovery well.
The impact on production rates and reserves will be assessed once the full results of the current Butlers appraisal/development drilling program have been evaluated and production rates from the new development wells have been established.
The next well in the eleven well drilling program is Parham-1, an exploration well located about 1 km to the southwest of the Butlers-1 discovery well. The details pertaining to Parham-1 will be announced when the well spuds.
Joint Venture Participants are Cooper Energy (25%) and Beach Energy (75% and Operator).
Range Wraps Up Ops at Tx. Cotton Valley Well
Range Wraps Up Ops at Tx. Cotton Valley Well
Wednesday, April 27, 2011
Range Resources Ltd.
Range announced that it has reached total depth in its Ross 3H exploratory well, the Company's first horizontal drilling venture. Located in Red River County, Texas, the well reached a total depth of 8,900 ft (2,715m), with a horizontal section of approximately 3,400 ft (1,040m).
Based upon open-hole logs, samples, and consistent oil shows during drilling operations from both the vertical pilot hole and horizontal leg, Range and its partners have successfully run and cemented in place a production liner to target depth, with completion operations having begun. Once fracking has been completed, Range will be able to accurately report on flow rates and update reserves.
Added Pete Landau, Range Executive Director, "The Ross 3H represents yet another milestone for the Company as we and our joint venture partners continue to apply the most cost-effective oil field technology available to our exploration and development programs. Consistent with our recently announced acquisitions in Trinidad, the East Texas Cotton Valley play represents a low-cost opportunity to build our portfolio of crude oil reserves in a period of strong commodity prices."
Wednesday, April 27, 2011
Range Resources Ltd.
Range announced that it has reached total depth in its Ross 3H exploratory well, the Company's first horizontal drilling venture. Located in Red River County, Texas, the well reached a total depth of 8,900 ft (2,715m), with a horizontal section of approximately 3,400 ft (1,040m).
Based upon open-hole logs, samples, and consistent oil shows during drilling operations from both the vertical pilot hole and horizontal leg, Range and its partners have successfully run and cemented in place a production liner to target depth, with completion operations having begun. Once fracking has been completed, Range will be able to accurately report on flow rates and update reserves.
Added Pete Landau, Range Executive Director, "The Ross 3H represents yet another milestone for the Company as we and our joint venture partners continue to apply the most cost-effective oil field technology available to our exploration and development programs. Consistent with our recently announced acquisitions in Trinidad, the East Texas Cotton Valley play represents a low-cost opportunity to build our portfolio of crude oil reserves in a period of strong commodity prices."
Egdon Updates Ops at Kirkleatham, Keddington
Egdon Updates Ops at Kirkleatham, Keddington
Wednesday, April 27, 2011
Egdon Resources plc
Egdon Resources provided an update on operations at two key UK projects.
Egdon reported that first gas flows were achieved on April 19, 2011 at the Kirkleatham gas development in PEDL068 where the Company holds a 40% operated interest. The joint venture partners are Sterling Resources (UK) Ltd (47%), Yorkshire Exploration Limited (8%) and Montrose Industries Limited (5%).
During the early stages of production from the field, gas flow rates and their duration will be restricted as system performance and gas quality is monitored and training undertaken of the site operatives. It is expected that flow rates will be gradually ramped up to the maximum of around 5 million cubic feet of gas per day and 24 hour operations will commence in the coming weeks.
The gas from Kirkleatham is sold to Sembcorp Utilities (UK) Limited, the operator of the Wilton site for use in their GT2 gas turbine power plant.
Egdon also reported that drilling operations have now been completed at Keddington-4 in Lincolnshire license PEDL005(Remainder) where Egdon holds a 75% operated interest. The joint venture partners are Terrain Energy Limited (15%) and Alba Resources Limited (10%), a wholly owned subsidiary of Nautical Petroleum.
The Keddington-4 well was drilled as a re-entry and horizontal sidetrack from the Keddington-1Z "donor" well, which was drilled by Candecca Resources in 1998. The British Drilling and Freezing Limited BDF28 drilling unit mobilized to site on April 1, and operations began on 4 April. The plugging-back of the existing well was completed and the drilling of the sidetrack commenced at 0700 hours on 9 April from a kick-off depth of 2080 meters. The well reached its total depth of 2468 meters at 1800 hours on April 22. A total of 120 meters of the primary reservoir Unit 1 sandstone with high gas readings indicative of the presence of oil was penetrated some 6 meters shallower than in the Keddington-1Z well. An additional 65 meters of Unit 2 was also drilled. Due to borehole stability concerns, it was decided not to deepen the well as planned to penetrate the "Namurian" sandstones, which had gas indications in Keddington-3. Keddington-4 has now been completed for pumped production with a slotted liner over the entire horizontal section of the well. Once the drilling rig has demobilized from site later this week all surface facilities will be reinstated and the well put into production. Production from the adjacent Keddington-3z well, which has been suspended for safety reasons during the drilling operations, will resume once Keddington-4 has been tested.
Commenting on these developments Egdon's Managing Director Mark Abbott said, "Having achieved the milestone of first gas at Kirkleatham, we now look forward to achieving optimum production rates in the coming weeks. The presence in Keddington-4 of a significant section of Unit 1 reservoir up-dip of the Keddington-1Z well is encouraging and we look forward to the results of production from this well during early May."
Wednesday, April 27, 2011
Egdon Resources plc
Egdon Resources provided an update on operations at two key UK projects.
Egdon reported that first gas flows were achieved on April 19, 2011 at the Kirkleatham gas development in PEDL068 where the Company holds a 40% operated interest. The joint venture partners are Sterling Resources (UK) Ltd (47%), Yorkshire Exploration Limited (8%) and Montrose Industries Limited (5%).
During the early stages of production from the field, gas flow rates and their duration will be restricted as system performance and gas quality is monitored and training undertaken of the site operatives. It is expected that flow rates will be gradually ramped up to the maximum of around 5 million cubic feet of gas per day and 24 hour operations will commence in the coming weeks.
