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Oil and Gas Energy News Update

Thursday, July 21, 2011

Oil & Gas Post - All News Report for Thursday, July 21, 2011

Thursday, July 21, 2011

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Commodity Corner: Oil Climbs on Europe Debt Plan

- Commodity Corner: Oil Climbs on Europe Debt Plan

Thursday, July 21, 2011
Rigzone Staff
by Saaniya Bangee

On Thursday, oil futures settled at their best since early June, briefly peaking above $100 a barrel, as European leaders made progress on a plan to deal with its debt crisis.

Crude for the new front-month contract gained 73 cents Thursday, settling at $99.13 a barrel. Prices peaked as high as $100.16 a barrel early in the session.

Top European officials met in Brussels today to discuss releasing a rescue package for Greece. The leaders agreed to lower interest rates on European Financial Stability Facility loans while extending loan maturities. Details from the plan are expected to be released soon.

Meanwhile, Brent crude fluctuated between $116.95 and $119.19, before settling at $117.51 a barrel.

Earlier Thursday, the International Energy Agency (IEA) said it won't release additional emergency oil reserves. Last month, the IEA released 60 million barrels of oil to alleviate the disruption of supplies from Libya.

August natural gas fell 11 cents, ending the session at $4.395 per thousand cubic feet after government reports reported an increase in natural gas stockpiles. The U.S. Energy Administration said natural gas stockpiles grew by 60 billion cubic feet, totaling 2.671 trillion cubic feet for the week ended July 15.

The intraday range for natural gas was $4.37 to $4.59 per thousand cubic feet.

Gasoline futures decreased nearly 5 cents, settling at $3.10 a gallon. RBOB prices peaked at $3.16 and bottomed out at $3.09 Thursday.

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Chevron Sells Union Oil Cook Inlet Assets to Independent

- Chevron Sells Union Oil Cook Inlet Assets to Independent

Thursday, July 21, 2011
Knight Ridder/Tribune Business News
by Lisa Demer, Anchorage Daily News, Alaska

Chevron, the biggest oil and gas operator in Cook Inlet, is selling its assets there to an independent company, Hilcorp Alaska LLC.

Chevron and Hilcorp announced Tuesday that Chevron's subsidiary, Union Oil Co. of California, is selling contracts and interests in the Granite Point, Middle Ground Shoals, Trading Bay and MacArthur River fields.

The sale to Hilcorp also covers Chevron's interests in 10 offshore platforms, onshore gas fields, two gas storage facilities and two pipeline companies.

Terms were not disclosed. The companies said the deal should close by the end of the year, after it clears regulatory steps. Chevron plans to maintain its interests in Alaska's North Slope fields and the trans-Alaska oil pipeline.

The current net production for Chevron in Cook Inlet is 3,900 barrels of oil and 85 million cubic feet of natural gas per day, the company said.

A state senator from Kenai said the changeover should be good for Cook Inlet production. An environmentalist said he wanted to look into whether the new player has the will and the ability to invest in Cook Inlet's crumbling infrastructure.

Hilcorp is one of the biggest privately held oil and natural gas exploration and production companies in the United States, but it is dwarfed by big producers like Exxon Mobil, BP and Conoco Phillips.

"The standard pattern is the majors come in and pick the low-hanging fruit, and then the independents and juniors come in and mop up," said Bob Shavelson, executive director of the environmental advocacy group Cook Inletkeeper. "The biggest question is: Do they have the assets to deal with aging infrastructure in Cook Inlet?"

Some of the platforms date back to the post-statehood era of the late 1960s, and there are serious maintenance and corrosion issues, Shavelson said.

Sen. Tom Wagoner, R-Kenai, said he didn't think Hilcorp would be making the deal if it wasn't ready to invest.

"They have looked at the assets. They know what's here in Cook Inlet," said Wagoner, who got a call from Hilcorp about the sale Tuesday.

Hilcorp may be better situated for upgrading and expanding than Chevron, which has numerous projects around the world competing for its investment dollars, the senator said.

Hilcorp, headquartered in Houston, Texas, operates in nine areas including the Gulf Coast and the Rockies. It has more than 700 employees and is actively growing. It's been recognized for a progressive corporate culture. Last year, the Houston Chronicle ranked Hilcorp the No. 1 midsize workplace.

Wagoner said he hopes Cook Inlet workers hold onto their jobs.

"Those are the people I worry about," Wagoner said. "Those platforms -- those are a lot of jobs in Cook Inlet. Most of those people are my neighbors."

The Hilcorp acquisition comes after the federal government announced there's far more oil and natural gas in Cook Inlet than previously thought.

Copyright (c) 2011, Anchorage Daily News, Alaska

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Caspian Energy, Partners Spud Kazakh Well

- Caspian Energy, Partners Spud Kazakh Well

Thursday, July 21, 2011
Caspian Energy Inc.

Caspian Energy and partners announced spudding of an exploration well between the two producing wells in the East Zhagabulak field of Kazakhstan.

The new well is the first step in a plan aimed at expanding the area held by the partners under a 25-year production licence, said Caspian Chairman and CEO William Ramsay. Ramsay said the well is one of six drilling targets approved July 8 by the Central Development Committee (CDC) of the Republic of Kazakhstan.

Well EZ #308 spud on July 16 and will take about 100 days to complete to about 4,700 meters, Ramsay said. It is targeting the same carboniferous structure of the Bashkirian layer from which the two earlier successful wells are currently producing about 400 barrels of oil per day.

All wells will be drilled under the direction of Aral Petroleum Capital, the operating entity in Kazakhstan, which is owned 40 per cent by Calgary-based Caspian and 60 per cent by Asia Sixth Energy of China.

Second target

At the same time that EZ #308 began drilling, a second rig was en route to a location southwest of the East Zhagabulak field, an area officially designated Zhagabulak II and III and locally known as Sakramabas. This rig is expected to commence drilling the CDC-approved Sakramabas #316 well before the end of July.

"Our seismic analysis indicates the potential for a high-porosity carbonate reef at the Sakramabas #316 site," Ramsay said. Neighbors have drilled successful wells on surrounding leases and our 3-D seismic indicates our well is on the same trend line as those producing wells and we have more advantageous geological conditions for oil and gas accumulation than our neighbors."

