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Oil and Gas Energy News Update

Tuesday, July 26, 2011

Oil & Gas Post - All News Report for Tuesday, July 26, 2011

Tuesday, July 26, 2011


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Commodity Corner: Debt Talks Boost Crude

- Commodity Corner: Debt Talks Boost Crude

Tuesday, July 26, 2011
Rigzone Staff
by Saaniya Bangee

Crude prices briefly passed the $100-mark Tuesday as investors remained uncertain about the U.S. economy.

Tuesday's trading volumes were moderate as oil traders anticipated the upcoming deal. Oil prices fluctuated between $97.76 and $100.62 during the trading session. Republican and Democrat lawmakers are trying to compromise on a deal to raise the federal government's debt ceiling ahead of the Treasury Department's Aug. 2 deadline.

Likewise, the political maneuvering surrounding the debt ceiling prompted the dollar to drop against the euro. Against a basket of six other major currencies, the dollar index fell 0.6 percent to 73.595.

Light, sweet crude for September delivery settled at $99.59 a barrel Tuesday.

In other economic news, consumer confidence rose to 59.5 in July, according to a Conference Board report. In addition, the Commerce Department reported a 5-month high in new single family homes.

Its European counterpart, Brent crude added 34 cents, settling at $118.28 a barrel. Brent prices traded between a range of $116.59 and $118.98 Tuesday.

Meanwhile, natural for August delivery slid lower Tuesday, ending the session at $4.37 per thousand cubic feet. Natural gas prices fluctuated between $4.316 and $4.391 Tuesday.

The front-month contract expires at the close of Wednesday's trading session.

RBOB gasoline added 1.68 cents to settle at $3.15 a gallon. The intraday range was $3.095 to $3.17 Tuesday.

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Precision Drilling Prices Senior Notes

- Precision Drilling Prices Senior Notes

Tuesday, July 26, 2011
Precision Drilling Corp.

Precision Drilling announced that it priced US $400 million aggregate principal amount of 6.5% senior unsecured notes due 2021 (the "notes") in a private placement.

Precision intends to use the net proceeds from the notes offering to fund its capital expenditure program, including its 2011 new build program, and for general corporate purposes.

The notes are being offered to qualified institutional buyers under Rule 144A and may be offered outside the United States pursuant to Regulation S. The notes have not been registered under the U.S. Securities Act of 1933, as amended (the "Securities Act"), and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. This news release shall not constitute an offer to sell or the solicitation of an offer to buy any securities, including the notes, nor shall there be any offer or sale of the notes in any state, or jurisdiction in which such offer, solicitation, or sale would be unlawful.

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Canadian Quantum Acquires Interest in Indian O&G Canada Permit

- Canadian Quantum Acquires Interest in Indian O&G Canada Permit

Tuesday, July 26, 2011
Canadian Quantum Energy Corp.

Canadian Quantum has acquired a 50% interest in an Indian Oil and Gas Canada Permit with Sundance Energy Corporation acquiring the other 50%. The acquisition covers all available P+NG rights underlying the Alexander First Nations Reserve, located in Central Alberta. The Alexander First Nation Permit is comprised of 6,946.17 gross hectares (17,365 gross acres) or approximately 27 sections of land. Sundance, as operator, is in the process of configuring an extensive 3D seismic program that will be shot as soon as possible. The Alexander First Nation lands have the potential for multi-zone light oil and natural gas production at relatively shallow depths with existing infrastructure in the area.

Canadian Quantum's President and CEO, Douglas Brett stated "We are excited to have acquired such a large land position in an area where another oil and gas company has recently announced a discovery well from a zone that we have mapped as being potential on the Alexander First Nation lands."

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Bowood to Resume Production at Armada Well

- Bowood to Resume Production at Armada Well

Tuesday, July 26, 2011
Bowood Energy Inc.

Bowood announced that the Energy Resources Conservation Board ("ERCB") has approved Bowood's application for Good Production Practice ("GPP") for a previously announced oil well at Armada (2-01-17-19w4). The well was shut in on April 19, 2011 after reaching the end of its new oil well production period ("NOWPP") in which ERCB regulations allowed it to produce approximately 15,000 bbls of oil from January 2011 through April 2011. With the GPP approval now in place, the well is able to resume production without regulatory restriction. Prior to being shut in, the well was flowing at a rate of 170 bbls of oil per day (60 bopd net). The Company's working interest in the well is 35%.


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Trafina Cases 2nd McMullen Vertical Well

- Trafina Cases 2nd McMullen Vertical Well

Tuesday, July 26, 2011
Trafina Energy Ltd.

Trafina announced that its second well in the McMullen area of northeastern Alberta has been drilled, cored, tested and cased. Trafina Martin Hills at 5-28-77-25W4 (5-28) was rig-released earlier this week. The rig is expected to be moved to the third location at 11-28-77-25W4 (11-28) this morning, weather permitting.

The 5-28 well encountered 10 meters of Wabasca A sand. Additionally, the two variables necessary for commercial production, pressure and viscosity, have been quantified. A pressure test performed on the well indicates a bottom-hole pressure between 1,850 and 1,910 kilopascals (kpa) and oil recovered from the core has a viscosity of 22,000 to 26,000 centipoises. As disclosed on July 11, 2011, pressure needs to exceed 1,200 kpa and viscosity needs to be less than 50,000 centipoises. Completion operations are underway and first production could occur in early August 2011.

Although the Wabasca zone could be construed to be a blanket sand, it is not a homogenous reservoir. Industry experience has shown that each well drilled may exhibit markedly different characteristics of pay thickness, porosity, water saturation, pressure and viscosity. Therefore, Trafina intends to announce the results of each vertical evaluation well drilled.

The results achieved with the 5-28 bode well for the success of Trafina's business plan for this rapidly developing core area. The initial well drilled in the McMullen area at 16-28 in early July encountered 8.5 meters of Wabasca A sand and will be completed in due course. If the third well at 11-28 provides the same characteristics as 16-28 and 5-28, it is likely that pod development in at least two quarter sections of section 28 will occur later in 2011.

West Pembina, Alberta

At West Pembina, Trafina's second non-operated Cardium horizontal well has reached total depth, albeit late and over budget as a result of drilling problems. It is anticipated that the well will be completed with a multi-stage fracturing operation as soon as time and ancillary services are available. Trafina has a 25 percent working interest in this well. Two additional Cardium wells are planned for the fourth quarter of 2011 and the first quarter of 2012.

Rangeview/Divide, Saskatchewan

Trafina recently increased its working interest in the Rangeview/Divide area of southwest Saskatchewan from 80 to 90 percent. The 10 percent increase is a result of the settlement of debt owed to Trafina by a working interest partner in the Rangeview/Divide properties.

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Shoal Point to Complete Testing Program at Well 3K-39

- Shoal Point to Complete Testing Program at Well 3K-39

Tuesday, July 26, 2011
Shoal Point Energy Ltd.

Shoal Point announced that casing has now been run to a depth of 1711 meters in the 3K-39 well and is being cemented into place. Once this operation is completed (expected to be in the next few days), the current rig in use will be released and a service rig will be brought in to complete the planned testing program.

The next stage of testing, subject to applicable regulatory approvals, will include a test over the open lower carbonate-rich section of the well to the total depth of 1745 meters, from which promising hydrocarbons were encountered during drilling and logging operations. Thereafter it is planned to perforate the casing and test a series of fractured shale zones (between 1325 and 750 meters) which were identified from log analysis and core data, and which, from a series of open-hole closed chamber drill stem tests, indicate significant natural permeability. These planned tests are expected to begin in mid-August and take up to 3 weeks to complete.

At the same time, the Company is waiting for the results of the core analysis being undertaken by Ingrain Digital Rock Physics Lab in Houston, Texas. These results are expected to complement the log analysis carried out by NuTech Energy Alliance. In addition, discussions have commenced with a major petroleum consulting company to prepare an initial resource estimate and 51-101 report.

Financing

Shoal Point has also closed the second tranche of a financing of common share units for the purpose of completion and testing Well 3K-39 on EL 1070. The total amount raised from both tranches of this financing is $2,035,250.

The first tranche of the financing for $535,500 was comprised of 1,785,000 common share units at $0.30 where each unit includes a common share at $0.30 and a 1/2 common share purchase warrant where a full warrant entitles the holder to acquire an additional common share at a price of $0.40 for 18 months. The second tranche of financing for $1,499,750 included 4,285,000 flow through units where each unit is comprised of a flow through common share at $0.35 and a 1/2 common share purchase warrant where a full warrant entitles the holder to acquire an additional common share at $0.40 for 18 months.

