Oil and Natural Gas in Libya

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Libya holds Africa's largest proven oil reserves at 36 billion barrels and gas reserves of an estimated 46 trillion cubic feet. The country has 12 oil fields with reserves of more than one billion barrels each. Many foreign oil company interests in Libya were nationalized in the 1970's. Others pulled out when the United States imposed sanctions in 1986, but the country has attracted considerable interest from international oil companies since 2004, when the United States and European Union eased sanctions following Libya's agreement not to pursue nuclear, chemical and biological weapons.
Libya relies on oil and natural gas to satisfy energy consumption demand. Economic growth in Libya is dependent on the hydrocarbon industry. According to the World Bank, the country’s hydrocarbon exports account for over 95 percent of total merchandize exports and revenues from the oil and natural gas sectors amount to over half of the country’s gross domestic product (GDP). Since the United Nations and the United States lifted sanctions over Libya in 2003 and 2004, respectively, oil majors have stepped up exploration efforts for oil and natural gas in the country. Likewise, companies have tried using enhanced oil recovery (EOR) techniques to increase production at maturing fields. Over the next six years, Libya would like to see oil production capacity increase by 40 percent from 1.8 million barrels per day (bbl/d) to 3 million bbl/d by 2013.
Libya, a member of the Organization of Petroleum Exporting Countries (OPEC), holds the largest proven oil reserves in Africa, followed by Nigeria and Algeria. According to Oil and Gas Journal (OGJ), Libya had total proven oil reserves of 41.5 billion barrels as of January 2007, up from 39.1 billion barrels in 2006. About 80 percent of Libya’s proven oil reserves are located in the Sirte basin, which is responsible for 90 percent of the country’s oil output. Libya remains "highly unexplored" according to reports by Wood Mackenzie, and only around 25 percent of Libya is covered by exploration agreements with oil companies. The under-exploration of Libya reflects the impact of former sanctions and also stringent fiscal terms imposed by Libya on foreign oil companies.

• Oil production: 1.72 million bbl/day (2006 est.)
• Oil exports: 1.34 million bbl/day (2004)
• Oil proved reserves: 42 billion bbl (2006 est.)

• Natural gas production: 8.06 billion cu m (2004 est.)
• Natural gas exports: 2.13 billion cu m (2004 est.)
• Natural gas proved reserves: 1.472 trillion cu m (1 January 2005 est.)

• According to the International Crude Oil Market Handbook, Libya’s National Oil Corporation (NOC) would like to raise oil production from 1.80 million bbl/d in 2006 to 2 million bbl/d by 2008 and to 3 million bbl/d by 2010-2013. In large part, NOC’s production goals depend on its ability to finance its share of development costs. Future foreign investment into the oil sector is likely, especially with the improved investment climate that stems from the United Nations and United States lifting sanctions. Previously, sanctions had caused delays in a number of field development and EOR projects and had deterred foreign capital investment. Overall, Libya is considered a highly attractive oil province due to its low cost of oil recovery (as low as $1 per barrel at some fields), the high quality of its oil, and its proximity to European markets.
  With state-operated oil fields undergoing a 7-8 percent natural decline rate, Libya's challenge is maintaining production at mature fields, while finding new oil and developing new discoveries.
  

• In November 2005, Repsol YPF (operator) announced that it had discovered a significant new oil deposit of light, sweet crude that extends over two licenses in the Murzuq Basin. Industry experts believe the discovery to be one of the biggest made in Libya for several years. The discovery is partly located in license NC-186, which currently produces around 60,000 bbl/d. Production on the license is expected to increase over the next 4-year period (2007-2011) by 100,000 – 150,000 bbl/d as oil from the discovery comes online. Repsol YPF is joined by a consortium of partners that includes OMV Aktiengesellschaft, Total and Norsk Hydro.

• Also located in Murzuq Basin is Eni’s Elephant field. In October 1997, an international consortium led by British company Lasmo plc, along with Eni and a group of five South Korean companies, announced that it had discovered large recoverable crude reserves (around 700 million barrels) at the NC-174 Block, 465 miles south of Tripoli. Lasmo, which was purchased by Eni in 2001, estimated that production from the field would cost around $1 per barrel. Elephant began production in February 2004 at around 10,000 bbl/d. In 2006, Eni indicated that Elephant was producing at around 125,000 bbl/d, and the company was hoping to see the field reach full capacity of 150,000 bbl/d by 2008.

• Waha Oil Company’s (WOC) Waha fields currently produce around 350,000 bbl/d, down from around 1 million bbl/d in 1969 and 400,000 bbl/d in 1986. However, WOC expects to increase Waha output by around 200,000 bbl/d over the next couple of years.

• In 2005, ConocoPhillips and co-venturers reached an agreement with NOC to both return to its operations in Libya and to extend the Waha concession by 25 years. ConocoPhillips operates the Waha fields with a 16.33 percent share in the project. NOC has the largest share of the Waha concession 59.17 percent, and additional partners include Marathon (16.33 percent), and Amerada Hess (8.17 percent).
  

• BP plc [NYSE:BP] negotiated an agreement with Libya to explore for natural gas in the north African country, the chairman of the state owned National Oil Corporation announced in May, 2007.

• ExxonMobil [NYSE:XOM] obtained a licence in 2005 to explore an area covering 2.5 million acres in the Cyrenaica Basin, one of the country's largest energy fields.