"It's a new direction for us and a potential new resource base, arising out of the success of our neighbors and a consequent re-examination of our seismic data.

"This is a deep well, targeting the same well know carboniferous structure of the Bashkirian layer at some 4,500 meters," he said. "Again we expect drilling to take about 100 days to reach total depth, with testing to follow.

"By drilling two separate exploration plays, we're offsetting risk and enhancing potential," Ramsay said. "We have good confidence in both prospects, but they are exploration wells and they entail some level of risk."

Next steps

Next steps in Aral's drilling plans will be governed by results at Sakramabas, Ramsay said. Success there may indicate the presence of a number of separate new oil and gas formations, from East Zhagabulak to Sakramabas. In the event of a good result at Sakramabas #316, the partners will complete the EZ #308 well and move that rig to a location northeast of Sakramabas, where it will test for oil between Sakramabas and East Zhagabulak. An additional drilling rig would then be contracted in October to pursue targets within East Zhagabulak.

Obtaining new geological data could prove regional distribution of oil and gas productive layers through all central parts of the Zhagabulak field and will enable Aral to apply for a production license on a greatly expanded area, Ramsay said.

"We would cross over into the new year with three rigs working full time to prove up the potential of the Zhagabulak field," he said.

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CB&I Lands LNG Gig in Asia Pacific Region

- CB&I Lands LNG Gig in Asia Pacific Region

Thursday, July 21, 2011

CB&I has been awarded a contract, valued in excess of US $500 million, for the engineering, fabrication and construction of two 160,000 cubic meter LNG storage tanks, as well as additional work for a confidential LNG liquefaction project in the Asia Pacific region. CB&I's contract is expected to be completed in 2015.

"We are pleased to be selected for this significant project," said Philip K. Asherman, President and CEO. "This award builds on our decades of proven worldwide experience in the LNG industry and capitalizes on CB&I's extensive history in the Asia Pacific region."

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US Shale Gas Weakening Russian, Iranian Petro-Power -Study

- US Shale Gas Weakening Russian, Iranian Petro-Power -Study

Thursday, July 21, 2011
Rice University

Rising U.S. natural gas production from shale formations has already played a critical role in weakening Russia's ability to wield an "energy weapon" over its European customers, and this trend will accelerate in the coming decades, according to a new Baker Institute study, "Shale Gas and U.S. National Security." The study, funded by the U.S. Department of Energy, projects that Russia's natural gas market share in Western Europe will decline to as little as 13 percent by 2040, down from 27 percent in 2009.

"The geopolitical repercussions of expanding U.S. shale gas production are going to be enormous," said Amy Myers Jaffe, the Wallace S. Wilson Fellow for Energy Studies and one of the authors of the study. "By increasing alternative supplies to Europe in the form of liquefied natural gas (LNG) displaced from the U.S. market, the petro-power of Russia, Venezuela and Iran is faltering on the back of plentiful American natural gas supply."

The study concludes that timely development of U.S. shale gas resources will limit the need for the United States to import LNG for at least two to three decades, thereby reducing negative energy-related stress on the U.S. trade deficit and economy. By creating greater competition among gas suppliers in global markets, shale gas will also lower the cost to average Americans of reducing greenhouse gases as the country moves to lower carbon fuels.

The Baker Institute study dismisses the notion, recently debated in the U.S. media, that the shale gas revolution is a transitory occurrence. The study projects that U.S. shale production will more than quadruple by 2040 from 2010 levels of more than 10 billion cubic feet per day, reaching more than 50 percent of total U.S. natural gas production by the 2030s. The study incorporates independent scientific and economic literature on shale costs and resources, including assessments by organizations such as the U.S. Geological Survey, the Potential Gas Committee and scholarly peer-reviewed papers of the American Association of Petroleum Geologists,

"The idea that shale gas is a flash-in-the-pan is simply incorrect," said Kenneth Medlock III, the James A. Baker III and Susan G. Baker Fellow for Energy and Resources Economics and co-author of the study. "The geologic data on the shale resource is hard science and the innovations that have occurred in the field to make this resource accessible are nothing short of game-changing. In fact, we continue to learn as we progress in this play, and it is vital that we understand and embrace the opportune circumstances that shale resources provide. U.S. policymakers should not get diverted from the real opportunities that responsible development of our domestic shale resources present."

Other findings of the study include that U.S. shale gas will:
  • Reduce competition for LNG supplies from the Middle East and thereby moderate prices and spur greater use of natural gas, an outcome with significant implications for global environmental objectives.
  • Combat the long-term potential monopoly power of a "gas OPEC."
  • Reduce U.S. and Chinese dependence on Middle East natural gas supplies, lowering the incentives for geopolitical and commercial competition between the two largest consuming countries and providing both countries with new opportunities to diversify their energy supply.
  • Reduce Iran's ability to tap energy diplomacy as a means to strengthen its regional power or to buttress its nuclear aspirations.

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Toyota Working On New Safety Technology

- Toyota Working On New Safety Technology

Jul 21, 2011

Toyota (NYSE:TM) is working on a safety technology that takes control of the steering so the car can swerve away when it isn't able to stop before a collision.

The new technology system uses cameras along with enhanced radar called "millimeter-wave," which will be put in front of the vehicle to, to detect potential crashes such as pedestrians crossing on the road.

Toyota did not comment on when the feature might be offered on a commercial model, or in which markets, but officials implied it was geared up to be offered soon.

Toyota Motor has a potential upside of 8.8% based on a current price of $84.92 and an average consensus analyst price target of $92.4.

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Entek Drills Ahead at Niobrara Shale Proj.

- Entek Drills Ahead at Niobrara Shale Proj.

Thursday, July 21, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L- current operation, drilling ahead at 805 ft after setting surface casing and testing rig equipment. The proposed total depth of the well is 7,600 ft.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas holding 45%. Entek is the Operator. The GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

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American Standard Adds Rig for Permian Basin Drilling Program

- American Standard Adds Rig for Permian Basin Drilling Program

Thursday, July 21, 2011
American Standard Energy Corp.

American Standard announced the addition of a second rig for its 10 net well drilling program in Andrews County, Texas.

