Eni has been present in Norway since 1965, with current production standing at approximately 110,000 boe per day through its subsidiary Eni Norge AS.

San Donato Milanese (Milan), 9 December, 2013 – Eni has made a new offshore oil and gas discovery in the Norwegian Barents Sea, approximately 240km from Hammerfest.
The well, which is located in the Skavl prospect in the PL532 license, has been drilled five kilometers south of the Johan Castberg area. It was drilled in approximately 349 meters of water and reached a target depth of 1,700 meters.

The well has confirmed good quality oil and gas in Jurassic and Triassic sandstone, with volumes of recoverable oil estimated at between 20 and 50 million barrels. The discovery is part of Eni's joint venture exploration activity to develop the Johan Castberg field.

Following completion of Skavl, the drilling rig will move 16 kilometers north where it will continue its exploration campaign in the execution of an additional exploration well on the prospect of Kramsnø. 
Statoil is the operator of production license PL532 with a 50% stake; the remaining shares are held by Eni Norge AS (30%) and Petoro AS (20%).

Eni has been present in Norway since 1965, with current production standing at approximately 110,000 boe per day through its subsidiary Eni Norge AS. Eni is operator of the ongoing development of the first oil field in the Barents Sea, the important Goliat discovery, and of the Marulk gas field in the Norwegian Sea. Furthermore, in Norway Eni has interests in the country in a number of exploration licenses and fields under development and in operation, including Ekofisk, Norne, Åsgard, Heidrun, Kristin, Mikkel and Urd.

VAALCO Energy, Inc. (NYSE: EGY) has announced that the Company has received written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire. The Ministry of Petroleum also confirmed that Sonangol E.P. will assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P.

With this confirmation, VAALCO has begun the process of contacting drilling rig companies to secure a semi-submersible rig to commence the exploration phase of the pre-salt / post-salt Kwanza Basin program.

Steve Guidry, CEO, commented, "We are excited to begin drilling offshore Angola, especially given the recent significant discoveries made elsewhere in the Kwanza basin in which Block 5 is located. Having Sonangol as our partner, with their extensive knowledge of the basin, reaffirms our confidence in the potential of discovering commercial quantities of hydrocarbons on our 1.4 million acre concession."

Following the assignment, Sonangol and its affiliates will hold a 60% working interest in Block 5, comprising a 20% carried working interest and the newly assigned 40% participatory working interest. VAALCO, as operator, continues to hold a 40% operating working interest in Block 5.

Gulf producing states to share in revenue from GOMESA blocks

As part of President Obama’s all-of-the-above energy strategy to continue to expand safe and responsible domestic energy production, the Bureau of Ocean Energy Management (BOEM) has announced that it will hold Gulf of Mexico Eastern Planning Area oil and gas lease sale 225 in New Orleans on March 19, 2014, immediately following the proposed Central Planning Area (CPA) Sale 231.

Proposed Sale 225 is the first lease sale proposed for the Eastern Planning Area under the 2012 – 2017 Outer Continental Shelf Oil and Natural Gas Leasing Program, and the first sale offering acreage in that area since Sale 224, held in March of 2008.

“This proposed sale is another important step to promote responsible domestic energy production through the safe, environmentally sound exploration and development of the Nation’s offshore energy resources,” said BOEM Director Tommy Beaudreau.

The proposed sale encompasses 134 whole or partial unleased blocks covering approximately 465,200 acres in the Eastern Planning Area. The blocks are located at least 125 statute miles offshore in water depths ranging from 2,657 feet (810 meters) to 10,213 feet (3,113 meters). The area is bordered by the Central Planning Area boundary on the West and the Military Mission Line (86º 41’W) on the East. It is south of eastern Alabama and western Florida; the nearest point of land is 125 miles northwest in Louisiana.