Oil and Natural Gas in Liberia

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In 2005, Liberia held its first licensing round since the cessation of its civil war in 2003. Liberia awarded exploration concessions to UK-based Regal Petroleum plc, Repsol, Woodside Petroleum Ltd, Broadway Consolidated and Oranto Petroleum. In addition, Canadian-based Ona Exploration Inc signed a Memorandum of Understanding (MoU) with the Liberian government for oil and natural gas drilling rights in two offshore concessions.

Oil and Natural Gas in Kenya

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Kenya currently does not produce crude oil, and must import all of the 57,000 bbl/d it consumes. Previous exploration attempts for a domestic source of oil have met mostly with disappointment. However, with the most recent round of exploration performed in the later half of 2003 by Australian-based Woodside Petroleum, Pancontinental, and UK-based Dana Petroleum, and others, hopes are high that the renewed search for oil in Kenya may enjoy greater success. The Kenyan government has spent about $169 million exploring for oil and natural gas over the past 15 years. Over 30 wells have been drilled so far, but without much success. Work is also continuing by the new Kenyan government of President Kibaki to introduce a New Petroleum Bill designed to help better regulate Kenya's petroleum sector.

• In April 2001, Dana Petroleum was awarded several production-sharing licenses by the Kenya.The blocks - L5, L7, L10 and L11 - situated in the Lamu Basin and represent one-half of Kenya's available offshore concessions.
  

• In May 2003, Woodside Petroleum, acquired a 40% stake in those blocks from Dana. Dana will retain a 40% holding, with the remaining 20% stake held by Star Petroleum, a subsidiary of Global Petroleum Ltd. Woodside is now the operator of the blocks. A seismic study was initiated in the third quarter of 2003, after which two exploration wells are scheduled to be drilled.
  

• In April 2002, the Kenyan government executed agreements that grant exclusive exploration rights of blocks L6, L8, and L9 to Pancontinental Oil & Gas NL (60%) and a UK-based Afrex Limited (40%). In August 2003, Woodside farmed into the three blocks, taking a 50% operating stake. Afrex will now hold a 30% stake, while Pancon will hold the remaining 20%. In return for its entry, Woodside will undertake the seismic work for the three blocks. A 3,488 mile survey across all seven blocks was completed and sent for data analysis during the fourth quarter of 2003 with results to be available in early 2004.

Oil and Natural Gas in Guinea-Bissau

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In March 2002, U.K.-independent Premier Oil plc announced the results of its first exploratory well on the Sinapa prospect (Block 2) offshore Guinea-Bissau. The Sinapa-1 exploratory well has been designated plugged and abandoned with oil shows. Despite the disappointing results, Premier Oil plans to retain its acreage in Guinea-Bissau, and is in the process of reviewing seismic data on its holdings. In addition, Premier Oil planned to drill exploration wells, Eirozes and Espinafre, towards the end of 2006. The national oil company of Guinea-Bissau, Petroguin, is planning to offer the country's new deep-water acreage to prospective investors. Exploration activity in the region has sparked interest in the remaining 11 offshore blocks.

Oil and Natural Gas in Guinea

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Houston's HyperDynamics Corporation has been meeting with government officials to discuss hydrocarbon development plans in the country. The company has exploration and data marketing rights for the entire continental margin of Guinea, which covers 210 miles of coastline and up to 150 miles offshore.

Oil and Natural Gas in Ghana

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The Ghana National Petroleum Corporation (GNPC) was established in 1983 as a body corporate to undertake the “exploration, development, production and disposal of petroleum”. GNPC began to operate in 1985.

• Oil production: 7,477 bbl/day (2004 est.)
• Oil proved reserves: 8.255 million bbl (1 January 2002)

• Natural gas proved reserves: 23.79 billion cu m (1 January 2005 est.)

• In 2002, Oklahoma-based Devon Energy and Canadian independent EnCana Corporation entered into an agreement with the GNPC to explore for hydrocarbons offshore of southeastern Ghana in the Keta Basin. The companies are currently analyzing seismic data on the Keta Block. Devon has been active in Ghana since 1997 when it acquired the Keta concession.

• Houston-based Vanco Energy Company also signed an exploration agreement with the Ghanaian government in August 2002. In May 2005, Vanco Energy completed 3D seismic research on its Cape Three Points Deepwater Block, and the company planned to drill its first exploration well on the block in 2006.
  

• In 2005, Saltpond Offshore Producing Ltd (SOPL), which is owned by the U.S.-registered Lushann-Eternit (60 percent) and the state-owned Ghana National Petroleum Company (GNPC) (40 percent), signed a $5 million redevelopment project that will restart six wells on the Saltpond oil and natural gas field. SOPL hopes the additional wells will increase production from the current 500 bbl/d to 1,500 bbl/d. The former operator of Saltpond field, Agripetco, had shut the field down in 1985 due to decreasing output.

• Scottish-based Dana Petroleum is currently analyzing exploration targets in the deepwater section of its West Tano Block. The company previously drilled two successful test wells, WT-1X and WT-2X on Tano field, and made estimates that the field contained oil reserves of 200 million barrels. However, Dana Petroleum indicated that only a small amount of the oil would be recoverable due to geological reasons. Dana Petroleum operates the block with 90 percent interest and is joined with GNPC (10 percent).

• Dallas-based, Kosmos Energy signed a seven-year oil exploration agreement with Ghana. Kosmos will search for oil in the Tano Basin, adjacent to Vanco Energy’s Cape Three Points Deepwater Block. Kosmos is operator of the West Cape Three Points license with 86.5 percent interest and is joined with GNPC (10 percent) and E.O. Group - a Ghanaian oil and gas company- (3.5 percent).
  