ASEN has secured the JW Rig #5 which will be moving onto the University 8 #1 location this week in Andrews County and is expected to spud Monday July 25th.

The Viking Rig #20 initiated the 10 net well drilling program and has spud the University 42 #2 well in Andrews County.

ASEN intends to drill the University Andrews 42 #2 well to the Devonian and then subsequent wells will be drilled to the Strawn and completed in the Strawn, Wolfcamp, Spraberry and Lower Clearfork formations. The Company will own 100% working interests in all 10 wells.

ASEN will have these dedicated two Rigs for the duration of this Phase 1 of our Permian Basin development program and expects to maintain them for future Phases. With the addition of the second rig, we project completion of this project to be cut by three months.

Scott Feldhacker, CEO of ASEN commented, "With over 4000 permits filed by various operators in the Permian Basin this year to date ASEN is demonstrating its abilities to aggregate the services needed to develop its assets in a marketplace of high demand."

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Synergy Sells Leases in Denver-Julesburg Basin

- Synergy Sells Leases in Denver-Julesburg Basin

Thursday, July 21, 2011
Synergy Resources Corp.

Synergy has sold certain mineral interests in 2,400 gross acres (1,355 net) in the Denver-Julesburg Basin for a total purchase price of $3,386,350 to an independent oil and natural gas company.

The leases are undeveloped and are located in Weld and Morgan Counties, Colorado. Use of proceeds from the sale will be directed toward further developing the Company's core oil and liquid-rich natural gas properties in the DJ-Basin's Wattenberg Field.

William Scaff, Vice President of Synergy said, "As a relatively small DJ-Basin player, we are continuing to seek new ways to maintain our strategic assets, expand our drilling program and maintain a strong balance sheet. The sale of select undeveloped acreage in Weld and Morgan Counties accomplishes these objectives. We divested a very small portion of our acreage position for proceeds of $3,386,350 and retained an overriding royalty interest on these properties. At the same time, we continue our disciplined approach towards the growth of the company."

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Iran's Southern Regions Producing 3 Million Barrels of Oil Per Day

- Iran's Southern Regions Producing 3 Million Barrels of Oil Per Day

Thursday, July 21, 2011
by Charles Kennedy

Iran is currently the second largest oil exporter in the Organization of Petroleum Exporting Countries (OPEC), exceeded only by Saudi Arabia.

According to National Iranian South Oil Company executive director Hormoz Qalavand, "From the beginning of the current year (starting March 21, 2011, according to the Iranian calendar) until now, an average of about 3 million barrels per day of crude oil has been produced within the operational scope of the company, which is equivalent to 99.98 percent of the plan set by the National Iranian Oil Company," Donya-e Eqtesad newspaper reported.

Qalavand observed, "according to the plan, through the installation and operation of the pumps inside the wells and the drilling of the new wells, the groundwork and mechanisms for which have been prepared, we will be able to achieve a level of production beyond that in the plan projected through the end of the current year." Regarding increasing production from Masjed Soleyman oil field Qalavand noted, "Through the complete inauguration of the development project of this oil field, which is in the experimental launch phase, the oil production capacity in the oil-rich regions of the south will increase to 25,000 barrels per day. The production of oil from the reserves of this company is carried out based on the principle of protecting the reservoirs, and this matter is considered as the main strategy for the oil-rich regions."

(Charles Kennedy is Deputy Editor of The original article is here.)

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MENA Completes Stake Acquisition Offshore Egypt

- MENA Completes Stake Acquisition Offshore Egypt

Thursday, July 21, 2011
MENA Hydrocarbons Inc.

MENA has received co-venturer approval for the acquisition of a 55 percent participating interest in the West Mediterranean, Block 1, Segment A block located 60 km off the Mediterranean coast of Egypt. It is proposed that the acquisition be completed by an indirect wholly-owned subsidiary of MENA. An agreement with the current operator, Hess Egypt West Mediterranean Limited, has been signed as of May 31, 2011. The acquisition was subject to rights of preemption in favor of the existing co-venturers. The co-venturers decided not to pre-empt and have also given their consent to the transaction. MENA intends to seek appointment as operator following the outstanding approval of the Egyptian General Petroleum Corporation and the Egyptian Government and the completion of other customary closing conditions.

Five gas or gas-condensate discoveries have been made on the block. The block is under standard commercial terms for Egyptian concessions. The offshore development lease governing the block is valid for 20 years from the date of first gas deliveries, with an optional five-year extension. The purchase price is US $7.5 million (subject to adjustments) payable in cash.

Graham Lyon, President & Chief Executive Officer of MENA said, "We are another step further in implementing MENA's strategy of building a portfolio of development, production and high impact exploration assets and are pleased to have passed this important step in project capture for MENA in such a short time. We will work with our co-venturers and the authorities to proceed in this development license to a profitable venture and address the significant exploration potential."

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Ecopetrol 2Q Profit Climbs 89% to $1.93B

- Ecopetrol 2Q Profit Climbs 89% to $1.93B

Thursday, July 21, 2011
Dow Jones Newswires
by Darcy Crowe

Colombia's state-controlled energy company Ecopetrol reported robust second-quarter net profits Thursday, fueled by higher oil prices and rising production.

Net profits last quarter were 3.4 trillion Colombian pesos ($1.93 billion), an 89% jump from COP1.8 trillion in the second quarter last year.

"In the first half of 2011 we had historically high financial and operating results," said Ecopetrol President Javier Gutierrez in a statement.

The company's earnings before interest, taxes, depreciation and amortization, or Ebitda, was COP7.57 trillion last quarter, a 111% jump from a year earlier, the statement said.

Ecopetrol's production, without its affiliates, rose to 674,400 barrels a day of oil equivalent in the second quarter, a 21% gain from that quarter of last year, it said.

Analysts attribute the increased oil output by Ecopetrol to higher recovery rates in mature fields and new projects coming into line.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Floating LNG to Play Greater Role in Global Gas Development

- Floating LNG to Play Greater Role in Global Gas Development

Thursday, July 21, 2011
Rigzone Staff
by Karen Boman

While floating liquefaction technology has yet to be commercially proven, the success of floating liquefied natural gas (FLNG) could open previously stranded or non-commercial gas reserves worldwide.

