Oil & Gas Post - All News Report for Wednesday, August 31, 2011

Wednesday, August 31, 2011

• BP Moscow Office Raided As Pressure In Russia Rises
• Study: Fracking Priciest for Wells
• Williams CEO Says Future of Natural Gas Looks Good
• Oil Spill Safety Bill Fails, Supporters Vow to Bring It Up Again
• Federal Review Calls for Changes in State Oil Regulations
• DNR Secretary Spotlights 3rd Possible Shale Play in La.
• Silvermere Shareholders Approve Mustang Interest Purchase
• Solstad Offshore Inks Contract with Ocean Installer for CSV
• Royal Dutch Shell Awards Enterprise Framework Agreement to Tyco
• Ford, Zipcar Announce New 2 Year Strategic Alliance for U.S. University Members
• Lukoil Reports $3.25B in 2Q Earnings, Up 67%
• BP Sees Russian Office Raids As 'Pressure' - Interfax
• Lundin Extends Avaldsnes Field with Second Appraisal Well
• OMV Makes Gas Discovery in Norwegian Sea
• GDF Suez Gets NPD Nod for North Sea Drilling
• Circle Oil Updates Ops at Geyad Field in Egypt
• Antrim Submits Development Plan for N. Sea Causeway Field
• Phoenix Reaches TD at Marathon Well
• JGC Bags Major EPC Contract for Bir Seba Field in Algeria
• RWE Dea's UK Fields Breagh and Clipper South on Track
• Oilex Prepares Cambay Well for Clean-Up Ops
• Texon Runs Production Tests at 2nd Eagle Ford Well
• Cameron to Acquire LeTourneau Technologies Drilling Systems

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BP Moscow Office Raided As Pressure In Russia Rises

- BP Moscow Office Raided As Pressure In Russia Rises

Wednesday, August 31, 2011
Dow Jones Newswires
MOSCOW
by William Mauldin, Alexander Kolyandr & James Herron

Russian court officials Wednesday raided the Moscow office of BP in the latest setback for BP in Russia following the collapse of a proposed $16 billion share-swap and Arctic oil exploration deal with state-controlled Rosneft.

The raid comes only a day after Rosneft signed a deal with ExxonMobil to explore the same offshore Arctic fields and work together in the U.S. and other locations.

Russian bailiffs entered BP's Moscow office to examine documents requested in a $3 billion lawsuit filed by Siberia-based minority shareholders in BP's exchange-listed Russian joint venture, TNK-BP Holding, BP spokesman Vladimir Buyanov said.

BP's London office said there are "no legitimate grounds for such a raid" and that the "entity raided has no connection with the process in Tyumen," Siberia, said a BP London spokeswoman. The documents seized by bailiffs "are confidential and have no connection with any shareholder issues," she said.

BP shares were flat Wednesday at 397 pence at 1123 GMT, slightly underperforming the broader U.K index. Some analysts said the Exxon-Rosneft deal was a big negative for the company, but others said the disappointing demise of the venture was already priced into the shares.

The escalating tensions are reminiscent of 2008, when BP fought a bitter battle in TNK-BP over strategic control of the venture that spawned raids by immigration officials and harmed relations between Russia and the U.K.

Dmitry Chepurenko, a lawyer representing TNK-BP minority shareholders, said BP Exploration Operating Company Ltd. didn't comply with a court order to provide documents connected with the abortive BP-Rosneft partnership. Thus the court in Tyumen, where the minority shareholders are based, Monday ordered bailiffs to retrieve the documents from BP Exploration Operating Company Ltd., Chepurenko said in a statement.

BP holds its TNK-BP stake through a unit based outside of Russia, although the staff who work with BP work out of its Russian office, which is also home to BP Exploration Operating Company Ltd. unit, BP's Buyanov said.

Most of BP's approximately 120 Moscow employees left work Wednesday as requested by the bailiffs, leaving mainly legal staff and security to work with the officials, Buyanov added. BP Russia chief Jeremy Huck also left the office and currently remains in Russia, the spokesman said.

TNK-BP minority shareholders are seeking RUB87 billion ($3 billion) from BP due to alleged losses stemming from BP's failed tie-up with Rosneft.

The powerful Alfa-Access-Renova consortium of Soviet-born businessmen successfully blocked the BP-Rosneft deal using a clause in the TNK-BP Ltd shareholder agreement.

Lawyers for the TNK-BP minority shareholders, who live in Tyumen, where TNK-BP Holding is based, said they have no connection with the consortium of billionaires, known as AAR.

BP in 2008 fought a losing battle with AAR for control of TNK-BP, then led by current BP Chief Executive Robert Dudley. The conflict included court battles in Tyumen as well as the removal of BP staff from Russia. The acrimonious dispute was resolved only when BP ceded greater influence over the joint venture to its Russian partners and Dudley resigned as TNK-BP CEO.

In a separate case from the Tyumen arbitration, AAR this month said it has asked a Stockholm arbitration panel to issue a final ruling on whether BP breached the TNK-BP shareholder agreement.

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

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Study: Fracking Priciest for Wells

- Study: Fracking Priciest for Wells

Wednesday, August 31, 2011
Pittsburgh Post-Gazette
by Erich Schwartzel

The hydraulic fracturing process that's brought the most controversy to the natural gas industry is also the most expensive aspect of operating a Marcellus Shale well, according to a University of Pittsburgh study released Tuesday.

The fracturing, or "fracking," process that splinters shale rock and lets gas escape costs an average of $2.5 million -- nearly one-third of the total $7.6 million that it costs a company to operate a single well.

Land acquisition and leasing accounted for $2.1 million of the total well costs, with the average signing bonus for land calculated as $2,700 per acre.

This examination of the economic impact of a single Marcellus well was deliberately more narrow than other academic takes on the industry, which have accounted for indirect or induced costs brought on by cottage industries associated with drilling. The conductors of the study called the direct cost of a well a "critical information gap" in gas research.

The study, conducted by Pitt's Institute for Entrepreneurial Excellence and the Katz Graduate School of Business, worked with Downtown-based EQT Corp. to study an operational drill site in Washington County.