• Tullow Oil plc was awarded operating interests in June 2006 in two offshore licences in Ghana, Shallow Water Tano and Deepwater Tano. Tullow Oil operates the Deepwater Tano license, in which a significant well was drilled in 2007, holding a 50% stake. Its partners are Kosmos Energy and a subsidiary of Anadarko Petroleum Corp, Sabre Oil & Gas, and the Ghana National Petroleum Corp. At the same time Tullow concluded a farm-in agreement on a third offshore licence thereby acquiring a 22.9% interest in the adjacent West Cape Three Points block. The Shallow Water Tano block contains three undeveloped oil and gas fields and Tullow's initial objective is to evaluate the potential to commercialise one or more of these accumulations. The other two blocks offer significant exploration potential in both the Albian and Upper Cretaceous intervals. The three licences lie in the greater Ivorian Basin and are on trend with the Espoir oil and gas field in neighbouring Côte d'Ivoire in which Tullow holds a 21.33% interest.

Source: Tullow Oil

Oil and Natural Gas in Gambia

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• Amerada Hess (80 percent interest) and Sterling Energy plc (20 percent) hold the rights to The Gambia's Deepwater PPL Block. The license has been issued for six years and the companies are currently finalizing interpretation studies and evaluating options for a 3D seismic data acquisition.

• In July 2005, The Gambia awarded Philippine National Oil Company (PNOC) one of The Gambia’s six oil exploration blocks. The Gambia gave the award to PNOC without tender, or a technical review of the company’s capabilities.

Oil and Natural Gas in Gabon

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Gabon’s economy is highly dependent on oil production, with the country’s oil exports accounting for 51 percent of GDP and 63 percent of government revenues. Gabon’s per capita GDP is approximately $5,500, well above most of sub-Saharan Africa.
According to Oil and Gas Journal (OGJ), Gabon had proven oil reserves of 2 billion barrels as of January 2007, down from 2.5 billion in 2006. Oil production for 2006 was an estimated 240,000 bbl/d, making Gabon the sixth largest producer in sub-Saharan Africa. This figure however, represents a sharp decline from the 1997 peak production of 370,000 bbl/d as most fields are beyond their peak production.
Gabon currently has 122 producing fields and new drilling is expected to increase production figures over the next couple of years. According to EIA’s Short-Term Energy Outlook, Gabonese oil production averaged around 240,000 bbl/d from January to September of 2007, increasing to 250,000 bbl/d in the fourth quarter of 2007. In 2006, domestic oil consumption was at 12,000 bbl/d, allowing most of the oil produced to be exported to the United States, Europe (mainly France) and, increasingly China and India.
The two major oil companies operating in Gabon are Royal Dutch Shell and Total—although the largest producer is currently Addax Petroleum, an independent company. Other independents operating in the country include Tullow Oil, Vaalco Energy Inc, Maurel et Prom (M&P).
Gabon’s Oil Ministry is responsible for all regulation in the oil industry. The country has a national oil company, Société Nationale Petrolière Gabonaise (SNPG); however, SNPG is not actively involved in development projects.

• Oil production: 268,900 bbl/day (2005 est.)

• Oil proved reserves: 1.827 billion bbl (2006 est.)

• Natural gas production: 100 million cu m (2004 est.)
• Natural gas proved reserves: 33.98 billion cu m (1 January 2005 est.)

Source: African Oil Journal

• The onshore Shell-operated Rabi-Kounga field contains the vast majority of Gabon’s proven oil, while additional reserves are located in the offshore Tchatamba Marin and Etame fields.

• In July 2006, Addax Petroleum purchased the interests of Pan-Ocean Energy in Gabon for $1.4 billion. The acquisition makes Addax the largest producer in Gabon, with total production of more than 100,000 bbl/d. According to Addax Petroleum, some of their near-term development plans include the continued drilling in the Tsengui and Obangue fields (where production has already increased by 20,000 bbl/d in the first half of 2007), completion of an export pipeline, which will transport oil from the onshore Obangue field to the Coucal pipeline system and export terminal at Cap Lopez, and future development of the Koula field.

• Tullow Oil recently increased its acreage position in Gabon and as a result holds interests in 18 licences including eleven producing fields. Oil production from Gabon during 2006 averaged 15,125 bopd net to Tullow, representing 23% of the Group's total.
  In a recently completed deal Tullow acquired a package of assets from the Gabonese Government through a 50:50 Joint Venture with AIC-Petrofi Limited. The package comprised interests in three producing fields and back-in rights to a further nine Exploration Licences. Two additional fields, where Tullow has back-in rights, are awaiting development approval and are expected on stream over the next 18 months.
  The acquisition adds production of approximately 550 boepd net to Tullow from the Obangue (3.75%), Tsiengui (3.75%) and Oba (5%) fields. This figure is expected to rise to approximately 1,000 boepd by early 2008 as development of the three fields progresses and when the two additional developments are brought on stream.
  The exploration licences are located in areas of significant potential and when combined with Tullow's existing Gabonese interests give the Group exposure to almost 40% of Gabon's currently licensed acreage.
  Development of the first Etame satellite, the Avouma (7.5%) field, was successfully completed in December 2006 and first production commenced in mid January 2007. Detailed planning for a further Etame satellite, the Ebouri discovery (7.5%) is under way with a view to first production during 2008.
  Gabon is regarded as a key growth area within the Tullow portfolio, with a range of exploration, development, commercial and acquisition activities. Opportunities to expand the Gabon portfolio are continually being assessed.

