Chevron sanctions deepwater Big Foot project

Chevron Corp announced it has sanctioned development of its $4 billion Big Foot project in the Deepwater U.S. Gulf of Mexico.

“Sanctioning Big Foot underscores our commitment to the Gulf of Mexico and will contribute to future U.S. energy supply,” said George Kirkland, vice chairman, Chevron Corporation. “This project is another example of Chevron’s disciplined approach to advancing our enviable queue of major capital projects.”

Big Foot will be Chevron’s sixth operated facility in the Deepwater Gulf of Mexico and located approximately 225 miles (360 km) south of New Orleans, Louisiana, in water depths of 5,200 feet (1,600 m). The development will utilize a dry tree Extended Tension Leg Platform with an on-board drilling rig and have production capacity of 75,000 barrels of oil and 25 million cubic feet of natural gas per day. First oil is anticipated in 2014.

“We have industry leading expertise in developing Deepwater projects of this type and have repeatedly proven that we can do so safely,” said Gary Luquette, president, Chevron North America Exploration and Production Company.

Discovered in 2006, the Big Foot field lies in the Walker Ridge Area and is estimated to contain total recoverable resources in excess of 200 million oil-equivalent barrels. Primary pay sands are Middle to Upper Miocene ranging from 19,000 to 24,000 feet (5,800 to 7,300 m) and lie below a salt canopy ranging from 8,000 to 15,000 feet (2,400 to 4,500 m) thick. Three exploration and appraisal wells with multiple sidetracks have been drilled safely and successfully in the field to define the Big Foot structure. Chevron, through its subsidiary Chevron U.S.A. Inc., has a 60 percent working interest in the Big Foot project.

Chevron is one of the top leaseholders in the Gulf of Mexico, averaging net daily production of 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids during 2009.

Geotrace, BP to develop POCS seismic technology

Geotrace, an independent Reservoir services company that provides subsurface imaging solutions to the oil and gas industry, is teaming with BP to further develop POCS (Projection Onto a Convex Set) technology for use in seismic data processing for the oil and gas industry. BP originally developed POCS technology, which is a powerful tool for interpolating—or reconstructing—data.

POCS technology uses information surrounding data that may be missing, such as in a particular Reservoir formation, in order to reconstruct the missing data. The technology targets those companies specializing in oil and gas production and exploration risk management.

“By providing missing information, POCS’ primary advantage is that it helps minimize risk in assessing a reservoir,” says Bill Schrom, CEO of Geotrace. “The technology opens doors that were previously closed by allowing geoscientists to build missing data from the information they already have.

“Ideally, geoscientists acquire all the data they need to help them understand Reservoir formations. However, in some cases, certain valuable information may be missed in initial data acquisition. This is where POCS plays a valuable role in reconstructing missing data and eliminating the cost of acquiring new data to fill in the gaps,” Schrom explains.

POCS technology is commonly used in many fields where data are corrupted or missing, such as Synthetic Aperture Radar (SAR) and Magnetic Resonance Imaging (MRI).

Petrobras, Statoil makes discovery Offshore Brazil

Statoil and Petrobras of Brazil have struck oil on the Indra prospect in the Espirito Santo basin off the coast of Brazil.

Petrobras is operator for licence BM-ES-32, where the discovery was made and where Statoil holds a 40% stake.

The exploration well was drilled at a depth of 2,130 metres and both oil and Reservoir quality is good. The Reservoir thickness is approximately 70 metres and is of good quality. The preliminary analysis of the oil shows a density in the range between 25 and 30 degrees API.

“We are very pleased to have struck oil here and the result will have an important bearing on our decision regarding further exploration activity in this area,” says Tim Dodson vice president, international exploration.

The Inndra find was made by the semi-submersible rig Paul Wolfe. The location is situated 140 kilometres from land and some 400 kilometres north of the Peregrino field.

At the moment Statoil is also participating in exploratory drilling in the Campos basin on licence BM-C-33, where Repsol is the operator.

Statoil is operator on the Peregrino field and will hold a 60% share once the 40% divestment to Sinochem has been approved by the Brazilian authorities. Peregrino is planned to come on stream in the latter half of the first quarter of 2011.

By next year Statoil plans to operate three exploration wells in Brazil, two in the Peregrino area in order to prove additional resources on the field, as well as an exploration well in the Camamu basin.