Costs were found to dramatically drop after the 23- to 35-day drilling phase, with the reclamation (or "completion") phase and pipeline (or "gathering") phase costing less than one-tenth of the overall price of the well.

The $7.6 million in direct costs that were found for the EQT well is higher than the industry standard of $4 million to $5 million.

EQT sites are considered more expensive on average because the company is not vertical integrated, which means its vertical and horizontal drilling processes occur separately.

The full breakdown included:

• Acquisition and leasing: $2.1 million
• Permitting: $10,000
• Vertical drilling: $663,000
• Horizontal drilling: $1.2 million
• Fracturing: $2.5 million
• Completion: $200,000
• Production to gathering: $472,000

Copyright (c) 2011 the Pittsburgh Post-Gazette

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Williams CEO Says Future of Natural Gas Looks Good

- Williams CEO Says Future of Natural Gas Looks Good

Wednesday, August 31, 2011
Tulsa World, Okla.
by Rod Walton

Falling natural gas prices can benefit the country and smart companies if they're willing to take advantage by getting bigger, Williams Cos. Inc. CEO and Chairman Alan Armstrong said Tuesday.

"Production companies are going to have to operate on a large scale," Armstrong said during the inaugural lecture of this academic year's Friends of Finance series on the University of Tulsa campus. "You better be a big player."

Williams knows something about size within the industry -- 14 percent of daily U.S. natural gas consumption moves on the company's interstate pipelines, while Williams' exploration and production side produces 1.2 billion cubic feet per day, according to the most recent data.

More efficient drilling techniques and shale gas discoveries have driven down natural gas prices from an average $7.91 per thousand cubic feet midway through the last decade to $4.37 in the past year. Crude oil now trades at 3.5 times the price of natural gas on an energy-equivalent basis.

And that's not such a bad thing, Armstrong told a capacity audience in the Great Hall of the Allen Chapman Activity Center. Cheaper natural gas pushes up demand, including the fuel's use as a petrochemical feedstock that is more cost-effective than plastic and petchem products made abroad.

In fact, the U.S. now enjoys a $16.4 billion trade surplus in basic chemical and plastics products, Armstrong said. Power generation companies also are replacing coal-fired units with gas-fired operations.

"We really do embrace the concept of low natural gas prices," Armstrong said. "We feel that growth is coming."

Change is certainly almost routine at Williams since Armstrong took over for Steve Malcolm in January. The Tulsa-based company announced the partial IPO and eventual spinoff of its exploration and production side into WPX Energy Inc., and it's also pursuing Houston-based pipeline and utility supplier Southern Union Co. for a possible merger.

Armstrong would not detail the offer for Southern Union since Williams is still in a bidding war with Energy Transfer Equity LP. But he did note that Southern Union's pipeline network and gas utility connections are attractive as power generation shifts toward natural gas.

"We really do believe that power generation markets will continue to expand," Armstrong said.

Energy Transfer Equity currently holds the higher offer at $44.25 per share in stock and cash. Williams, however, has argued that its all-cash bid, at $44 per share, is a better value for Southern Union because of stock market volatility.

The WPX Energy spinoff and IPO offers more immediate benefits locally. Few investors view Williams as a producer despite its top-10 domestic status, so WPX will give a strong, focused option to long-term investors who are not interested in the quarterly distributions promised by fee-based master limited partnerships.

"There really is a revolution going on before us," Armstrong said of the production and processing opportunities awaiting growth-oriented natural gas players.

Williams still would own 80 percent of WPX after the partial IPO, using the maximum $750 million in equity raised to pay down debt and shore up the company's investment-grade status. Williams shareholders would receive the remaining stake in a tax-free spinoff next year.

The final result would be that two of the nation's largest independent pure-play energy companies would both based in Tulsa.

Williams currently employs about 1,300 people in the city. The companywide workforce, including operations in offshore drilling and Canadian off-gas processing and olefins production, stands at about 5,000. Williams Cos. Inc. by the numbers

• 103 years old
• 1,300 employees in Tulsa; 5,000 companywide
• 14 percent of U.S. natural gas consumption moves on its pipelines
• 1.2 billion cubic feet in natural gas produced per day

Copyright (c) 2011 Tulsa World (Tulsa, Okla.)

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Oil Spill Safety Bill Fails, Supporters Vow to Bring It Up Again

- Oil Spill Safety Bill Fails, Supporters Vow to Bring It Up Again

Wednesday, August 31, 2011
San Jose Mercury News, Calif.
by Paul Rogers

With the state agency that regulates oil tanker safety facing potential layoffs, a bill to raise the fee that oil companies pay to fund California's oil spill safety programs failed Tuesday in the state Senate.

The bill, a priority for environmental groups, has been staunchly opposed by BP PLC and the Western States Petroleum Association.

"We're not done," said Assemblyman Jared Huffman, D-San Rafael, the measure's author. "The fat lady hasn't sung. We still have a week and a half to bring it back."

The bill, AB 1112, already has passed the Assembly and needed 21 votes Tuesday to move to the governor's desk. But it failed, achieving 17 votes, with 14 senators voting no and nine not voting.

The bill would increase the fee that oil companies pay from 5 cents per barrel to 6.75 cents per barrel over the next three years. The money raises $25 million a year and provides the bulk of the budget for the state Office of Spill Prevention and Response, an arm of the state Department of Fish and Game.

State lawmakers passed the fee in 1990 after the Exxon Valdez spill to increase California's oil safety efforts. Since then, the amount of oil spilled into state waters has fallen by 95 percent. The money has funded emergency drills, tougher oversight of tankers and terminals, and scientific studies of oiled wildlife. Since the original fee passed, at 4 cents a barrel, it has been raised once, in 2002.

Capt. Scott Schaefer, administrator of the state oil spill agency, said that because of costs associated with new laws passed after the 2007 Cosco Busan oil spill in San Francisco Bay, the fund will be $5 million in deficit by 2013 without an increase.