Source: Tullow Oil

• VAALCO Energy, Inc has a 30.350% (28.074% development and production) interest in the 750,000 acre Etame Marin Block offshore Gabon, West Africa. VAALCO also has a production sharing contract with the Ministry of Mines, Energy, Petroleum, and Hydraulic Resources of Gabon for the Mutamba Iroru G4-219 Permit located onshore Gabon containing approximately 270,000 acres.

Oil and Natural Gas in Ethiopia

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"Ethiopia: White Nile to Ink Oil Exploration Deal"

Ethiopia's current proven hydrocarbon reserves are minimal, but the potential to increase reserves to commercial viability is seen as promising. The country's geology is similar to that of its oil-producing neighbors to the east (on the Arabian peninsula) and the west (Sudan). In April 2001, the Ministry of Mines and Energy reported that hydrocarbon seeps had been discovered in several regions. The government plans to conduct feasibility studies to establish the extent and viability of the deposits.
Hydrocarbon exploration in Ethiopia's Ogaden Basin began over 80 years ago (Standard Oil in 1920). The Ethiopian government formed the Calub Gas Share Company (CGSC) to develop the fields. In 1994, the World Bank approved a $74 million loan to develop the Ogaden Basin fields. The Ethiopian Privatization Agency (EPA) put the CGSC up for privatization in 1998, but the EPA, citing weak bids, withdrew the tender. In December 1999, Houston-based Sicor Inc announced that it had signed a $1.4 billion joint-venture deal to develop the Calub natural gas project. Under the terms of the agreement, Gasoil Ethiopia Project (GEP), the joint-venture firm, will acquire 95 percent of the CGSC under the Ethiopian government's privatization law. Currently, 5 percent of the CGSC is held by local private investors. The Ethiopian government will hold a 20 percent interest in GEP with Sicor holding the remaining share. In December 2002, the Russian state-owned companies Methanol and Stroytransgas were negotiating with the Government to buy 50% of CGSC.
GEP plans to construct a 375-mile, 24-inch pipeline to transmit natural gas to the town of Awash, which is approximately 75 miles east of the capital Addis Ababa. At Awash, plans call for construction of a cryogenic liquids plant and two gas-to-liquids process systems with capacity to process 200 million cubic feet per day (Mmcf/d) of natural gas. The end products would be synthetic fuels and petrochemical feedstocks plus steam to generate electricity and help produce 20,000 bbl/d of potable water. A planned refinery would produce products including diesel, gasoline, kerosene and jet fuels. The gas-to-liquids system would also produce some 500 tons of ammonia per day as feedstock for a urea plant to be constructed. Construction of the pipeline had originally been planned for 2002; however, gas development in Ogaden has not yet begun.

In June 2003, the Ethiopian government signed an oil exploration deal with Petronas for 5,800 square mile tract in Gambela, in the far western part of the country. The region is closely related to the Sudan oil fields. Petronas has committed to investing in regional infrastructure, employing local staff, improving health services, and developing the skills of the ministry of Mines. Petronas is also interested in natural gas exploration in Ogaden, but no official plans have yet been made.

• Oil proved reserves: 214,000 bbl (1 January 2002)

• Natural gas proved reserves: 24.92 billion cu m (1 January 2005 est.)

Oil and Natural Gas in Eritrea

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• Hydrocarbon exploration, primarily offshore in the Red Sea, began in the 1960's when Eritrea was still federated with Ethiopia. In 1995, Eritrea signed a production sharing contract (PSC) with U.S.-based Anadarko Petroleum (Anadarko) for the offshore Zula Block. Anadarko signed a second PSC for the offshore Edd Block, located south of the Zula Block, in September 1997. Anadarko announced, in December 1997, that it had reached an agreement with ENI/Agip (Agip) to swap interests in exploration acreage. Anadarko received a 25 percent interest in a Tunisian block operated by Agip, and Agip received a 30 percent share in the 6.7-million acre Zula Block and 30 percent interest in the Edd Block. Burlington Resources, a U.S.-based independent who later merged with ConocoPhillips, later joined the consortium by acquiring a 20 percent interest in both acreages. Anadarko's first two exploration wells, both drilled on the Zula Block, were unsuccessful. In January 1999, a third dry well, Edd-1 on the Edd Block, was drilled. Citing the disappointing exploration results, Anadarko and its partners ceased exploration activities and relinquished their rights to the offshore blocks.

• Another attempt also did not meet with success. In May 2001, U.S.-firm CMS Energy signed an exploration agreement for a 14,000-square kilometer block in northeastern Eritrea, but the company did not find oil. CMS Energy sold its exploration interests to Perenco S.A. of France in late 2002.

Oil and Natural Gas in Morocco

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According to January 2006 estimates by the Oil and Gas Journal (OGJ), Morocco has proven oil reserves of 1.07 million barrels and natural gas reserves of 60 billion cubic feet (Bcf). Morocco may have additional hydrocarbon reserves, as many of the country's sedimentary basins have not yet been explored.
Morocco produces small volumes of oil and natural gas from the Essaouira Basin and small amounts of natural gas from the Gharb Basin. Consequently, Morocco is the largest energy importer in northern Africa. The country’s total yearly costs for energy imports range from $1- $1.5 billion. However, high oil prices in 2005 increased import costs to approximately $2 billion for the year. In 2003, the Moroccan government announced that foreign companies could import oil without paying import tariffs. This followed a 2000 decision, in which, Morocco modified its hydrocarbons law in order to offer a 10-year tax break to offshore oil production firms, and to reduce the government's stake in future oil concessions to a maximum of 25 percent. The entire energy sector is due to be liberalized by 2007.
The Moroccan Office of Hydrocarbons and Mining (ONHYM) has become optimistic about finding additional reserves - particularly offshore - following discoveries in neighboring Mauritania. At the end of 2005, 19 foreign companies were operating in Morocco, with an estimated total investment of $56 million per year.