In May, Shell made the final investment decision to proceed with the development of its Prelude floating LNG project. Shell's Prelude facility, which will be deployed in the Browse Basin offshore Northwest Australia, will be the largest floating structure ever built.

While Shell's decision to push ahead with the Prelude project is a major breakthrough for FLNG liquefaction, the unit will not come on stream until the second half of the decade, said Douglas-Westwood analyst Lucy Miller. There are a number of other projects ongoing, but it's likely that these will also fall into this timeframe; no other projects have been approved. "On the whole, onshore developments are still favored; however, FLNG may prove to be more competitive in certain cases depending on the specific project's requirements."

Austral-Asia is seen as a key region for FLNG, particularly the Timor Sea offshore Australia and Papua New Guinea; other key areas include Southeast Asia and offshore Brazil, Miller said.

Douglas Westwood last year estimated that over $23 billion would be spent on FLNG development from 2010 to 2016, most of which will be spent on liquefaction facilities. During that time, Australia is expected to dominate the FLNG market with $5.3 billion in projects, followed by Africa with $5.2 billion in projects and Asia with $4.7 billion in projects. While North America has the greatest number of FLNG prospects, North American projects are expected to account for only seven percent of global expenditures from 2010 to 2016.

Douglas-Westwood views FLNG solutions as a solution for monetizing stranded gas assets that lie far offshore and distant to production infrastructure, addressing the security issues of onshore facilities and pipelines or boundary disputes such as the Timor Sea and South China Sea, and creating a market for gas that would normally be flared.

Accessing stranded gas reserves will be critical to meet the anticipated rise in global gas demand due to population and economic growth, particularly in emerging economies such as China. Douglas-Westwood notes that 6,531 Tcf of gas reserves remain worldwide; 3,000 Tcf of these reserves are considered stranded gas assets.

FLNG may allow Europe other gas supply options that could wean its dependence on Russian gas. More than 40 percent of the European Union's gas is imported -- about half of which comes from Russia – and imports are expected to rise to 75 percent by 2030. Europe's dependence on Russian imports makes it vulnerable to price hikes and supply cut-offs, as demonstrated when Gazprom doubled prices and cut supply going to the Ukraine, Lithuanian, Belarus and Georgia from 2006-2009.

FLNG import terminals are operating in Argentina, Brazil, Kuwait, the UK and the U.S. These include a mix of technological concepts such as regasification vessels and floating storage and regasification units. Some of the technologies involved in proposed FLNG projects have yet to be proven, Douglas-Westwood noted. Technical challenges facing FLNG development include development of sloshing-resistant containment systems; cryogenic offloading, side by side by loading arms or by tandem offloading; marinisation of liquefaction processing equipment; field specific and general topside modules; and the need to develop multiple small-scale or large-scale FLNG vessels, or vessels between 1 and 3 mmtpa and greater than 3 mmtpa.

Besides Shell, other companies seeking to develop liquefaction FLNG facilities include Flex LNG, Petrobras, SBM Offshore, Bluewater, Hoegh LNG, Excelerate Energy, ConocoPhillips and Sevan Marine are developing FLNG liquefaction design concepts, but no specific fields have been announced.

The anticipated start of operations on Flex LNG's FLNG project in Papua New Guinea (PNG) in 2014 is "perfect timing" for the anticipated wave of Asian LNG demand, Flex LNG reported earlier this year. Flex LNG in April entered agreements agreement with Interoil, Pacific LNG, Liquid Niugini Gas Ltd., and Samsung Heavy Industries for a FLNG project in PNG that would liquefy natural gas from the onshore Elk and Antelope gas fields in PNG's Gulf Province.

Samsung last month began field specific front-end engineering and design work (FEED) for the hull portion of the FLNG vessel. WorleyParsons and Kanfa Aragon will carry out the FEED work for the topsides. Samsung will remain responsible for the overall design, engineering, construction and commissioning of the FLNG vessel. FEED is set to be completed in time for the project to reach a Final Investment Decision before the end of this year, with operations in PNG targeted to begin in 2014.

FLEX LNG has already completed a generic FEED in 2009 and the field specific FEED will tailor the vessel for the PNG project where the FLNG vessel is expected to be moored alongside a jetty and have a nominal production capacity of close to 2 million tons of LNG per annum and to process an estimated 2.25 trillion cubic feet of gas over a firm 25-year period. The Elk and Antelope gas fields have substantial certified gas resources, with 6.5 Tcf of P90 resources and 8.6 Tcf and 10 Tcf in P50 and P10 estimates respectively.

Flex LNG reported that LNG projects are more costly than ever to develop, as the capital expenditures/ton of installed liquefaction capacity has made a permanent shift over the last decade from an average figure below 500USD/ton to typical range of 1,500-2,500 USD/ton. Due to the uniqueness of projects, current LNG development costs exceed the average cost for the oil and gas industry. Flex LNG anticipates that it will be in the lower end of the USD550-700 ton/liquefaction capacity CAPEX range for its PNG project.

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Texon Reaches TD at Leighton Olmos Well

- Texon Reaches TD at Leighton Olmos Well

Thursday, July 21, 2011
Global Petroleum Ltd.

Texon Petroleum has advised that the latest Leighton Olmos vertical production well, Peeler #3, has reached its total vertical depth of 2,774 meters (9,100 feet). This is the ninth well targeting the Olmos reservoir in which Global has a 15% working interest (11.25% net revenue interest).

Peeler #3 is the northern most well drilled to date in the Leighton field. The targeted Olmos sand in Peeler #3 has reservoir characteristics similar to the other Olmos production wells.

Production casing has been installed in the well in preparation for fracture stimulation in August. The well will then be connected for oil and gas production.

The closest three Olmos production wells, Peelers #1 and #2 and Tyler Ranch #5 tested at initial rates of 170-445 boepd, including 80% oil, although as production progresses the proportion of gas increases.

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Statoil Gets Green Light to Drill N. Sea Block 15/8

- Statoil Gets Green Light to Drill N. Sea Block 15/8

Thursday, July 21, 2011
Petroleum Safety Authority Norway

Statoil has secured consent to conduct exploration drilling in the central part of the North Sea using the COSLPioneer mobile facility.