In connection with the total financing of $2,035,250, the Company is paying cash fees totaling $122,115 to registered agents and issuing 364,200 broker warrants. Each broker warrant will entitle the holder to acquire an additional common share at a price of $0.30 for a period of 18 months.

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Coastal Says Hello to Non-Executive Director

- Coastal Says Hello to Non-Executive Director

Tuesday, July 26, 2011
Coastal Energy Co.

Coastal announced the appointment of Andrew Cochran as Non-Executive Director of the Company effective from Thursday, July 21, 2011.

Randy Bartley, President & CEO of Coastal commented, "We are pleased to have Mr. Cochran join our Board of Directors. His extensive experience in the international energy industry will be a great asset as Coastal continues to grow as a company."

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Chevron Puerto Rico Fined $600,000

- Chevron Puerto Rico Fined $600,000



Jul 26, 2011

Chevron Puerto Rico(NYSE:CVX) has agreed to improve safety standards at about 100 of its underground storage tank facilities for leakage violations.

The U.S. Environmental Protection Agency says the company will pay a $600,000 fine and has decided to spend $5.2 million in improvements as part of a settlement.

On Tuesday, the agency stated that Chevron plans to install leak detection, monitoring and alarm systems by March 2013.

The settlement arrives as Chevron plans to sell its 187 Texaco stations across the U.S. Caribbean territory.

Chevron has a potential upside of 13.3% based on a current price of $108.24 and an average consensus analyst price target of $122.67.


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Tap Oil's Manora Development On Track

- Tap Oil's Manora Development On Track

Tuesday, July 26, 2011
Tap Oil Ltd.

Tap Oil provided the following update on its Manora Oil Development in the Gulf of Thailand.

Tap's Managing Director/CEO Troy Hayden said, "The Manora development is a highly significant project for Tap. It is expected to more than triple our existing reserves toward the end of 2011 and deliver production and revenue in early 2014.

While much of our current focus in Thailand is on the Manora development, we also see significant exploration potential in the Kra, Hua-Hin and Sattakut basins. These exploration opportunities are being actively pursued with substantial resources committed over the next six to 18 months to define and drill them."

Highlights
  • Potential to more than triple Tap's total company reserves by the end of 2011
  • Final Investment Decision (FID) for Manora expected second quarter of 2012
  • Manora field on schedule for first production in early 2014
  • Active exploration program targeting Manora style prospects in the Kra, Hua-Hin and Sattakut basins

Manora Development Timeline

Since the acquisition, Tap has met regularly with Pearl to monitor progress on the development of the Manora field. Pearl has now set a development schedule for the field with key milestones as follows:
  • 2011 Third Quarter - Field Development Plan (FDP) completed
  • 2011 Fourth Quarter - Fourth Quarter Concept Selection finalized
    • - Award Front End Engineering and Design (FEED)
    • - Tap expects to book reserves
  • 2012 Second Quarter - Final Investment Decision
  • 2012 Third Quarter - Award Engineering Procurement and Construction (EPC) contract
  • 2014 First Quarter - First oil

It is envisaged that construction will commence in 2012 and initial development drilling will occur in 2013. This schedule remains in line with our acquisition assumptions.

Manora Development Concept

The venture has been rigorous in its screening of development options and work continues with the aim of finalizing the concept selection in the fourth quarter of 2011. Tap believes that the likely development concept will be a Central Production and Processing Complex with a Floating Storage and Offtake vessel (FSO).

Following concept selection, the venture will award the contract for FEED and submit the remaining environmental and other regulatory approvals.

Upon completion of the FEED and receipt of key regulatory approvals, the joint venture will make the FID for the field. This is expected to be in the second quarter of 2012.

As the project moves toward FID, the venture will tender the contracts to build the facilities. The construction contracts are expected to be awarded at the same time as the FID is made.

Under this timetable, first production is expected in early 2014.

Reserves and Production

Under Pearl's current development timetable, Tap believes it will be in position to make an initial booking of reserves in late 2011 following concept selection and completion of the Field Development Plan. No further drilling is required to prove reserves.

The reservoirs at Manora are expected to require water flooding to maximize oil recovery. While Tap still carries the 24 mmbbl gross resource (7.2 mmbbls net to Tap) as the likely ultimately recoverable number, it is expected that in late 2011 Tap will be able to book 2P reserves of 20 mmbbls gross (6 mmbbls net to Tap) with the additional 4 mmbbls gross (1.2 mmbbls net to Tap) to be booked once actual field production confirms the effect of waterflood.

It is estimated that production from the field will commence in early 2014 and reach a peak rate of approximately 15,000 bbls per day.

Fiscal Terms

The three concessions that Tap has interests in are governed by the Thailand III Fiscal Regime that was introduced in 1989. The Thailand III Fiscal Regime involves a royalty, special remuneratory benefit (SRB) linked to drilling and income tax at 50%. This all combines to provide the concessionaire with a net take of approximately 15-20% of gross revenues over the life of the project.

Exploration

The joint venture has been focusing its exploration effort on delineating a number of prospects in G1/48 and G3/48 in order to mount a drilling campaign in the second half of 2012.

The venture's exploration effort across these concessions includes the acquisition, processing and interpretation of new seismic, reprocessing of existing seismic and regional geological and geophysical studies.

The Kra 3D seismic survey was acquired in 2007 and interpretation of this data led to the Manora discovery. Tap's interpretation of this data has generated four prospects. Pearl's current interpretation is similar to that of Tap. Deeper objectives have not yet been interpreted.

The venture is currently reprocessing the Kra 3D data using pre stack depth migration (PSDM).

he Kinnaree 3D seismic survey in G1/48 was acquired in early 2011. The fast-track processed data has been received and the interpretation is underway.

Recently the joint venture agreed to two new 3D seismic surveys in G1/48 and G3/48 – Sida and Sattakut. These surveys are aimed at locating similar prospects to Manora and additional prospects in the overlying fluvial section. Pearl is currently finalizing the tendering process and acquisition is expected to commence within the next two months. Acquisition of these surveys will take approximately three months.

The new Sida 3D seismic survey will be conducted over the Hua-Hin basin, adjacent to the existing Hua-Hin survey. The survey will be up to 700 km2 and will straddle G3/48 and G1/48. The larger Sattakut 3D seismic survey will be up to 1,800 km2 and will be over the Sattakut basin and will also straddle G3/48 and G1/48.

In G6/48, Tap is currently assessing the merits of acquiring 3D seismic over the concession. G6/48 contains the Rossukon discovery which is in fluvial sands as is typical for this part of the Gulf. Although Rossukon flowed oil at over 800 bbls per day during test, on current mapping it is not considered large enough for a stand-alone development. Entry into the Year 6 concession period at the end of 2011 involves committing to a well in 2012.

Under the terms of all three of the concessions, 50% of the acreage must be relinquished at the end of concession Year 4. The joint venture submitted its relinquishment plans to the regulator in early 2011. Under the plan, the joint venture retains all of the acreage over the prospective basins. The permit areas outlined in the maps above are prior to any relinquishments.

Concession Partners
  • Pearl Energy (Operator) 60%
  • Northern Gulf Petroleum Pte Ltd 40% (Tap is the 75% owner of Northern Gulf Petroleum)

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Range Resources CEO: Balance Sheet Strongest in Co History

- Range Resources CEO: Balance Sheet Strongest in Co History

Tuesday, July 26, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Range Resources Chief Executive John Pinkerton said Tuesday that the natural gas explorer's balance sheet, fattened by the recent sale of its Barnett Shale assets, is in the best shape it has ever been in.

Range in May sold some 52,000 acres in the Barnett Shale formation near its headquarters in Fort Worth, Texas, to a private buyer for $900 million. Proceeds went toward paying off debt and accelerating drilling in Pennsylvania's prolific Marcellus Shale formation, which accounts for most of Range's production and spending.

"The Barnett sale was hugely important for our company," Pinkerton told investors during a conference call to discuss Range's second-quarter results. "The proceeds generated by the sale are the catalyst for Range becoming internally funded by the end of 2013," so long as natural gas prices don't collapse.

Range ended the second quarter with $290 million cash on hand, no bank debt and no bond maturities until 2017, Pinkerton said.

Range Resources posted second-quarter net profit of $51.3 million, or 32 cents a share, up from $9.1 million, or 6 cents a share, a year earlier. Excluding items, earnings were 27 cents, up from 9 cents. Revenue jumped 60% to $306.6 million on higher oil and gas sales.