Of the 134 blocks available in this sale, 93 are located in the same area offered in 2008’s Eastern Planning Area Sale 224 and are subject to revenue sharing under the Gulf of Mexico Energy Security Act of 2006 (GOMESA), which provides that the states of Alabama, Mississippi, Louisiana and Texas share in 37.5 percent of the bonus payments. These four Gulf producing states will also share in 37.5 percent of all future revenues generated from those leases. Additionally, 12.5 percent of revenues from those leases are allocated to the Land and Water Conservation Fund. The remaining 41 blocks, located just south of that area, are not subject to revenue sharing under GOMESA.

BOEM estimates the proposed lease sale could result in the production of 71 million barrels of oil and 162 billion cubic feet of natural gas.

The decision to move forward with plans for this lease sale follows extensive environmental analysis, public comment, and consideration of the best scientific information available. In October, BOEM published a Final Environmental Impact Statement (EIS) for proposed Eastern Planning Area Sales 225 and 226. The Final EIS updated information gathered in three previous EIS’s. EPA Sale 226, scheduled for 2016, is the only other Eastern Gulf of Mexico lease sale proposed under the current Five Year Program.

The proposed terms of this sale include conditions to ensure both orderly resource development and protection of the human, marine and coastal environments. These include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species, and avoid potential conflicts associated with oil and gas development in the region.

All proposed terms and conditions for Lease Sale 225 will be finalized when the Final Notice of Sale is published at least 30 days prior to the Sale.

The Notice of Availability of the Proposed Notice of Sale can be viewed today in the Federal Register at: www.archives.gov/federal-register/public-inspection/index.html. Proposed terms and conditions for the sale are fully explained in a new streamlined format, available at: www.boem.gov/Sale-225/.

CD’s of the sale package as well as hard copies of the maps can be requested from the Gulf of Mexico Region’s Public Information Office at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).

The Gulf of Mexico contributes about 25 percent of U.S. domestic oil and 11 percent of domestic gas production, providing the bulk of the $14.2 billion in mineral revenue disbursed to Federal, state and American Indian accounts from onshore and offshore energy revenue collections in Fiscal Year 2013. That was a 17 percent increase over FY 2012 disbursements of $12.15 billion, due primarily to $2.77 billion in bonus bids received for new oil and gas leases in the Gulf of Mexico

The 2012-2017 Five Year Program offers nearly 219 million acres on the U.S. Outer Continental Shelf for lease, making all areas of the OCS with the highest oil and gas resource potential available for exploration and development. The plan includes up to 15 lease sales in the Gulf of Mexico and Alaska. The first three sales under the Five Year Program offered more than 79 million acres for development and garnered $1.4 billion in high bids.

The Statfjord A platform in the North Sea actually should have been shut down several years ago. Statoil, Centrica and ExxonMobil have now decided to extend production from the platform until 2020.

"Statfjord A is our oldest platform and represents the history of the company's inception. The extension means that Statfjord A will still be in operation when the new giant Johan Sverdrup comes on stream. The size of the Statfjord field is unique, making it a significant part of the history of the Norwegian shelf for 40 years. We will take the experiences from Statfjord with us in our work with Johan Sverdrup, which has a horizon of 40 years," says Atle Rettedal, director of production for the Statfjord field. 

Originally, the partnership hoped to recover 40% of the oil in the Statfjord field. The outcome so far is a record 66%. The global average for oil fields is 35%. The goal is to recover 74% of the gas from Statfjord.

"We are reaping the benefits of the efforts we have invested over many years in that we will now manage to recover even more of the resources in a manner that creates value for the owners and for society," Rettedal continues.

From bold decision to successful implementation
Statfjord has gone from its original status as an oil field to the present, where mainly gas is produced and is sent to customers on the Continent and in the UK.

The Statfjord A platform in the North Sea. (Photo: Harald Pettersen/Statoil)

The fact that the Statfjord field still has many years of production ahead of it is the result of the partnership's bold decision ten years ago to rebuild the entire field to produce gas (Statfjord late life).

Good work by Statoil's own organisation, partners and suppliers all these years - along with NOK 23 billion in investments - have also been important contributions in maintaining the production.

Each year, 2,500 full-time equivalents are invested in the Stat fjord field, including the contribution from the suppliers, to enable safe and efficient operations.