Recent activity in Western Sahara, which is believed to contain viable hydrocarbon reserves, has been controversial. In 2001, Morocco granted exploration contracts to Total and Kerr-McGee, angering Premier Oil and Sterling Energy, which previously had obtained licenses from the Polisario government. In 2005, the government-in-exile of the Western Sahara invited foreign companies to bid on 12 contracts for offshore exploration, with hopes of awarding production sharing contracts by the end of 2005. Both Premier Oil and Sterling Energy received conditional exploration rights. Foreign companies operating under Moroccan concession in Western Sahara have become targets of international protest campaigns. These companies include Total, Wessex Exploration Ltd, Svitzer (the British subsidiary of the Dutch company Fugro), Wales' Robertson Research International and Norway's TGS Nopec. All have ended their operations in Western Sahara, with the exception of Kerr-McGee. As of November 2005, the company was the last to be drilling in Western Sahara, although the Polisario government has pressured it to pull out.

• Oil production: 300 bbl/day (2005 est.)
• Oil proved reserves: 100 million bbl (2006 est.)

• Natural gas production: 50 million cu m (2004 est.)
• Natural gas proved reserves: 1.218 billion cu m (1 January 2005 est.)

• In March 2004, Calgary-based Stratic Energy Corporation committed to a three-year exploration program in two onshore blocks in northwest Morocco. The two concessions cover approximately 1,544 square miles.

• In April 2004, Norway's Norsk Hydro signed a 12-month exploration contract for the Safi Offshore Northwest zone, while Denmark's Maersk signed an eight-year agreement for eight blocks near Tarfaya.

• In May 2004, China National Oil Corporation (CNOOC) received a license to drill near Agadir.
  

• Other foreign firms engaged in exploration include Petronas, Cooper Energy NL, Shell, Total, and Tullow Oil.

Oil and Natural Gas in Equatorial Guinea

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Equatorial Guinea has experienced rapid economic growth due to the discovery of large offshore oil reserves, and has become Sub-Saharan Africa’s third largest oil exporter after Nigeria and Angola. According to the World Bank, oil revenues increased in value from $3 million in 1993 to $190 million in 2000 to $3.3 billion in 2006. From 2002 to 2006 the country experienced an average real annual GDP growth of 15.8 percent. Oil exports currently represent over 90 percent of total export earnings. However, a slowdown in oil production has caused GDP growth to decelerate to 6.8 percent in 2007.
According to the Oil and Gas Journal, Equatorial Guinea had estimated proved oil reserves of 1.1 billion barrels as of January 2007. The majority of these reserves are located offshore in the oil-rich Gulf of Guinea. Since the 1995 discovery of the Zafiro field, Equatorial Guinea's oil production has increased dramatically. In 1995, oil production was 5,000 barrels per day (bbl/d), which increased to 385,970 b/d in 2006.
The Ministry of Mines, Industry and Energy is the overall regulatory body for the petroleum industry in Equatorial Guinea. The Equatoguinean government created a national oil company (GEPetrol) that became operational in 2002. GEPetrol’s primary focus is to manage the interest stakes of the Equatoguinean government in various production sharing contracts (PSAs) and joint ventures (JVs) with foreign oil companies. The company can also participate in oil exploration and production activities outside Equatorial Guinea.

• Oil production: 420,000 bbl/day (2005 est.)
• Oil proved reserves: 563.5 million bbl (1 January 2002)

• Natural gas production: 100 million cu m (2004 est.)
• Natural gas proved reserves: 36.81 billion cu m (1 January 2005 est.)

• In 1995, ExxonMobil and Ocean Energy discovered the Zafiro field, which is located northwest of Bioko Island. Zafiro was the first deepwater field to be brought on stream in West Africa and is currently the main producing field in Equatorial Guinea. Zafiro is currently operated by an ExxonMobil-led consortium that includes Devon Louisiana and GEPetrol. According to the Energy Intelligence Group (EIG) the field contains estimated recoverable reserves of over 400 million barrels, and is Equatorial Guinea's largest oil producer, with an output of 245,000 bbl/d for the first half of 2006.
  Zafiro, as of 2005, has been blended with Topacio and marketed as “New Zafiro”, a low-sulfur distillate rich crude oil. Zafiro was traditionally sold across the US, Europe and Asia-Pacific markets, but recently China has emerged as its single most important purchaser, buying over half its export volumes.

• Alba, Equatorial Guinea's third largest field is located 12 miles north of Bioko Island. According to the EIG, Alba is a major condensate field containing an estimated 400 million barrels of liquids. The field currently produces between 65,000 and 75,000 bbl/d of condensates and 20,000 bbl/d of liquefied petroleum gas (LPG). Marathon Oil Corporation serves as operator of Alba field along with GEPetrol.

• Additional production could come from( Amerada) Hess Corporation’s Northern Block G field, expected to come on stream at the end of 2007. According to EIG, initial production is expected to be around 60,000 bbl/d.