The consent relates to the drilling of exploration well 15/8-2 in production license 303. The well is located about 250 kilometers southwest of Stavanger. The consent also covers the drilling of a potential sidetrack.

The well has the following geographical coordinates: N 58° 24' 55.08", E 01° 32' 49.89" Water depth at the site is approx. 119 meters.

Drilling is scheduled to start in late July/early August 2011. The expected duration of the activity is about 79-124 days, depending on potential discoveries.

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Melrose Commences Drilling at Bulgaria Block

- Melrose Commences Drilling at Bulgaria Block

Thursday, July 21, 2011
Melrose Resources plc

Melrose provided an update on its exploration activities.


  • the Company is pursuing a number of high potential exploration initiatives and plans to allocate approximately 40 percent of its capital expenditure to drilling and seismic work programs over the next three years.
  • the exploration program includes projects in proven hydrocarbon basins offshore Bulgaria and Romania, as well as new frontier exploration plays in northern and southern Egypt, Turkey and offshore France.
  • the Company expects to complete three exploration wells in the second half of 2011, in Turkey (on its South Mardin acreage), Bulgaria (on the Galata block) and Egypt (on the South East Mansoura concession).
  • the 2011 drilling program is targeting net unrisked prospective resources of 43 MMbbl of oil and 59 Bcf of gas and two of the wells are potentially new exploration play openers with significant follow-on opportunities.
  • seismic surveys acquired in early 2011 on the Mesaha concession in southern Egypt and the Rhône Maritime block offshore France will help define the longer term exploration potential in these untested frontier areas.
  • seismic data will be acquired later in the year offshore Bulgaria, where the Company hopes to extend the existing proven gas play to the north of the Galata-Kaliakra field trend.

Exploration Update


In Bulgaria, the Company has received formal Government notification that the Galata block exploration permit has been extended to 4 February 2013 with a work program commitment including 3D seismic acquisition and one firm well.

Following receipt of the notification, the Kaliakra East exploration well was spudded on July 20 in the Galata block. The well is targeting a structure containing net prospective resources of 59 Bcf (P50 basis) with a chance of success of 34 percent and should take approximately one month to complete.

The Company is also moving forward with its plans to acquire 500 square kilometers of 3D seismic data within the Galata block to the north of the Galata-Kaliakra field trend. This area of the concession is thought to be on the gas migration path and contains a number of leads identified on the existing 2D seismic data. The 3D acquisition contract has been tendered and the survey is expected to commence in September this year.


Drilling operations continue on the South West Kanun well on the Company's South Mardin acreage in southern Turkey. This well has dual objectives in the Cretaceous and Ordovician formations and is targeting net prospective resources of 37 MMbbl of oil with an average chance of success of 19 percent. Intermediate casing has been set at 3,814 feet and the well is currently drilling ahead at a depth of 5,910 feet. The well has experienced some minor operational delays associated with equipment procurement and is expected to complete in mid to late August.


The processing and interpretation of the 3D seismic data recently acquired over the Cretaceous oil play in the South East Mansoura concession has been completed. The interpretation has confirmed the presence of multiple prospects and leads with combined unrisked prospective resources of 54 MMbbl. One prospect, called Al Hajarisah, has been selected for drilling in the fourth quarter 2011 and this has prospective resources of 6 MMbbl (working interest basis) and a chance of success of 21 percent.

On the Mesaha frontier exploration concession, the 2011 2D seismic survey has been completed with a total of 1844 kilometers of data acquired. The quality of the new seismic data is superior to the 2010 2D survey and has significantly improved the definition of the sedimentary basin. Based on this encouragement, the scope of the 2011 survey was expanded as compared to the original plan (which was to acquire 700 kilometers of data) and the processing and interpretation will complete around year end. The first well is expected to be drilled on the block in the second half of 2012.

Well flow testing operations have recently been completed on the West Zahayra-1 well which was a Qawasim formation discovery made in 2008, seven kilometers west of the West Dikirnis field. Prior to testing the original well was sidetracked by approximately 114 feet and the new wellbore encountered 39 feet of net oil pay with an average porosity of 16 percent.

During testing the well flowed good quality black oil (44 degree gravity) with only small amounts of gas. The well was produced for a period of 4 days but had an unstable flow regime with oil rates fluctuating between 80 and 280 bopd. The Company is currently evaluating whether, with an improved completion design, the well may be placed on commercial production and in parallel is reviewing the field appraisal options.


Preliminary interpretation of the 7,500 kilometers of 2D seismic data acquired on the Rhône Maritime block earlier this year has confirmed the presence of some significant structures on the block and detailed analysis is ongoing to ascertain whether the data exhibit any direct hydrocarbon indicators. The interpretation is due to be completed late in the fourth quarter.


Melrose is planning to acquire seismic data over the Muridava and East Cobalcescu blocks offshore Romania in 2012 during the summer. A provision of $17.8 million for these surveys was included as a contingent item in the Company's 2011 capital budget and this will be rephrased in the Company's next financial forecast.

Commenting on today's announcement, David Thomas, Chief Executive, said, "This is a key period in the Company's evolution as we transition from predominantly production and development related investments to place more emphasis on our exploration portfolio. We are looking forward to seeing the results from our exploration wells in Turkey and Bulgaria, both of which represent an important part of the Company's broader exploration program. The results of the West Zahayra flow test in Egypt are also encouraging since they have extended the oil productive area of the Mansoura concession and we will be reviewing the geologic interpretation of this region in parallel with our appraisal studies on the discovery."

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Aker Bags Umbilical Gig for Endeavour's E. Rochelle Proj.

- Aker Bags Umbilical Gig for Endeavour's E. Rochelle Proj.

Thursday, July 21, 2011
Aker Solutions

Aker Solutions has signed a contract with Endeavour Energy UK, a subsidiary of Endeavour International Corporation, to supply subsea umbilicals and associated equipment for the East Rochelle development project located offshore UK. The contract value is approximately NOK 83 million (USD 15 million).

Aker Solutions will supply one 30 kilometer infield control umbilical and one 650 meter riser umbilical that will provide all system functions for the Rochelle field. Subsea umbilicals are deployed on the seabed to supply necessary control and chemicals to subsea oil and gas wells, subsea manifolds and any subsea system requiring a remote control.