The gas from Kirkleatham is sold to Sembcorp Utilities (UK) Limited, the operator of the Wilton site for use in their GT2 gas turbine power plant.
Egdon also reported that drilling operations have now been completed at Keddington-4 in Lincolnshire license PEDL005(Remainder) where Egdon holds a 75% operated interest. The joint venture partners are Terrain Energy Limited (15%) and Alba Resources Limited (10%), a wholly owned subsidiary of Nautical Petroleum.
The Keddington-4 well was drilled as a re-entry and horizontal sidetrack from the Keddington-1Z "donor" well, which was drilled by Candecca Resources in 1998. The British Drilling and Freezing Limited BDF28 drilling unit mobilized to site on April 1, and operations began on 4 April. The plugging-back of the existing well was completed and the drilling of the sidetrack commenced at 0700 hours on 9 April from a kick-off depth of 2080 meters. The well reached its total depth of 2468 meters at 1800 hours on April 22. A total of 120 meters of the primary reservoir Unit 1 sandstone with high gas readings indicative of the presence of oil was penetrated some 6 meters shallower than in the Keddington-1Z well. An additional 65 meters of Unit 2 was also drilled. Due to borehole stability concerns, it was decided not to deepen the well as planned to penetrate the "Namurian" sandstones, which had gas indications in Keddington-3. Keddington-4 has now been completed for pumped production with a slotted liner over the entire horizontal section of the well. Once the drilling rig has demobilized from site later this week all surface facilities will be reinstated and the well put into production. Production from the adjacent Keddington-3z well, which has been suspended for safety reasons during the drilling operations, will resume once Keddington-4 has been tested.
Commenting on these developments Egdon's Managing Director Mark Abbott said, "Having achieved the milestone of first gas at Kirkleatham, we now look forward to achieving optimum production rates in the coming weeks. The presence in Keddington-4 of a significant section of Unit 1 reservoir up-dip of the Keddington-1Z well is encouraging and we look forward to the results of production from this well during early May."
ConocoPhillips Reports Weak Q1, Misses Estimates
ConocoPhillips Reports Weak Q1, Misses Estimates
Apr 27, 2011
ConocoPhillips (NYSE:COP) reported Q1 EPS of $1.82 today, missing the consensus estimate for $1.97 per share. Revenue for the quarter was up 27% year-over-year to $58.25 billion, missing the consensus estimate for $61.72 billion.
Jim Mulva, chairman and chief executive officer said, "While our financial results were much improved from a year ago, E&P production and R&M capacity utilization did not meet our targets. The quarter was negatively impacted by approximately $200 million from unplanned downtime and from variable compensation expense related to prior-year performance."
Apr 27, 2011
ConocoPhillips (NYSE:COP) reported Q1 EPS of $1.82 today, missing the consensus estimate for $1.97 per share. Revenue for the quarter was up 27% year-over-year to $58.25 billion, missing the consensus estimate for $61.72 billion.
Jim Mulva, chairman and chief executive officer said, "While our financial results were much improved from a year ago, E&P production and R&M capacity utilization did not meet our targets. The quarter was negatively impacted by approximately $200 million from unplanned downtime and from variable compensation expense related to prior-year performance."
EPA to Shed Light on Fracturing Rules
EPA to Shed Light on Fracturing Rules
Wednesday, April 27, 2011
Houston Chronicle
by Jennifer A. Dlouhy
Federal regulators will soon clarify the rules for natural gas companies that inject diesel fuel into the ground as part of their hydraulic fracturing operations, the head of the Environmental Protection Agency said Tuesday.
The guidance, which EPA Administrator Lisa Jackson says is coming "very shortly," is meant to clear up rules for natural gas producers.
A congressional investigation concluded earlier this year that companies have not secured EPA permits before injecting more than 32 million gallons of diesel fuel and other fluids into the ground in fracturing operations between 2005 and 2009.
States historically have regulated hydraulic fracturing. The technique involves injecting mixtures of water, sand and chemicals including diesel fuel deep underground at high pressures to break up dense shale rock and release gas locked in it. Although Congress exempted most hydraulic fracturing activities from EPA's jurisdiction as part of a 2005 rewrite of the Safe Drinking Water Act, that exception does not apply to diesel -- even though the government only began to regulate it last year.
Jackson insisted that the EPA has authority to regulate diesel fuel in fracturing fluids.
"Our belief is that this is not exempt," she said. "That exception specifically says that diesel is not exempt. So if you are injecting diesel, that is a concern."
Environmental worries
The move comes amid mounting environmental fears about the hydraulic fracturing process, which is being combined with horizontal drilling techniques to extract previously unrecoverable natural gas from shale formations across North America.
Conservationists are concerned about the high water demands of fracturing. Environmentalists warn that natural gas can escape out of poorly designed wells and that chemicals in fracturing fluids can taint nearby water sources.
A blowout at a Chesapeake Energy natural gas well in Pennsylvania last week renewed those fears. The incident prompted the company to temporarily stop hydraulic fracturing in the region.
Easing public concerns about the process is key to natural gas development, said Gene Sperling, the chairman of the White House's National Economic Council.
Speaking at an Energy Information Administration conference, Sperling said the energy industry should embrace "common-sense regulation that builds the public trust" that fracturing does not put at risk clean or safe drinking water.
Industry representatives broadly have argued against federal regulation of hydraulic fracturing and insist state officials are better positioned to oversee the work. Although some oil field services companies and natural gas producers have begun voluntarily providing details about the ingredients of their fracturing fluids, there is no federal mandate for that disclosure.
Backing from Shell
Marvin Odum, the president of Shell Oil Co., said the company "supports regulations that require companies to disclose the chemicals they use in the process ... and adhere to the highest safety standards."
"Responsible operators should have no problem complying," Odum added.