Eni becomes operator of three Polish Baltic Basin licenses

Eni has reached an agreement for the acquisition of Minsk Energy Resources and to become operator of three licenses in the Polish Baltic Basin, a highly prospective Shale gas play.

The acreage is located in the northeast of Poland and consists of 1,967 square kilometers. Drilling operations are expected to start in 2011, with a total exploration commitment of six wells.

Eni will operate the licenses leveraging the extensive knowledge and expertise acquired through its JV in the Barnett Shale in Texas, the first Shale gas basin in the world to be developed on a large-scale.

Through this agreement Eni makes its entrance into European Unconventional Gas, in line with the company's strategy of expanding its position in unconventional resources.

Poland, which is currently importing almost 70% of its gas requirements, represents the ideal environment for Eni to start its operations in this emerging play which is of great interest to the oil & gas industry as a whole.

Marathon enters Eagle Ford Shale Play

Marathon Oil Corporation announced that it has completed an agreement with Denali Oil & Gas for entry into the Eagle Ford Shale formation in Wilson and Atascosa counties, Texas. Under the terms of the agreement, Marathon will pay Denali $10 million as well as drill and complete four wells to earn approximately 17,000 net acres. Marathon also has the option to purchase Denali's remaining 58,000 net acres in the Eagle Ford Shale in these two counties. If Marathon executes this option, the full 75,000 net acres, including the initial payment, carried well interest and lease extensions, will cost approximately $2,800 per acre or a total of approximately $209 million. Marathon has until Oct. 31, 2011, to exercise this option.

In the event Marathon does not exercise its purchase option, Denali has the option to sell the remaining 58,000 acres to Marathon. The total cost under this option, including the initial payment, carried well interest and lease extensions, would be $92 million or approximately $1,225 per acre. Denali has until the later of Nov. 15, 2011, or 15 days after the completion of the final well, to exercise this option. This agreement covers all of Denali's acreage in Wilson and Atascosa counties but excludes Denali's 25,000 acres in Gonzales and Fayette counties.

"Since acquiring our first Shale assets in the onshore U.S. market in 2006, Marathon has developed substantial expertise that we can apply to emerging plays like the Eagle Ford and create more opportunities for mid- and long-term profitable production growth," said Dave Roberts, the Company's executive vice president, Upstream. "This new entry reinforces a key element of our Upstream strategy of targeting unconventional, primarily liquids-rich resource plays providing low-risk, scalable growth."

Oman’s Farha South-5 well tests in excess of 1,500 bopd

The 2010 drilling programme onshore the Sultane of Oman has continued with the successful testing of the Farha South-5 well ("FS-5") on Block 3. FS-5 tested in excess of 1,500 BOPD from a 160 metres long horizontal section in the Barik formation using an electric submersible pump (ESP). The well has been completed as a producer and is being produced into the Farha South Early Production System for a long term production test.

"We are very pleased with the results from the FS-5 well. Oil was encountered both in the Barik and the Lower Al Bashir layers. The results emphasize the importance of the Farha area and underscores the potential also of the Barik Reservoir along the Farha trend," says Magnus Nordin, Managing Director of Tethys Oil AB.

The FS-5 well spudded in early October, and was drilled as a stepout exploration well 6.8 kilometres northeast of the discovery well FS-3. The pilot hole was drilled to a depth of 2,370 metres. Both the Barik formation and the Lower Al Bashir formation were penetrated with oil shows. Electrical logs were run. Subsequently, a horizontal sidetrack was drilled 160 metres within the Barik formation, which lies at 1,240 metres below ground level. A pump was installed and the well was placed on production. The average daily production rate is in excess of 1,500 BOPD of 44 API gravity.

The drilling rig has been moved to the Saiwan East-4 well, in Block 4, to carry out production tests. SE-4 showed oil in several formations when drilled in the summer of 2010, but was not tested at the time.

Tethys has a 30% interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20% and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50%.

Ecopetrol confirms hydrocarbons in the Cano Sur Block

The presence of hydrocarbons announced in the Mago-1 well is confirmed. -- Ecopetrol is the operator and has an interest of 50%. -- This discovery brings the total number of wells with presence of hydrocarbons to seven in 2010 (including exploratory and stratigraphic) .

Ecopetrol reports that it proved the presence of hydrocarbons in the second stratigraphic well drilled under the Cano Sur Exploration and Production contract, located in the province of Meta.