Huffman said he will bring the bill up again before the end of the legislative session, Sept. 9. All 17 who voted for the bill were Democrats. Twelve of the 14 no votes were from Republicans, many of whom oppose increasing state fees and taxes. Environmental groups were surprised that several senators from coastal areas did not vote, including Sen. Leland Yee, of San Francisco; Juan Vargas, of San Diego; Curren Price and Alex Padilla, of Los Angeles; and Sam Blakeslee, whose district extends from San Luis Obispo along Monterey Bay to south San Jose.

"Sen. Yee supports the bill," said his spokesman Adam Keglin afterward. "He was off the floor at the time. It will come back up, and he'll vote for it as is."

Copyright (c) 2011 the San Jose Mercury News (San Jose, Calif.)

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Federal Review Calls for Changes in State Oil Regulations

- Federal Review Calls for Changes in State Oil Regulations

Wednesday, August 31, 2011
The Bakersfield Californian
by John Cox

A recent federal review calls for tightening California's oversight of certain underground injection activities common in Kern County oil fields.

Saying more should be done to protect underground sources of drinking water, the U.S. Environmental Protection Agency-commissioned review recommends several measures that could make it harder for oil companies to get permission to inject steam, wastewater and other materials underground.

The review comes at a sensitive time for California local oil producers. For months the industry has howled about the more cautious, time-consuming approach that Sacramento has taken to regulating underground injection projects over about the last year and a half. Trade associations say delays cost jobs and worsen California's dependence on foreign oil.

Industry representatives said Tuesday it is unclear what exactly will be the impact of the review, a summary of which was posted online Friday by the state Division of Oil, Gas and Geothermal Resources. Oil industry spokespeople noted that DOGGR officials have not officially responded to the review.

Rock Zierman, CEO of the California Independent Petroleum Association, said he saw no "red flags" raised in the report. The most important question, he said, is how the recommendations are implemented by the state, if it comes to that.

"Keep in mind that much of what they're raising is a paperwork problem," Zierman said.

A DOGGR spokesman wrote in an email Tuesday that some of the review's findings are reflected in regulatory changes already instituted at DOGGR over the last three years. Spokesman Don Drysdale indicated that this point will be discussed in meetings tentatively set to begin next month between State Oil and Gas Supervisor Elena Miller and David Albright, the San Francisco-based manager of the EPA's Pacific Southwest Ground Water Office.

Drysdale added that any new rules would have to be drafted by DOGGR and then go through a public review process before being reviewed by the state Office of Administrative Law.

Since 1983, DOGGR has regulated underground injection projects under a "primacy" agreement with the EPA. The agreement requires periodic reviews such as the one posted in summary form Friday.

Three specific issues

In a letter to Miller dated July 18, Albright made specific mention of three issues discussed in the review, which was conducted by Horsley Witten Group, an East Coast environmental science and engineering firm:

• Unlike federal rules, DOGGR regulations do not clearly require the agency to protect water containing up to 10,000 milligrams per liter of dissolved solids. State rules define "fresh water" as containing no more than 3,500 milligrams per liter of dissolved solids;
• State regulators are approving underground injection projects based on reviews that extend a quarter mile around the proposed injection well. "Whereas the fixed radius approach may be appropriate for some injection wells," Albright wrote, other wells may require a wider area of study;
• Federal and state laws say that the maximum surface injection pressure must not exceed a level capable of fracturing the area's underground geology. DOGGR regulators, however, often use only estimates of the fracturing pressure, and that when they perform a more detailed pressure study, then fail to gather "the more accurate combination of surface and bottom-hole measurement."

Albright's letter to DOGGR made brief reference to several other matters raised in the Horsley group's review. These range from the professional qualifications of DOGGR's underground injection control staff and the frequency of project reviews to well plugging and abandonment requirements.

A theme raised repeatedly in the review is that DOGGR has lacked adequate staffing to address various regulatory challenges. It also notes that DOGGR has recently received approval to hire more staff.

DOGGR wrote Tuesday that in fiscal year 2010-11 it received approval to fill 17 underground injection control positions statewide. That brought DOGGR's total payroll to 157, not all of these related to underground injection.

The DOGGR district that includes Kern County performs more underground injections than any other district, comprising 86 percent of the state's active underground injection wells.

The specific uses of Kern injection wells range from cyclic steam (58 percent of all California's active underground injection wells) and steam flooding (14 percent) to water disposal (3 percent).

Cathy Reheis-Boyd, president of the Western States Petroleum Association, said she and her staff were anxious Tuesday to get a copy of the full EPA-ordered review, which was not available on DOGGR's website. She said the goal of WSPA, which represents the state's largest oil producers, was to begin work with DOGGR to address the federal government's concerns as quickly as possible and then return to the business of producing oil.

"From a bigger policy perspective," she said, "we really need to come to agreement on how we're going to proceed with all parties."

Copyright (c) 2011 The Bakersfield Californian (Bakersfield, Calif.)

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DNR Secretary Spotlights 3rd Possible Shale Play in La.

- DNR Secretary Spotlights 3rd Possible Shale Play in La.

Wednesday, August 31, 2011
Louisiana Department of Natural Resources

Louisiana Department of Natural Resources (DNR) Secretary Scott Angelle said Wednesday that the energy exploration industry has begun work on developing yet another new oil and natural gas shale play in Louisiana – giving the state one proven and producing shale formation and two that are being watched closely as the early stages of activity begin.

The potential new interest area, spanning portions of North Louisiana and southern Arkansas, is referred to as the "Brown Dense" or the "Lower Smackover," and is believed to be a layer of limestone at the base of the Smackover Formation – which itself is a well-known formation that has long been a source for traditionally produced oil and natural gas in North Louisiana.

The "Brown Dense" joins the Tuscaloosa Marine Shale as the second half of Louisiana's duo of dense rock plays believed to have the kind of production potential that has made shale plays such as Louisiana's Haynesville and the Barnett and Eagle Ford Shales of Texas the new normal in energy exploration. The Tuscaloosa Marine Shale is believed to underlie much of Central Louisiana, with potential productive areas currently being explored from Vernon Parish to East Feliciana Parish.