Active drilling program - an active drilling program is contributing to the continued maturation of recoverable reserves on Stat fjord. By the time 2013 draws to a close, we will have drilled 11 wells, while 10 new wells are planned for 2014.

Impressive production/track record
- The Stat fjord field has produced more than 4.7 billion barrels of oil equivalent. Stacked up on top of each other, the oil barrels would have yielded 10 towers reaching from the earth to the moon.

Stat fjord A's highest producing well, A-06, has produced 120 million barrels on its own, more than many of the field developments we see today.
The production record for a single day was set on 16 January 1987, when 850,204 barrels of oil were produced.

Licensees on the Stat fjord field: 
Statoil Petroleum AS (44.34% - operator), ExxonMobil Exploration and Production Norway AS (21.37%) Centrica Resources (Norway) AS (19.76%) and Centrica Resources Limited (14.53%).

Total announces the signature of a farm-in agreement with InterOil Corporation that gives it a 61.3% interest in Petroleum Retention License (PRL) 15 in Papua New Guinea. The Elk and Antelope gas fields, two of the biggest finds in the Asia-Pacific region in recent years, were discovered in the license in 2006 and 2009 respectively.

Total and InterOil Corporation retain the flexibility to farm-down an aggregate of up to a 19.3% interest (before any election by the government to exercise its option to join the project with a 22.5% interest) to a strategic partner.

The common objective of Total, who will operate the project, and InterOil, is to complete the delineation of the two discoveries and to continue to explore for new resources in the license area. Depending on the results, this could lead to a final investment decision by 2016 for the development of the fields and the construction of a liquefaction plant located onshore on the Gulf of Papua.

In addition, Total has an option to take an interest in Petroleum Prospecting Licenses PPL 236, PPL 237 and PPL 238 in the same area.

"Following Total's entry into exploration in Papua New Guinea in 2012, this new acquisition of an interest in significant discovered resources is an exciting opportunity for Total to develop a new gas production and liquefaction hub in the Asia-Pacific region, where gas demand is very dynamic", stated Yves-Louis Darricarrère, President Upstream at Total. "Total will leverage its technology and experience in major LNG projects to reinforce its long-term production post-2020."

Total will pay $470 million for a 42% interest (32.5% if the government executes its option to join the project) with a contingent payment estimated by Total at approximately $590 million. The transaction remains subject to the approval of the Papua New Guinea government.

Total in Papua New Guinea
In October 2012, Total acquired from Oil Search Limited a 40% stake in the PPL 234 and PPL 244 offshore permits, 50% in the PRL 10 offshore permit and an option for 35% in the PPL 338 and PPL 339 onshore permits (in the same area as the Elk and Antelope gas fields and PPLs 236, PPL 237 and PPL 238).

In April 2012, Total Marketing & Services created a new affiliate in Papua New Guinea, with offices in Port Moresby. Total Marketing & Services had been marketing lubricants in the country via a distributor arrangement for several years. The new affiliate will allow Total to more effectively support its mining and manufacturing customers in implementing their development projects in Papua New Guinea, which is enjoying strong economic growth.

Apache Corporation announces that CEPSA Suriname S.L., a Spanish company, has farmed in to a 25-percent participating interest in Suriname's Block 53, a 867,117-acre (3,509 km2) area located in 1,640-5,900 feet (500-1,800 meters) of water about 80 miles (130 km) offshore.

Apache Suriname Corporation LDC, a subsidiary of Apache, signed a production sharing contract for Block 53 with Staatsolie Maatschappij Suriname NV — the Surinamese national oil company — in 2012 after a competitive bid round. The Block 53 work program includes a 3-D seismic program, currently in processing, and two exploration wells. Apache retains a 75-percent participating interest in the block. Staatsolie has an option to obtain a 20-percent participating interest in commercial fields discovered on the block.

Statoil has obtained 100% equity share in an exploration permit in the Reinga-Northland Offshore Release Area in the New Zealand Block Offer 2013.