Odum said that Shell is working toward a goal of recycling 100 percent of the water it uses in its hydraulic fracturing operations.
He insisted that hydraulic fracturing techniques can be used to extract natural gas safely.
"Make no mistake," he said. "It can be done without harming the environment. Anything less is unacceptable."
Wednesday, April 27, 2011
Houston Chronicle
by Jennifer A. Dlouhy
Federal regulators will soon clarify the rules for natural gas companies that inject diesel fuel into the ground as part of their hydraulic fracturing operations, the head of the Environmental Protection Agency said Tuesday.
The guidance, which EPA Administrator Lisa Jackson says is coming "very shortly," is meant to clear up rules for natural gas producers.
A congressional investigation concluded earlier this year that companies have not secured EPA permits before injecting more than 32 million gallons of diesel fuel and other fluids into the ground in fracturing operations between 2005 and 2009.
States historically have regulated hydraulic fracturing. The technique involves injecting mixtures of water, sand and chemicals including diesel fuel deep underground at high pressures to break up dense shale rock and release gas locked in it. Although Congress exempted most hydraulic fracturing activities from EPA's jurisdiction as part of a 2005 rewrite of the Safe Drinking Water Act, that exception does not apply to diesel -- even though the government only began to regulate it last year.
Jackson insisted that the EPA has authority to regulate diesel fuel in fracturing fluids.
"Our belief is that this is not exempt," she said. "That exception specifically says that diesel is not exempt. So if you are injecting diesel, that is a concern."
Environmental worries
The move comes amid mounting environmental fears about the hydraulic fracturing process, which is being combined with horizontal drilling techniques to extract previously unrecoverable natural gas from shale formations across North America.
Conservationists are concerned about the high water demands of fracturing. Environmentalists warn that natural gas can escape out of poorly designed wells and that chemicals in fracturing fluids can taint nearby water sources.
A blowout at a Chesapeake Energy natural gas well in Pennsylvania last week renewed those fears. The incident prompted the company to temporarily stop hydraulic fracturing in the region.
Easing public concerns about the process is key to natural gas development, said Gene Sperling, the chairman of the White House's National Economic Council.
Speaking at an Energy Information Administration conference, Sperling said the energy industry should embrace "common-sense regulation that builds the public trust" that fracturing does not put at risk clean or safe drinking water.
Industry representatives broadly have argued against federal regulation of hydraulic fracturing and insist state officials are better positioned to oversee the work. Although some oil field services companies and natural gas producers have begun voluntarily providing details about the ingredients of their fracturing fluids, there is no federal mandate for that disclosure.
Backing from Shell
Marvin Odum, the president of Shell Oil Co., said the company "supports regulations that require companies to disclose the chemicals they use in the process ... and adhere to the highest safety standards."
"Responsible operators should have no problem complying," Odum added.
Odum said that Shell is working toward a goal of recycling 100 percent of the water it uses in its hydraulic fracturing operations.
He insisted that hydraulic fracturing techniques can be used to extract natural gas safely.
"Make no mistake," he said. "It can be done without harming the environment. Anything less is unacceptable."
Hess Reports Strong Q1, Beats EPS By $0.87, Revs Up 21% YoY
Hess Reports Strong Q1, Beats EPS By $0.87, Revs Up 21% YoY
Apr 27, 2011
Hess Corporation (NYSE:HES) reported Q1 EPS of $2.74 today, beating the consensus estimate for $1.87 per share. Revenues for the quarter were up 21% year-over-year to $10.22 billion, beating the consensus estimate for $9.45 billion.
Hess has a potential upside of 19.9% based on a current price of $80.67 and an average consensus analyst price target of $96.7.
Apr 27, 2011
Hess Corporation (NYSE:HES) reported Q1 EPS of $2.74 today, beating the consensus estimate for $1.87 per share. Revenues for the quarter were up 21% year-over-year to $10.22 billion, beating the consensus estimate for $9.45 billion.
Hess has a potential upside of 19.9% based on a current price of $80.67 and an average consensus analyst price target of $96.7.
ConocoPhillips 1Q Earnings Increase to $3B
Wednesday, April 27, 2011
ConocoPhillips
ConocoPhillips reported first-quarter earnings of $3.0 billion, compared with first-quarter 2010 earnings of $2.1 billion. Excluding gains from asset dispositions, first-quarter 2011 adjusted earnings were $2.6 billion, or $1.82 per share.
"While our financial results were much improved from a year ago, E&P production and R&M capacity utilization did not meet our targets," said Jim Mulva, chairman and chief executive officer. "The quarter was negatively impacted by approximately $200 million from unplanned downtime and from variable compensation expense related to prior-year performance."
Exploration and Production's (E&P) first-quarter 2011 adjusted earnings were higher, compared with the same period in 2010, primarily due to higher prices, partially offset by lower volumes and higher taxes.
Production for the first quarter of 2011 was 1.7 million barrels of oil equivalent (BOE) per day, a decrease of about 125,000 BOE per day versus the same period in 2010. Field decline, primarily in the North Sea, Lower 48, China and Alaska, decreased production by approximately 190,000 BOE per day, which was largely offset by about 180,000 BOE per day of new production and improved well performance. The new production was primarily from the company's Qatargas 3 project, Bohai Bay's development optimization program and the liquids-rich shale plays in the Lower 48. Unplanned E&P downtime, primarily from the temporary shutdown of the Trans Alaska Pipeline System in January, a supply vessel collision with the company's Britannia platform and civil unrest in Libya, adversely impacted production by about 65,000 BOE per day. Asset dispositions in 2010 and the first quarter of 2011 also negatively impacted year-over-year production by approximately 50,000 BOE per day.
The unplanned E&P downtime of approximately 65,000 BOE per day reduced earnings for the quarter by about $100 million.
"Consistent with our strategy, we continue to build our Exploration portfolio of high-impact drillable prospects and expand our positions in world-class shale opportunities," added Mulva.