The energy industry is watching the development of the Tuscaloosa Marine Shale and the Brown Dense closely, as both are believed to have the potential to contain oil reserves, in addition to natural gas. New processes and technology have led to rapid gains in domestic oil and natural gas reserves, making them recoverable from ultra-dense formations once thought uneconomical to produce.

"We in Louisiana have a long and distinguished history of providing the energy that fuels this nation, and I am bullish on the future of energy production in this state and the role it will play in providing jobs and economic strength," Angelle said. "We are seeing that exploration companies and investors share that optimism and belief in Louisiana's natural resources as they seek new domestic reserves of oil and natural gas. The development of the Haynesville Shale natural gas play, the top-producing natural gas play in the nation, has helped give them that confidence."

Initial development of the Brown Dense formation, generally believed to underlie northern Claiborne, Union and Morehouse parishes in North Louisiana, has barely begun – with Southwestern Energy having begun the process of drilling its first well in Arkansas and having announced that it will seek a permit to begin drilling for a Brown Dense well in Claiborne Parish before the end of 2011.

Southwestern Energy has also announced that it has invested $150 million in leasing mineral rights for 460,000 acres to develop the play. Southwestern Energy recently applied to the Louisiana Office of Conservation for approval of an area of the Lower Smackover formation in Claiborne Parish near the Arkansas border as a designated unit for drilling.

Devon Energy has also announced that is has secured 40,000 acres in mineral leases for the Brown Dense and that the company intends to drill a test well for the play. Devon has already received a permit for a well targeting the deeper section of the Smackover in Morehouse Parish.

Devon is also active in the Tuscaloosa Marine Shale, where the company has secured 250,000 acres of mineral leases and is in the process of drilling two wells in the shale. About half a dozen wells targeting the Tuscaloosa Marine Shale – long thought to contain substantial reserves, but considered uneconomical to reach through previous methods – are currently in the process of permitting or drilling.

"New exploration methods have changed the game for development of energy prospects in Louisiana and the nation, as we saw firsthand with the incredible upswing investment and economic activity in North Louisiana in 2008," said Angelle. "This is yet another opportunity for Louisiana to show that we can be an inviting and exciting province to do the business of finding and providing new sources of domestic energy that provide economic strength and opportunity for our state and our nation."

"With that exploration of the denser formations will come the need for water for hydraulic fracturing," said state Conservation Commissioner Jim Welsh.

Welsh said that companies drilling for the Brown Dense formation have informed the Office of Conservation they intend to use surface water and recycled water for their overall project needs, in conformance with guidelines and advisories issued in nearby areas experiencing stressed ground water conditions.

The anticipated Brown Dense area of development in Louisiana underlies the Sparta Aquifer, which is currently experiencing improved water levels after combined state and local efforts to manage ground water use in the area.

"We are still discouraging new high-volume users from using ground water in that area, and giving guidance on alternative sources for water," Welsh said.

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Silvermere Shareholders Approve Mustang Interest Purchase

- Silvermere Shareholders Approve Mustang Interest Purchase

Wednesday, August 31, 2011
Rigzone Staff
by Karen Boman

Silvermere shares began trading on Aug. 31 in London after shareholders approved the acquisition of interest in the Mustang asset in the Gulf of Mexico and other resolutions.

The company announced in early August that it had conditionally risen £1.52 million via a placing at 25p her share, the proceeds of which would provide working capital for the Group and pay the costs associated with acquiring interest in the Mustang Island 818-L field and admission to trading on AIM, the London Stock Exchange's international market for smaller growing companies.

The development of the Mustang Island 818-L field, located in Kleberg County offshore Texas in the U.S. Gulf, is a field rehabilitation project targeting bypassed or only partially produced gas-condensate.

The field was drilled and produced by Samedan Oil Corp. in the 1980s, based on 2-D seismic mapping. From January 1980 to February 1995, the field had produced a total of 138.9 Bcf of gas. This includes production from the D1 and D2 wells, which are outside of the seismic area and therefore not taken into consideration for this evaluation. Total historic production from the wells within the seismic coverage is 125.6 Bcf.

At abandonment, some 25 wells had been drilled targeting several stacked clastic reservoir sands grouped as the A, B, G, and I sands. The I sands, which lie at depths of more than 11,000 feet, are the primary targets for the initial phases of development of wells within the Mustang asset.

The company is recommending three new wells in the outline field development plan to test and produce remaining gas, based on the fact that each of the three fault blocks mapped has a structural high that has not been drilled, supporting the idea of remaining attic gas being present.

Drilling and tie-in costs have been estimated between US $5 million and US $8 million, including the costs of connecting the wells into the existing infrastructure which is itself connected to the Six Pigs processing facility onshore on Padre Island, Texas. The infrastructure, including mini platform, flowlines, main 20-inch export line to Six Pigs and the Six Pigs processing facility, is believed to be in good order.

The Mustang asset comprises a 33.3 percent working interest and a 20.83 percent net entitlement interest (after deductions of overriding royalties) in the Mustang license area.

Silvermere, previously known as Chalkwell Investments Plc, initiated discussions last year with Core Oil and Gas Inc. which had agreed to terms to acquire the Mustang asset. Since November 2010, the company has made a series of loans to Core, which now total £2.595 million, which Core has used principally to finance its share of the costs for the re-entering and subsequent testing of the I-1 well, which lies within the Mustang license area, and to pay the consideration due from Core for the Mustang asset. On April 29, the company entered into the option agreement with Core, superseding a previous option between the parties.

Shareholders also approved a new board of directors for the company. Under the new board's guidance, Silvermere will pursue a strategy of acquiring a portfolio of U.S. oil and gas license interests onshore and in shallow offshore water, characterized by relatively low risk and low cost with the potential for near term production. The company said in a statement that the acquisition will provide a good base from which to develop this strategy.