The permit covers approximately 10,000 square kilometers and is located approximately 100 kilometers from shore to the west of New Zealand's North Island, in water depths ranging from 1,000 to 2,000 meters.

"We are very pleased with the award, which is in line with the sharpened exploration strategy Statoil has pursued over the last three years. Safe and secure operations are our first priority as we proceed to explore the permit's potential," says Erling Vågnes, senior vice president for Statoil's exploration activities in the Eastern hemisphere.

The work program is designed to fully evaluate the prospectivity of the permit in a staged manner within the 15-year permit timeframe. Statoil is committed to collect new 2D seismic data and to undertake a multibeam seafloor survey with selected core samples within the first three years. Following an analysis and interpretation of this data, Statoil will decide on further steps.
"Health, safety and the environment (HSE) is always Statoil's first priority. We will draw on our broad global experience in seismic data collection to secure safe operations offshore New Zealand," says Vågnes.

Statoil will now enter into an extensive dialogue process with New Zealand authorities, and engage with a wide range of stakeholders in order to understand the local community, and ensure adherence with local regulations, customs and considerations.

"Statoil strongly believes in a good dialogue with the communities we operate in," Vågnes says.
"New Zealand authorities have emphasized that Block Offer 2013 is an important step towards realizing the potential of New Zealand's oil and gas resources. We are glad that our bid was accepted and look forward to being a part of New Zealand's next phase in oil and gas development."

Petrobras has completed drilling another well in the Franco area (Santos Basin pre-salt), included in the Right's Transfer agreement.

Known as the 3-BRSA-1184-RJS (3-RJS-723), the well is located at a water depth of 2,011 meters, some 200 km from the city of Rio de Janeiro and 7.5 km southeast of discovery well 2-ANP-1-RJS (Franco).

The new well has confirmed the presence of good quality oil (28º API) in excellent carbonate reservoirs below the salt layer, starting at a depth of 5,398 meters. A total depth of 5,900 meters was reached after a 396-meter column of oil was confirmed.

Samples were collected in reservoirs of thickness similar to that of the discovery well, confirming the extension of these oil reservoirs towards the eastern section of the Franco block.

The drilling of this well is an addition to the mandatory exploration program for Franco, designed to improve volume delimitation.

Under the Right's Transfer Agreement, Petrobras is entitled to produce up to 3,058 billion barrels of oil equivalent in Franco. The exploratory phase is under way and is expected to be completed by September 2014.

Statoil and co-venturer ExxonMobil announce its fifth discovery in Block 2 offshore Tanzania.

The discovery of an additional 2-3 trillion cubic feet (Tcf)* of natural gas in place in the Mronge-1 well brings the total of in-place volumes up to 17-20 Tcf in Block 2.

Mronge-1 is drilled by the drillship Discoverer Americas, and the site is located 20 kilometers north of the Zafarani discovery, and at 2,500-meter water depth.

"We have initiated a new and ambitious drilling campaign offshore Tanzania following four successful discoveries during the first drilling phase. The Mronge-1 well discovered additional gas volumes and furthers the potential for a natural gas development in Tanzania. The new drilling program also allows us to fully explore the remaining exploration potential in Block 2," says Nick Maden, senior vice president for Statoil's exploration activities in the Western hemisphere.

The Mronge-1 well discovered gas at two separate levels. The main accumulation is at the same stratigraphic level as proven in the Zafarani-1 well in Block 2. The Zafarani-1 discovery was made in 2012 and was a play opener for the block.

The secondary accumulation was encountered in a separate, younger gas bearing reservoir, in a play which previously has not been tested in Block 2.

The Mronge-1 discovery is the venture's fifth discovery in Block 2. It was preceded by three successful high-impact gas discoveries during the first drilling phase with Tangawizi-1, Zafarani-1 and Lavani-1, and a deeper discovery in a separate reservoir in Lavani-2.

"These are high value resources. The attractiveness is also demonstrated by a recent asset transaction in the neighboring block. The discoveries also demonstrate how Statoil's strategy of focusing on high-impact opportunities is paying off and supports the company's ambition for international growth," Maden says.