During the quarter, significant exploration activities included the acquisition of two Norwegian blocks in the Barents Sea, the spudding of the Peking Duck wildcat well in the North Sea and the acquisition of 33,000 net acres in the emerging Wolfcamp shale play in North America. In the Lower 48 shale plays of Eagle Ford, North Barnett and Bakken, exploration and development continues with 20 operated rigs currently drilling. Results from these programs continue to meet or exceed expectations.
"While we had significant improvement in earnings from our downstream business, we did not capture all the market opportunities available to us due to downtime at several refineries," said Mulva.
Refining & Marketing's (R&M) first-quarter 2011 earnings were higher than the corresponding period of 2010, primarily due to improved global refining margins. Improved market crack spreads were partially offset by weaker crude differentials and lower secondary product margins. The U.S. refining crude oil capacity utilization rate was 87 percent and the international rate was 96 percent in the quarter.
"For the quarter, earnings would have been about $50 million higher if we had operated our U.S. downstream at planned levels," said Mulva.
During the quarter, R&M's working capital increased $2.0 billion, adversely impacting cash from operations. The increase was primarily related to management of the company's discretionary inventory position. An earnings benefit of about $50 million was recognized this quarter related to trading around these inventory positions. Later this year, ConocoPhillips expects to recognize an additional $50 million of earnings from inventory positions taken in the first quarter of 2011.
The Chemicals segment posted record earnings of $193 million in the first quarter. The strong earnings were due to higher margins, mostly in olefins and polyolefins, as well as lower costs. The Midstream segment's results for the first quarter of 2011 were in line with the first quarter of 2010.
Corporate expenses for the quarter of $304 million after-tax were improved slightly compared with the first quarter of 2010. Although interest expense decreased due to reduced debt levels, higher benefit-related expenses and taxes nearly offset the improvement.
Controllable costs were flat for the quarter compared with a year ago. However, variable compensation expense related to prior-year performance negatively impacted earnings for the quarter by approximately $50 million after-tax.
The company completed the sale of its OAO LUKOIL shares in the first quarter. In addition, ConocoPhillips repurchased 21 million of its own shares for $1.6 billion and increased the quarterly dividend rate by 20 percent to 66 cents per share.
Also during the quarter, the company announced plans to sell an additional $5 billion to $10 billion of noncore assets over the next two years. Proceeds from the increased asset sales are expected to be used primarily to fund the company's recently announced $10 billion share repurchase program and for capital investment opportunities.
"We remain focused on delivering value through improving returns, increasing shareholder distributions and growing production and reserves per share," said Mulva.
First-Quarter Financial Highlights
For the first quarter of 2011, ConocoPhillips reported earnings of $3.0 billion, or $2.09 per share, compared with earnings of $2.1 billion, or $1.40 per share, for the same period in 2010. First-quarter 2011 earnings included $394 million in gains from North American asset sales and LUKOIL share dispositions.
First-quarter 2011 adjusted earnings were $2.6 billion, or $1.82 per share, compared with adjusted earnings of $2.2 billion, or $1.47 per share, for the same period in 2010. Adjusted earnings for the quarter increased versus the prior year, primarily due to the impact of higher commodity prices and global refining margins. This increase was partially offset by lower production volumes, the absence of equity earnings from LUKOIL and higher taxes.
During the first quarter of 2011, ConocoPhillips generated $4.0 billion in cash from operations excluding working capital increases of $2.1 billion, resulting in cash from operations of $1.9 billion. In addition, the company received $1.8 billion in proceeds from asset dispositions. These proceeds plus available cash were used to fund a $3.1 billion capital program, repurchase $1.6 billion of ConocoPhillips common stock, pay $0.9 billion in dividends and reduce debt by $0.4 billion. At March 31, 2011, the company's cash and short-term investments were $8.4 billion, including cash and cash equivalents of $6.2 billion. The company ended the quarter with debt of $23.2 billion and a debt-to-capital ratio of 25 percent.
Nexen to Take Stake in Marathon's Polish Shale Play
Nexen to Take Stake in Marathon's Polish Shale Play
Wednesday, April 27, 2011
Marathon Oil Corp.
Marathon Oil has signed an agreement with a wholly owned subsidiary of Nexen under which Nexen will acquire a 40 percent working interest in 10 of Marathon's concessions in Poland's Paleozoic shale play.
"We are pleased Nexen will be joining Marathon to explore the resource potential of the substantial shale play acreage position we have established in Poland," said Annell R. Bay, Marathon's senior vice president of Worldwide Exploration. "This partnership provides not only financial risk mitigation but combines the extensive unconventional drilling and completion experience of Marathon and Nexen to fully evaluate the potential of these concessions."
Marathon currently holds an interest in 11 concessions in Poland, encompassing 2.3 million acres. The shales are Lower Paleozoic and located at depths of between 8,000 and 13,000 feet. Marathon plans to acquire 2D seismic during the first half of 2011, potentially followed by the drilling of one to two wells in the fourth quarter of 2011 and seven to eight wells during 2012. Marathon will remain operator of the 11 concessions.
Wednesday, April 27, 2011
Marathon Oil Corp.
Marathon Oil has signed an agreement with a wholly owned subsidiary of Nexen under which Nexen will acquire a 40 percent working interest in 10 of Marathon's concessions in Poland's Paleozoic shale play.
"We are pleased Nexen will be joining Marathon to explore the resource potential of the substantial shale play acreage position we have established in Poland," said Annell R. Bay, Marathon's senior vice president of Worldwide Exploration. "This partnership provides not only financial risk mitigation but combines the extensive unconventional drilling and completion experience of Marathon and Nexen to fully evaluate the potential of these concessions."