The East Rochelle development project comprises of block 15/27 in the Central North Sea, and represents the first phase of the development of the Rochelle area. Endeavour is the operator of East Rochelle.

"We are very pleased to sign our first contract with Endeavour Energy UK. This is an important award for Aker Solutions and confirms our strong position in the umbilical market globally," said Tove Røskaft, senior vice president of Aker Solutions' umbilical business.

Engineering of the umbilicals will be managed out of Aker Solutions' facility in Oslo, Norway, and the umbilicals will be manufactured at Aker Solutions' facility in Moss, Norway. Final deliveries will be made in 2012.

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Noble 2Q Earnings Drop on Rig Downtime

- Noble 2Q Earnings Drop on Rig Downtime

Thursday, July 21, 2011
Noble Corp.

Noble reported second quarter 2011 earnings of $54 million, or $0.21 per diluted share, matching earnings reported for the first quarter of 2011. Results for the second quarter included a $0.04 per diluted share benefit relating to the settlement of certain discrete tax matters. First quarter 2011 results included a one-time after-tax net gain of $0.06 per diluted share relating to the substitution of the drillship Noble Phoenix for the drillship Noble Muravlenko in Brazil. Contract drilling services revenues totaled $590 million in the second quarter of 2011, up nine percent from $543 million in the first quarter of 2011. Contract drilling margin percentage for the second quarter of 2011 was approximately 43 percent compared to 44 percent in the prior quarter. Noble invested $815 million in capital projects during the second quarter.

At June 30, 2011, approximately 73 percent of the Company's available rig operating days were committed for the remainder of 2011 and approximately 43 percent were committed for 2012. The Company's total backlog at June 30, 2011 was approximately $13 billion.

David W. Williams, Chairman, President and Chief Executive Officer, noted, "Second quarter results were significantly hindered by several downtime events involving five rigs. Although we were disappointed by the interruption in service on these rigs, most of which pertained to subsea equipment and control systems, four out of five rigs returned to service prior to the end of the second quarter. Despite the fleet downtime, the quarter was characterized by an improvement in business fundamentals, as utilization and tendering activity improved for both jackups and deepwater units, and several Noble rigs returned to active status."

Operations Highlights

In Mexico, six of Noble's jackups returned to active status during the second quarter following the award of contracts, while a contract on the Noble Sam Noble is expected to commence by the end of July. Also, the Noble Roy Butler was awarded a three-year contract in July, which is expected to commence in September 2011 following the completion of a leg-extension project. Dayrates for the rigs that have or will soon return to work range from approximately $80,000 to $100,000. Noble now has all 12 of its jackup rigs in Mexico under contract, with 10 of the 12 units under contract into late 2011 or beyond.

In the North Sea, the jackup Noble Byron Welliver was awarded a three-well contract at a dayrate of $91,000, while the jackup Noble Lynda Bossler was awarded a two-well contract at a dayrate of $105,000. Both rigs are expected to commence their new contracts in or around January 2012.

The Company continued to build its presence in Saudi Arabia following the award of contracts for the jackups Noble Gene House and Noble Joe Beall. The three-year contracts are expected to commence in September 2011 with an operating dayrate for each rig of $81,000. With these awards, the Company now has four jackups committed to Saudi Aramco.

Finally, in the U.S. Gulf of Mexico, the semisubmersible Noble Jim Day began receiving its full contract dayrate of $485,000 on July 11 following the award to our client of permits necessary to commence well operations in the region. In addition, certification of the subsea control system on the semisubmersible Noble Driller was completed in July and the rig is expected to resume operations shortly at its full operating dayrate, pending receipt of a drilling permit. The Company now has certified subsea equipment and control systems on all six of its active semisubmersibles in the U.S. Gulf of Mexico.

"Offshore demand continues to build in most regions around the world, supporting expectations for gradually improving utilization and dayrates among our jackups and floating rigs," said Williams. He added, "Additional client demand for jackups is visible in Mexico and the Middle East. In the deepwater sector, Petrobras continues to tender for dynamically positioned and moored rigs for offshore Brazil with contract lengths of three to five years and we continue to see client interest in some of the emerging deepwater frontiers."

In closing, Williams stated, "Our fleet enhancement program, currently composed of the construction of seven ultra-deepwater drillships and four high-specification jackups, is transforming Noble into one of the industry's most modern and capable offshore drilling contractors. As client demand in the offshore sector increases and expands geographically, so does the need for technically advanced, versatile and efficient rigs that address both shallow and deepwater prospects. We believe our strategic growth initiatives strongly position the Company to benefit from further client demand and offshore industry expansion."

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Harvest Natural Strikes Again Offshore Gabon

- Harvest Natural Strikes Again Offshore Gabon

Thursday, July 21, 2011
Harvest Natural Resources Inc.

Harvest Natural Resources announced an update to its drilling operations in the Dussafu Ruche Marin-1 (DRM-1) well drilled in the Dussafu Marin PSC, offshore Gabon, West Africa. Harvest operates the Dussafu PSC, holding a 66.667% interest.

The DRM-1 well was initially drilled in 380 feet of water. On June 10, 2011, Harvest announced an oil discovery in the pre-salt Gamba reservoir with plans to deepen the well to test Middle and Lower Dentale exploration potential and sidetrack to appraise the extent of the Gamba oil discovery.

Subsequently the DRM-1 well has been deepened to reach a true vertical depth subsea (TVDSS) of 11,355 feet to test the prospectivity of the Middle and Lower Dentale Formations. Log evaluation, pressure data and a fluid sample indicate that Harvest has discovered a second oil accumulation with approximately 35 feet of oil pay within the secondary objective of the Middle Dentale Formation.

The Gamba discovery has been appraised by drilling a sidetrack (DRM-1ST1) 0.75 miles to the southwest to test the lateral extent and structural elevation of the Gamba reservoir. The sidetrack was drilled to a TD in the Upper Dentale of 11,562 feet, (9,428 feet TVDSS) and found 19 feet of oil pay in the Gamba reservoir.

Harvest will now sidetrack the DRM-1 well to the northwest of the original DRM-1 wellbore to further appraise the extent and structural elevation of the Gamba and the commerciality of the Ruche discovery.