"The Tanzania government is pleased to learn about additional gas resources discovered in Block 2," says Hon. Prof. Sospeter Muhongo, Minister for Energy and Minerals in Tanzania.

The Statoil-operated partnership started its new drilling campaign in Block 2 in September 2013. In addition to Mronge-1, the campaign includes drilling of several new prospects and appraisal of previous discoveries. Following Mronge-1, the partnership is scheduled to appraise the 2012 Zafarani discovery.

Statoil operates the license on Block 2 on behalf of Tanzania Petroleum Development

The 488-meter-long-hull of Shell's Prelude floating liquefied natural gas (FLNG) facility has been floated out of the dry dock at the Samsung Heavy Industries (SHI) yard in Geoje, South Korea, where the facility is currently under construction. Once complete, Prelude FLNG will be the largest floating facility ever built. It will unlock new energy resources offshore and produce approximately 3.6 million tons of liquefied natural gas (LNG) per annum to meet growing demand.

"Making FLNG a reality is no simple feat," said Matthias Bichsel, Shell Projects & Technology Director. "A project of this complexity – both in size and ingenuity – harnesses the best of engineering, design, manufacturing and supply chain expertise from around the world. Getting to this stage of construction, given that we only cut the first steel a year ago, is down to the expert team we have ensuring that the project's critical dimensions of safety, quality, cost and schedule are delivered."

FLNG will allow Shell to produce natural gas at sea, turn it into liquefied natural gas and then transfer it directly to the ships that will transport it to customers. It will enable the development of gas resources ranging from clusters of smaller more remote fields to potentially larger fields via multiple facilities where, for a range of reasons, an onshore development is not viable. This can mean faster, cheaper, more flexible development and deployment strategies for resources that were previously uneconomic, or constrained by technical or other risks.
Prelude FLNG is the first deployment of Shell's FLNG technology and will operate in a remote basin around 475 kilometers north-east of Broome, Western Australia for around 25 years. The facility will remain onsite during all weather events, having been designed to withstand a category 5 cyclone.
Shell is the operator of Prelude FLNG in joint venture with INPEX (17.5%), KOGAS (10%) and OPIC (5%), working with long-term strategic partners Technip and Samsung Heavy Industries (the Technip Samsung Consortium).

About Prelude
• Prelude is expected to produce 3.6 million tons per annum (mtpa) of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG, and to remain on location for approximately 25 years.
• The Prelude FLNG hull is longer than four soccer fields laid end to end and it is longer than the Empire State Building is tall.

• The LNG storage tanks have a capacity equivalent to approximately 175 Olympic swimming pools.

• Once complete, the FLNG facility will weigh more than 600,000 tons fully loaded, displacing the same amount of water as six of the world's largest aircraft carriers.

• Whilst the Prelude facility is big it is also small – taking up 1/4 the area of an equivalent onshore LNG plant.

• Existing technology that has been adapted for FLNG includes:

• Close coupling between the producing wells and the LNG processing facility – This is the physically short length from one to the other

• Mooring systems – making it bigger for the largest floating facility ever built and dealing with the associated forces.

• The marinisation of processing equipment, so that it will work on a floating facility

• Water intake risers, as water will be used as part of the cooling process needed to turn the gas into LNG.

• LNG tanks that can handle sloshing – that is the motions of the liquid LNG within the hull if and when there are stormy seas.

• LNG offloading arms which will transfer LNG from the facility to the ships moored alongside – two moving facilities instead of just one.

• On 2 September 2013, Woodside announced the use of Shell FLNG technology as the development concept to progress through the Basis of Design (BOD) phase to commercialize the Browse     gas fields.

AMEC, the international engineering and project management company, has been awarded a Project Management Consultancy services contract by Abu Dhabi Marine Operating Company (ADMA OPCO) for their Umm Lulu Phase-2 full field development projects offshore United Arab Emirates (UAE).

The contract is worth $124 million (£76 million).

This five-year contract follows a previous award from ADMA OPCO in 2011 for the provision of services for the first phase of Umm Lulu and the Nasr phase 1 project.