Marathon currently holds an interest in 11 concessions in Poland, encompassing 2.3 million acres. The shales are Lower Paleozoic and located at depths of between 8,000 and 13,000 feet. Marathon plans to acquire 2D seismic during the first half of 2011, potentially followed by the drilling of one to two wells in the fourth quarter of 2011 and seven to eight wells during 2012. Marathon will remain operator of the 11 concessions.
PTTEP Turns Focus to S. America and Africa
PTTEP Turns Focus to S. America and Africa
Wednesday, April 27, 2011
Knight Ridder/Tribune Business News
by Nalin Viboonchart, The Nation, Bangkok, Thailand
Thai oil giant PTT Exploration and Production (PTTEP) is exploring business opportunities in South America and Africa, with a view to turning the areas into the company's third business pillar, following Thailand plus Burma and Australia plus Canada.
The company's success in collaborating with Norway's national oil company Statoil in the Kai Kos Dehseh (KKD) oil sands project in Canada late last year is the inspiration behind further expansion of oil and gas exploration and production overseas, said president and CEO Anon Sirisaengtaksin.
"Since we acquired a 40-percent stake in KKD for US $2.28 billion, many big energy players in the world have been looking at PTTEP. They were surprised at our having joined a big project like KKD, as they didn't think a small player like us would do such a big deal. Now, PTTEP is attracting the interest of those giant firms and some want to do business with us," he said.
Anon said PTTEP's existing operations were now very strong and stable. Its first business pillar is oil and gas exploration and production in the Gulf of Thailand and Burma.
This pillar comprises many fields, such as Thailand's Sirikit, Bongkot and Arthit and Burma's Yadana and Yetagun, for which PTTEP has to maintain production and revenue, as well as seeking new blocks for oil and gas production.
The company is also thinking about how to utilize new technology to increase capacity from the existing blocks, he said.
PTTEP is making its presence felt in the second pillar, which covers Australia and Canada. Production at the Montara field off Australia is expected to resume by the end of this year, while Canada commenced production early in the year.
The company is looking to invest in other Canadian exploration and production projects with Statoil, with the two businesses having just inked an agreement to cooperate in this area.
"PTTEP has set a target to have a production capacity of 900,000 barrels of oil equivalent per day [boe/d] by 2020. The production sites we have right now will produce half of our target by that year. Therefore, we have to look for new projects to help us accomplish the goal," said Anon.
He added that once PTTEP achieved its target, it should step up to become one of the top five oil and gas exploration and production companies in Asia, behind enterprises in China, Malaysia, Japan and South Korea. It is currently in the top 10.
The company presently aims to produce and sell nearly 300,000boe/d of oil and gas, while the KKD project is expected to have a capacity of 150,000boe/d by 2020. KKD is scheduled to produce 8,000boe/d by the end of this year, rising to 80,000-100,000 within the next five years.
The company president said PTTEP had divided its projects into three groups: those that are already generating revenue; those that are going to generate revenue; and projects in which it has to invest for the exploration stage.
KKD and Montara are projects that are going to make money and in which the company has to invest more in order to drive output.
The new projects PTTEP is seeking may be greenfield sites or existing projects. The latter type of deal is more likely to be concluded, as the company needs projects that can generate revenue immediately, Anon said.
"We're looking for many deals in South American countries such as Brazil, and some in Africa. These are unfamiliar areas for PTTEP, so we have to consider everything carefully. We need partners if we want to grow in these regions, compete with existing players and learn new things in which we are not experts," he said.
Anon said he would not commit to concluding any new deals this year, saying that it depended on the opportunities presented.
PTTEP is currently exploring about 20 projects in the Middle East and Canada. The company will consider all the risks and opportunities carefully before making a decision on any of these, he added.
Wednesday, April 27, 2011
Knight Ridder/Tribune Business News
by Nalin Viboonchart, The Nation, Bangkok, Thailand
Thai oil giant PTT Exploration and Production (PTTEP) is exploring business opportunities in South America and Africa, with a view to turning the areas into the company's third business pillar, following Thailand plus Burma and Australia plus Canada.
The company's success in collaborating with Norway's national oil company Statoil in the Kai Kos Dehseh (KKD) oil sands project in Canada late last year is the inspiration behind further expansion of oil and gas exploration and production overseas, said president and CEO Anon Sirisaengtaksin.
"Since we acquired a 40-percent stake in KKD for US $2.28 billion, many big energy players in the world have been looking at PTTEP. They were surprised at our having joined a big project like KKD, as they didn't think a small player like us would do such a big deal. Now, PTTEP is attracting the interest of those giant firms and some want to do business with us," he said.
Anon said PTTEP's existing operations were now very strong and stable. Its first business pillar is oil and gas exploration and production in the Gulf of Thailand and Burma.
This pillar comprises many fields, such as Thailand's Sirikit, Bongkot and Arthit and Burma's Yadana and Yetagun, for which PTTEP has to maintain production and revenue, as well as seeking new blocks for oil and gas production.
The company is also thinking about how to utilize new technology to increase capacity from the existing blocks, he said.
PTTEP is making its presence felt in the second pillar, which covers Australia and Canada. Production at the Montara field off Australia is expected to resume by the end of this year, while Canada commenced production early in the year.
The company is looking to invest in other Canadian exploration and production projects with Statoil, with the two businesses having just inked an agreement to cooperate in this area.
"PTTEP has set a target to have a production capacity of 900,000 barrels of oil equivalent per day [boe/d] by 2020. The production sites we have right now will produce half of our target by that year. Therefore, we have to look for new projects to help us accomplish the goal," said Anon.
He added that once PTTEP achieved its target, it should step up to become one of the top five oil and gas exploration and production companies in Asia, behind enterprises in China, Malaysia, Japan and South Korea. It is currently in the top 10.
The company presently aims to produce and sell nearly 300,000boe/d of oil and gas, while the KKD project is expected to have a capacity of 150,000boe/d by 2020. KKD is scheduled to produce 8,000boe/d by the end of this year, rising to 80,000-100,000 within the next five years.