Analysts polled by Thomson Reuters expected a profit of 19 cents on revenue of $262 million.

Shares recently traded 2.1% higher at $65.14.

The Barnett Shale accounted for about 20% of Range's output, but accelerated drilling, primarily in the Marcellus, replaced half of the lost Texas production in the second quarter, Pinkerton said. The remaining half should be replaced this quarter, he said.

Range anticipates third-quarter production rising about 3% year-over-year to the equivalent of 515 million to 520 million cubic feet per day, Pinkerton said. Fourth-quarter growth is expected to rise about 13% to between 606/MMcfe and 611/MMcfe per day.

In 2012, Range expects production to grow 25% to 30%, Pinkerton said.

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

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Tesoro Fined For Refinery Violations

- Tesoro Fined For Refinery Violations



Jul 26, 2011

Oil giant Tesoro Corp.(NYSE:TSO) has arranged to pay $500,000 in fines for dozens of air pollution violations at its refinery in Martinez.

The Bay Area Air Quality Management District reported the settlement to the San Antonio-based company on Monday. District officials say emissions from the Golden Eagle refinery often surpassed air-quality standards for carbon monoxide, soot and other pollutants between 2006 and 2009.

The refinery was also fined for failing to fix leaky equipment and failing to correctly sample and monitor pollution during that period. In total, Tesoro collected 46 different citations.

Company spokesman Mike Marcy tells the Contra Costa Times while the violations were regrettable, they were reported by the company for the most part. He also claimed that 40% of them were for paperwork errors.

Tesoro has a potential upside of 12.5% based on a current price of $25.48 and an average consensus analyst price target of $28.67.

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NZEC Completes Drilling Ops at Talon-1 Well

- NZEC Completes Drilling Ops at Talon-1 Well

Tuesday, July 26, 2011
New Zealand Energy Corp.

New Zealand Energy Corp. (NZEC) announced the completion of drilling of the Talon-1 exploration well on the Alton Permit located in New Zealand's Taranaki basin. Completion of the Talon-1 well work program requirements is a condition of NZEC's acquisition of a 50% working interest in the Alton Permit and allows NZEC to become the operator of the Permit. Upon receipt of the consent of New Zealand's Minister of Energy, NZEC will own the 50% working interest in the Alton Permit and NZEC's portfolio in the Taranaki Basin will consist of:
  • Operatorship and 50% working interest in the Alton Permit covering 119,200 (59,600 net) acres with prospective recoverable resources of 34.6 million barrels of oil equivalent (as estimated by AJM Petroleum Consultants effective February 1, 2011)
  • 100% working interest in the Eltham Permit covering 92,467 net acres with prospective recoverable resources of 32.1 million barrels of oil equivalent (as estimated by AJM Petroleum Consultants effective February 1, 2011)

The Talon-1 well location, chosen by the previous operator of the Alton Permit using 2D seismic information, intersected over 75 meters of the targeted Manutahi reservoir with minor amounts of natural gas observed. NZEC has decided to not complete the well at this time, but will use the information obtained from Talon-1 drilling to identify other viable targets and may use 3D seismic to further define the prospect.

NZEC has cash on hand of approximately $2.6 million dollars following the drilling of the Talon-1 well. NZEC will now focus its Alton Permit exploration program on the multi-zone Horoi lead, offsetting the Copper Moki-1 well. The Horoi lead is the largest single lead that NZEC has identified and was one of the main reasons for acquiring the Alton Permit. Both the Copper Moki-1 and the Horoi leads were identified using 3D seismic. NZEC will concentrate its efforts on locations that can be identified on 3D seismic coverage in order to increase the certainty of an economic outcome.

"We continue to expand our knowledge of New Zealand Energy's portfolio of properties," said Bruce McIntyre, President of NZEC. "Now that we have earned our right to become operator of the Alton Permit, we will focus our efforts on completion of the Copper Moki-1 well and look forward to reporting progress to our shareholders as the projects advance."

Copper Moki-1 Update

NZEC has secured the Ensign Rig 6 service rig to carry out completion of its 100% working interest Copper Moki-1 well. Completion of the well will commence within the next 10 days. NZEC plans to perforate and production test approximately 10 meters of net oil pay in the Mount Messenger Formation. Once the Mount Messenger Formation has been tested, the reservoir will be shut in for a pressure build up. NZEC will then production test approximately 15 meters of net natural gas pay in the shallower Urenui Formation, and then shut the well in for pressure build up. NZEC expects to report the results of the well tests by mid-August.

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Galoc JV to Install Improved Mooring at FPSO

- Galoc JV to Install Improved Mooring at FPSO

Tuesday, July 26, 2011
Otto Energy Ltd.

Otto has continued to focus on its Philippines-based portfolio of high quality exploration assets, complemented by oil production from the Galoc field.

Highlights:
  • Galoc production during the quarter of 618,244 bbl gross of crude oil (116,106 bbl net to Otto), with 88% 12-month rolling uptime for the field
  • Exercise of farm-in option by BHP Billiton in SC55 and Otto (through its wholly-owned subsidiary NorAsian Energy Ltd) lodgement of notice to enter drilling exploration sub-phase
  • Completion of Duhat-1/1A exploration well drilling provides strong support for follow up in SC51
  • Completion of 210 km2 high quality 3D seismic acquisition over Lampos and Lampos South prospects in SC69
  • Galoc joint venture approval in July to install an improved mooring and riser system upgrade for FPSO Rubicon Intrepid, crucial to progressing Phase 2 field development

Production

Since the start-up of production in October 2008, the Galoc oil field has produced a total of 7.54 million barrels of crude oil as of 30th June 2011, and delivered 22 offtakes to refinery customers. As at the end of the June 2011 quarter, the field was producing around 6,750 barrels of oil a day

Otto, through its shareholding in the field operator Galoc Production Company WLL (GPC), has commenced pre-planning activities for the further development of the Galoc field with a decision on Phase 2 due to be taken in early 2012.

Exploration and Development

Interpretation of the recently acquired 3D seismic from Service Contract 55, offshore Palawan, has matured the amplitude-supported Hawkeye prospect and a series of large Nido level carbonate prospects. The permit contains a significant number of high quality, large volume prospects that are being quickly matured for drilling by Otto and its partners. The JV has recently elected to enter the next permit sub-phase which requires a commitment well to be drilled prior to August 2012.

Corporate

The Board is currently finalizing negotiations for the appointment of a new CEO and will advise the market accordingly once completed.

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NOV Reports $3.51B in 2Q Earnings

- NOV Reports $3.51B in 2Q Earnings

Tuesday, July 26, 2011
National Oilwell Varco Inc.

National Oilwell Varco reported that for its second quarter ended June 30, 2011 it earned net income of $481 million, or $1.13 per fully diluted share. Earnings per share increased 18 percent compared to both the second quarter of 2010 and the first quarter of 2011. Excluding transaction charges of $4 million pre-tax, second quarter 2011 net income was $484 million, or $1.14 per fully diluted share.

The Company's revenues for the second quarter of 2011 were $3.51 billion, which improved 12 percent from the first quarter of 2011 and 19 percent from the second quarter of 2010. Operating profit for the second quarter of 2011 was $712 million or 20.3 percent of sales, compared to 20.2 percent in the second quarter of 2010 and 20.0 percent in the first quarter of 2011, excluding transaction charges and Libya asset write downs from all periods. Year-over-year second quarter operating profit increased 20 percent, excluding transaction charges. Sequentially, second quarter operating profit increased 13 percent, resulting in operating profit flow-through (change in operating profit divided by the change in revenue) of 23 percent, excluding transaction and restructuring charges.

During the second quarter of 2011 the Company's Rig Technology segment booked $2.96 billion in new orders. Backlog for capital equipment orders for the Company's Rig Technology segment was $7.74 billion at June 30, 2011, up 26 percent from the end of the first quarter.

Pete Miller, Chairman, President and CEO of National Oilwell Varco, remarked, "Our Company achieved strong earnings this quarter, thanks to the hard work of our dedicated employees, who provide great service, quality products, and remarkable technology to the oil and gas industry worldwide, every day. All three segments posted higher sequential and year-over-year revenues, and we were pleased by the record level of bookings into our capital equipment backlog, which increased again this quarter for both land and offshore rigs. The Company continues to expand organically and pursue promising acquisition opportunities, supported by its substantial financial resources and strong technology portfolio."