Preliminary results of the Draco-1 well, which reached a depth of 3,284 feet (close to one kilometer) confirm the presence of hydrocarbons which was previously announced on November 2 of 2010 in the Mago-1 well.

The interests under the Cano Sur contract are split equally between Ecopetrol, which is the operator, and Shell Exploration and Production Cano Sur GMBH.
The preliminary technical evaluation indicates the presence of crude petroleum in the Carbonera formation, in a net Reservoir thickness of close to 9 feet, with average porosities of 30%.

The findings registered in this new stratigraphic well, together with those registered in Mago-1, confirm the hydrocarbons potential of the eastern region of the province of Meta, where the Rubiales and Quifa fields also are located.

This discovery brings the total number of wells (in which Ecopetrol has a participation) where the presence of hydrocarbons has been proved in 2010 to seven (including exploratory and stratigraphic). Four of these wells are located in the Eastern Llanos Region of Colombia.

During 2011 exploration activities are expected to continue in the Cano Sur block, with the goal of evaluating the potential of the Reservoir and the eventual conditions for production.

ION begins multi-client seismic survey in Marcellus Shale

ION Geophysical Corporation has announced the commencement of a new 3D multi-client seismic survey in the Marcellus shale play in central Pennsylvania. ION will manage and execute the entire program, providing a proven mix of survey design, planning and permitting, data acquisition using advanced technologies, data processing, and Reservoir analysis from ION's GX Technology (GXT) imaging solutions subsidiary.

ION has commenced mobilization for the 200-square-mile initial phase of the program.

The Marcellus Shale is one of the hottest Unconventional Gas plays in North America. In April 2009, the United States Department of Energy estimated the Marcellus to contain 262 trillion cubic feet (TCF) of recoverable gas, about 44 billion barrels of oil equivalent (BOE). Economic viability in Shale plays has traditionally been achieved primarily through two engineering technologies, Horizontal Drilling and hydraulic fracture stimulation. Lower gas prices, however, are creating an increased interest in the use of seismic data to not only help the drilling engineer "stay in zone" and avoid geo-hazards, but also to help operators prioritize acreage positions and drilling locations, optimize their drainage strategies and well spacing, and better design their stimulation programs.

Bob Peebler, Chief Executive Officer of ION, commented, "Since 2003, we've been collaborating with E&P companies to push the limits of seismic data in unconventional Reservoirs to help them maximize their return on investment. We've recently conducted several pilot studies in the Marcellus and other North American shales that have demonstrated how we can help our clients determine reservoir rock properties, such as brittleness and natural fracture networks, and help predict the geometry of hydraulically induced fractures, both of which are critical to well planning, stimulation and completion. The Marcellus program is further validation of the growing value leading E&P companies are capturing from the use of seismic to create a sustainable business at scale in the Shale resource plays. We believe there is tremendous upside potential to expand our programs in unconventional Reservoirs in North America and abroad."

ION is working with Tesla-Conquest to provide acquisition services utilizing land seismic technologies from INOVA, the newly formed joint venture between BGP (51%) and ION (49%). INOVA technologies to be deployed on this survey include the FireFly(R) cableless acquisition system and the VectorSeis(R) digital, full-wave sensor.

Steve Bate, President and Chief Executive Officer of INOVA, added, "We are extremely pleased to work with ION and Tesla-Conquest to acquire full-azimuth, multicomponent data to meet our clients' geologic and interpretation objectives. Pennsylvania is both an environmentally sensitive and logistically challenging area, and FireFly and VectorSeis are uniquely capable of enabling a safe, efficient and low impact winter acquisition campaign while delivering state-of-the-art multicomponent measurements."

Eni, Oxy, KOGAS achieve 10% production increase at Iraq’s Zubair Field

Eni, Occidental Petroleum Corporation (NYSE:OXY) and Korea Gas Corporation (KOGAS) announced that they have achieved and sustained a 10-percent increase in oil production at the Zubair field, near Basra in southern Iraq.

Production from the Zubair field has grown to more than 200,000 barrels of oil per day from the approximately 183,000 barrels of oil a day produced when the consortium started field operations in the first quarter of 2010.