The company president said PTTEP had divided its projects into three groups: those that are already generating revenue; those that are going to generate revenue; and projects in which it has to invest for the exploration stage.
KKD and Montara are projects that are going to make money and in which the company has to invest more in order to drive output.
The new projects PTTEP is seeking may be greenfield sites or existing projects. The latter type of deal is more likely to be concluded, as the company needs projects that can generate revenue immediately, Anon said.
"We're looking for many deals in South American countries such as Brazil, and some in Africa. These are unfamiliar areas for PTTEP, so we have to consider everything carefully. We need partners if we want to grow in these regions, compete with existing players and learn new things in which we are not experts," he said.
Anon said he would not commit to concluding any new deals this year, saying that it depended on the opportunities presented.
PTTEP is currently exploring about 20 projects in the Middle East and Canada. The company will consider all the risks and opportunities carefully before making a decision on any of these, he added.
NPD to Carry Out Seismic Acquisition near Jan Mayen in Summer
NPD to Carry Out Seismic Acquisition near Jan Mayen in Summer
Wednesday, April 27, 2011
Norwegian Petroleum Directorate
The Norwegian Petroleum Directorate (NPD) will carry out acquisition of 2D seismic data in the waters around Jan Mayen this summer. The acquisition activity will start around June 10 and will last up to three months.
Last fall, the Norwegian government resolved that an impact assessment would be made of the maritime zones off Jan Mayen, with a view to future petroleum activity. The NPD's acquisition of seismic data is part of this impact assessment. Seismic data acquisition around Jan Mayen is also planned for next summer.
The data acquisition will take place using the vessel R.V. Harrier Explorer operated by PGS, and with the aid of PGS' Geostreamer technology. This is a new technology for seismic acquisition, characterized in part by the fact that the streamer, which in this case is eight kilometres long, is towed somewhat deeper in the water than is the case in conventional seismic acquisition. This means that the streamer can withstand higher waves, thus making the acquisition activity less dependent on weather and consequently more efficient.
Wednesday, April 27, 2011
Norwegian Petroleum Directorate
The Norwegian Petroleum Directorate (NPD) will carry out acquisition of 2D seismic data in the waters around Jan Mayen this summer. The acquisition activity will start around June 10 and will last up to three months.
Last fall, the Norwegian government resolved that an impact assessment would be made of the maritime zones off Jan Mayen, with a view to future petroleum activity. The NPD's acquisition of seismic data is part of this impact assessment. Seismic data acquisition around Jan Mayen is also planned for next summer.
The data acquisition will take place using the vessel R.V. Harrier Explorer operated by PGS, and with the aid of PGS' Geostreamer technology. This is a new technology for seismic acquisition, characterized in part by the fact that the streamer, which in this case is eight kilometres long, is towed somewhat deeper in the water than is the case in conventional seismic acquisition. This means that the streamer can withstand higher waves, thus making the acquisition activity less dependent on weather and consequently more efficient.
BP Reports Mixed Results, Misses EPS by $0.14, Beats Revs On Asset Sales
BP Reports Mixed Results, Misses EPS by $0.14, Beats Revs On Asset Sales
Apr 27, 2011
BP Plc (NYSE:BP) reported Q1 EPS of $1.75 early this morning, missing the consensus estimate for $1.89 per share. Revenue for the quarter rose 18.7% year-over-year to $88.31 billion, beating the consensus estimate for $71.40 billion.
BP has a potential upside of 22.1% based on a current price of $46.32 and an average consensus analyst price target of $56.55.
Apr 27, 2011
BP Plc (NYSE:BP) reported Q1 EPS of $1.75 early this morning, missing the consensus estimate for $1.89 per share. Revenue for the quarter rose 18.7% year-over-year to $88.31 billion, beating the consensus estimate for $71.40 billion.
BP has a potential upside of 22.1% based on a current price of $46.32 and an average consensus analyst price target of $56.55.
Salamander Resumes Drilling Ops at Thai Block
Wednesday, April 27, 2011
Salamander Energy plc
Salamander provided the following update on its current drilling operations in Thailand and Indonesia.
- Thailand -
Dao Ruang-3 well, Block L15/50
The Dao Ruang-3 appraisal well has spudded and will be drilled to a planned depth of 1,900 m TVDSS using the MB Century-26 rig. The well is forecast to take 45 days to drill on a dry hole basis. Salamander has a 50% interest in, and is operator of, Block L15/50.
Block B8/38
The Ocean Sovereign rig is back on location at the Bualuang Alpha wellhead platform and has resumed drilling operations. Salamander has a 100% interest in, and operatorship of, Block B8/38.
- Indonesia -
South Sebuku-2 appraisal well, Bengara-1 PSC
The HPS-1 land rig that will be used to drill the South Sebuku-2 well ("SS-2") has commenced mobilization to the well site. The SS-2 well is expected to spud in mid-May. SS-2 is appraising the South Sebuku gas discovery made in 2009 that is thought to contain gross mean contingent resources of 80 Bcf. Salamander has a 41% interest in the Bengara-1 PSC.
Baker Hughes Reports Solid Results, Beats EPS By $0.09
Baker Hughes Reports Solid Results, Beats EPS By $0.09
Apr 27, 2011
Baker Hughes (NYSE:BHI) reported EPS of $0.87 today, beating the consensus estimate for $0.78 per share. Revenue for the quarter was up 78% year-over-year to $4.53 billion, beating the consensus estimate for $4.28 billion. The year ago quarter does not included the results of BJ Services, which Baker Hughes acquired at the end of April 2010.
Chad C. Deaton, Baker Hughes chairman and chief executive officer, said, "International margins continued to improve in the first quarter, despite weather and geopolitical disruptions, as we made steady progress towards our goal of exiting 2011 with international operating margins in the mid-teens. The foundation of our improvement plan has been managing costs and improving efficiency, which have driven the increase in profitability we have seen to date. As we move towards the second half of 2011, activity growth becomes a more important driver of future improvement.