Under this latest contract AMEC's scope of work includes project management of the engineering, procurement and construction contractors who are delivering a large offshore super complex located in the Umm Lulu Field. The complex will comprise six bridge-linked platforms including gathering, separation, gas treatment and water disposal facilities, utilities and accommodation modules. The work is being delivered from the UAE and is expected to create 100 additional jobs for AMEC in Abu Dhabi.

"Further expansion in the Middle East is a key part of AMEC's growth strategy," said Ross Gibson, Operations Director, Gulf and North Africa. "It is good to see we are winning repeat business based on our previous performance and strength of our local capabilities."

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Statoil has together with partners in PL348/348B made an oil discovery in the Snilehorn prospect in the Norwegian Sea, approximately fifteen kilometers northeast of the Njord field.

This is the third near-field discovery in the Norwegian Sea in three months.

Exploration well 6407/8-6 and sidetrack 6407/8-6A, drilled by the Songa Trym drilling rig, have proven several oil columns in formations dating from the Jurassic period.

The main wellbore has also proven oil at a deeper level, in reservoir rocks of Triassic age, probably Grey Beds formation. Further data analysis will clarify the age of this oil bearing formation.

The estimated volume of the discovery is in the range of 55 - 100 million barrels of recoverable oil equivalent. This is light oil of high quality.

"We are very pleased with the results of our near-field exploration programme in the Norwegian Sea this year," says Gro G. Haatvedt, Statoil senior vice president for exploration on the Norwegian continental shelf.

"In three months we have made three new discoveries in the Norne, Åsgard and Njord areas proving a total of 86-166 million barrels of recoverable oil equivalent. These are high value barrels that allow us to extend the production life of our installations."

The Smørbukk North gas/condensate discovery in the Åsgard area and the Svale North oil discovery in the Norne area were announced in August and September respectively.

"A most likely future development of the Snilehorn discovery will be via the Hyme production system to Njord, or as a direct tie-in to the Njord platform," says Arve Rennemo, vice president and asset owner of Njord.

The Snilehorn well results also provide new important information about the Halten Bank area in shallow water in the Norwegian Sea and indicate that there may be interesting follow-up potential in this area.

"This is probably the first time hydrocarbons have been proven in Grey Beds formation in this part of the Norwegian Sea. This will be confirmed by further analyses of the data and may imply further upside potential in this area," says Haatvedt.

Exploration wells 6407/8-6 and 6407/8-6A are located in PL348/348B in the Norwegian Sea. Statoil is operator with an interest of 35%. The partners are GDF SUEZ E&P Norge AS (20%); E.ON E&P Norge AS (17.5%); Core Energy AS (17.5%); Faroe Petroleum Norge AS (7.5%) and VNG Norge AS (2.5%).

For further details on the results of exploration wells 6407/8-6 and 6407/8-6A, please see the press release issued by the Norwegian Petroleum Directorate (NPD) >>

A group comprised of 17 oil and gas companies has established a project for joint seismic acquisition in the southeastern Barents Sea. Statoil is the operator of the project.

Seismic vessel Ramford Vanguard. (Photo: Ole Jørgen Bratland)

At the request of the Norwegian Ministry of Petroleum and Energy (MPE), the industry, via the Norwegian Oil and Gas Association, has taken the initiative to jointly acquire seismic 3D data from the blocks in the southeastern Barents Sea that will be announced in the 23rd licensing round for the Norwegian continental shelf (NCS) in 2014.

This is the first new area on the NCS to be opened since 1994. Thirty companies showed interest in participating in such a collaboration.

17 of these companies signed an agreement to establish a joint project for planning and implementing the acquisition. As the largest operator on the Norwegian shelf Statoil has taken on the operator role.

"Coordinated seismic acquisition has several advantages. It will ensure very good data quality, since the industry to a much greater extent will be able to utilise the companies' collective professional expertise within geological understanding and seismic acquisition and processing. The initiative lays the foundation for fewer, well-planned operations, thus reducing acquisition costs and potential disadvantages for the fishing industry," says Gro G. Haatvedt, Statoil's senior vice president for exploration on the NCS.

