CNOOC starts production in Bohai Bay

CNOOC announced that BZ 29-4, an independent oil field in the Bohai Bay, has commenced production successfully.

BZ 29-4 oil field, with an averaged water depth of about 22 meters, is located in the south part of Bohai Bay. The field's development and production operation will mainly rely on the facilities of the producing field BZ 28-2S. BZ 29-4 is projected to peak its daily production at 7,800 barrels within 2010.

Mr. Chen Bi, Executive Vice President of the Company, said, "The start-up of BZ 29-4 gives us more confidence in meeting our annual production target. We will continue to enhance our operation performance and ensure more projects to be brought on stream within this year."

BZ 29-4 is an independent oil field. CNOOC Ltd holds 100% interest and acts as the Operator.

OGX finds hydrocarbons in well OGX-15

OGX Petróleo e Gás Participações S.A. (“OGX”), the Brazilian oil and gas company conducting the largest private sector exploratory campaign in Brazil, announced today that it has identified an oil-bearing interval in the Albian section of well 1-OGX-15-RJS, located in the BM-C-41 block, in the shallow waters of the Campos Basin. OGX holds a 100% working interest in this block.

An oil column of about 96 meters with approximately 32 meters of net pay was encountered in carbonate reservoirs in the Albian section. The drilling of well OGX-15, also known as the Santa Helena prospect, is still in progress and is expected to continue to a maximum final depth of approximately 3,450 meters.

The information obtained to date from the drilling of the well OGX-15, mainly pressure data from the structure, analyzed in conjunction with the interpretation of 3D seismic data, suggests connectivity between this prospect and the discoveries of Etna (OGX-6) and Pipeline (OGX-2). The Santa Helena prospect is located 1.81km northwest of the Etna prospect and 6.41 km northeast of the Pipeline prospect.

“This information reinforces the hypothesis that the accumulation identified in the Albian section of the Santa Helena prospect is the same that was verified through the drilling of the Etna and Pipeline prospects. This ratifies the great importance of petrolific potential of the southern Campos Basin and contributes enormously to a better understanding of the recently discovered province in the region,” commented Mr. Paulo Mendonça, General Executive Officer of OGX.

The OGX-15 well, located in the BM-C-41 block, is situated approximately 78 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 130 meters. The rig Ocean Ambassador initiated drilling activities there on June 18, 2010.

GOM spill relief efforts resume

BP today provided an update on developments in the response to the MC252 oil well incident in the Gulf of Mexico.

Subsea Source Control and Containment
On July 23, with the guidance and approval of the National Incident Commander (NIC) and the leadership and direction of the federal government, relief well activities at the MC252 well site were temporarily suspended because of potentially adverse weather associated with Tropical Storm Bonnie. Following the passing of the weather system, the DDIII drilling rig returned to the relief well site on July 24 and is taking steps necessary to reconnect with the well and resume drilling operations. These steps are expected to take a number of days.

The DDII drilling rig is moving back into position, and will take steps necessary to reconnect to the second relief well. However, work on the second relief well has been suspended so as not to interfere with the first.
The MC252 well has been successfully shut-in for integrity testing since July 15.

BP continues to closely monitor the MC252 well and well-capping structure, under the guidance of the Unified Command.

Tullow hits oil pay in deep waters offshore Ghana

Tullow announced that the Owo-1 exploration well in the Deepwater Tano license offshore Ghana has intersected a significant column of excellent quality light oil, potentially adding a billion barrels of oil equivalent to the resource estimate for the area. Results of drilling, wireline logs and samples of reservoir fluids have established Owo as a major new oil field requiring further appraisal.

The deviated well, located approximately 6km to the west of the Tweneboa wells, has encountered a gross vertical reservoir interval of 154 meters containing 53 meters of net oil pay in two zones of high quality stacked reservoir sandstones. Pressure data indicates that these zones are part of the same accumulation and samples show that it is a light oil of between 33 and 36 degrees API.

Following completion of logging operations the well will be sidetracked 0.6km east to provide additional information on lateral reservoir distribution and to intersect a deeper part of the Owo channel system.

The Sedco-702 dynamically positioned semi-submersible drilled Owo-1 to a final depth of 3,891 meters in water depths of 1,428 meters. On completion of operations on the Owo-1 sidetrack, the rig will remain in the Deepwater Tano block to drill the Onyina-1 exploration well which targets a large fan/channel system between the Tweneboa and Jubilee fields.

Tullow (49.95%) operates the Deepwater Tano licence and is partnered by Kosmos Energy Ghana (18%), Anadarko Petroleum (18%), Sabre Oil & Gas (4.05%) and the Ghana National Petroleum Corporation (GNPC) (10% carried interest).

Commenting today, Angus McCoss, Exploration Director, said, "Owo-1 has made a very substantial light oil discovery and continues the success of Tullow's Equatorial Atlantic exploration campaign in West Africa. Given this success, we are immediately drilling an appraisal sidetrack to further assess the size of this find. Accelerated appraisal drilling will now focus on maturing the resources in both Owo and the adjacent Tweneboa accumulation towards commercialization."

Petromanas begins seismic work in Albania

Petromanas announced that the start up of seismic operations on Blocks D-E and Blocks 2-3 in Albania as planned and on schedule, and is anticipated to be completed by October 2010. All operating licenses and permits have been received and the contractor's personnel and equipment are on site. This program includes 250 km of 2D seismic survey including 105 km which is part of the licenses required work commitments.

Manas Adriatic GmbH, a wholly owned subsidiary of Petromanas Energy Inc., has signed two agreements for Land Seismic Services with the Italian company Geotec S.p.A, on May 27, 2010, one each for Blocks D-E and Blocks 2-3 which are onshore Production Sharing Contracts in Albania. Geotec S.p.A. has extensive experience in the hydrocarbon exploration industry performing seismic work in Albania in conjunction with international oil and gas companies for many years.