• In 2005, the Equatoguinean government planned to begin a new licensing round for offshore acreage, including parts of Blocks F, G, H and L in the Rio Muni Basin. After several delays, the licensing round went ahead in September 2007. Blocks were awarded to India’s Oil and Natural Gas Corporation Ltd, the Nigerian National Petroleum Corporation, and other independent producers. Prior to the licensing round, PetroSA, the South African state oil company was allocated three blocks for the country’s role in preventing a coup attempt against the government of Equatorial Guinea in 2004.

• Asian firms from China, India and the Philippines are especially interested in gaining exploration rights. In February 2006, the China National Offshore Oil Company (CNOOC) signed a production sharing agreement (PSA) for offshore acreage in Equatoguinean waters. Under the contract, CNOOC and GEPetrol will have the rights to explore the acreage over the next five years.

• Tullow Oil holds interests in two production licences offshore Equatorial Guinea, covering the Ceiba field and the Okume Complex. An extension is currently being negotiated on a third licence, which covers exploration Block L, to allow completion of the required regional studies prior to commiting to a well in the next exploration period2006 average gross production from the Ceiba field (Tullow 14.25%) was 40,000 bopd. This was maintained by a successful infill and water injection programme to re-pressurise the reservoir. Infill drilling will continue in 2007 and production is expected to remain around 2006 levels throughout 2007. Production from the Hess operated Okume Complex development (Tullow 14.25%) commenced, ahead of schedule, on 14 December 2006. By early March 2007 the field was producing at 20,000 bopd from 5 wells. This figure will steadily increase during 2007 as more wells are brought on stream. Peak production of 60,000 bopd, is expected to be achieved in mid-2008. The project involves the integrated development of the Okume, Oveng, Ebano and Elon oil fields, collectively known as the Okume Complex. The development includes two tension leg platforms (TLPs), four fixed platforms, and the drilling of over 40 wells. Production from the fields is gathered at a central processing facility (CPF) located at the shallow water Elon field. A 24 km pipeline connects the CPF to the Sendje Ceiba FPSO vessel, which has a storage capacity of 2.1 million barrels, and currently handles production from the nearby Ceiba field.

Source: Tullow Oil

Oil and Natural Gas in Egypt

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Though Egypt’s net exports of crude oil and petroleum products have declined in recent years, higher prices on world markets have pushed Egypt's oil revenues upward. The country also began exports of liquefied natural gas (LNG) in January 2005, adding to its hydrocarbon revenues.
According to the Oil and Gas Journal, Egypt’s estimated proven oil reserves stand at 3.7 billon barrels, or 0.3 percent of world reserves, while crude oil production averaged 579,000 bbl/d in 2005, less than 1 percent of world production. Egypt is hoping that exploration activity, particularly in new areas, will discover sufficient oil in the coming years to slow recent annual declines in output. Egyptian oil production comes from four main areas: the Gulf of Suez (about 50 percent), the Western Desert, the Eastern Desert, and the Sinai Peninsula.

• Oil production: 700,000 bbl/day (2005 est.)
• Oil exports: 134,000 bbl/day (2004 est.)
• Oil proved reserves: 2.6 billion bbl (2006 est.)

• Natural gas production: 32.56 billion cu m (2004 est.)
• Natural gas exports: 1.1 billion cu m (2004 est.)
• Natural gas proved reserves: 1.657 trillion cu m (1 January 2005 est.)

• Oil from the Gulf of Suez basin is produced mainly by Gupco (Gulf of Suez Petroleum Company) under a Production Sharing Agreement (PSA) between BP and the Egyptian General Petroleum Corporation (EGPC). Production in the Gupco fields, with most wells in operation since the 1960s and 1970s, has fallen in recent years. Gupco is attempting to slow the natural decline in its fields through significant investments in enhanced oil recovery (EOR) as well as in increased exploration. In May 2003, BP announced a large new find, the Saqqara field, which represents the largest new crude oil discovery in Egypt since 1989. Located offshore adjacent to the existing El-Morgan field, it is expected to begin commercial production in 2007. With estimated peak production of around 40,000 to 50,000 bbl/d this find may stem the decline in overall Gulf of Suez production.

• Egypt's second largest oil producer is Petrobel, which is a joint venture between EGPC and Eni of Italy. Petrobel operates the Belayim fields near the Gulf of Suez and also is undertaking an EOR program to stem declining production. A joint venture between EGPC and Eni also is producing about 40,000 bbl/d from an area in the Qattara Depression in the Western Desert, in the Meleiha and West Razzaq blocks.

• Other major companies in the Egyptian oil industry include Badr el-Din Petroleum Company (EGPC and Shell); Suez Oil Company (EGPC and Deminex); and El Zaafarana Oil Company (EGPC and British Gas).
  

• Egypt's overall oil production has been declining more slowly than in the Gulf of Suez fields, due to new output from independent producers like Apache Corporation and Seagull Energy Corporation at smaller fields, especially in the Western Desert and Upper Egypt. Since 2000, Western Desert production has risen substantially, accounting for roughly 27 percent of total oil production, more than double 2000 levels. Of additional significance is that oil in this area is on average cheaper to produce and lighter than other domestic crudes. Apache and Seagull also have developed the Wadi El-Sahl field in the South Hurghada block, which is producing around 20,000 bbl/d. Khalda Petroleum, a joint venture between Apache and EGPC, produces around 50,000 bbl/d in the Western Desert in the Khalda and East Bahariyya areas.

• Firms are beginning to explore offshore oil production possibilities in the Mediterranean. The largest concession was awarded to Shell in February 1999 for a large deepwater area off Egypt's Mediterranean coast. Shell reportedly is optimistic about the prospects for its North East Mediterranean Deepwater (NEMED) concession, but drilling so far has yielded natural gas rather than significant quantities of oil.