Rig Technology

Second quarter revenues for the Rig Technology segment were $1.89 billion, an increase of 18 percent from the first quarter of 2011 and an increase of 13 percent from the second quarter of 2010. Operating profit for this segment was $517 million, or 27.3 percent of sales. Revenue out of backlog for the segment increased 24 percent sequentially and increased 11 percent year-over-year, to $1.39 billion for the second quarter of 2011.

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BP's Dudley Says He's Open to Radical Restructuring of Company

- BP's Dudley Says He's Open to Radical Restructuring of Company

Tuesday, July 26, 2011
Dow Jones Newswires
LONDON
by Alexis Flynn

BP hasn't ruled out a major restructuring along the lines of the recent overhaul announced by ConocoPhillips, but the British giant will prosper either way once it gets beyond the current difficult transition period, Chief Executive Bob Dudley said Tuesday.

"We're not ruling it in or out. What we do often is review our portfolio and consider our options," Dudley told reporters.

Speculation has grown in recent weeks as to whether BP might consider following ConocoPhillips (COP) in separating its exploration and production, or upstream, and refining and marketing, or downstream, divisions into different businesses. Those questions took on new immediacy Tuesday after BP reported quarterly earnings that missed expectations due in part to a big drop in oil and gas production. The news drove BP shares down more than 2%.

Dudley Tuesday was non-committal on the Conoco plan, while BP's top refining executive pointed out the two companies have very different downstream profiles.

Analysts and some shareholders have argued that a major ConocoPhillips-style shakeup would lead to an immediate improvement in the value of BP stocks, which has lost a third of its value since the Deepwater Horizon disaster last year.

Dudley insisted that BP was capable of radical change if needed. Dudley said he was "committed to seeing the true value of the business more strongly reflected in our share price," but that 2011 was a "year of consolidation," as BP recovered from the fallout of the Gulf of Mexico oil spill.

But head of refining and marketing Iain Conn made it clear Tuesday that the company still believes refining can be a good business. "If you look at Conoco's downstream earnings per unit of throughput, its about half ours," said Conn.

"We're a very different downstream company, we have a global downstream company unlike Conoco, which is largely a U.S. one, and we have large sources of growth in that downstream company," said Conn.

While BP said plans to sell its U.S. Texas City and Carson refineries were progressing, Dudley said Tuesday it planned to invest $1 billion over the next five years in modernizing the Whiting refinery in Indiana.

Separately, Chief Financial Officer Byron Grote said the BP's completion of the $30 billion divestment program aimed at recovering some of the costs from the Gulf of Mexico doesn't necessarily mean it will cease asset sales. BP has so far sold about $25 billion in assets of the $30 billion it has targeted since the U.S. Gulf accident.

"We will continue to actively look at the portfolio. The end of the $30 billion doesn't mean the end [of our asset sales]," said Grote.

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

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Tie-In Boosts Kulczyk Oil's Ukraine Gas Production

- Tie-In Boosts Kulczyk Oil's Ukraine Gas Production

Tuesday, July 26, 2011
Kulczyk Oil Ventures Inc.

Kulczyk Oil announced that total gas production on its properties in Ukraine has increased by 70% to more than 10 million cubic feet per day ("MMcf/d") (more than 7 MMcf/d net to KOV), as a result of the tie-in of the M-19 discovery well in the Makeevskoye Field.

Highlights
  • M-19 well initial average gas production rate in excess of 5.5 MMcf/d (3.85 MMcf/d net to KOV) since tie-in;
  • Projected production rate for the remainder of 2011 from the M-19 well is a minimum of 4 MMcf/d (2.8 MMcf/d net to KOV);
  • The tie-in of the M-19 well has increased the gas production by almost 70% from an average of approximately 6 MMcf/d (4.2 MMcf/d net to KOV) for the first six months of 2011 to the current rate of more than 10 MMcf/d (more than 7 MMcf/d net to KOV).

Timothy M. Elliott, the President and Chief Executive Officer of KOV, stated that "we have substantially increased production from our Ukraine assets since closing the acquisition in June 2010 and are very pleased that KUB-Gas is already producing more than 10 MMcf/d before the end of July. We are confident that we will meet or exceed our target of exiting 2011 with a production rate for KUB-Gas of 12 MMcf/d (8.4 MMcf/d net to KOV). KOV will continue with its active development program in the Ukraine during the coming year and we expect to have a number of new locations defined once the 3D seismic surveys recently completed at Makeevskoye and Olgovskoye are processed and interpreted. The successful start-up of gas production from the newly discovered zone in the M-19 well has confirmed the effectiveness of modern seismic interpretation techniques in the identification of new exploration targets".

The M-19 well

The M-19 exploration well was drilled in the second half of 2010 to a total depth of 2,060 metres and tested gas at a rate of approximately 5 MMcf/d in January 2011 before being suspended pending completion of a pipeline to tie the well to the production facilities of KUB-Gas LLC ("KUB-Gas"). The pipeline was completed and all regulatory approvals required for the commercial production of the well were obtained prior to the start of production on July 11, 2011.

Average gas production from the M-19 well was 5.52 MMcf/d (3.86 MMcf/d net to KOV) since the first full day of production on July 11, 2011. It is presently anticipated that production rates from the well will stabilize at a lower rate and average about 4.0 MMcf/d for the remainder of 2011. The successful tie-in of the M-19 well to production facilities has increased total KUB-Gas production from its four producing gas licenses in Ukraine to an average of 10.73 MMcf/d (7.51 MMcf/d net KOV) during the 10 producing days ended July 24th.

The estimated selling price per thousand cubic feet ("Mcf") in the second quarter of 2011 was approximately US $9.00 per Mcf with as estimated netback of US $5.80. The netback during the first quarter of 2011 was US $4.77 per Mcf. The final financial information with respect to the second quarter will be released in mid-August.

The M-19 well was the first well operated by KUB-Gas logged with western logging tools. By comparing the Ukrainian and western logging data over the same formations, the Company is developing a methodology to better understand and analyze existing Ukrainian log data with a view to more effectively evaluating the potential of the area.

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TNK-BP Touts Financial Results for 1H 2011

- TNK-BP Touts Financial Results for 1H 2011

Tuesday, July 26, 2011
TNK-BP

TNK-BP reported its results for the first half of 2011.

Commenting on the results, Mikhail Fridman, Executive Chairman of TNK-BP Ltd., said, "This was an exceptional first half performance for TNK-BP. Thanks to management's continuous efforts to enhance operational efficiency and further develop our key business streams, the Company was able to deliver robust results. We have increased production, significantly expanded our resource base and nearly doubled net profit for the period. Growing our international business is a key priority for TNK-BP and we've made great progress thus far in 2011 by closing the deal to acquire BP's upstream assets in Venezuela and identifying several additional acquisition targets abroad."

1H11 OPERATIONAL HIGHLIGHTS
  • In 1H11, oil and gas production (excluding JVs) continued to grow and reached 1,765 mboe/d, up 1.2% on 1H10. This growth was primarily driven by further production increases at our producing greenfields, Uvat and Verkhnechonskoye, and also by continued success in developing our Orenburg fields as well as increasing gas production at Rospan. We have developed and started implementation of a long-term West Siberia efficiency improvement program targeting a decrease in the annual production decline rate from the current 7% to approximately 2-3% per year.
  • We have made good progress in our exploration and appraisal program aimed at growing the company’s resource base. Over 200 million boe of resources were added in 1H11 through exploration and appraisal. We have also demonstrated our ability to obtain new acreage by successfully acquiring 3 licenses through the federal auctions in the Orenburg region with estimated resources of 149 million boe.
  • On the international front, we have closed the acquisition of upstream assets from BP in Venezuela in June, while the Vietnam deal close is expected in 3Q pending approval by the Vietnamese Ministry of Industry and Trade. We will now focus on the integration of these assets into our portfolio and ensuring their operational and financial efficiency. We have also just announced the signing of a Farm-out Agreement with Brazilian Petra Energia for the acquisition of a 45% stake in 21 blocks in the Brazilian Solimoes Basin. We hope to have the necessary agreements finalized before the end of August.
  • Refining throughput was at 761 mb/d, increasing 11% y-o-y as a result of continuing debottlenecking efforts.
  • We have progressed with expansion of our retail chain by opening the first two new-format highway service stations under the BP brand in Tver region within the framework of our long-term retail business development strategy. Opening these new service stations is the first step in implementing a strategy to develop highway retail sites in the European part of Russia. The operations of the sites have been very successful with initial fuel sale volumes exceeding the plan by 2-3 times.
  • We also continued to reinforce our position in B2B by signing a long-term formula-based jet fuel supply agreement signed with Transaero Airlines, in line with the company’s strategy to strengthen its presence in Russia’s jet fuel market and increase transparency of fuel sales.
  • Finally on the corporate side, we have embarked on an important initiative of improving the organizational structure of our business, led by Deputy Chairman of the Management Board, Maxim Barskiy. This involves switching from an asset-based management system, where local management has both wide functional and operational responsibility, to a functional governance model (or matrix model), with clear segregation of functions and more streamlined decision making. The first practical steps of this transition were the integration of Technology and Supply Chain Management streams into Upstream, as well as development and enactment of the new Delegation of Authority Matrix. The new organizational structure will improve decision-making, focus local management on its area of expertise, and improve our competitive advantage, as we continue our transformation into a global oil and gas player.