"We are very pleased to be bringing the company back to the market with a promising and attractive asset," said Chief Executive Andy Morrison earlier this month. "The area surrounding the Mustang Asset has a proven producing history and continues to have significant potential."

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Solstad Offshore Inks Contract with Ocean Installer for CSV

- Solstad Offshore Inks Contract with Ocean Installer for CSV

Wednesday, August 31, 2011
Solstad Offshore ASA

Solstad Offshore ASA (SOFF) has signed a contract with Ocean Installer AS (OI.II) for hire of SOFF's offshore construction vessel (CSV) Normand Clipper.

The duration of the contract is firm for 5 years with further 5 x 1 year option. Commencement is expected to be during second quarter of 2012.

The contract value is confidential between the parties, but gives SOFF an acceptable return on its investment. SOFF and OI.II intend to investigate and develop opportunities for further co-operation with regards to future assets.

Normand Clipper is a CSV built in 2001 and extensively upgraded in 2005. The vessel is very well suited for subsea construction work in both deep and more shallow waters. The vessel has a 250 t subsea crane, a deck area of approximately 1700 m2 and accommodation to approximately 100 people.

Ocean Installer is a newly established subsea construction company based in Stavanger, Norway. O.II is 100% owned by HitecVision.

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Royal Dutch Shell Awards Enterprise Framework Agreement to Tyco

- Royal Dutch Shell Awards Enterprise Framework Agreement to Tyco



Aug 31, 2011

Tyco International's (NYSE:TYC) flow control unit has been selected by Shell (NYSE:RDS-A) to provide butterfly valves to Shell globally.

The five-year Enterprise Framework Agreement covers more than 2,500 of Tyco's Vanessa, Winn, NeoTecha, Sapag brand butterfly valves, for use in projects, maintenance repair operations and turnaround applications.

David Dunbar, president of Tyco Valves & Controls, a unit of Tyco Flow Control said, "We appreciate the confidence Shell has shown in Tyco Flow Control with this EFA. As Shell grows, Tyco can scale with the company, bringing technology, leadership and service wherever they are needed."

Tyco International (NYSE:TYC) has a potential upside of 25.3% based on a current price of $41.9 and an average consensus analyst price target of $52.5.

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Ford, Zipcar Announce New 2 Year Strategic Alliance for U.S. University Members

- Ford, Zipcar Announce New 2 Year Strategic Alliance for U.S. University Members



Aug 31, 2011

Ford (NYSE:F) and Zipcar (NASDAQ:ZIP) announced a new a strategic alliance establishing Ford as Zipcar's largest university vehicle partner, reaching students at more than 250 campuses.

The first of its kind, two-year tie up introduces a new generation of drivers to Ford vehicles with the highly-fuel efficient Focus and Escape now part of Zipcar's existing fleet of environmentally friendly, reliable and fun vehicles.

Zipcar will offer $10 off the $35 annual membership fee for the first 100,000 new University members who sign up for Zipcar, plus $1 off the hourly rate for the first 1 million hours of use on any of the new Ford vehicles at select colleges and universities

New Ford vehicles start arriving on campuses this week. The program, which could generate 2 million hours behind the wheel of Ford vehicles for college-age drivers, also helps reduce parking demand, congestion and emissions.

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Lukoil Reports $3.25B in 2Q Earnings, Up 67%

- Lukoil Reports $3.25B in 2Q Earnings, Up 67%

Wednesday, August 31, 2011
OAO Lukoil Holdings

LUKOIL has published consolidated US GAAP financial statements for the second quarter and first half of 2011.

The Company's net income was $6.768 billion in the first half of 2011, which is 69.1% higher y-o-y, including $3.251 billion in the second quarter. EBITDA in the first half of 2011 was $10.688 billion, which is 43.8% higher y-o-y. Sales revenues were $64.538 billion (+29.7% y-o-y). Positive dynamics of our financial results was mainly due to increase in hydrocarbon prices and refining margin in the first half of 2011 compared to the respective period of 2010.

Capital expenditures including non-cash transactions in the first half of 2011 were $3.6 billion, which is 13.3% higher y-o-y. The Company's strict financial discipline helped to generate high free cash flow which reached $4,714 million in the first half of 2011 compared to $3,127 million in the first half of 2010.

In the first half of 2011, lifting costs per boe of production were $4.72, which is 17.4% higher y-o-y. The growth was mainly due to the real ruble appreciation, which was 15.0% in the first half of 2011.

In the first half of 2011, LUKOIL Group total hydrocarbon production available for sale reached 2,162 th. boe per day, which is a 4.4% decrease y-o-y.

In the first half of 2011 throughputs at the Company's refineries (including its share in crude oil and petroleum product throughput at the ISAB and TRN refining complexes) decreased by 1.2% y-o-y and reached 32.03 MM tonnes. Throughputs at the Company's refineries in Russia increased by 1.5% y-o-y, throughputs at the Company's international refineries decreased by 6.9% y-o-y due to shutdown of the Odessa Refinery because of unfavorable economic conditions in the first half of 2011.

Measures aimed at higher efficiency and cost control allowed the Company to generate strong free cash flow and increase net income.

Also, an extended meeting of the OAO LUKOIL Board of Directors was held on Wednesday. The meeting considered the Company's production and financial performance and the investment program implementation results in the first half of 2011.

In his address to the meeting, LUKOIL President Vagit Alekperov specified the need to develop a Hydrocarbon Production Stabilization Program and to rigorously implement it.

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BP Sees Russian Office Raids As 'Pressure' - Interfax

- BP Sees Russian Office Raids As 'Pressure' - Interfax

Wednesday, August 31, 2011
Dow Jones Newswires
MOSCOW
by Ira Iosebashvili

Russian raids on BP's Moscow offices are a means of pressuring the company's business activities within the country, BP Russia head Jeremy Huck said Wednesday, Interfax reported.

The court decree to raid BP's office "has no legal basis," Huck said.

"The work of our office is paralyzed. We see these actions as an element of pressure on BP's business in Russia."