"Interest in the Barents Sea has increased considerably in recent years, due in part to the discoveries in the Johan Castberg area. High-quality 3D data will be important to the industry in order to increase understanding of the area's potential."

When the authorities circulate the 23rd round nominated blocks for public consultation, other oil companies will get a new opportunity to engage in the project. It is expected that several companies will make use of this offer.

The project will immediately initiate a tender process for the seismic acquisition. The plan is for the seismic surveys to start in April 2014 and conclude in the autumn of the same year.

The companies who will be taking part from the beginning are BP, Chevron, ConocoPhillips, Det norske oljeselskap, Eni, GDF Suez, Idemitsu, Lukoil, Lundin, Norske Shell, PGNiG, Repsol, Spike, Statoil, Suncor, VNG and Wintershall.

Noble Energy, Inc. (NYSE: NBL) announced on Wednesday discoveries at the Dantzler exploration well in the Deepwater Gulf of Mexico and at the Tamar Southwest (SW) exploration well offshore Israel.

At Dantzler, wireline logging data indicates that the well encountered over 120 net feet of primarily crude oil pay in two high-quality Miocene reservoirs. The discovery well, located in Mississippi Canyon 782, was drilled to a total depth of 19,234 feet in 6,580 feet of water. Dantzler is located 12 miles west of the Company's Rio Grande development area, which includes discoveries at Big Bend and Troubadour. Discovered gross resources(1) at Dantzler are now estimated at between 55 and 95 million barrels of oil equivalent.

The Tamar SW well, testing a new exploration prospect, encountered approximately 355 feet of net natural gas pay within the targeted Miocene intervals. Tamar SW, which was drilled to a total depth of 17,420 feet in 5,405 feet of water, is the Company's eighth consecutive discovery in the Levant Basin. The field is located approximately 8 miles southwest of the Tamar field. Evaluation of drilling data and wireline logs has confirmed the range(1) of gross resources of the field to be between 640 billion cubic feet (Bcf) of natural gas and 770 Bcf. The well encountered high-quality reservoir sands, with per well productivity anticipated to be approximately 250 million cubic feet of natural gas per day.

Mike Putnam, Noble Energy's Vice President, Exploration and Geoscience, commented, "These new discoveries, combined with our exploration and appraisal successes earlier this year, have continued our successful organic exploration track record and identified new sources of future growth for Noble Energy. Dantzler represents our third consecutive exploration discovery in the Miocene trend of the Gulf of Mexico and complements our existing developments at Rio Grande and Gunflint. The field's proximity to our Rio Grande area provides the opportunity for an accelerated development at Dantzler. In Israel, the discovery at Tamar SW further enhances our discovered resources in the Eastern Mediterranean, which now totals nearly 40 trillion cubic feet of natural gas. The discovery also underpins our ability to meet the growing market demand in Israel and within the region."

Noble Energy operates Dantzler with a 45 percent participating interest. Additional interest owners are entities managed by Ridgewood Energy Corporation (including Riverstone Holdings LLC and its portfolio company ILX Holdings II, LLC) with 35 percent and W&T Energy VI, LLC (a wholly owned subsidiary of W&T Offshore Inc.) with 20 percent. In the Deepwater Gulf of Mexico, the Company anticipates drilling at least two additional Miocene trend prospects in 2014.

Following completion of operations at Tamar SW, the drilling rig will be released to another operator. Noble Energy operates Tamar SW with a 36 percent working interest. Other interest owners are Isramco Negev 2 with 28.75 percent, Delek Drilling with 15.625 percent, Avner Oil Exploration with 15.625 percent and Dor Gas Exploration with four percent.

(1) Range of resource estimate based on 75th and 25th percentile probabilities.