The majority of the seismic work will be carried out with heliportable rigs and the remainder through conventional shallow drilling rigs.

This seismic survey is being carried out to improve the quality of the existing prospect data, and hence increase the chances of success of the exploratory wells to be drilled upon completion and interpretation of the new seismic data. The first well is anticipated to be drilled in early 2011.

BP’s capping stack continues to shut in well

Subsea Source Control and Containment
BP continues to work cooperatively with the guidance and approval of the National Incident Commander and the leadership and direction of federal government including the Department of Energy, Department of the Interior, Federal Science Team, Bureau of Ocean Energy, Management, Regulation and Enforcement, U.S. Coast Guard and secretaries Ken Salazar and Steven Chu. At this time, the well integrity test on the MC252 exploratory well continues.

During the test, the three ram capping stack has been closed, shutting in the well. All sub-sea containment systems (namely, the Q4000 and Helix Producer systems) have been temporarily suspended.

The pressure inside the well recently has been measured at approximately 6,792 pounds per square inch and continues to rise slowly. As directed by the National Incident Commander, extensive monitoring activities are being carried out around the well site. Information gathered during the test is being reviewed with the government agencies, including the Federal Science Team, to determine next steps. Depending upon the results of the test and monitoring activities, these steps may include extending the well integrity test or returning to containment options.

Should the test conclude, the Q4000 is expected to resume capturing and flaring oil and gas through the existing system. It has been capturing and flaring an average of 8,000 barrels a day (b/d) of oil in recent weeks.

The Helix Producer also is expected to be available to resume capturing oil and flaring gas through the recently installed floating riser system. It has the capacity to capture approximately 20,000 - 25,000 b/d of oil.
Plans continue for additional containment capacity and flexibility that are expected to ultimately increase recoverable oil volumes to 60,000-80,000 b/d.

The sealing cap system and many of the other containment systems have never before been deployed at these depths or under these conditions, and their efficiency and ability to contain or flare the oil and gas cannot be assured.

To date, the total volume of oil collected or flared by the containment systems is approximately 826,800 barrels. Information on the subsea operational status is updated daily on BP's website, www.bp.com.

Work on the first relief well, which started May 2, continues. The well reached a depth of 17,864 feet as of July 18th and the next scheduled operation is to carry out a ranging run. The first relief well has approached its last casing end point and, following the casing set, additional ranging runs will be used to guide the drill bit to a MC252 well intercept point. After interception, operations are expected to begin to kill the flow of oil and gas from the reservoir by pumping specialized heavy fluids down the relief well.

The second relief well, which started May 16, is at a measured depth of 15,874 feet and has been temporarily halted so as not to interfere with the ranging runs being performed in the first relief well.

Although uncertainty remains, the first half of August remains the current estimate of the most likely date by which the first relief well will be completed and kill operations performed.

Surface Spill Response as of July 17
Work continues to collect and disperse oil that has reached the surface of the sea, to protect the shoreline of the Gulf of Mexico, and to collect and clean up any oil that has reached shore. Approximately 43,100 personnel, more than 6,470 vessels and dozens of aircraft are engaged in the response effort.

Operations to skim oil continued over the weekend. These operations have recovered, in total, approximately 807,143 barrels (33.9 million gallons) of oily liquid. In addition, a total of 408 controlled burns have been carried out to date, removing an estimated 261,904 barrels of oil (11 million gallons) from the sea's surface.

The total length of containment boom deployed as part of efforts to prevent oil from reaching the coast is now almost 3.36 million feet (681.8 miles).

Additional information
To date, almost 116,000 claims have been submitted and more than 67,500 payments have been made, totalling $207 million.

The cost of the response to date amounts to approximately $3.95 billion, including the cost of the spill response, containment, relief well drilling, grants to the Gulf states, claims paid, and federal costs. On June 16, BP announced an agreed package of measures, including the creation of a $20 billion fund to satisfy certain obligations arising from the oil and gas spill. It is too early to quantify other potential costs and liabilities associated with the incident.

OGX concludes drilling well OGX-12 in Santos Basin

OGX has concluded the drilling of the well 1-OGX-12-SPS, located in the BM-S-57 block, in the shallow waters of the Santos Basin. OGX holds a 100% working interest in this block.

The drilling of well OGX-12, also known as Niterói, reached a total depth of 5,074 meters, and encountered carbonate reservoirs in the Albian section with good conditions of permo-porosity, although with an ineffective geological seal. In addition, two thin intervals of carbonate reservoirs with indications of hydrocarbons were found in the Aptian and Barremian sections, confirming an active petrolific system. Although these hydrocarbon evidences are considered to be non-commercial, information obtained in the drilling of this well will play a very important role in calibrating the new geological model for the region.

"After a highly successful exploratory campaign with announced discoveries in all 14 of our previously drilled wells, the drilling of the Niteroi prospect had as main objective the testing of a new geological model. The post-mortem of the well leads us to believe that the lack of a geological seal was the cause of a non-commercial hydrocarbon accumulation, given that the Albian structure is prominent. The fact that we encountered good reservoirs and confirmed the existence of an active petrolific system in this part of the basin is very positive since it decreases the risk in future wells," commented Paulo Mendonça, General Executive Officer of OGX.

The OGX-12 well, located in the BM-S-57 block, is situated approximately 95 kilometers off the coast at a water depth of approximately 150 meters. The rig used in this drilling will be moved to the BM-S-56 block and will drill the Belém prospect.

Range reports production record

Range Resources Corp. announced that its production for the second quarter 2010 reached a record level. Production for the second quarter averaged 472 Mmcfe per day, representing a 9% increase over the prior-year period. Adjusting for the sale of the Ohio properties, which closed at the end of March 2010, the second quarter production growth rate would have been 13%.