Commenting on the financial results, Jonathan Muir, Chief Financial Officer of TNK-BP Ltd., said, "In the first half 2011, TNK-BP continued to demonstrate strong financial results, supported by a favorable market environment, sustainable production growth and refinery throughput improvement. EBITDA increased by 59% y-o-y to USD 7.4 bn, underpinned by a 42% rise in the oil price, partially offset by cost increases due to higher excise rates, rising electricity and transportation tariffs, and continuing rouble appreciation. Our net income increased by 87% y-o-y to USD 4.5 bn on the back of EBITDA growth. Healthy cash flows from operations allowed us to raise organic capital expenditure by 33% y-o-y to USD 2.2 bn with particular focus on our key growth assets: Uvat, Verkhnechonskoye and Orenburg. Our financial discipline remained strong with good cash flow and successful debt portfolio management giving us the flexibility to pursue strategic inorganic opportunities."

1H11 FINANCIAL HIGHLIGHTS
  • Revenues for 1H11 increased by 41% relative to 1H10 reflecting a 42% higher Urals price and 21 mboe/d (1.2%) production growth partly offset by a decrease of export sales in favor of the domestic market to avail of higher netbacks.
  • Export duties and taxes other than income tax increased by 38% for 1H11 relative to 1H10 as a result of the impact of higher Urals prices on export duty and mineral extraction tax rates as well as the growth in excise rates in Russia partly offset by a significant duty lag benefit.
  • Underlying materials, service and payroll inflation on cash costs amounted to only 4% year-on-year. However, electricity and transport tariff growth inflated cash costs by 8%. Rouble appreciation added 4% year-on-year. In addition, a one-off increase on an environmental provision in 2Q11 related to reassessment of some legacy issues increased costs by 3%.
  • EBITDA for 1H11 amounted to USD 7.4 bn which is 59% higher compared to 1H10 largely due to the higher prices and duty lag benefit supported on the operations side by higher production and sales volumes. These positive factors were partly offset by a negative exchange rate impact as well as tariff and excise rates growth.
  • 1H11 Net income amounted to USD 4.5 bn which is 87% up on the same period of 2010. This increase outpaced the EBITDA growth primarily due to relatively flat DD&A.
  • Operating cash flow for 1H11 totaled USD 5.9 bn, up 51% compared to 1H10. This is a reflection of the higher EBITDA (adjusted for non-cash provisions), partly offset by a USD 0.5 bn increase in working capital primarily due to a price-driven growth in inventory and accounts receivable balances.
  • Net debt increased by USD 0.6 bn compared to year end 2010 resulting in gearing growing to 22%.
  • Organic capital investment in 1H11 amounted to USD 2.2 bn, 33% above 1H10, largely associated with increased investments in our growth greenfields (VCNG, Uvat) and Orenburg.

2Q11 RESULTS
  • Revenues for 2Q11 increased by 11% relative to 1Q, reflecting primarily the increase in Urals price.
  • Export duties and other taxes increased 20% q-o-q driven by a 12% increase from the price effect on export duties and MET and a decrease in duty lag benefit in 2Q, partly offset by the effect of lower export sales volumes.
  • Cash costs (operating expenses, transportation and SG&A) increased by 15% largely due to rouble appreciation, increase in wellwork, contracting and other activities compared to a seasonally slower 1Q as well as increased environmental provisions.
  • EBITDA for 2Q11 was 12% lower compared to 1Q. The most significant reason is the decrease of duty lag benefit further exacerbated by price-driven growth in duties, taxes and costs of purchases that effectively eliminated all q-o-q benefit of higher prices on revenues. Other factors include a comparative negative impact of one-offs - disposal gains in 1Q and higher provisions in 2Q, as well as rouble appreciation and increased spending on well-work together with annual wages and salary indexation and Moscow offices relocation cost.
  • 2Q11 Net Income decreased by 14%, generally following the EBITDA trend.
  • Operating cash flow in 2Q increased by 55% compared to 1Q attributed primarily to lower working capital. This is mainly due to a comparative USD 1.3 bn reduction in accounts receivable balances driven by a general decrease of trade accounts receivable due to lower crude export sales in June as well as shorter receivables collection terms.
  • Organic capital investments were $0.4bn higher than in 1Q11, representing primarily a seasonally higher activity level.
  • Compared to the 2Q 2010 results, 2Q 2011 EBITDA and net income increased by 45% and 81%, respectively. This reflects a stronger external environment with the Urals price increasing by 48% and a higher duty lag benefit supported by an increase in trading volumes and an improvement in trading mix, including in particular a 6% higher share of refined products. These positive factors were partly offset by the effect of a stronger rouble and inflationary pressure on costs and a USD 0.1 bn comparative net loss related to one-off impacts.

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Drilling Commences at Cooper's Rincon Well

- Drilling Commences at Cooper's Rincon Well

Tuesday, July 26, 2011
Cooper Energy Ltd.

Cooper reported that the Rincon-1 exploration well in PEL 92 spudded at 1400 hours on Friday, July 22, 2011. The surface hole has been drilled to 700 meters and 9 5/8" surface casing was run and cemented. The current operation is making preparations to drill ahead 8 1/2" hole.

The well's primary objective is the Namur Sandstone with secondary objectives in the Birkhead, Hutton and Poolowanna Formations. Rincon-1 is located 19 km northwest of the Callawonga oil field and 9.6 km northwest of the Hanson-1 oil discovery well in PEL 91. Rincon-1 will be drilled to a total depth of about 1,886 meters and is expected to take about 10 days to drill and evaluate.

The primary objective Namur Sandstone, which is the oil reservoir in the nearby oil fields, is estimated to contain 0.551 million barrels of Prospective Resources (P50). The deeper formations would be expected to add to this estimate if they result in discovery.

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OXY 2Q Earnings Up 17%

- OXY 2Q Earnings Up 17%

Tuesday, July 26, 2011
Occidental Petroleum Corp.

Occidental Petroleum Corporation announced core income of $1.8 billion ($2.23 per diluted share) for the second quarter of 2011, compared with $1.1 billion ($1.32 per diluted share) for the second quarter of 2010. Net income was $1.8 billion ($2.23 per diluted share) for the second quarter of 2011, compared with $1.1 billion ($1.31 per diluted share) for the second quarter of 2010.

In announcing the results, Stephen I. Chazen, President and Chief Executive Officer, said, "The second quarter 2011 net income of $1.8 billion was an increase of 17 percent over the first quarter results. Improved earnings in all of our business segments resulted in a six month, year-to-date cash flow from operations of $5.6 billion and an annualized return on equity of 20 percent. Our second quarter domestic oil and gas production grew 11 percent from the second quarter of the prior year to 424,000 BOE per day."

QUARTERLY RESULTS

Oil and Gas

Oil and gas segment earnings were $2.6 billion for the second quarter of 2011, compared with $1.9 billion for the same period in 2010. The increase in the second quarter of 2011 earnings was due mainly to higher crude oil prices.

For the second quarter of 2011, daily oil and gas production volumes averaged 715,000 barrels of oil equivalent (BOE), compared with 701,000 BOE in the second quarter of 2010. As a result of higher year-over-year average oil prices and other factors affecting production sharing and similar contracts, production was reduced in the Middle East/North Africa and Colombia by 11,000 BOE per day, with another 1,000 BOE per day reduction at THUMS in Long Beach.