The consortium, led by Eni (32.81%) with partners Oxy (23.44%), KOGAS (18.75%) and the Missan Oil Company (25%), signed a technical service contract in late January to redevelop the Zubair field with Iraq's state-owned South Oil Company (SOC) and Missan Oil Company as State Partner.

With the successful 10-percent increase in initial production, the consortium’s contract cost recovery mechanism commences, with the group additionally earning $2 per barrel on the incremental oil production.
The consortium plans to increase production from the Zubair field to 1.2 million barrels of oil a day, representing an increase of about 1 million barrels of oil per day. Target production is expected to be reached progressively within the next six years and maintained for seven years thereafter.

“Oxy’s success in Iraq is a direct result of an outstanding partnership with the Iraqi government and our consortium partners in developing one of the world’s great oilfields,” said Dr. Ray R. Irani, Chairman and Chief Executive Officer of Occidental Petroleum. “We are proud of our initial results in Iraq as well as our continued success in numerous other projects across the Middle East.”

The redevelopment of the Zubair field, one of the largest discovered fields in the world, will support Iraq in becoming a major player in global oil markets. It also will foster social and economic development at a regional and national level, by providing training and development opportunities for the thousands of Iraqi workers of Zubair and by promoting much-needed economic stimulus.

The Zubair Field Operating Division manages the rehabilitation and expansion project, which is staffed mainly by employees from South Oil Company with expert support from the consortium.

Sun River Energy completes Permian Basin well

Sun River Energy, Inc. announced that it has turned the Stansberry # 1 well to production on November 30, 2010.

The Stansberry # 1 well (API # 42-451-32661) is drilled to a total depth of 5,507 feet in Tom Green County, Texas. The well is completed in the Harkey Sand geological formation at 4,780' to 4,784'. The well initially shut-in at 1,650 PSI tubing pressure while awaiting a pipeline connection. Presently, the well is producing both natural gas and crude.

Sun River Operating, Inc. operates the well. Sun River Energy, Inc. owns a 39% working interest in the well.

Statoil awarded licenses offshore Canada

Statoil has been awarded interests in four new licenses offshore Canada. The new acreage underlines the company's ambitions in the area.

The licenses include a Significant Discovery License (SDL) and three Exploration Licences (ELs) off the coast of Newfoundland, awarded through a land sale issue by the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB).

"We are very pleased to learn that we have been successful in acquiring new licences Offshore Newfoundland," says Tim Dodson, senior vice president of Statoil’s global exploration entity.

"Securing these new licences provides further growth opportunities near our Mizzen discovery in the Flemish Pass Basin and near existing infrastructure in the Jeanne d’Arc Basin, as well as more frontier opportunities in a promising basin. We are looking forward to exploring these new opportunities together with our partners and in close cooperation with the authorities."

Statoil has been successful in acquiring the following licenses:
• One SDL, which is an extension of Statoil’s current Mizzen licence. Statoil is operator with a 65% interest and with Husky Oil Operation Limited as partner.
• Two ELs located in the Flemish Pass Basin/Central Ridge region, approximately 500 kilometres Offshore Newfoundland. For the licence located in the vicinity of the Mizzen SDL, Statoil is operator with a 65% interest and Husky Oil as partner. For the licence situated in the northern part of the Flemish Pass Basin, Statoil is operator with a 75% interest and with Repsol as partner.
• One EL located in the Jeanne d’Arc Basin, approximately 250 kilometres offshore Newfoundland. Statoil Canada has a 50% interest and Husky Oil Operation Limited is the operating partner.

Statoil is partner in the ongoing drilling of the Suncor Energy operated Ballicatters well in the Jeanne d’Arc Basin. As operator Statoil is planning to drill a well on its Mizzen discovery located in the Flemish Pass Basin and another on its Fiddlehead licence in the Jeanne d’Arc Basin in 2011/ 2012.

Statoil is also partner in two producing Offshore fields, Terra Nova and Hibernia, and in the field developments of Hibernia Southern Extension and Hebron.

BG Group discovers gas in second Tanzanian well

BG Group announced that its second Tanzanian exploration well, Chewa-1, has also discovered gas. The well, located in Block 4 approximately 80 kilometres Offshore southern Tanzania in a water depth of around 1 300 metres, is some eight kilometres north-west of BG Group's Pweza-1 gas discovery announced in October.