• BP and Total also were awarded a large offshore block from the same bidding round.
  

• A smaller offshore concession was awarded to Eni. While most offshore discoveries in the Nile Delta have been natural gas, it is believed that there may also be significant quantities of oil in the area.
  

• EGPC awarded five exploration contracts in July 2004 to a newly-formed, state-owned upstream oil firm, Tharwa Oil. Four of the five concessions cover unexplored areas of the Western Desert, with the fifth covering an offshore block in the Mediterranean.
  

• Burren Energy of the UK also was awarded two blocks in the Gulf of Suez under the 2004 licensing round, which closed in January 2005. Other awards under the 2004 licensing round are still pending.

Oil and Natural Gas in Mauritania

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Mauritania's offshore region became a new oil province with Woodside Petroleum Ltd's Chinguetti, Banda, Tiof and Tevet discoveries between 2001 and 2004 which have oil reserves of several hundred million barrels. In February 2006, Mauritania began producing its first oil from the Chinguetti oilfield , which is located offshore 56 miles southwest of Nouakchott. The field has estimated proven reserves of 123 million barrels of oil. The field was producing around 15,000 barrels per day (bbl/d), but output was expected to reach capacity of 75,000 bbl/d by the end of 2006.
The Mauritanian government created the national oil company, Société Mauritanienne des Hydrocarbures(SMH), in 2004.
In March 2005, the Mauritanian government created a separate ministry of oil and energy to handle the energy portfolio. The ministry is headed by Mohamed Aly Ould Sidi Mohamed. In 2005, Mauritania imported 24,000 bbl/d of petroleum products, as its refinery is not in use.

• Oil production: 75,000 bbl/day (2006 est.)
• Oil proved reserves: 1 billion bbl (2005)

• Woodside Petroleum operates the Chinguetti field with a 47.38 percent interest and is joined with partners Hardman Resources (19.01 percent), Mauritanian-government controlled Société Mauritanienne des Hydrocarbures (12 percent), BG Group (10.23 percent), Premier Oil (8.12 percent) and Roc Oil Company Ltd (3.25 percent).
  In addition to Chinguetti field, Mauritania possesses several other promising offshore oil and gas fields. The Tiof oilfield, which is located 16 miles north of the Chinguetti field, may contain up to 350 million barrels of oil. The Tiof-6 exploration well was drilled successfully in February 2005. Woodside and its partners believe that the field may start producing at 50,000 bbl/d in mid-2007, with production potentially rising to 150,000 bbl/d in 2008.
  

• The Banda field, located 12 miles east of Nouakchott, may contain natural gas reserves of 3-5 trillion cubic feet (Tcf).
  

• UK-based Dana Petroleum is working with LNG operators to determine development options for the Pelican field. The Pelican natural gas field is estimated to hold 1 to 1.5 Tcf.
  

• With Mauritania's best offshore blocks under contract, other companies have lined up to explore onshore blocks, particularly in the Taoudeni Basin in the northeastern part of the Mauritanian desert. Spain's Repsol, China National Petroleum Co. and Woodside Petroleum are among the companies that have been awarded Taoudeni blocks.

• In January 2005, France's Total signed two production sharing contracts there, covering nearly 22,394 square miles.
  

• Tullow Oil holds interests in eight blocks offshore Mauritania, the majority of which were acquired as part of the Hardman Resources takeover. These blocks cover nearly 47,000 sq km, extend along 750 km of coastline and include most of the prospective offshore basin area. Since 2000, over 30 exploration, appraisal and development wells have been drilled. Of the exploration wells, Chinguetti, Tiof, Tevet and Banda all resulted in significant oil and gas discoveries, while the Pelican well discovered gas (with the possibility of a downdip oil leg). Exploration success to date is roughly 50% at the Miocene stratigraphic level and 25% at the Cretaceous.
  

Source: Tullow Oil

Oil and Natural Gas in Madagascar

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In April 2006, Madagascar opened up 96 new offshore oil and natural gas blocks for tender. The government accepted bids from interested parties until November 17, 2006. The licensing round is overseen by the Office des Mines Nationales et des Industries Strategiques (OMNIS) and TGS-Nopec, which completed seismic data on the blocks. International oil and natural gas companies active in Madagascar include ExxonMobil, Norsk Hydro (Norway), Vanco Energy (U.S.), Vuna Resources (China) and SUNPEC International Ltd (China). The government was in the process of negotiating concessions with several other oil giants, including Chevron, Texaco, Royal Dutch Shell, BP, Total, Norway's Statoil and China's National Petroleum Corporation.

• Oil production: 90.59 bbl/day (2004 est.)

• Madagascar Oil is the current license holder of the Tsimiroro and Bemolanga tar sand deposits in the onshore Morondava Basin of Madagascar discovered in the early 1900s. Tsimiroro is a large heavy oil field at 100-300m depth. The block, with an area of 6,670 km2, is located in NW Madagascar about 100km from the coast. Sixty-one wells have been drilled on Tsimiroro’s 70 km² core area to date. With the use of SAGD the expected recovery factor is estimated to be 55%. The Company is currently executing a pilot project on Tsimiroro. Tsimiroro is also prospective for conventional hydrocarbons. A Tsimiroro sample of 22º API oil was reported in 1988 from a test well in the south of the block.l
  Bemolanga is a bitumen field at 0-30m depth with a reserve of 16.6 billion barrels (9.8 billion recoverable). The Bemolanga block, with an area of 7,175 km2, is located in NW Madagascar about 120km from the coast. Thirteen wells and over 500 core-holes have been drilled from the 1950s to the early 1980s and the surface mining area is defined by less than 40 meters depth to top tarsand. The average overburden in the surface mining area is around 15m, considerably less than average overburden in Canada. Madagascar Oil also has a 100% interest in conventional oil and gas exploration onshore blocks 2103, 3105, 3106, 3107 and a 50% interest in block 3109, where Tullow Oil is the operator.
  