The second quarter 2011 production volume increase was a result of 42,000 BOE per day higher domestic volumes, partially offset by reduced volumes in the Middle East / North Africa. The domestic increase was mainly from the new acquisitions in South Texas and the North Dakota Williston Basin. The Middle East/North Africa was lower primarily due to the lack of production in Libya and price impacts on production sharing contracts, partially offset by production from Iraq coming on line in 2011 and higher volumes from the Mukhaizna field in Oman.

Daily sales volumes remained flat at 705,000 BOE per day in the second quarter of 2011, compared with 705,000 BOE per day in the second quarter of 2010. The 2011 sales volumes were lower than the production volumes due to the timing of liftings in Iraq, Qatar and Oman.

Second quarter realized prices improved for all products on a year-over-year basis. The price for worldwide crude oil was $103.12 per barrel for the second quarter of 2011, compared with $74.39 per barrel for the second quarter of 2010. The second quarter of 2011 realized oil price represents 101 percent of the average WTI price for the quarter. Worldwide NGL prices were $57.67 per barrel in the second quarter of 2011, compared with $44.08 per barrel in the second quarter of 2010. Domestic gas prices increased from $4.19 per MCF in the second quarter of 2010 to $4.27 per MCF for the second quarter of 2011.

SIX-MONTH RESULTS

Year-to-date 2011 core results were over $3.4 billion ($4.19 per diluted share), compared with $2.2 billion ($2.67 per diluted share) for the same period in 2010. Net income for the first six months of 2011 was $3.4 billion ($4.13 per diluted share), compared with $2.1 billion ($2.61 per diluted share) for the same period in 2010.

Oil and Gas

Oil and gas segment earnings were $5.1 billion for the six months of 2011, compared with $3.7 billion for the same period of 2010. The $1.4 billion increase in the 2011 results reflected higher crude oil and NGL prices and higher sales volumes, partially offset by higher operating costs and DD&A rates.

Daily oil and gas production volumes for the six months were 723,000 BOE per day for 2011, compared with 701,000 BOE per day for the 2010 period. Higher year-over-year average oil prices and other factors affecting our production sharing and similar contracts lowered our Middle East/North Africa, Long Beach and Colombia production by 14,000 BOE per day.

Domestic volumes increased primarily due to new operations in South Texas and the Williston Basin, partially offset by lower gas volumes in California. The Middle East/North Africa's production declined due to impacts of price and other factors on production sharing contracts, lower production in Libya and planned maintenance in Dolphin. Partially offsetting these declines were increases from the new production in Iraq and higher production in the Mukhaizna field in Oman.

Daily sales volumes were 717,000 BOE in the first six months of 2011, compared with 695,000 BOE for 2010.

Oxy's realized prices improved for crude oil and NGLs but declined for natural gas on a year-over-year basis. Worldwide crude oil prices were $97.38 per barrel for the six months of 2011, compared with $74.24 per barrel for the six months of 2010. Worldwide NGL prices were $55.38 per barrel for the six months of 2011, compared with $45.73 per barrel in the six months of 2010. Domestic gas prices declined from $4.90 per MCF in the six months of 2010 to $4.24 per MCF in the six months of 2011.

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Ford Topped Q2 Estimates, Top Line Up 16%, Maintained FY Industry Volume Estimate

- Ford Topped Q2 Estimates, Top Line Up 16%, Maintained FY Industry Volume Estimate



Jul 26, 2011

Ford (NYSE:F) reported Q2 EPS of $0.65, ex-items, ahead of consensus estimates of $0.60 per share. Auto sector revenues rose 16.3% year-over-year to $33.5 billion, topping consensus estimates of $31.6 billion.

The company expects full year industry volume of 13 to 13.5 million units, in line with its previous estimate.

Chairman and CEO Mike Bannister said, "Ford Credit's business continues to perform well, with low credit losses and strong originations capability. We continue to succeed in our mission to support Ford sales."

Ford Motor has a potential upside of 49.3% based on a current price of $13.17 and an average consensus analyst price target of $19.67.

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Weatherford Reaches Record Revenues in 2Q11

- Weatherford Reaches Record Revenues in 2Q11

Tuesday, July 26, 2011
Weatherford International Ltd.

Weatherford reported second quarter 2011 income of $126 million, or $0.17 per diluted share, excluding an after-tax loss of $16 million. On a GAAP basis, our net income for the second quarter of 2011 was $110 million, or $0.15 per diluted share. The excluded after-tax loss is comprised of $13 million in severance and exit charges and $3 million in government investigation costs.

Second quarter diluted earnings per share reflect an increase of $0.09 over the second quarter of 2010 diluted earnings per share of $0.08, before charges. Sequentially, the company's second quarter diluted earnings per share, before charges, were $0.07 higher than the first quarter of 2011. International markets drove the entire sequential improvement in both revenue and profitability.

Second quarter revenues of $3.052 billion were the highest in the company's history, despite the severe negative impact of Canada's spring break-up. Revenues were 25 percent higher than the same period last year and seven percent higher than the prior quarter. International revenues were up 14 percent sequentially and up 12 percent versus the year ago quarter. North America revenue was down one percent sequentially and up 46 percent versus the second quarter of 2010. The sequential decline in North America was due to the severe impact of the Canadian break-up. The Canadian results overshadowed a very strong performance in the U.S., where sequential revenue growth outpaced rig count by more than two-to-one and operating margins expanded.

Segment operating income of $421 million improved 36 percent year-over-year and 19 percent sequentially. The company's international operations provided all of the sequential growth compared to the first quarter of 2011 and delivered 51 percent incremental margins. International operating income was down three percent compared to the year ago quarter.

The company expects earnings per share before excluded items of approximately $0.24 to $0.26 in the third quarter of 2011, supported by a seasonal recovery in Canada and steady improvement in the U.S. and international markets. For full-year 2011, the company anticipates that revenue growth will be approximately 25 percent, which is higher than the 20 percent growth rate estimated last quarter. In addition, the company expects international margins in the fourth quarter of 2011 to be meaningfully higher than full-year 2010 margins of 11 percent.

North America

Revenues for the quarter were $1.344 billion, which is a 46 percent increase over the same quarter in the prior year and down one percent sequentially. The Stimulation and Chemicals, Artificial Lift and Well Construction product lines contributed strong results for the quarter.

The current quarter's operating income was $244 million, up $117 million from the second quarter of 2010 and was down $40 million, or 14 percent, compared to the prior quarter. On a sequential basis, strong growth and steadily expanding margins in the U.S. were offset by the impact of the Canadian break-up.

Middle East/North Africa/Asia

Second quarter revenues of $617 million were two percent higher than the second quarter of 2010 and seven percent higher than the prior quarter. Weather improvements in China and Australia and a stronger Iraq helped offset the impact of a full quarter of reduced activity due to political unrest in the Middle East and North Africa. Libya operating expenses cost almost $0.01 per share. The Well Construction, Integrated Drilling and Artificial Lift product lines posted strong sequential performances.

The current quarter's operating income of $34 million decreased 54 percent as compared to the same quarter in the prior year and increased $23 million compared to the first quarter of 2011.

Europe/West Africa/FSU

Second quarter revenues of $592 million were 17 percent higher than the second quarter of 2010 and 16 percent higher than the prior quarter. The region had strong performances in the North Sea, Russia and Caspian as the winter seasonality abated. The Completion, Stimulation and Chemicals, Drilling Services and Integrated Drilling product lines had the strongest sequential growth.

The current quarter's operating income of $93 million was up 37 percent compared to the same quarter in the prior year and up $55 million compared to the prior quarter.

Latin America

Second quarter revenues of $498 million were 21 percent higher than both the second quarter of 2010 and the first quarter of 2011. Argentina, Colombia and Venezuela posted strong sequential performances. The Drilling Services, Stimulation and Chemicals and Artificial Lift product lines benefited from improved demand.

The current quarter's operating income of $51 million increased 22 percent as compared to the same quarter in the prior year and increased $30 million compared to the prior quarter.

Liquidity and Net Debt

Net debt for the quarter increased $144 million, with working capital increasing $193 million during the quarter. Recently, the company successfully renegotiated its unsecured revolving credit facility to increase the size of the facility from $1.75 billion to $2.25 billion and extend the scheduled maturity to July 16, 2016.

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Idemitsu Petroleum Drills Duster in North Sea

- Idemitsu Petroleum Drills Duster in North Sea

Tuesday, July 26, 2011
Norwegian Petroleum Directorate

Idemitsu Petroleum Norge, operator of production license 377 S, has completed the drilling of wildcat well 35/7-1 ST2. The well was drilled about seven kilometers west of the Vega field in the North Sea.