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Encana Delivers Solid Financial Results on Hedging Gains

- Encana Delivers Solid Financial Results on Hedging Gains

Thursday, July 21, 2011
Encana Corp.

Encana delivered strong operational performance and solid financial results in the second quarter of 2011, growing natural gas and liquids production by 4 percent per share from the second quarter in 2010. Cash flow was US $1.1 billion, or $1.47 per share. Operating earnings were $166 million, or 22 cents per share. As a result of commodity price hedging in the second quarter, Encana's cash flow was $131 million, after tax, or 18 cents per share, higher than what the company would have generated without its commodity price hedging program. Second quarter total production was approximately 3.46 billion cubic feet equivalent per day (Bcfe/d), up 111 million cubic feet equivalent per day (MMcfe/d) from the same quarter in 2010.

"Encana delivered another quarter of strong operating performance and achieved solid cash flow and operating earnings in the face of natural gas prices that remain at levels that we believe are unsustainably low in the long term. We are on track to meet our annual guidance for cash flow and production, which is expected to grow between 5 and 7 percent per share in 2011. We remain firmly focused on being among the lowest-cost producers in the natural gas industry, diligently applying capital discipline, risk management and increased operational efficiencies in all of our decision making," said Randy Eresman, President & Chief Executive Officer.

Pursuing cost savings through operating efficiencies and supply chain optimization

"We have adapted to this prolonged period of soft natural gas prices by taking meaningful steps and applying advanced technologies to manage costs over the long term as we pursue margin maximization on all of the natural gas that we produce. On our Haynesville resource play hubs, we have reduced well drilling times in the last year by 20 percent to 40 days, and a number of wells this year have been drilled in 35 days. To counter the high demand and inflationary rates for well completion equipment, we have established long-term, efficiency-based contracts with four new, dedicated completions crews. In addition, by applying effective logistics management and leveraging Encana's demand, we have reduced our cost of commodities by self-sourcing steel, sand and fuel. These are proactive cost management programs that we expect will result in significant and ongoing cost savings. Our integrated supply chain approach also helps eliminate bottlenecks and optimize cycle times. We now have 15 rigs fueled by natural gas, about one-third of our current drilling complement, generating fuel savings of between $300,000 and $1 million per rig per year, depending on the rig's size and fuel system. While industry cost inflation this year is expected to average about 10 percent, we expect our inflation rate to average approximately half that level – which we expect will be more than offset by improvements in efficiencies," Eresman said.

Encana establishes sizable positions in two promising liquids rich plays – Duvernay and Tuscaloosa

In keeping with the company's first-mover strategy of quietly assembling meaningful land positions to capture large resource opportunities, Encana has established two more sizable land positions in prospective liquids rich plays. In western Alberta, the company has accumulated more than 365,000 net acres in the Duvernay play, where preliminary drilling results by Encana and other operators show significant potential. Two more Duvernay exploration wells are planned for this year. In Mississippi and Louisiana, Encana has captured more than 250,000 net acres of the Tuscaloosa marine shale lands and the company plans to evaluate the play's potential this year.

"Both of these plays are in their early days, but we are encouraged by our exploration results to date. Duvernay and Tuscaloosa are just two of a handful of exciting opportunities that we are pursuing on the more than 2.1 million net acres we hold with strong potential for liquids production. The Niobrara formation in Colorado and the Collingwood shale in Michigan, plus our well-established land positions in the Alberta Deep Basin and the Montney formation in Alberta and British Columbia, provide us with a diverse and promising portfolio of prospective opportunities to grow liquids production over the long term," Eresman said.

Several divestiture and joint venture initiatives moving forward

Encana's non-core divestiture program is well underway towards achieving the company's 2011 net divestitures goal of between $1 billion and $2 billion. Encana is actively engaged with a number of parties in a competitive process to divest of non-core midstream and upstream assets in Canada and the U.S. – transactions that include the northern portion of Encana's Greater Sierra resource play, midstream assets in the Cutbank Ridge resource play which straddles the British Columbia-Alberta border, the company's interest in the Cabin Gas Plant in Horn River and midstream assets in the Piceance basin of Colorado. In its joint venture initiatives to accelerate the value recognition of its enormous resource potential, Encana is also pursuing investment partners in its undeveloped Horn River lands and producing properties in the south portion of Greater Sierra. In addition, competitive marketing of joint venture opportunities on Encana's extensive undeveloped lands in its Cutbank Ridge resource play will commence this summer. Proceeds from these planned transactions are expected to supplement 2011 cash flow generation in the current low price environment and strengthen the company's balance sheet, providing financial flexibility going into 2012.

Deep Panuke project gearing up to begin production in fourth quarter

After sailing from its Abu Dhabi construction site in the Middle East, the production field center (PFC) for Encana's Deep Panuke natural gas development offshore Nova Scotia arrived in the port of Mulgrave on the Strait of Canso in late June. Crews are completing pre-commissioning work before the PFC is towed to the field location for installation about 250 kilometres southeast of Halifax. Deep Panuke is expected to deliver its first natural gas to market in the fourth quarter of 2011, with production ramping up to about 200 million cubic feet per day (MMcf/d). Offshore work this fall includes commissioning of all the operational systems, hooking up the four production wells to the PFC and connecting production facilities to the 176 kilometer pipeline that will deliver natural gas to shore at Goldboro, Nova Scotia.

"Our Deep Panuke project is gearing up to begin delivering clean natural gas to prime markets along the Eastern seaboard of North America," said Michael Graham, Encana's Executive Vice-President & President, Canadian Division.

Natural gas hedges help protect cash flow generation

For the next 18 months, Encana has about half of its expected production hedged at attractive prices – about 1.8 billion cubic feet per day (Bcf/d) at an average NYMEX price of $5.75 per thousand cubic feet (Mcf) for the last half of 2011 and approximately 2.0 Bcf/d of expected 2012 natural gas production at an average NYMEX price of about $5.80 per Mcf.

"Our risk management programs increase the certainty of our cash flow generation and help ensure stability for our capital programs and dividend payments – prudent measures that continue to underpin Encana's financial strength," Eresman said.