Second quarter 2010 production materially exceeded the Company's previous guidance of 450 to 455 Mmcfe per day. Due to the better than expected performance, Range was able to achieve its 30th consecutive quarter of sequential production growth. Driving the record level of production was higher production from all of the Company's divisions. In particular, production from the Marcellus Shale division saw the largest increase due to continued outstanding drilling results.

The Company also announced that preliminary second quarter 2010 oil and gas price realizations (including the impact of derivative settlements) averaged $5.07 per mcfe. This represents an 18% decrease from the prior-year period and a 9% decrease versus first quarter 2010. For the second half of 2010, 77% of anticipated natural gas production is hedged at an average floor price of $5.54 per mcf and for 2011, 51% is hedged at a $5.73 floor.

Second quarter drilling expenditures totaled approximately $240 million, funding the drilling of 87 (65.6 net) wells. A 97% success rate was achieved. For the first six months of the year, 159 (123.5 net) wells were drilled. At June 30, 53 (38.6 net) wells were in various stages of completion or waiting on pipeline connection. To date, Range has drilled 146 horizontal Marcellus wells, of which 29 are awaiting completion and four are awaiting pipeline hook up.

AWE provides update on Jebel Al Milh-1 well

AWE Limited reports that on 14 July, the Jebel Al Milh-1 well was at a depth of 2,870 ms and drilling ahead in 121/4” hole in the Lam Member of the Madbi Formation.

Elevated gas and oil shows have continued to be observed while drilling through this section. Progress for the week was 123 metres.

Jebel Al Milh-1 is located 16 kilometres north-northeast of the Al Meashar-1 well, which recently discovered oil in the basement. The primary target is fractured Pre-Cambrian basement and the structure is well defined on 3D and 2D seismic. The well is expected to drill to a depth of approximately 3,700 metres.

The participants in Block 7 are: ARC Energy Holdings Ltd (21.25%), Oil Search (ROY) Ltd (Operator, 34.00%), Kuwait Foreign Petroleum Exploration Co. (Aden) Ltd (21.25%), Yemen General Corporation for Oil and Gas (15.00%) and Mitsui E & P Middle East B.V (8.50%.)

Marathon announces first oil from deepwater GOM Droshky development

Marathon Oil Corporation announced today that its Droshky development in the deepwater Gulf of Mexico has begun production on time and under budget. Marathon owns a 100 percent working interest in Droshky, which is expected to produce approximately 50,000 net barrels of oil equivalent per day at its peak, consisting of approximately 45,000 barrels per day of liquid hydrocarbons and 30 million cubic feet per day of natural gas.

Located in approximately 3,000 feet of water in Green Canyon Block 244, about 160 miles southwest of New Orleans, Droshky is a major subsea project consisting of four development wells tied back to the third-party Bullwinkle platform with dual, 18-mile flowlines.

At a final development cost of less than $900 million, the initial stage of development is expected to produce 35 million of the estimated 60 million barrels of oil equivalent (boe) net resource. Future expansion of the project and ultimate total recovery will largely depend upon well performance. At year-end 2009, Droshky had booked proved reserves of approximately 26 million boe.

“Droshky is an excellent example of our ongoing commitment to execute major projects on time and at competitive costs,” said Dave Roberts, Marathon’s executive vice president, Upstream. “Specifically, it illustrates that Marathon can take a deepwater field from initial discovery to production in a little more than three years, and I’m proud of the many teams from across our Company that contributed to this milestone. Our safety and environmental performance, subsurface work and drilling and completion accomplishments were outstanding, and the result is a development that will contribute significant, profitable production and value to Marathon’s growing Upstream portfolio.”

US offers to help India explore shale gas

India claims the US has offered to help it explore shale gas reserves, a move that will aid the former's efforts to strengthen its energy security program. The development, which Mint couldn't independently confirm with the appropriate US agencies over the weekend, comes even as India is finalizing the contours of a policy framework for commercial exploitation of domestic shale gas reserves.

Shale is fine-grained sedimentary rock containing organic material, called kerogen, which, when distilled, can produce oil and gas. There are no official estimates of shale gas reserves in India; the north-eastern states and the Cambay basin are thought to have shale reserves.

India is seeking the assistance of the US Geological Survey to identify areas where shale gas reserves exist, transfer the technology required to tap them and finalize a policy to explore them.

An Indian team comprising representatives of the Directorate General of Hydrocarbons (DGH), Oil and Natural Gas Corp. Ltd (ONGC) and the petroleum ministry is expected to visit the US next month to discuss the proposal, said government officials aware of the development, who did not want to be identified. The US state department's coordinator for international energy affairs will oversee the bilateral efforts on behalf of the US government, they added.

"The US is the biggest producer of shale gas. It is better to learn their proven technology than trying to develop something of our own," said a senior DGH official, who did not want to be identified.

"We have received an invitation from the US government and are following it up," said a senior government official, who also requested anonymity.

Around 32,500 trillion cu. ft of shale gas has been identified globally. The US has been the leading producer, with shale gas accounting for 17% of its domestic gas production. Countries such as Estonia, Brazil, China and Australia are also looking at the commercial production of shale gas.
Signaling the government's intent to tap shale reserves, petroleum minister Murli Deora had said on 30 June, "We have initiated action to develop a framework for assessment of resource potential, which would lead to exploitation of this resource."

Given India's growing dependence on energy imports, there is emerging interest in tapping alternative energy sources such as shale gas and gas hydrates. ONGC's Keshava Deva Malviya Institute of Petroleum Exploration has a shale gas research agreement with the University of Utah and has been allowed to undertake studies in two coal bed methane blocks in Raniganj and North Karanpura coalfields.