Earlier, Russian bailiffs entered a BP Moscow office to examine documents requested in a $3 billion lawsuit filed by Siberia-based minority shareholders in BP's Russian joint venture, TNK-BP Holding (TNBP.RS).

Huck said he expected the raids to continue until the end of the week.

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

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Lundin Extends Avaldsnes Field with Second Appraisal Well

- Lundin Extends Avaldsnes Field with Second Appraisal Well

Wednesday, August 31, 2011
Lundin Petroleum AB

Lundin announced that the second appraisal well, 16/2-7, has confirmed the extension of the Avaldsnes field approximately 5.5 kilometers south of the 16/2-6 discovery well and 4.5 kilometers south-west of the first appraisal well 16/3-4. The Avaldsnes field is located in license PL501 on the Norwegian Continental Shelf and is in communication with the recently announced Aldous Major South discovery in PL265 to the west.

The second Avaldsnes appraisal well encountered a gross reservoir column of excellent quality Upper Jurassic age sandstone of approximately 35 meters of which seven meters was above the oil water contact. A comprehensive coring and logging program has been performed which has confirmed excellent quality reservoir characteristics.

The appraisal well will now be sidetracked to obtain further reservoir information. The sidetrack will be completed by mid September. The well was drilled to a total depth of 2,500 meters MD and in a water depth of 113 meters.

Lundin Petroleum is using the semi submersible drilling rig Bredford Dolphin to drill the well.

Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "The second Avaldsnes appraisal well results have confirmed the extension of the field to the south. We will, following the sidetrack, incorporate the results of the two well appraisal program and Statoil's Aldous Major South well in PL265 into our geotechnical models. We will then release a revised resource range from the previously announced 100 - 400 million barrels of recoverable of oil equivalent contained within PL501. The Avaldsnes /Aldous Major South discovery is already the largest discovery on the Norwegian Continental Shelf since the mid 1980s and I am confident has the potential to grow as the field is appraised. It is likely that a third appraisal well will be drilled on Avaldsnes during the fourth quarter of 2011."

Lundin Norway AS is the operator of PL501 with a 40 percent interest. Partners are Statoil Petroleum AS with 40 percent interest and Maersk Oil Norway with 20 percent interest.

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OMV Makes Gas Discovery in Norwegian Sea

- OMV Makes Gas Discovery in Norwegian Sea

Wednesday, August 31, 2011
Valiant Petroleum plc
by SubseaIQ

Valiant announced that drilling has completed on exploration well 6407/5-2S on PL471 located in the Norwegian Sea. The primary Chamonix target, a Cretaceous-age stratigraphic trap, was found to be dry having encountered poorly developed sands in the drill location. However, the well has made a small gas discovery in the secondary Cortina target having encountered a gross gas column of about 40 meters in the Upper and Middle Jurassic sandstones of the Rogn and Garn formations. An extensive data sampling program has been undertaken giving important information to de-risk similar nearby prospects. The discovery will be evaluated with the view to determine viability as a tie-back as part of a larger field development to surrounding infrastructure.

The well was drilled in a water depth of 230 meters using the semisubmersible rig Borgland Dolphin and was completed ahead of schedule and budget without any operational problems. The well has a deviated path and was terminated in the Lower Jurassic Tilje Formation at a vertical depth of 3359 m below sea surface. The partners in license PL471 are OMV Norge (50%, operator), Noreco (30%) and Valiant (20%).

Peter Buchanan, CEO, commented, "We are pleased to have made a small gas discovery on our first exploration well in Norway and we look forward to continuing to work together with our partners in order to fully evaluate its potential and the prospectivity of the rest of the license."

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GDF Suez Gets NPD Nod for North Sea Drilling

- GDF Suez Gets NPD Nod for North Sea Drilling

Wednesday, August 31, 2011
Norwegian Petroleum Directorate
by SubseaIQ

The Norwegian Petroleum Directorate has granted GDF Suez Norge AS a drilling permit for well 7124/4-1 S, cf. Section 8 of the Resource Management Regulations.

Well 7124/4-1 S will be drilled from the Aker Barents drilling facility at position 71°35'16.16" north and 24°5'56.84" east after completing the drilling of wildcat well 6508/1-2 for Det Norske Oljeselskap ASA in production license 482.

The drilling program for wellbore 7124/4-1 S relates to drilling a wildcat well in production license 530. GDF Suez Norge AS is the operator with a 30 percent ownership interest. The other licensees are Rocksource ASA (20 percent), Front Exploration AS (20 percent), North Energy ASA (20 percent) and Repsol Exploration Norge AS (10 percent).

The area in this license consists of the blocks 7123/6 and 7124/4. The well will be drilled about 100 kilometers north of Hammerfest and about 70 kilometers northeast of the Goliat field.

Production license 530 was awarded in the 20th licensing round. This is the first well to be drilled in the license.

The permit is contingent upon the operator securing all permits and consents required by other authorities prior to commencing drilling activity.

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Circle Oil Updates Ops at Geyad Field in Egypt

- Circle Oil Updates Ops at Geyad Field in Egypt

Wednesday, August 31, 2011
Circle Oil plc

Circle Oil announced the following update regarding the Geyad-5X water injection well drilled to support production in the Geyad Field.

Geyad-5X

Geyad-5X, located to the south-west of the field and downdip of the Geyad-1X ST discovery well in the Geyad Development Lease, was drilled to 7,350 ft MD in the Upper Rudeis. The main objective for this well was to appraise the Shagar and Rahmi sandstones of the Kareem Formation in a downdip location and to provide water injection to support oil production from the updip Geyad field wells. The Shagar sands were encountered with 15 ft MD of net reservoir, an average porosity of 14% and perforations made between 6,510 and 6,525 ft MD. The Rahmi sands were encountered with 15 ft MD of net reservoir, an average of 13% porosity and perforations made between 6,583 and 6,899 ft MD. As expected, below the field oil-water contact both sands were found to be water bearing. The well has been completed as an injector.

The rig has now been mobilized to drill the water injector well Al Ola-2, located on the south-eastern flank of the Al Amir SE field, downdip of the Al Ola-1X producer. The well is planned to appraise both the Shagar and Rahmi sands for injection in that location.