The primary exploration target for the well was to prove hydrocarbons in Middle Jurassic reservoir rocks (the Brent group). The secondary exploration target was to prove hydrocarbons in the Cook formation from the Early Jurassic Age. The well encountered both the Brent group and the Cook formation, but both had poorer reservoir quality than expected. Data acquisition and sampling have been carried out, and this has been classified as a dry well.

The well is the first wildcat well in production license 377 S, which was awarded in APA 2005.

The well was drilled to a vertical depth of 4773 meters below the sea surface, and was terminated in the Dunlin group from the Early Jurassic Age. The water depth at the site is 386 meters. The well will now be permanently plugged and abandoned.

Well 35/7-1 ST2 was drilled by the Aker Barents drilling facility, which will now proceed to production license 482 in the Norwegian Sea.

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TGS Extends Seismic Acquisition in Barents Sea

- TGS Extends Seismic Acquisition in Barents Sea

Tuesday, July 26, 2011
TGS-NOPEC Geophysical Co. ASA

TGS has commenced the acquisition of an extension of its multi-client 3D seismic data in the Hoop Fault Complex area of the Barents Sea. This extension is to the west of the previously announced industry funded Hoop Fault Complex survey and will add 3,391 km2 to the existing data in the area. Upon completion of the expanded project, TGS will have over 7,300 km2 of contiguous multi-client 3D data over the Hoop Fault Complex. In conjunction with this multi-client survey, TGS will also acquire approximately 1,100 km2 of seismic data on a proprietary basis for a TGS customer.

Acquisition of the data will be performed by the M/V Polar Duke towing 10 x 6,000 m streamers with 75 m cable separation and acquisition is scheduled to complete during early 4Q 2011. Data processing will be performed by TGS and will be available to clients from 2Q 2012.

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BP Shares Drop after Earnings Miss Expectations

- BP Shares Drop after Earnings Miss Expectations

Tuesday, July 26, 2011
Dow Jones Newswires
LONDON
by Alexis Flynn

BP faced fresh scrutiny from investors Tuesday after quarterly earnings beat last year's level but came in below expectations following a big drop in oil and gas production.

BP posted a 12% rise in adjusted profit for the second quarter as it benefited from higher crude prices and better refining margins. But oil and gas production fell a whopping 11% compared with the 2010 quarter due in part to anemic output in the Gulf of Mexico and unexpected maintenance in the North Sea and Angola.

BP shares were down 11 pence to 464p at 803 GMT, the biggest drop Tuesday morning in the FTSE 100. Analysts also had pointed questions on the slow resumption of BP activities in the Gulf of Mexico, its growth strategy after the demise of a major proposed deal in Russia and the effectiveness of much-touted safety upgrades following a recent fire in the North Sea that has further crimped output.

The U.K.-based energy giant said its clean replacement cost of supplies, a keenly-watched figure that strips out gains or losses from inventories and other non-operating items, for the three months ended June 30 totaled $5.60 billion, compared with $4.98 billion for the second quarter of 2010.

This was below expectations of $6.04 billion in a Dow Jones Newswires poll of 11 analysts. BP said this was due to the loss of production from high-margin areas, such as Angola and the North Sea.

BP Chief Executive Robert Dudley said the company is "making rapid progress" and that the results are in line with expectations that 2011 would be a "year of consolidation" after the travails of recent years.

Total oil and gas production was 3.43 million barrels a day, a decline of almost 11% on the year. BP said that after adjusting for acquisitions and divestitures and entitlement impacts from production agreements, the output decrease was 7% compared with the same period of 2010.

"BP appears to be running a business as usual strategy and we are not convinced that the market will put up with this for much longer," said analyst Dougie Youngson from Arbuthnot Securities. "BP has been significantly under-performing the peer group for some time and this looks set to continue."

Royal Bank of Canada analyst Peter Hutton said investors are anxious about BP's difficulty controlling costs compared with peer companies. A complicating factor is the slow progress in resuming operations in the U.S. Gulf, Hutton added. "Other operators are getting things through and BP has a sum total of zero approvals," Hutton said. "When you rank BP against the others, it is quite stark."

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

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BG 2Q Earnings Double on Commodity Prices, Output

- BG 2Q Earnings Double on Commodity Prices, Output

Tuesday, July 26, 2011
BG Group plc

BG Group reported its second quarter and half year results for 2011.

Second Quarter Key Points
  • Earnings up 27%; cash generated by operations up 11%
  • Interim dividend of 10.8 cents per share, up 10%
  • Reserves and resources doubled in Brazil since 2010; upside potential now 8 billion boe net
  • Brazil reservoir performance significantly reduces unit costs; unit resource value increased
  • Lifted first one million barrels of equity oil from Lula field
  • Assumed operatorship offshore Tanzania; agreements to operate offshore Kenya

BG Group's Chief Executive, Sir Frank Chapman said, "We made good progress in both our E&P and LNG businesses. In Brazil, we saw major increases in our reserves and resources; with the new resources delivering a higher unit value as their production is expected to require no additional surface facilities. We have invested $4.4B in organic growth in the first half and made good progress across our major growth projects in Australia, Brazil and the USA; progress that continues to de-risk the delivery of our growth program."

Second quarter

Revenue and other operating income increased by 26% to $5.115 billion, reflecting the benefit of higher commodity prices and a 3% increase in E&P production, with solid operational performance across the Group's assets.

As a result of the above and a lower exploration charge in the quarter, total operating profit increased by 43% to $2.152 billion.

Cash generated by operations increased by 11% to $2.581 billion as a result of higher profits and, as anticipated, the partial reversal of prior period margin calls on the Group's hedged LNG contracts.

As of 30 June 2011, the Group's net debt was $9.468 billion with an average maturity of around 8 years, and the gearing ratio was 24%. During the quarter, BG Group signed a cooperation agreement with Bank of China that allows for up to $1.5 billion of new funding alternatives to support the Group's major growth programme. The Group's undrawn committed facilities have been increased to $5.5 billion with maturities from 2012 to 2016.

Net finance costs amounted to $59 million for the quarter, against $25 million income in 2010, including foreign exchange gains of $7 million (2010 $71 million gain).

Capital investment (including acquisitions of $113 million) in the quarter was $2.537 billion and comprised investment in E&P ($1 918 million), LNG ($537 million) and T&D ($82 million). This investment focused primarily on the Group's major growth projects in Australia, Brazil and the USA and represents a 58% increase in underlying organic capital investment compared with second quarter 2010. More details on project developments are provided in the relevant segmental business highlights.

Half year

Revenue and other operating income of $9 918 million was 16% higher than in the same period in 2010, reflecting 48% and 14% increases in realised oil and gas prices, respectively. This revenue performance, combined with a lower exploration charge, was the main contributor to the 19% increase in total operating profit from $3.456 billion to $4.117 billion.

Cash generated by operations of $4.380 billion was 9% lower than last year, principally as a result of changes in working capital associated with margin calls on the Group's hedged LNG contracts. As already observed, the cash outflow associated with margin calls has reversed in the second quarter, a trend that is expected to continue in future periods when the underlying LNG contracts settle.

The $153 million increase in net finance costs was driven primarily by changes in foreign exchange (2011 foreign exchange losses of $15 million compared with a $122 million gain in 2010).

The Group's effective tax rate (including BG Group's share of joint venture and associates' tax but excluding prior period taxation) for the full year is expected to be 45% (2010 38.5%). The increase is primarily as a result of the change in UK North Sea taxation announced in March 2011. This led to an additional charge of $324 million consisting of a $121 million charge for the half year in addition to a one-off tax charge of $203 million in respect of the revision of opening deferred tax balances. The one-off charge was partially offset by an $8 million credit as a result of a reduction in the UK taxation rate applicable outside the UK North Sea (net $195 million). The Group's effective tax rate in future years is expected to be 43% to 44% in the near term and trend downwards thereafter as more of the Group's profits are generated from outside of the UK North Sea.

As previously announced, the Group is undertaking an extensive investment programme to deliver its growth. Capital investment in the half year (including acquisitions of $432 million) was $4 833 million and comprised investment in E&P ($3.744 billion), LNG ($936 million) and T&D ($153 million). This investment focused primarily on the Group's major growth projects in Australia, Brazil and the USA and represents a 28% increase in underlying organic capital investment compared with 2010. This expenditure is in line with the Group's previous guidance of $10 billion for the full year at reference conditions.