Recently, Reliance Industries Ltd, India's most valuable firm, picked up a 45% stake in Texas-based Pioneer Natural Resources Co. for $1.32 billion (around Rs6,165 crore today)--its second such acquisition of shale assets in the US in less than three months. In April, it had acquired a 40% stake in Atlas Energy Inc.'s Marcellus shale assets for $1.7 billion.

"Shale gas offers a more immediate opportunity for cross-border investment between India and the US. Reliance has already led India's investment in shale acreages in the US. Bilateral co-operation involving technology transfer will enable inflow of investment and skills for development of shale assets in India, by both domestic and international players," said Gokul Chaudhri, partner at audit and consulting firm BMR Advisors.

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ADX begins drilling operations offshore Tunisia

Gulfsands Petroleum announced that ADX, the operator of the Kerkouane Exploration Licence offshore Tunisia (Kerkouane License), has advised of the commencement of drilling operations on the Lambouka-1 well on the Lambouka Prospect in the Sicily Channel.

ADX Energy has estimated the mean prospective resource for the Lambouka Prospect at 270 million barrels oil equivalent ("MMBOE") with the primary objectives for the well being the Miocene aged Birsa Formation and the Cretaceous aged Abiod Formation.

Drilling of the Lambouka-1 well is being carried out by the Atwood Southern Cross semi-submersible drilling rig and it is expected to take approximately 35 days to drill and evaluate this well.

Gulfsands is acquiring a 30% participating interest in the Kerkouane License and the adjacent Pantelleria Permit which lies in the Sicily Channel in Italian waters.

Ric Malcolm, Gulfsands CEO, said, "We are pleased to be able to report that the Southern Cross semi-submersible has now commenced drilling operations on the Lambouka-1 well. Lambouka-1 represents our first exploration well in Tunisia and comes ahead of a well to be drilled onshore on the Chorbane license in the fourth quarter of 2010. We will be reporting on progress with the Lambouka-1 well as appropriate, during the coming month."

CNPC, BP take over operation and management of Rumaila field in Iraq

The operational management of Iraq's Rumaila project has been officially transferred to Rumaila Field Operating Organization (ROO), a consortium led by CNPC, BP and Iraq's South Oil Company.

On July 3, BP, CNPC and Iraq's South Oil Company held a ceremony at Basra on the operational management transferring of the Rumaila Oilfield. More than 130 representatives from the three companies as well as from Iraqi government, the oil ministry and concerned sectors of the community attended the ceremony, which marks the consortium's official taking over of the oilfield and the commencement of oilfield operations.

Average daily output of Rumaila Oilfield is currently maintained at 1.03 million barrels, and is expected to be increased by 10% at 1.17 million barrels by the end of the year.

BP Operations in the Eastern Hemisphere

Many large Oil companies would consider buying BP�s assets if they are put on sale. BP is setting aside some assets as security while it builds up the $20 billion fund agreed upon with the U.S. to compensate for the damage from the Gulf of Mexico oil spill.

BP and its affiliates operate facilities or market products in most of the world�s countries and explore for oil and natural gas on six continents.

In the Middle East, the BP group has offices in Kuwait, Oman, Qatar, Saudi Arabia and the UAE. The head office for BP Middle East exploration and production activities is in Abu Dhabi. Many of BP's Important projects exist in the UAE such as Lower Zakum Development, Sharjah - Sajaa Gas Concession and Abu Dhabi Hydrogen Power Plant with Masdar. BP main business in Saudi Arabia is the supply and trading of petroleum products such as lubricants and aviation fuel to wholesale and retail customers.

In Asia, BP�s exploration and production activities are centered in Russia, Azerbaijan and China. BP also holds a leadership position in Liquefied Natural Gas (LNG) in China through a number of joint ventures.

In Russia, BP has an important joint venture through 50 per cent ownership of TNK-BP through its major producing assets, which are located in West Siberia, the Volga-Urals and East Siberia. BP is the operator of major projects in Azerbaijan such as Azeri-Chirag-Guneshli" and �Shahdeniz�, as well as Baku-Tbilisi-Jeyhan and South Caucasus pipeline projects. These developments converge at the Sangachal Terminal. Also BP recently signed an agreement to explore and develop the Shafag - Asiman structure.

BP Group has a large number of exploration and production activities in North Africa focused on Algeria and Egypt. In Algeria, BP had plans to spend $2 billion over the next five years to develop its operations in Salah and Amenas fields. In Egypt, BP has many fields in the Gulf of Suez and the Western Desert, which are operated through its subsidiary Gulf of Suez Petroleum Company (GUPCO); and operating gas assets in the Nile Delta through the Pharaonic Petroleum Company (PhPC).

BP has well-established operations in Sub-Saharan Africa including Angola, Botswana, Malawi, Mozambique, Namibia, South Africa, Tanzania, Zambia and Zimbabwe. In Angola, the first BP-operated asset is Block 18, which was discovered in 1999-2001, and consists of five distinct fields (Galio, Cromio, Paladio, Plutonio, and Cobalto).

A Comprehensive coverage of BP operations and major assets in the eastern hemisphere can be found as part of the 3D projects online database available at Gulfoilandgas.com. Additional information can be found at the following link: http://www.gulfoilandgas.com/webpro1/Projects/main.asp.

Testing begins on MC252 well's capping stack

The three ram capping stack was installed on the Deepwater Horizon LMRP at 7 p.m. CDT. The stack completes the installation of the new sealing cap.

Following installation of the capping stack and in line with the procedure approved by the National Incident Commander and Unified Area Command, the well integrity test will begin July 13 on the MC252 well.

For the duration of the test, which will be a minimum of 6 hours and could extend up to 48 hours, the three ram capping stack will be closed and all sub-sea containment systems (namely, the Q4000 and Helix Producer) will be temporarily suspended, effectively shutting in the well. It is expected, although cannot be assured, that no oil will be released to the ocean for the duration of the test. This will not however be an indication that flow from the wellbore has been permanently stopped.