The NW Gemsa Concession, containing the Al Amir and Geyad Development Leases, covering an area of over 260 square kilometers, lies about 300 kilometers southeast of Cairo in a partially unexplored area of the Gulf of Suez Basin. The concession agreement includes the right of conversion to a production license of 20 years, plus extensions, in the event of commercial discoveries. The NW Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).

Prof Chris Green, CEO, said, "I am pleased to report another successful result as the partnership's plans in NW Gemsa continue on schedule. The rig will now move to start drilling the Al Ola-2 injector well situated on the Al Amir SE field. The water injection program is part of the continuing plan to increase production rates for the medium and long term."

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Antrim Submits Development Plan for N. Sea Causeway Field

- Antrim Submits Development Plan for N. Sea Causeway Field

Wednesday, August 31, 2011
Antrim Energy Inc.

Antrim, a partner in the Causeway Field located in UKCS Block 211/22a South West Area and Block 211/23d (Antrim 35.5%), announced submission of the final Field Development Plan ("FDP") to the Department of Energy and Climate Change ("DECC") and that Board approval has been gained from partners to progress into the development phase. DECC approval of the Causeway FDP is anticipated during 2011.

The Causeway FDP includes a production well and a water injection well in the East and Far East fault panels and will utilize existing wells on the field drilled during the appraisal phase. The production well will be completed with dual electrical submersible pumps and first oil is anticipated in mid 2012. Hydrocarbons will be transported to and processed at the Cormorant North platform operated by TAQA Bratani Limited before being exported to the Sullom Voe terminal for sale. Antrim's reserves evaluator, McDaniel and Associates Consultants Ltd., estimate 8.9 million barrels of proved plus probable oil reserves (Antrim net 3.2 million barrels) from the East and Far East fault compartments (as of December 31, 2010). Development costs net to Antrim are estimated at $32 million, inclusive of $21.8 million associated with the previously announced sale of Antrim Causeway (N.I.) Limited (Aug. 9, 2011). Commitments are now in place for all long lead equipment and the operator has awarded a letter of intent for the main subsea installation contract to Technip UK Limited.

The Causeway development plan includes an option to develop the Central panel, which is still under review by the partners and not included in the above referenced reserves or costs.

Stephen Greer, CEO of Antrim, commented, "The submission of the FDP for Causeway marks a significant milestone for Antrim, demonstrating a clear and defined path to first oil production from the Company's UK North Sea properties."

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Phoenix Reaches TD at Marathon Well

- Phoenix Reaches TD at Marathon Well

Wednesday, August 31, 2011
Petsec Energy Ltd.

Petsec advised that the Marathon #2 well was drilled to a total depth of 21,160 feet (6,450 meters) and electric logging was completed. The well is a follow up to the successful #1 well and is situated in 8 feet (2.4 meters) of water approximately 900 meters from the #1 well location. The #2 well was designed to serve as a development well for the field in addition to testing deeper, previously undrilled exploratory reserve potential on the Marathon structure.

The #2 well confirmed the gas productive reservoirs found in the # 1 well, extending the known field pays across the structure. The deeper, exploratory section of the well was found to contain noncommercial hydrocarbons and as a result the well will be completed for production in one of the upper pay sands. Production is expected to commence in the fourth quarter of 2011.

Participating working interests in the well are:

• Petsec Energy Ltd 8%
• Phoenix Exploration Company LP (operator) 65%
• Private Companies 27%

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JGC Bags Major EPC Contract for Bir Seba Field in Algeria

- JGC Bags Major EPC Contract for Bir Seba Field in Algeria

Wednesday, August 31, 2011
JGC Corp.

JGC and its subsidiary JGC Algeria Ltd. have been awarded the engineering, procurement and construction (EPC) services contract for the Bir Seba Field Development Project by Groupement Bir Seba, comprising Sonatrach, the Algerian state-owned oil and gas company, Petrovietnam Exploration Production Corporation (PVEP), and PTT Exploration and Production Algeria (PTTEP). Participating interests in Groupement Bir Seba are 25%, 40%, and 35%, respectively.

The Bir Seba Field Development Project, located in an inland and desert area 130 kilometers north east of Hassi Messaoud, calls for construction of a gathering system from 16 productive wells, crude oil processing facilities (20,000 bpd), and oil & gas export pipelines.

The lump-sum turnkey contract has a value of more than US $400 million and calls for Project completion in the first half of 2014.

With the award of the Bir Seba Field Development Project, JGC will be collaborating with JGC Algeria for the fourth time on an EPC project. Moreover, this Project will strengthen JGC Algeria's project execution capabilities.

JGC was awarded the contract for an oil refinery construction project in Arzew in 1969. Since then, the company has accumulated a long and impressive track record of hydrocarbon projects for Sonatrach and other foreign companies. JGC is currently executing three consecutive EPC projects in Algeria: gas and oil separation facilities in the Rhourde Nouss field (awarded in 2008); gas processing facilities in the Gassi Touil field (awarded in 2009); and gas compressors in the In Amenas field (awarded in 2011).

One of the goals set forth in JGC Group's "New Horizon 2015" five-year management plan is the strengthening and expansion of the Group's overseas subsidiaries. As a vastly experienced engineering and construction company in possession of the latest technologies, JGC, together with JGC Algeria, will continue to vigorously promote sales activities aimed at expanding its business opportunities in Algeria.

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RWE Dea's UK Fields Breagh and Clipper South on Track

- RWE Dea's UK Fields Breagh and Clipper South on Track

Wednesday, August 31, 2011
RWE Dea AG

RWE Dea UK's field developments Breagh and Clipper South are both progressing on schedule. On a visit to Heerema's fabrication yard in Zwijndrecht (Netherlands) Wednesday, RWE Dea CEO Thomas Rappuhn emphasized the high significance of both projects: "The proven reserves play an important role to significantly increase RWE Dea's gas production in the North Sea."