Petrobras has acquired, alone or in partnership, 49 blocks, out of the 50 to which the company presented offers, in the 12th Bidding Round held today by the Brazilian National Petroleum, Natural Gas and Biofuels Agency (ANP). Among the blocks acquired, 22 were in partnership, and 16 of them will be operated by Petrobras and 6 by partners. The value of signature bonus to be paid by Petrobras is R$ 120 million, in addition to R$ 23 million to be paid by partners. The sum of these amounts, which reaches approximately R$ 143 million, corresponds to 87% of the total bonus to be collected in the round.

In addition to the signature bonus, the Minimum Exploratory Program (MEP) to be applied on the block, expressed in units of work (UWs), and the percentage of local content in the exploration and production phases were also taken into account as judgment criteria in the bidding.

The blocks offered in the 12th Bidding Round are located in new exploratory frontiers andin mature basins. The strategy adopted by Petrobras in the bidding is aligned with the goal of the company to increase its reserves and production of natural gas in the vicinity of existing production facilities, by expanding the knowledge on Brazilian sedimentary basins and diversifying its exploration investment. The participation of Petrobras in consortiums is in line with the objective of strengthening partnerships with national and foreign companies in order to foster integration of knowledge and technologies used in the exploration and production onshore.

Among the new frontier basins, located in areas with little geologic information or technological barriers to be overcome, Petrobras has invested primarily in Paraná and Acre-Madre de Dios basins, seeking to identify new producing provinces with a focus on natural gas. In these basins, the Company has acquired 10 out of 11 blocks in which the Company submitted a proposal.
In mature basins, Petrobras purchased all 39 blocks in which it submitted a proposal. The company made offers to both basins of Sergipe-Alagoas and Recôncavo, in blocks near to production areas that can have synergies with the existing infrastructure.

The Bureau of Safety and Environmental Enforcement (BSEE) announces  that the Texas A&M Engineering Experiment Station’s (TEES) Mary Kay O’Connor Process Safety Center has been selected to manage the Ocean Energy Safety Institute (Institute). The five-year agreement, with $5 million in total funding from BSEE, will provide a forum for dialogue, shared learning and cooperative research among academia, government, industry and other non-government organizations in offshore-related technologies and activities that help ensure environmentally safe and responsible offshore operations. TEES is partnering with Texas A&M University, University of Texas and University of Houston to manage the institute.

“I look forward to working closely with our partners at the Institute on finding ways to improve safety offshore,” said BSEE Director Brian Salerno. “The Institute will develop a program of research, technical assistance, and education that serves as a center of expertise in offshore oil and gas exploration, development, and production technology, including frontier areas, such as high temperature/high pressure reservoirs, deepwater, and Arctic exploration and development.”

“The three partner universities represent a unique combination of capabilities and resources needed to address the needs for the Institute,” said Dr. M. Sam Mannan, TEES Chemical Engineering Professor and PI for the project.  “We applaud BSEE for supporting this major undertaking of national importance that will impact ocean energy safety for the nation and world for years to come.”

Earlier today, BSEE Director Brian Salerno toured the facilities on the Texas A&M campus in College Station and spoke with university professors, TEES researchers, and officials from the University of Houston and University of Texas about how the Institute will be managed. The facilities visited by Director Salerno included the Offshore Technology Research Center, which is capable of large scale simulations of the effects of wind, waves, and currents on fixed, floating and moored floating structures.

The Institute stems from a recommendation from the Ocean Energy Safety Advisory Committee, a federal advisory group comprised of representatives from industry, federal government agencies, non-governmental organizations and the academic community. The Institute will be an important source of unbiased, independent information and will not have any regulatory authority over the offshore industry. It will be a collaborative venture that will also include involvement on science and technology issues from the Bureau of Ocean Energy Management.

The Institute will provide recommendations and technical assistance to BSEE related to emerging technologies and the best available and safest technologies.  In addition, it will develop and maintain an equipment failure monitoring system and train Federal employees to enable them to remain current on state-of-the-art technology.  The Institute will also promote collaboration among Federal agencies, industry, standards organizations, academia, and the National Academy of Sciences.  Information on issues related to offshore research and best practices will be shared with industry, government, and the public through Institute held forums.

For additional information about OESI, see BSEE Fact Sheets: OESI