Information gathered during the test will be reviewed with the relevant government agencies including the federal science team to determine the way forward. Options include reinstatement of containment as well as extending the test duration beyond 48 hours.

The sealing cap system never before has been deployed at these depths or under these conditions, and its efficiency and ability to contain the oil and gas cannot be assured.

The Helix Producer containment system started operations on July 12. The Q4000 containment system continues to capture oil and gas from the MC252 well and flare the hydrocarbons safely at the surface.

Relief well operations continue throughout this period and remain the sole means to permanently seal and isolate the well.

BP reportedly seeking sale of assets to Apache, ExxonMobil

BP is in talks to sell its Prudhoe Bay, Alaska assets to Apache Corp. as it seeks funds to pay for the biggest U.S. oil spill in history, according to a Bloomberg news report.

Robert Dye, a spokesman for Apache, and Max McGahan, a BP spokesman, declined to comment. The talks between BP and Apache were first reported yesterday by the London-based Sunday Times newspaper, which said the assets may be worth $12 billion.

The Sunday Times also said that Exxon Mobil Corp., based in Irving, Texas, has been told by the U.S. government it can look at a potential bid for BP.

BP owns a 26% share in Prudhoe Bay and neighboring fields in Alaska with Exxon Mobil Corp., ConocoPhillips and Chevron Corp. The Prudhoe Bay field, the largest field in the U.S., came online in 1977 and can produce about 400,000 BOPD.

Prudhoe Bay and other Alaskan fields were BP’s largest source of crude in the Western Hemisphere in 2009 after the Gulf of Mexico. Alaskan fields provided one in every 14 barrels of oil BP pumped worldwide last year. BP operates or owns stakes in 20 other fields on Alaska’s North Slope, as well as four pipelines.

BP also is considering selling oil and natural gas fields in Colombia, Venezuela and Vietnam, according to the Bloomberg news report.

Source: Bloomberg

Poland agrees to join in US shale gas research program

Poland agrees to join in US shale gas research program Poland has agreed to join in US research into extracting natural gas from shale, US Secretary of State Hillary Clinton said Saturday.

"Poland has agreed to participate in the global shale gas initiative, which is focused on tapping into unconventional gas resources to drive economic growth and lower emissions," Clinton said on a visit to Krakow.
"The shale gas initiative will bring together interested countries that have both potential gas development as well as will to develop the expertise in order to create the conditions that this resource can be exploited in a safe, environmentally sustainable manner," she said.

"We think that Poland has a very good opportunity to be a leader in a full range of energy issues, including shale gas."

Technical experts from both countries will work on releasing gas trapped in rock, of which Poland is thought to have substantial reserves, through unconventional techniques such as horizontal drilling. Though more costly than the usual methods, it has enabled the United States to limit dependence on imported natural gas.

In 2000 it represented just one percent of US gas production, but has now reached 20 percent and could account for half by 2030, according to industry experts IHS Cera.

"This is a very good sign of Polish leadership in the energy sector because energy security and independence is one of the most important aspects of national security," Clinton said.

Voyager begins drilling in Niobrara Formation

Voyager has signed an exploration and development agreement with Slawson Exploration to develop Slawson's 48,000 net acres in the Denver-Julesberg Basin Niobrara Formation in Weld County, Colorado in close proximity to several high-rate producers.

Slawson will commence the continuous drilling program in early July 2010 with an initial series of three test wells expected to be completed by October 2010. Subject to the results of these wells, Slawson expects to commence a continuous drilling program targeting 57 additional locations in the prospect that will be drilled throughout 2011.

Voyager purchased a 50% working interest in the approximately 48,000 acre block for $7.5 million and will participate on a heads-up basis on all wells drilled, as well as participate for its proportionate working interest in all additional acreage acquired in an Area of Mutual Interest consisting of all of Weld and Laramie Counties. Voyager will fund the purchase price and initial drilling commitments out of cash on hand and cash flows from current production. Voyager remains fully funded through 2010 with no debt and approximately $12.5 million of cash on hand.

According to state records, EOG Resources' Jake well, a horizontal Niobrara discovery in Colorado's Weld County in close proximity to the Voyager acreage, flowed an average 1,750 barrels of oil and 360,000 cubic feet of gas per day for its first eight days on production in October 2009. The Jake produced more than 50,000 barrels of oil in its first 90 days.

TGS commences high density multi-client 3D data acquisition

TGS announces the commencement of a 1650 km2 high density multi-client 3D seismic survey located in the outer part of Moray Firth off the Northeast coast of Scotland.

The survey covers open as well as held acreage and is located in an area proven to be particularly prolific for hydrocarbon exploration. This has been confirmed by recent discoveries including Golden Eagle, Hobby, Pink and Blackbird.

TGS has contracted the Polarcus Nadia vessel to acquire the Moray Firth 3D survey. The Nadia will deploy 8 X 5000m of streamers for the acquisition and the project is expected to complete in late Q3-2010. The data processing will be done at TGS' imaging center in Bedford, England.

Data from the Moray Firth survey will be available for customers from Q1-2011. The Moray Firth high density multi-client 3D survey is supported by industry funding.

Project Focus: Nabucco Pipeline

The 3300 km long Nabucco is supposed to connect the European Union better to the natural gas sources in the Caspian Sea and the Middle East regions. The cost estimates for this project is around �7.9 billion.