Chewa-1, operated by Ophir Energy plc (40%), is the second of a three-well initial work programme planned for Blocks 1, 3 and 4 Offshore southern Tanzania. The initial work programme also includes the acquisition of 4,000 square kilometres of 3D seismic data. BG Group (60%) has the option to assume operatorship of all three Blocks upon completion of the initial work programme.

BG Group Chief Executive Frank Chapman said: "This is an encouraging start to our campaign in Tanzania. We have a large acreage position to explore and an extensive exploration programme will be needed to assess the full potential of this new play."

Black Dragon begins new drilling program

Black Dragon will commence a new drilling program which will include the drilling of 2-3 new wells.

Black Dragon is also in talks to complete a joint venture on its Spider Field. The company is in the process of sending its land man and geologist to the field to pick the most prolific 12 locations to drill and intends to begin the permit process shortly after.

According to Tom Neely, President, "Management is committed to reaching its year end production goals. The addition of these new wells will increase production rates for the company and lead to increased cash flow. Black Dragon is committed to enhancing shareholder value by exploiting the full potential of its properties expeditiously."

Pertamina, Exxon to develop Natuna gas block Offshore Indonesia

Pertamina and US oil giant Exxon Mobil have signed an agreement to develop Offshore natural gas block Natuna D-Alpha, located off Indonesia in the South China Sea.

Considered the largest gas reserve in Asia, Natuna D-Alpha is estimated to hold 46 million Tcf of natural gas. Production is expected to begin around 2018.

Exxon initially had development rights to the field, however, after a dispute with the Indondesian government about revenue-sharing, rights to Natuna D-Alpha were given to Pertamina in 2008.

Iran to begin drilling for gas in Arash Field

According to Iran's Mehr News agency, Iran will begin gas well drilling operations Offshore at its Arash gas field in the Persian Gulf, Iranian Offshore Oil Company’s managing director Mahmoud Zirakchianzadeh said.

Zirakchianzadeh also added that Iran currently has plans to drill four wells at the field, which contains an extimated 20 Tcf of natural gas between Iran, Kuwait and Saudi Arabia.

Currently, a drilling jacket has been constructed, installed and came on stream at the Arash gas field.

Petrobras confirms oil discovery in the Amazon

Petrobras announced that the first data obtained from the Extended Well Test (EWT), which got underway in September at exploratory well 1-ICB-1-AM (Igarapé Chibata No. 1), confirms the discovery of a new accumulation of light oil (46º API) and natural gas in the city of Tefé (state of Amazonas), 630 km away from the city of Manaus and 32 km from the Urucu oil province. The Company already has three fields producing oil and natural gas in the city of Coari.

The 3,485-meter well was drilled in the Solimões Basin, in Block SOL-T-171, for which Petrobras owns the exploration and production rights. Thus far, the EWT data indicate that the well is capable of producing 2,500 barrels of oil per day, an excellent result when dealing with this type of basin in Brazil.

In addition to the EWT, expected to last a year, the Evaluation Plan, approved by the National Petroleum Agency (ANP), provides for the acquisition of new seismic data and the drilling of delimitation wells. This work aims to determine the extent of the accumulation, to quantify the reserves, and to prove the cost-effectiveness of the accumulation.

This exploratory success is the outcome of the resumption of the exploratory investments, made from 2005, in the onshore basins in the Amazon, as foreseen under the Company's Strategic Plan, which directs efforts to new frontiers where Petrobras' knowledge, technology, and operating experience afford it a competitive advantage.

BP awarded exploration block in Indonesia

Following an announcement last week by the Government of Indonesia last week, BP confirmed that it has been awarded a 100% interest in the North Arafura oil and gas production sharing contract (PSC) in onshore Papua Province. The PSC was signed in Jakarta by representatives of the Government and BP.

The North Arafura PSC is located on the coast of the Arafura Sea, 480 kilometres southeast of the BP-operated Tangguh plant, covering an area of just over 5,000 square kilometers. BP expects to commence seismic operations on the block in the near future.

"This award is further evidence of BP's commitment to a long-term presence in Indonesia, working in partnership with the Government of Indonesia both centrally and regionally. BP is very pleased to expand our position in Papua, an area with huge potential in its people, culture and natural resources," said William Lin, BP's President for Asia Pacific Exploration & Production.

BP makes deep gas discovery in Egypt's West Nile Delta

BP Egypt announced that it has made a significant gas discovery in the Deepwater West Nile Delta area.