Apr 27, 2011
Baker Hughes (NYSE:BHI) reported EPS of $0.87 today, beating the consensus estimate for $0.78 per share. Revenue for the quarter was up 78% year-over-year to $4.53 billion, beating the consensus estimate for $4.28 billion. The year ago quarter does not included the results of BJ Services, which Baker Hughes acquired at the end of April 2010.
Chad C. Deaton, Baker Hughes chairman and chief executive officer, said, "International margins continued to improve in the first quarter, despite weather and geopolitical disruptions, as we made steady progress towards our goal of exiting 2011 with international operating margins in the mid-teens. The foundation of our improvement plan has been managing costs and improving efficiency, which have driven the increase in profitability we have seen to date. As we move towards the second half of 2011, activity growth becomes a more important driver of future improvement.
CNOOC Ramps Up Production in 1Q11
Wednesday, April 27, 2011
CNOOC Ltd.
CNOOC announced its results for the first quarter of 2011.
During the period, the Company achieved a total net production of 85.2 million barrels of oil equivalent (BOE), representing an increase of 26.6% year-on-year (YoY).
For the first quarter of 2011, the Company made five new discoveries and successfully drilled six appraisal wells offshore China. Within the period, Jinzhou 25-1 project offshore China commenced production successfully. Other major projects were progressing as planned.
In the first quarter of 2011, the Company purchased a 33.3% undivided interest in Chesapeake's Niobrara project. In addition, the Company and Tullow Oil entered into agreements for the acquisition of its one-third interests in each of Exploration Areas 1, 2 and 3A in Uganda. The transaction is expected to be completed in the first half of 2011.
Benefiting from increased oil and gas production and higher realized prices, the total unaudited revenue of the Company amounted to approximately RMB48.51 billion for the first quarter of 2011, representing a significant increase of 59.1% YoY. During the period, the Company's average realized oil price rose 32.7% YoY to US $99.98 per barrel. The Company's average realized gas price was US $4.81 per thousand cubic feet, up 8.6% YoY.
For the first quarter of 2011, the Company's capital expenditure reached approximately RMB6.40 billion, representing an increase of 10.3% YoY.
Mr. Yang Hua, Chief Executive Officer of the Company commented, "We have recorded excellent first quarter results driven by our efficient operation and higher realized oil prices. Meanwhile, we have made great progress in overseas development, which will provide a strong support for our reserve and production growth in the future."
BP Profit, Output Still Weighted Down by GOM Effects
Wednesday, April 27, 2011
Dow Jones Newswires
by Alexis Flynn
BP Wednesday posted a 5% fall in adjusted profit for the first quarter, as the damage wrought by the Deepwater Horizon disaster last year continued to weigh down its earnings and petroleum production outlook despite high oil prices.
The oil giant's results narrowly missed expectations for "clean replacement cost of supplies," which strips out gains or losses from inventories and other non-operating items. Profits under this keenly-watched benchmark totaled $5.37 billion for the quarter, compared with $5.65 billion for the first quarter of 2010. Analysts had expected $5.71 billion.
On the positive side, BP's latest charge of $400 million in Gulf of Mexico cleanup costs was more modest than some analysts feared. But BP said year-on-year oil and gas output dropped 11% in the first quarter, and signaled continued weakness in the second quarter, partly the result of increased maintenance procedures instituted after the 2010 U.S. drilling disaster.
While BP shares "look attractive," the "risk remains high for now" due to the uncertain status of BP's efforts in Russia, said Evolution Securities analyst Richard Griffith.
Analysts and investors will be looking for guidance on the company's ongoing Russian travails when Chief Financial Officer Byron Grote discusses the first-quarter results this afternoon at 1300 GMT.
BP's $16 billion share-swap and exploration deal with Russian state-owned giant Rosneft was blocked by an arbitration court last month following objections from BP's partners in its TNK-BP joint venture, and the U.K. firm could be forced to pay substantial compensation for it to go ahead. TNK-BP is also scheduled to report earnings Wednesday.
BP said it booked an additional $400 million charge related to the Gulf of Mexico spill, citing higher cleanup costs. But analyst Jason Kenney of ING said investors were relieved the latest charge was not higher.
Total oil and gas production was 3.58 million barrels a day, a decline of 11% on the year. This drop was partly the result of asset sales to pay for the Gulf of Mexico cleanup and production effects from due to the ongoing drilling shutdown in the U.S. Gulf. But BP said its output was also weighed down by higher maintenance in the North Sea and Angola, and by an interruption in the Trans-Alaska oil pipeline.BP said its second-quarter oil and gas output would also reflect these impacts.
"The main impact by far on production is the Gulf Of Mexico moratorium," a BP spokesman said. "There's also higher turnaround activity that we've been doing as we go through the increased spending on safety, particularly in the North Sea."
In the year since the disaster, BP has re-emerged as a fundamentally different company: it is smaller than before, having already shorn some $22 billion of assets; and with a different strategic focus, looking to fresh opportunities abroad to underpin its future growth.
However, a key part of this new strategy already appears to be floundering, with the challenge to the Russian deal.
BP didn't receive a dividend from TNK-BP for the period, the first time it hasn't received a payout from its Russian joint venture since the first quarter of 2009.
A BP spokesman said the decision to withhold the dividend was made by TNK-BP's board. However its partners in the joint venture, the Alpha-Access Renova group, in April threatened to withhold dividend payments for the year. BP is currently engaged in a dispute with AAR over its proposed alliance with Rosneft.
Net profit for the quarter was up 17% at $7.12 billion, compared with $6.08 billion a year ago.
Adjusted profit from BP's downstream business improved substantially year on year, nearly trebling to $2.07 billion, although the company cautioned that this was due to a favorable refining environment and a good performance by its trading division, and was unlikely to be repeated in the second quarter.