Nabucco Gas Pipeline Project

	Location	From Turkey to Austria - TR
	Investment	10,000,000,000 USD
	Announced	2/28/2002
	Completion	6/15/2015
	Recent Update 6/8/2010	Turkey and Azerbaijan have signed an agreement in Ankara defining terms for the transit of gas to Turkey and Europe.
	Scope	Nabucco pipeline (Turkey - Austria gas pipeline) is a proposed natural gas pipeline from Erzurum in Turkey to Baumgarten an der March in Austria diversifying natural gas suppliers and delivery routes for Europe. The pipeline attempts to lessen European dependence on Russian energy. The project is backed by several European Union states and the United States and is seen as rival to the Gazprom-led South Stream pipeline project. At the same time, there are some doubts concerning viability of supplies. The main supplier is expected to be Azerbaijan in cooperation with Turkmenistan, Iraq and Egypt. The Nabucco pipeline will be built in two stages. The first stage of construction will consist of the 2,071 km stretch from Ankara in Turkey to Baumgarten in Austria, as well as the 360 km extension from Ankara to Sivas. The second stage will serve to link the upstream feeder lines from Turkey�s borders to the main pipeline, which will equate to an additional 1,600 km. It is anticipated that the lifespan of the pipeline will be 50 years. The pipeline will run from Turkey via - Bulgaria, Romania and Hungary ending up in Austria close to the Gas Hub in Baumgarten. The feeder line concept in Turkey currently foresees a connection to the Turkish/Georgian border and to the Turkish/Iraqi border. Near Erzurum, it will be connected with the Tabriz - Erzurum pipeline and with the South Caucasus Pipeline, connecting Nabucco Pipeline with the planned Trans-Caspian Gas Pipeline. About 2,730 km kilometres of the pipeline will be laid in Turkey, 412 kilometres in Bulgaria, 469 kilometres in Romania, 384 kilometres in Hungary, and 47 kilometres in Austria. The technical details of the pipeline:- Total length: 3,300 km to 4,000km Diameter: 1,422mm / 56� Diameter Material: Steel Capacity: 31bcm/ year Wall thickness: 20-36 mm Burial Depth: Minimum 1,0m Pressure: 100 bar Control: One Main Control Center and one Sub-Control Center In-Country Control Centres (ICCC): Ankara, Turkey; Sofia, Bulgaria; Medias, Romania; Budapest, Hungary; Baumgarten, Austria Compressor stations: 11 The pipeline, valves and fittings will be treated for internal and external corrosion with protective coatings as well as an impressed cathodic protection system. The pipeline system includes all of the above ground installations associated with the Project. These will comprise main, local and sub control centres, compressor stations, custody transfer bordering metering stations, intermediate take-offs, cathodic protection stations, pigging and block valve stations, SCADA and a fibre optic telecommunication system. The Nabucco Pipeline construction is scheduled to start at the end of 2011 and the first gas will flow end of 2014. The main section of the pipeline completed by 2015. In early years after completion the deliveries are expected to be between 4.5 and 13 billion cubic meters (bcm) per year or 158 to 459 billion cubic feet (Bcf). Around 2020, the supply volume is expected to reach 31 bcm (1.1 trillion cubic feet) per year, of which up to 16 bcm (565 Bcf) will go to Baumgarten. The Nabucco project is being financed through a combination of investment from shareholders and debt financing from European financial institutions, mainly development banks. Total investment is estimated at EUR 7.9 billion, 70% of which will be financed through loans from financial institutions and 30% by the project's partners.

Development Milestones

	2/28/2002	Initial discussions took place for the Nabucco project between OMV Gas & Power GmbH (Austria) and BOTAS (Turkey).
	6/30/2002	Five companies (OMV of Austria, MOL Group of Hungary, Bulgargaz of Bulgaria, Transgaz of Romania and BOTAS of Turkey) signed a protocol of intention to construct the Nabucco pipeline.
	6/28/2005	The joint venture agreement (JVA) was signed by the five Nabucco partners. The agreement laid out the rules of the Nabucco pipeline project.
	1/8/2008	The British company Penspen has been appointed as owner's engineer, in a European wide tender procedure, for coordinating the detailed planning of the project.
	2/28/2008	The German RWE joined the Nabucco Project as the sixth shareholder.
	6/11/2008	The first contract to supply gas from Azerbaijan through the Nabucco pipeline to Bulgaria was signed. Azerbaijan confirmed that it was planning to at least double its gas production in the coming five years to supply the pipeline.
	5/12/2009	Detailed engineering and planning for the complete route of the multinational Nabucco Pipeline Route has reached the intensive phase. Five Local FEED (Front End Engineering and Design) Engineers for Austria, Hungary, Romania, Bulgaria and Turkey have been appointed and the British owned engineering consultant company Penspen now coordinates the planning efforts. These local firms are currently evaluating and investigating all technical details of the entire pipeline route to realise the necessary detailed planning.
	7/13/2009	The Intergovernmental Agreement (IGA) was signed in form of a Treaty between the Nabucco transit countries - Austria, Hungary, Romania, Bulgaria and Turkey - in Ankara. Under the IGA, the five countries guarantee to facilitate the construction and operation of the Nabucco pipeline within their territories over a total length of around 3,300 kilometres, all regulated under a single legal regime.
	3/5/2010	Turkey has completed the ratification process as the fifth transit country of the Nabucco consortium that have endorsed the agreement, following Hungary (October 2009), Austria (December 2009), Bulgaria and Romania (February 2010).
	4/23/2010	Nabucco Gas Pipeline International launched the pre-qualification process as a starting phase for the procurement of long lead items such as pipes and valves needed for the pipeline construction. The value of the entire package is around Euro 3.5 Billion ($4.7 billion) and the deadline for companies to participate in the prequalification was 17th May. Nabucco requires 250,000 pipes and over 2 million tons of steel, along with several pieces of specialist equipment and more than 30 compressor units.
	6/8/2010	Turkey and Azerbaijan have signed an agreement in Ankara defining terms for the transit of gas to Turkey and Europe.