In line with the Group's financial performance, the Board has approved the payment of an interim dividend of 10.80 cents per share. This is half of the 2010 total dividend, in accordance with the Board's established policy. The interim dividend has been converted to Sterling at the average of the closing exchange rate for the three business days preceding this announcement and will be paid on 8 September 2011 as 6.63 pence per share to shareholders on the register as at August 5, 2011.

Disposals, re-measurements and impairments - continuing operations

A post-tax gain of $123 million for the quarter (2010 $443 million charge) was recorded in respect of disposals, re-measurements and impairments. This comprised a post-tax gain of $121 million (2010 $302 million charge) in relation to mark-to-market movements on long-term commodity contracts and economic hedges, a $24 million post-tax gain in respect of disposals of non-current assets and impairments (2010 $135 million charge) and a $22 million post-tax charge (2010 $6 million charge) in respect of re-measurements of treasury financial instruments.

A post-tax charge of $100 million for the half year (2010 $377 million charge) was recorded in respect of disposals, re-measurements and impairments.

Exploration and Production (E&P)

Second quarter

Revenue and other operating income increased by 35% to $2 787 million, reflecting the benefit of higher realized prices and a 3% increase in production volumes. Total operating profit of $1.420 billion was 90% higher as a result of the increase in revenue and other operating income and a lower exploration charge.

Higher production volumes in the quarter reflected continuing production build-up in the USA, Brazil and at Hasdrubal in Tunisia. In the UK North Sea, the Everest, Lomond and Erskine fields progressively returned to production following the shutdown in the first quarter. BG Group expects Buzzard to return to full capacity in the third quarter following a period of restricted production. Whilst there continued to be sporadic disruption from social unrest in Egypt and Tunisia, this had a relatively small impact on production in the second quarter.

BG Group continues to expect modest production growth in 2011, ahead of the strong ramp-up in production volumes which begins in 2012 and continues through the decade.

International gas price realizations were 17% higher at 39.02 cents per produced therm, reflecting changes in the production mix and the effects of higher oil prices. The average realized gas price in the UK increased by 48% to 44.43 pence per produced therm, as a result of higher contract and market prices.

The exploration charge of $120 million is $246 million lower than 2010 as a result of lower well write-off costs.

Unit operating expenditure increased to $8.93 per barrel of oil equivalent, reflecting the impact of higher commodity prices, adverse foreign exchange movements and changes in the production mix, including higher than portfolio average costs associated with the production start-up activities in Brazil. BG Group continues to expect unit operating costs to be between $8.50 and $9.00 per barrel of oil equivalent at an oil price of around $100 per barrel for the full year.

Capital investment of $1 918 million in the quarter comprised investment in the Americas ($673 million, including $113 million on acquisitions), Australia ($496 million), Europe and Central Asia ($443 million) and Africa, Middle East and Asia ($306 million).
Half year

Revenue and other operating income increased by 22% to $5.297 billion, principally as a result of higher realized prices. Total operating profit increased by 38% to $2.678 billion, reflecting the increase in revenue and other operating income and a lower exploration charge.

The Group's average realized gas price per produced therm increased by 14% to 41.12 cents, reflecting generally higher market prices and changes in the production mix.

Unit operating expenditure increased to $8.46 per barrel of oil equivalent, reflecting the impact of the UK North Sea shutdown during the first quarter, higher commodity prices and changes in the production mix.

Capital investment of $3 744 million in the half year comprised investment in the Americas ($1.450 billion, including $376 million on acquisitions), Australia ($899 million), Europe and Central Asia ($798 million, including $56 million on acquisitions) and Africa, Middle East and Asia ($597 million).

Second quarter business highlights

Bolivia

In July, BG Group sanctioned Phase II of the Margarita project. This follows on from the sanction of Phase I in 2010, where construction is underway and early production facilities are onstream. Production from the two phases and the early production facilities is expected to reach over 40 thousand barrels of oil equivalent per day net to BG Group by 2014. Net investment in Phase I is estimated at $164 million and Phase II at $250 million.

Brazil

In June 2011, BG Group issued a material reserves and resources upgrade for its interests in the pre-salt Santos Basin, offshore Brazil. Mean total reserves and resources are now estimated to amount to some 6 billion barrels of oil equivalent (boe) net to BG Group, with an upside potential of 8 billion boe net.

The mean total reserves and resources represents a doubling of BG Group's previous best estimate of 3 billion boe prevailing at the time of the Group's February 2010 Strategy Presentation. The aggregate range of total reserves and resources net to BG Group is from 4 billion boe (P90) to 8 billion boe (P10).

The Lula, Guará, Cernambi, Iara and Carioca fields account for 95% of BG Group's total reserves and resources in the Santos Basin.

The recent increase in BG Group's estimate of its reserves and resources in Brazil was based upon a wealth of drilling, appraisal and other new data. Importantly, this includes dynamic data showing much higher well deliverability and greater connectivity within the reservoirs allowing increased recovery per well.

In addition to improved reservoir characteristics and resource estimates, there has been significant progress on the cost front. Experience with tendering, construction progress and operations experience with FPSOs has given confidence in the cost and schedule for surface facilities. Meanwhile a substantial improvement in drilling performance in the first half of 2011 has provided greater confidence that anticipated drilling cost reductions will be achieved over future phases.

In summary, as a consequence of the above BG Group now expects:
  • Higher flow rates and recovery per well;
  • Earlier achievement of plateau production from fewer wells;
  • Lower unit costs and higher unit value.

Significantly, BG Group expects that virtually all of the additional resources announced in June, contained within the Lula, Guará, Cernambi, Iara and Carioca fields, will be recovered from the same surface facilities envisaged in BG Group's field development plan prior to the resources upgrade. The incremental volumes are thus of a substantially higher value and result in significant unit cost reductions and higher unit value for the now increased total resources base.

Finally, during the quarter, BG Group took delivery of the oil tanker Windsor Knutsen which will be used to transport

BG Group's equity oil from Brazil. The Windsor Knutsen was converted from a conventional Suezmax tanker into the world's largest shuttle tanker, with the capacity to hold 1.1 million barrels of crude oil. First crude oil from the Lula FPSO has been lifted and is in transit to be delivered in August. BG Group has also committed to charter four further Suezmax shuttle tankers which are expected to be delivered in the period 2013 to 2014.

Egypt

In May, BG Group and its partner sanctioned Phase 8b, the next phase of investment in the West Delta Deep Marine Concession (WDDM) offshore the Nile Delta. This is one of a series of investments to maintain production from this concession that supplies gas for domestic and export needs. Phase 8b will bring seven additional wells onstream, allowing BG Group to meet its contracted gas commitments.

In 2011, BG Group, with its partners, also invested in WDDM development Phases 7 and 8a. The Phase 7 third pipeline came onstream in January with the compression project due onstream later this year. Phase 8a will bring onstream nine additional sub-sea wells. The first stage of drilling for Phase 8a has been completed with first gas expected in late 2011.

Kazakhstan

In June 2011, a fourth liquid stabilization train at the Karachaganak Processing Complex was successfully put into operation. The start-up of the new oil processing facility raises the stabilization and export capacity of the plant to 10.3 million tonnes of condensate per year.

Kenya

In May, BG Group announced it had signed Production Sharing Contracts with the Government of Kenya for two offshore exploration blocks - L10A and L10B. BG Group will be the operator of both blocks and will hold a 40% equity interest in block L10A and a 45% interest in block L10B. These blocks together cover an area of more than 10 400 square kilometres in the southern portion of the Lamu Basin. The initial work program consists of a commitment to acquire seismic data during an initial two-year exploration period.

Norway

In June, the plan for development and operation of the Knarr field (previously known as Jordbær) was approved by the Norwegian Parliament. Production is scheduled to start in 2014. Knarr is an oil field in a water depth of 410 meters, situated in the Tampen North area in the Norwegian North Sea. Also in June, the lease and operate contract for the FPSO for the Knarr field was signed.

Tanzania

BG Group received approval from the Government of Tanzania to assume the role of Operator of Blocks 1, 3 and 4, offshore Tanzania, effective from 1 July 2011. To date, three successful exploration wells have been drilled. As part of the operatorship transition arrangements, BG Group has led a number of project activities over recent months in preparation for the next stage of the exploration and appraisal program, scheduled to commence in late 2011.

USA

Progress in BG Group's shale gas operations continued to gather pace with production continuing to build-up and the 200th EXCO-operated Haynesville horizontal well being brought into production. During the quarter, 38 wells were spudded and 22 rigs were operating in the Haynesville, while 8 wells were drilled in the Marcellus shale.

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