Baker Hughes Boosts 1Q Revenue by 78% in 2011
Wednesday, April 27, 2011
Baker Hughes Inc.
Baker Hughes announced net income attributable to Baker Hughes for the first quarter 2011 of $381 million or $0.87 per diluted share compared to $129 million or $0.41 per diluted share for the first quarter 2010 and $335 million or $0.77 per diluted share for the fourth quarter 2010.
Revenue for the first quarter 2011 was $4.53 billion, up 78% compared to $2.54 billion for the first quarter 2010 and up 2% compared to $4.42 billion for the fourth quarter 2010.
Results for the first quarter 2010 do not include the results of BJ Services, acquired at the end of April 2010.
Chad C. Deaton, Baker Hughes chairman and chief executive officer, said, "International margins continued to improve in the first quarter, despite weather and geopolitical disruptions, as we made steady progress towards our goal of exiting 2011 with international operating margins in the mid-teens. The foundation of our improvement plan has been managing costs and improving efficiency, which have driven the increase in profitability we have seen to date. As we move towards the second half of 2011, activity growth becomes a more important driver of future improvement.
"Geopolitical supply disruptions have focused attention on the limits of spare oil production capacity and have driven oil prices higher. High oil prices have spurred both international oil companies and national oil companies to accelerate their spending plans. Assuming oil prices do not increase to levels high enough to destroy demand, we expect oil-driven spending growth to be sustained for multiple years. Recent announcements by the Kingdom of Saudi Arabia and Abu Dhabi regarding increased rig activity in the Middle East, and steady increases in spending by Petrobras and other companies to develop fields offshore Brazil give us confidence that the volume growth supporting our margin plans will occur.
"The impact of higher oil prices has not been isolated to the international markets. In North America, on land, overall spending levels have increased as incremental spending on oil and liquids-rich natural gas plays has more than offset weakness in dry gas plays. The rig count in Canada is already dominated by oil-directed drilling and as of last week, for the first time since 1995, the US has more rigs drilling for oil than natural gas. Service intensity in the unconventional shales continues to increase as we drill longer horizontal wells requiring more frac stages and complex completions.
"Our pressure pumping is sold out in North America. We expect to accelerate the deployment of new hydraulic fracturing fleets in the second half of 2011; however, we do not expect that supply will match higher demand for fracturing this year. Although weather improved in March, utilization of equipment was high and we were unable to catch up on work we missed due to colder weather earlier in the quarter.
"Offshore markets will benefit from the resumption of deepwater activity in the Gulf of Mexico. We are encouraged by the recent permitting activity. However, we also recognize that the ten deepwater wells recently permitted to be drilled will only be a fraction of the activity levels we saw before the drilling moratorium was announced. This level of activity is insufficient to offset the 380,000 barrel per day or 23% drop in Gulf of Mexico oil production forecast by the EIA for 2012 compared to 2010. We have continued to invest in our training, safety, and competency assurance programs during the last year, and we are well positioned in the Gulf of Mexico, with our suite of advanced technology and services and experienced personnel, for a resumption of deepwater drilling activity.
"We expect demand for hydrocarbons to continue to increase as the global economy grows. Following the tragic earthquake and tsunami in Japan, we expect oil and LNG to experience higher incremental demand, supporting high oil prices. With shrinking spare capacity, we believe that exploration, development and production spending will increase, raising our confidence that the second half of 2011 will set the stage for a strong 2012."
Debt decreased by $44 million to $3.84 billion and cash and short-term investments decreased by $311 million to $1.40 billion compared to the fourth quarter 2010. Capital expenditures were $429 million, depreciation and amortization expense was $315 million, and dividend payments were $65 million in the first quarter 2011.
Statoil Secures New Light Well Intervention Vessel
Wednesday, April 27, 2011
Statoil
Statoil has awarded Island Offshore a framework agreement for a new light well intervention (LWI) vessel on the Norwegian continental shelf (NCS).
The third of its type in Statoil's portfolio the vessel will help reduce the costs of well interventions and enhanced oil recovery.
Statoil has awarded Island Offshore a framework agreement for light well intervention (LWI) services from their vessel Island Constructor. The duration of the framework agreement is three years, with an option to extend for another year.
A first call-off has been made for 168 days at an approximate value of NOK 320 million, all services included.
"Light well intervention vessels are an important tool in Statoil's toolbox to increase recovery from the fields on which we operate. We already have two similar vessels in our NCS portfolio operating year-around, and it is of high value to us, both in terms of efficiency and cost-reduction. Compared with conventional drilling units these LWI vessels reduce the cost of well interventions by 50 to 70 percent," said senior vice president of drilling and well in Statoil, Øystein Arvid Håland.
A growing number of discoveries on the NCS are developed via subsea installations. At the same time, production from mature fields is declining. Wells need workovers to maintain their output by removing deposits and halting water intrusion. But performing conventional jobs of this kind for subsea developments has been expensive. To address this, Statoil has put LWI vessels into service on a large scale.
An aging rig fleet and securing sufficient fit-for-purpose rig capacity at a competitive and sustainable rig rate level are the main challenges in the NCS rig market. Several initiatives have been launched to address these challenges.
Statoil has made a substantial commitment to research and technology development in order to improve its drilling and well operations. The LWI vessels can improve drilling efficiency and also have the potential to offset rig capacity.
"We are pleased to secure additional capacity for LWI services with this new framework agreement. It is also an example of how we want to contract fit-for purpose units to assure that we use the right tools at the right time. We hereby address the need for well intervention without compromising on drilling capacity," said chief procurement officer in Statoil, Jon Arnt Jacobsen.
Island Constructor is designed to operate in water depths of up to 600 meters. Plans call for the intervention unit to start its first operation for Statoil in November 2011.
Statoil has been pursuing riserless wirelining in subsea wells since 2003, and the technology has steadily improved.
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