BP: Relief wells close to completion

BP: Relief wells close to completion

Subsea Source Control and Containment
Two containment systems continue to collect oil and gas flowing from the Deepwater Horizon’s failed blow-out preventer (BOP) and transport them to vessels on the surface.

The lower marine riser package (LMRP) containment cap, installed on June 3, takes oil and gas to the Discoverer Enterprise where oil is collected and gas flared. The second system, which began operations on June 16, takes oil and gas to the Q4000 vessel on the surface where both oil and gas are flared.

On July 3, a total of approximately 25,198 barrels of oil were collected or flared by the two systems and 57.0 million cubic feet of gas were flared. Specifically, the LMRP containment system connected to the Discoverer Enterprise collected 17,022 barrels of oil, and the Q4000 flared an additional 8,176 barrels of oil. To date, the total volume of oil collected or flared by the containment systems is approximately 585,400 barrels. Information on the volumes of oil and gas that are collected or flared is updated twice daily on BP’s website, www.bp.com.

Preparations continue for the next step in containment operations. Work on the first floating riser containment system planned to be connected to the Helix Producer was delayed by heightened sea states caused by Hurricane Alex as it passed through the Gulf of Mexico. The floating riser system is designed to allow more rapid disconnection and reconnection of the system, reducing the time that collection may be impacted in the case of, for example, inclement weather. It is currently anticipated that this first floating riser system will be available to begin first operations towards the end of the week.

Plans also are being developed for additional containment capacity and flexibility. These projects are currently anticipated to begin operations around mid- late July.

The LMRP containment cap system, the Q4000 system, and the planned additional containment systems have not been deployed at these depths or under these conditions, and their efficiency and ability to contain or flare the oil and gas cannot be assured.

Work on the first relief well, which started May 2, continues. The well reached a depth of 17,725 feet on July 4 and a sixth ‘ranging’ run was completed. The second relief well, which started May 16, has now reached a measured depth of 13,871 feet. Both wells are still estimated to take approximately three months to complete from commencement of drilling.

Surface Spill Response and Containment
Work continues to collect and disperse oil that has reached the surface of the sea, to protect the shoreline of the Gulf of Mexico, and to collect and clean up any oil that has reached shore.

Approximately 44,500 personnel, more than 6,563 vessels and some 113 aircraft are now engaged in the response effort.

Operations to skim oil from the surface of the water were temporarily placed on hold for approximately three days because of the effects of Hurricane Alex. To date, these operations have recovered, in total, approximately 673,497 barrels (23.5 million gallons) of oily liquid. In addition, a total of 275 controlled burns have been carried out to date, removing an estimated 238,000 barrels of oil from the sea’s surface.

The total length of containment boom deployed as part of efforts to prevent oil from reaching the coast is now almost 2.9 million feet (550 miles).

Iran discovers 28Tcf of gas reserves at new fields

Iran’s Oil Minister announced the discovery of two new natural gas fields according to a report from Dow Jones newswires.
"Forouz gas field is located in the Persian Gulf near Kish island and has 700 billion cubic metres of gas reserves," Masoud Mir-kazemi said, adding that when brought on stream the field could produce around 70 million cubic metres of gas daily.

The combined gas reserves of the two fields amount to around 800 billion cubic metres (28 trillion cubic feet), he told reporters. He said the second field was found in the northeastern province of Khorasan Razavi and has 62.5 billion cubic metres of gas reserves.

This second field is capable of producing four million cubic metres of gas daily, the minister added. Iran has the world's second-largest reserves of natural gas after Russia.

The South Pars field in the Gulf has around 14 trillion cubic meters of gas, which represents about eight percent of world reserves.

In April Mir-Kazemi said domestic gas prices should be hiked tenfold, to help the state save about US$17 billion and boost development of the gas and refined products industry. The minister said that the Oil Ministry had asked the government to allow it to hike prices in order to stave off a "consumption crisis".

Alange Energy awarded two exploration blocks in Colombia

Alange Energy Corp. (ALE) announced successful bids on two blocks in the recently completed 2010 Open Round conducted by Colombia's National Hydrocarbon Agency ("ANH"). The two blocks awarded to the company with 100% participation and operatorship are located in the Llanos and Cordillera Basins and cover a total area of 94,921 hectares.

The LLA 41 Block in the Llanos Basin, which has an area of 72,263 hectares, was awarded to the company as a Type 1 E&P block and carries an additional royalty of 1%. During the first 36-month exploration phase, the company is committed to the drilling of one exploratory well and the acquisition of seismic.

Located in the Llanos Basin, near the giant Cano Limon field, the main reservoirs of LLA 41 are tertiary sandstones and there is potential for several structures with API gravity of greater than 25 degrees.

The COR 33 Block in the Cordillera Basin, which has an area of 22,658 hectares, was awarded to Alange Energy as a Type 1 E&P block and carries an additional royalty of 1%.

During the first 36-month exploration phase, the company is committed to the drilling of one exploratory well and the acquisition of seismic.

Located on the border of the Cordillera and Upper Magdalena Valley basins, near the Guando field, the main reservoirs of COR 33 are Monserrate Sandstones and the source rock is the Villeta Formation. The block has potential structures with API gravity of greater than 25 degrees.

The open process was available to those pre-qualified by the ANH and successful bid contracts are expected to be finalized by October 2010. The total estimated net investment will be $5.5 million and $6.8 million for LLA 41 and COR 33, respectively, over the next three years. This exploration spending will be funded with operating cash flow starting in 2011 and is subject to ANH exploration regulations.

RIL announces seventh oil discovery in Cambay block

Reliance Industries Limited (RIL) announced its seventh oil discovery in exploration block CB-ONN-2003/1 (CB 10 A&B), awarded under the NELP-V round of exploration bidding.