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Diamond Offshore 2Q Earnings Up 19%

- Diamond Offshore 2Q Earnings Up 19%

Thursday, July 21, 2011
Diamond Offshore Drilling Inc.

Diamond Offshore Drilling reported net income for the second quarter of 2011 of $266.6 million, or $1.92 per share on a diluted basis, compared with net income of $224.4 million, or $1.61 per share on a diluted basis, in the same period a year earlier. Revenues in the second quarter of 2011 were $889.5 million, compared with revenues of $822.6 million for the second quarter of 2010.

For the six months ended June 30, 2011, the Company reported net income of $517.2 million, or $3.72 per share on a diluted basis, compared with net income of $515.2 million, or $3.70 per share on a diluted basis, for the same period in 2010. Revenue for the six months ended June 30, 2011 was $1.7 billion, essentially identical with $1.7 billion for the first six months of 2010.

In addition, in the past 45 days the Company has put in place 10 new agreements that are expected to generate combined maximum total revenue of approximately $1 billion and represent over 14 years of contract drilling backlog. Significant among these agreements:

  • Petrobras has given notice of its intent to exercise a right to convert the Ocean Baroness and Ocean Valor contracts from three years to five years, in return for which the Company will lower each dayrate by $10,000. The two rigs are expected to earn additional combined maximum total revenue of approximately $500 million, excluding any potential performance bonus payments.
  • The Company has reached agreement with OGX to extend both the Ocean Quest and Ocean Star contracts in Brazil by one year. The extensions are expected to result in combined maximum total revenue of approximately $200 million.
  • The Ocean Yorktown has received a letter of award for a 930-day contract with Pemex in Mexico commencing mid-November 2011 that is expected to earn maximum total revenue of approximately $171 million. The unit is currently under contract to Petrobras in Brazil, but under mutually agreed terms will demobe to Mexico as soon as practical. The remaining days of the Yorktown contract with Petrobras will be added to the Ocean Concord contract.
  • The jack-up Ocean Summit has received a letter of award for a 985-day contract with Pemex in Mexico commencing in late February 2012 that is expected to earn maximum total revenue of approximately $85 million.
  • The jack-up Ocean Titan has received a letter of award for a 777-day contract with Pemex in Mexico commencing in mid-November 2011 that is expected to earn maximum total revenue of approximately $80 million.

Diamond Offshore provides contract drilling services to the energy industry and is a leader in deepwater drilling.

Maximum contract revenue as stated above assumes 100% rig utilization. Generally, rig utilization rates approach 95-98% during contracted periods; however, utilization rates can be adversely impacted by additional downtime due to unscheduled repairs, maintenance and weather.

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Pennsylvania Shale Gas Output to More Than Double This Year - Study

- Pennsylvania Shale Gas Output to More Than Double This Year - Study

Thursday, July 21, 2011
Dow Jones Newswires
by Ryan Dezember

Natural gas production from Pennsylvania's Marcellus Shale should reach the equivalent of 3.5 billion cubic feet per day this year, more than double 2010's output, according to new research by a trio of Pennsylvania State University professors.

The study, released Wednesday, further estimates that production in the state from the deeply-buried rock formation will rise to the equivalent of 6.7 billion cubic feet per day in 2012 and 17.5 bcfe in 2020.

That level of production would make the Pennsylvania basin the largest supplier of natural gas in the U.S., able to meet about 25% of the country's demand, said Kathryn Klaber, who heads the Marcellus Shale Coalition, an oil and gas industry advocacy group.

The Marcellus Shale underlies parts of several Mid-Atlantic and Midwestern states but production is centered in Pennsylvania.

In 2010 1,405 wells were drilled there, yielding the equivalent of 1.3 billion cubic feet of gas per day, according to the study. The professors, who obtained data from producers through the advocacy group, said that 2,300 wells are planned to be drilled this year and forecast that the number will steadily rise to about 2,500 a year by 2020.

While producers have focused on Pennsylvania with some forays into Ohio and West Virginia, several are eying an expansion into New York.

Many initially believed that southwest Pennsylvania held the most productive fields. But a string of recently drilled wells in northern Pennsylvania have made exploration in New York -- where a ban on hydraulic fracturing, the controversial technique needed to crack open the energy-bearing rock, was recently lifted -- more attractive.

Twenty-four of Pennsylvania's 25 highest producing wells are in counties that border New York, according to the Pennsylvania Department of Environmental Protection.

In May, Houston-based Cabot Oil & Gas said two of its wells in that border area are producing nearly 30 million cubic feet of natural gas per day -- significantly more than any previous Pennsylvania wells.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Schlumberger CEO Steps Down

- Schlumberger CEO Steps Down

Thursday, July 21, 2011
Schlumberger Ltd.

Schlumberger announced that Andrew Gould, Chairman and Chief Executive Officer of Schlumberger Limited will retire as Chief Executive Officer effective August 1st 2011. Mr. Gould will continue to serve as Chairman of the Board until the annual general meeting of the company's stockholders in April 2012. It is the Board's intention that its directors will select the current independent lead director, Tony Isaac, to be the new non-executive Chairman upon Mr. Gould's departure.

Andrew Gould will be succeeded as Chief Executive Officer by Paal Kibsgaard, Chief Operating Officer of Schlumberger Limited. During more than 14 years of employment with the company, Mr. Kibsgaard has held operational and management responsibility in the Middle East, Europe and the U.S., and has been involved in all aspects of the company's operations. Prior to his appointment as Chief Operating Officer, Mr. Kibsgaard served as President of the Reservoir Characterization Group after assignments as Vice President, Engineering, Manufacturing and Sustaining; and Vice President of Personnel following a series of earlier international positions.

Commenting on the move, Tony Isaac, the current independent lead director of the Schlumberger Board remarked, "The Board joins me in thanking Andrew for his 36 years of service to Schlumberger and appreciates the significant contributions he has made in driving the company's strong business results during his tenure as Chief Executive Officer."

Mr. Isaac continued, "The Board welcomes Paal Kibsgaard as Chief Executive Officer, and is highly confident that Schlumberger will continue to grow and prosper under his leadership."

Kibsgaard has served as Chief Operating Officer since February 2010, and as a member of the Schlumberger Limited Board since April 2011.

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