The Hodoa discovery is located in the West Mediterranean Deepwater, Nile Delta concession, some 80 km northwest of Alexandria. The WMDW-7 well was drilled to a depth of 6350 metres and is the first Oligocene Deep Water discovery in the West Nile Delta area. Further appraisal is underway.

BP operates and holds 80% of the West Mediterranean Deepwater concession with RWE Dea holding the remaining 20%. Hodoa was drilled by the Pride North America Semi-Sub rig, in a water depth of 1077 metres.

Mike Daly, BP's Executive Vice President of Exploration said: "The Hodoa discovery further demonstrates the great potential of the deep reservoirs in the Nile Delta."

Hesham Mekawi, President and General Manager of BP Egypt, commented: "Hodoa is an important discovery which builds upon BP's previous successes in the West Nile Delta. This discovery further reinforces the leadership role played by BP in Egypt and its ongoing commitment towards the development of Egypt's future gas business."

Statoil and partners awarded new licenses Offshore Greenland

Statoil and its consortium partners – Shell and GDF Suez – have been awarded two large exploration blocks in the Baffin Bay bid round in West Greenland. Shell will be the operator of both blocks.
Blocks 5 and 8, where Greenland’s national oil company Nunaoil will have a carried interest during the exploration phase, are 9,991 and 10,618 square kilometres, respectively. Each block is equivalent to approximately 15 Norwegian blocks.

“We are looking forward to exploring these new frontier opportunities in the Baffin Bay together with our partners in the bid consortium and in close cooperation with the Greenland authorities,” says Tim Dodson, Statoil’s senior vice president for global exploration.

“These awards increase the optionality of our exploration portfolio. While early access to such frontier opportunities entails more uncertainties related to probability of discovery, the potential reward of one or more sizeable discoveries may be high. Together with our partners, we will use all of our experience and competence from more than 30 years of oil and gas operations in harsh environments on the Norwegian continental shelf,” Dodson continues.

This is not the first time Statoil has carried out activities in Greenland. In the 1990s, Statoil drilled an exploration well in the Fylla area west of Greenland – but the company relinquished this exploration license in 2002. Statoil is also part of the Kanumas group in East Greenland.

Statoil already holds important Offshore positions in sub-Arctic conditions in Norway, Russia and Canada.

Anadarko makes third major gas discovery offshore Mozambique

Anadarko announced its third major natural gas discovery this year in the Offshore Area 1 of Mozambique's Rovuma Basin at the Lagosta prospect. The discovery well encountered a total of more than 550 net feet of natural gas pay in multiple high-quality Oligocene and Eocene sands.

"The Lagosta discovery, located approximately 16 miles to the south of the previously announced Barquentine discovery and 14 miles to the southeast of the Windjammer discovery, significantly expands this emerging world-class natural gas province," Anadarko Sr. Vice President, Worldwide Exploration Bob Daniels said. "The Lagosta discovery continues to validate our geophysical models, and we expect to keep the Belford Dolphin drillship in the basin for the foreseeable future to continue a very active exploration and appraisal program, including at least one planned drillstem test in 2011.

"Although additional appraisal drilling will be required, we believe the three discoveries announced to date already exceed the resource size threshold necessary to support an LNG (liquefied natural gas) development, and we have assigned an integrated project team to begin advancing commercialization options. Given the global LNG trade and its indexing to the global crude market, this resource can provide tremendous economic value for the people of Mozambique, the government and the partnership," added Daniels.

The Lagosta exploration well has been drilled to a current depth of approximately 13,850 feet in water depths of approximately 5,080 feet. The partnership plans to drill to a total depth of approximately 15,900 feet to evaluate a deeper zone. Once operations are complete at Lagosta, the partnership expects to mobilize the rig 17.5 miles to the southwest to drill the Tubarao exploration well, which also is located in the 2.6-million-acre Offshore Area 1.

Anadarko is the operator of Offshore Area 1 with a 36.5% working interest. Co-owners in the area are Mitsui E&P Mozambique Area 1, Limited (20%), BPRL Ventures Mozambique B.V. (10%), Videocon Mozambique Rovuma 1 Limited (10%) and Cove Energy Mozambique Rovuma Offshore, Ltd. (8.5%). Empresa Nacional de Hidrocarbonetos, ep's 15% interest is carried through the exploration phase.