The well CB10A-N1 was drilled to a total depth of 1579m in Part A of the block with the objective of exploring the play fairway in the Miocene Basal Sand (MBS) of Babaguru and the Oligocene play of Tarapur Formations. The hydrocarbon bearing zone was identified from 1388-1403m in the Miocene Basal Sand (MBS) of Babaguru formation. Conventional production testing was carried out in the interval 1389-1400m.

The well flowed at a rate of 410 barrels of oil per day (bopd) through a 6-mm bean, with a flowing tubing head pressure of 360 psia.

The discovery is significant, as this play fairway is expected to open more oil pool areasleading to better hydrocarbon potential within the block. The block CB-ONN-2003/1 is located at a distance of nearly 130-km from Ahmedabad, Gujarat in the Cambay basin. The block covers an area of 635-sq km in two parts, viz. Part A & Part B. RIL, as Operator, holds 100% Participating Interest (PI) in the block.

While the entire block was covered with 2D seismic, nearly 80% of the block area has 3D seismic coverage. Of the 17 exploratory wells drilled in the block by RIL so far, 13 are located in Part A and the remaining 4 in Part B of the block. RIL is continuing further exploratory drilling efforts in the block.

This discovery, named ‘Dhirubhai–50’, the seventh oil discovery in the block so far, has been notified to the Government of India and to the Director General, Directorate General of Hydrocarbons. The potential commercial interest of the discovery is being ascertained through more data gathering and analysis.

This discovery supplements the understanding of the petroleum system in the Cambay basin in general and this block in particular. Based on interpretation of the acquired 3D seismic campaign in the contract area, several more prospects with upside potential have been identified at different stratigraphic levels.

Kulczyk Oil to test first Brunei exploration well

Kulczyk Oil Ventures announced that preliminary results from analysis of drilling data and interpretation of wire line logs from the Lukut-1 well on Brunei Block L indicates a number of potential hydrocarbon-bearing zones. Consequently, KOV and its joint venture partners (the "JV Partners") have decided to proceed with a testing program.

The Lukut-1 well, which commenced drilling on May 2, 2010, had an initial target depth of 2,150 metres. The well was designed to test the hydrocarbon potential of a structural feature defined by 3D seismic shot by KOV and its joint venture partners in 2009.

The well reached the target depth of 2,150 metres on May 31, 2010 and, as elevated gas readings were reported in the drilling mud, the JV Partners elected to deepen the well to 2,230 metres to facilitate assessment of a zone of interest between 2,130 metres and 2,210 metres before carrying out the wire line logging program.

Preliminary analysis of data acquired from the gas logs which evaluated the hydrocarbon content of the drilling fluid during the drilling operation showed a continual increase in gas content with indications of C1 to C5 over the interval from 1,745 metres to 2,230 metres. Gas shows were noted at 1,745 metres, 1,945 metres and from 2,150 metres to 2,185 metres. Elevated gas readings at 2,230 metres led the JV Partners to further extend drilling to 2,366 metres after running a liner to 2,230 metres.

During the drilling of the additional section elevated gas readings were also recorded from 2,295 metres to 2,317 metres but due to hole and drilling conditions this section of the wellbore was not able to be effectively cased. The well was plugged back to 2,230 metres. During the plugging back of the well the cement set up prematurely resulting in a section of tubing being left in the hole. Operations are underway to remove this impediment to the testing of the well. The Nabors 503 drilling rig will be moved off of the location and relocated to the Lempuyang-1 location once the tubing has been removed from the wellbore to allow for the testing of the zones below 2,066 metres.

Further interpretation of drilling results and a petrophysical evaluation of the wire line logs for the entire hole is progressing and will be factored in to the final design of the testing program. A smaller service rig will be sourced to undertake the testing of the well and the testing program is expected to commence in July, 2010.

The partners in Brunei Block L and in the Lukut-1 well are Kulczyk Oil (40%), AED South East Asia Limited (50%) and QAF Brunei Sdn Bhd (10%). The Lukut-1 exploratory well is the first well in a program of a minimum of four wells to be drilled in Brunei by Kulczyk Oil and its joint venture partners in 2010. Two of the wells, Lukut-1 and Lempuyang-1, are located on Block L (KOV 40%) and the two additional wells will be drilled on Block M (KOV 36%) to the south. All four of the wells will evaluate prospects identified by newly-acquired 3D seismic.

Petrobras confirms light oil potential in Tupi

Petróleo Brasileiro S.A. - Petrobras announces that the drilling of the seventh well in the Tupi area confirmed the light oil potential in the pre-salt reservoirs, located in ultra-deep Santos Basin waters.

The new well, called 3-BRSA-821-RJS (3-RJS-674) and informally known as Tupi Alto, is located in the Tupi Evaluation Plan area, at a depth of 2,111 meters below the water line, nearly 275 km of the coast of Rio de Janeiro, and 12 km northeast of discovery well 1-RJS-628 (1-BRSA-369).

The well was drilled in a higher structural position than the other wells in Tupi, and proved the discovery of light oil via a cable test. The sample obtained in the test presented lighter oil (about 30 degrees API) than the average of the oils found in the other Tupi wells (about 28 degrees API).

The information obtained from this well and from the other ones that have already been drilled in the area reinforces the estimations of the potential of 5 to 8 billion recoverable barrels of light oil and natural gas in the pre-salt reservoirs of the Tupi area.

The Consortium, formed by Petrobras (65% - Operator), BG Group (25%), and Galp Energia (10%), to explore block BM-S-11 will carry on with the activities and investments called for in the Evaluation Plan which was approved by the ANP and foresees the drilling of other wells until the declaration of commerciality, which is expected to be made in December 2010.

This announcement is not an offer of Petrobras shares. Petrobras shares may not be offered or sold in the United States absent registration or an exemption from registration, and Petrobras currently intends to register the proposed offering in the United States. Any public offering of Petrobras shares will be made by means of a prospectus containing detailed information about Petrobras and the offering.