"Breagh for example is one of the largest natural gas discoveries in the Southern North Sea and our target is to bring field developments on stream quickly," added RWE Dea UK Managing Director René Pawel.

Gross investments are GBP 430 million (Breagh, Phase 1) and GBP 240 million (Clipper South). RWE Dea holds 70% interest in the Breagh gas field as operator (Sterling Resources UK 30%). With a stake of 50% in Clipper South, RWE Dea is operator with Fairfield Energy and Bayerngas each holding a 25% stake.

Pawel said, "We remain on course to achieve production from the Breagh field less than three years after we acquired operatorship of the Breagh license and expect first gas in the second half of 2012 and from Clipper South in the first half of 2012."

Both platforms are being constructed by the Heerema Fabrication Group. The Breagh platform consists of a jacket approximately 85 meters tall with a total weight of some 4,000 tonnes and topside of approximately 1,400 tonnes. The topsides have been moved out of the shed and are ready for sail-away from Heerema's fabrication yard mid September. The jacket is on schedule for load out early September. The Clipper South platform with topsides weighing 1,900 tonnes has accommodation for 40 persons and sailed away for offshore on Thursday 25th and was successfully installed on Saturday, August 27 with standalone overnight manning on the day of installation – testimony to the very high level of completion on departure from the yard. The Clipper South platform is in a water depth of approximately 23 meters, and a 12" pipeline will connect to the ConocoPhilips operated LOGGS complex for onwards transportation of gas to the Theddlethorpe terminal in the UK.

The Breagh field is located in UKCS blocks 42/12a and 42/13a of the southern North Sea in 62 meters water depth, approximately 100 kilometers east of Teesside. Around 100 kilometers of 20" pipeline have been successfully installed offshore. The platform will be installed by Heerema Marine Contractors.

The field is being developed in two phases. Phase 1 entails gas to be exported via the 20" pipeline from the Breagh Alpha platform to Coatham Sands, Redcar on the UK mainland, and a 10 kilometers onshore pipeline for processing at the Teesside Gas Processing Plant (TGPP) at Seal Sands. The TGPP site is owned by Teesside Gas & Liquids Processing, and after processing at the TGPP, the gas will enter the UK National Transmission System. Phase 2, planned to receive project sanction in late 2011, is expected to include additional wells in the east of the field likely to be drilled from a further Breagh platform tied back to Alpha.

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Oilex Prepares Cambay Well for Clean-Up Ops

- Oilex Prepares Cambay Well for Clean-Up Ops

Wednesday, August 31, 2011
Oilex Ltd.

Oilex advised that operations to prepare for well clean-up flow and production testing are continuing. The coil tubing unit was not able to retrieve milling tools being used to open the second fracture stimulation stage. Consequently, it is planned to mobilize a work-over rig to the well location to retrieve the milling tools. Following this, operations will resume to open up the remaining fracture stimulation stages so that clean-up operations and a flow test can be conducted.

The Cambay-76H "proof of concept" horizontal well is evaluating the production potential of the Y Zone interval of the extensive deep Eocene "tight" reservoirs in the onshore Cambay Production Sharing Contract area, Gujarat, India.

• Report date: August 30, 2011
• Status: Preparations for well clean-up flow and production testing
• Past Week's Operations:
  • Coil tubing operations to retrieve tools
  • Mobilizing chemical cutting equipment
  • Initial planning for work-over rig operations
• Objective: Cambay Eocene "tight" reservoir Y Zone
• Total Depth: 2,740 meters including 610 meters horizontal section

The participating interests in the Cambay PSC are:

• Oilex Ltd (Operator) 30%
• Oilex NL Holdings (India) Limited 15%
• Gujarat State Petroleum Corporation Ltd 55%

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Texon Runs Production Tests at 2nd Eagle Ford Well

- Texon Runs Production Tests at 2nd Eagle Ford Well

Wednesday, August 31, 2011
Global Petroleum Ltd.

Texon has advised that the second Eagle Ford well in which Global has an interest (Tyler Ranch EFS #2H) has tested oil and gas at the rates of 1,488 bopd and 700 mcfgpd (combined 1,605 boepd) through a 16/64" choke at a flowing tubing pressure of 3,000 psi.

The well is located just to the north of the first Eagle Ford well (Tyler Ranch EFS #1H) which had an initial test rate of 1,200 bopd through the same sized choke. Tyler Ranch EFS #2H also has a higher flowing pressure than the first Eagle Ford well. The second Eagle Ford well has been connected for oil and gas production through the EFS #1H production facilities.

Global has a 7.939% working interest (5.95% NRI) in approximately 1,651 acres beneath the Olmos formation including the Eagle Ford Shale. Global's interest in the Leighton prospect also includes a 15% working interest in approximately 873 acres from the surface down to the stratigraphic equivalent of the Olmos formation.

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Cameron to Acquire LeTourneau Technologies Drilling Systems

- Cameron to Acquire LeTourneau Technologies Drilling Systems

Wednesday, August 31, 2011
Cameron

Cameron has agreed to acquire LeTourneau Technologies Drillings Systems and Offshore Products divisions from Joy Global for approximately $375 million in cash. The boards of Cameron and Joy Global Inc. have unanimously approved the transaction, which is subject to customary closing conditions. Closing is scheduled during the 4th quarter of 2011.

LeTourneau is a well established provider of drilling equipment and rig designs and components for both the land and offshore rig markets. LeTourneau's products include elevating systems, skidding systems, cranes, top drives, rotary tables, draw works, mud pumps and rig control and power systems.

"The addition of LeTourneau's portfolio of drilling equipment and rig components adds to our existing products offering and enhances the growth opportunities for our drilling systems platform", said Jack Moore, Chairman and CEO of Cameron. "We welcome the LeTourneau team to the Cameron family and look forward to providing our customers and theirs with a greater suite of products and services." Moore further stated that this acquisition is expected to be accretive to Cameron's 2012 earnings.

Credit Suisse Securities (USA) LLC advised Cameron in connection with the transaction. Porter Hedges LLP are serving as legal advisor.

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