  

• In 2005, U.K.-based Sterling Energy sold 70 percent of offshore Ambilobe and Ampasindava licenses to ExxonMobil. ExxonMobil plans to finance exploration work on the licenses.

• In August, 2005, Aminex plc announced the award of onshore exploration acreage in Madagascar. Aminex, with partner Mocoh Resources Ltd.(“Mocoh”), has been awarded the rights to Block 3108, known as Manja, onshore the west coast of Madagascar and covering an area of 10,725 square kilometres, (approximately 2.6 million acres).
  The rights to this block are held through a Production Sharing Agreement (“PSA”) between OMNIS, the Madagascar state oil and mining organisation and Amicoh Resources Limited (“Amicoh”), a newly formed company, in which Aminex and Mocoh each holds an equal number of shares and through which the shareholders will fund exploration activity in equal proportions. Mocoh is an active downstream African petroleum group with existing assets and distribution operations in a number of countries including Madagascar.
  
  

• Tullow Oil plc signed its first licence in Madagascar in early December 2005. Onshore Block 3109 (Mandabe), situated in the Morandava Basin, covers 11,050 sq km in the southwest of the country. The work programme includes a 6,700 km reconnaissance aerogravity survey to aid the design of a seismic acquisition programme. Tullow signed the PSA for a second licence in Oct 2006. The onshore Block 3111 (Berenty) lies adjacent to, and south of, Block 3109 and covers 9,050 sq km. The agreed work programme for the initial 3-year exploration period includes the acquisition of 200km of 2D seismic and the drilling of a well. This licence requires a presidential decree before it becomes effective.

Source: Tullow Oil

Oil and Natural Gas in Cameroon

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Cameroon has experienced a fairly steady decline in its domestic oil production over the past 20 years. The country is still a net oil exporter, but if new fields do not come online in the near future, Cameroon could become a net oil importer. Currently, Cameroon does not produce any natural gas, but the country has plans to develop its natural gas reserves for generating electricity in the future. The majority of electricity generated in Cameroon comes from hydroelectric power stations, though droughts can often leave the country dealing with electricity shortages.
As of January 2006, Oil and Gas Journal estimated that Cameroon had proven oil reserves of 400 million barrels, with the majority of reserves located offshore in the Rio del Rey basin of the Niger Delta. Less significant reserve deposits are located in the Douala/Kribi-Camp basins off Cameroon’s western coast, and onshore in the northern Logone-Birni basin.
n 2006 Cameroon produced 90,000 bbl/d of oil in 2006. Oil exported from landlocked Chad is transported via the Chad-Cameroon pipeline, which ends at Cameroon’s Kribi terminal.
The Cameroonian government revised its petroleum laws to include financial incentives and tax breaks on exploration in both 1999 and 2002. Although the country has been well explored, Cameroon’s state oil company, the Societe Nationale des Hydrocarbures (SNH), believes that discovery and development of smaller fields is still possible. Renewed interest in oil investment has led to exploration in all three of Cameroon’s major petroleum basins -- Logone Birni, Douala and Rio del Rey. SNH, which Cameroon has committed to privatize, engages in exploration and production in conjunction with several foreign oil companies, the largest being Total.

• Oil production: 82,300 bbl/day (2005 est.)
• Oil proved reserves: 90 million bbl (2006 est.)

• Natural gas proved reserves: 110.4 billion cu m (1 January 2005 est.)

• Major companies active in Cameroon include ExxonMobil, Chevron, Petronas, Total, Shell and Perenco.

• In 2005, Total brought its Bakingili discovery online. In 2005, SNH awarded Total the first production sharing contract (PSC) in Cameroon’s history for the Dissoni permit in the Rio del Rey basin. In 2006, Total announced that it struck oil after drilling its first well on the block.

• Interoil Corporation also conducted exploratory drilling in three fields.
  
  
• In 2007, Cameroon had plans to open a licensing round which will offer six oil blocks for bid in the Rio del Rey region. The blocks will be awarded under PSCs. In the medium term, Cameroon is expected to open a licensing round for the Bakassi Peninsula, which Nigeria agreed to withdraw from in June 2006. Industry experts believe Bakassi acreage could contain significant amounts of oil reserves as it borders areas in the Gulf of Guinea that, in the past, have yielded numerous oil discoveries.
  
  
• Tullow Oil and partner Addax Petroleum signed an exploration licence with the Cameroon Government for the Ngosso Area in December 2002. Addax operates the licence with a 60% interest, while Tullow holds the remaining 40%. The Ngosso licence, which lies in shallow water, contains a number of existing small oil discoveries - Narendi, Odiong and Oongue - in addition to numerous exploration opportunities. One of the objectives of the initial work programme is to appraise these discoveries with a view to establishing their commerciality.

Source: Tullow Oil

Oil and Natural Gas in Eritrea

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• Hydrocarbon exploration, primarily offshore in the Red Sea, began in the 1960's when Eritrea was still federated with Ethiopia. In 1995, Eritrea signed a production sharing contract (PSC) with U.S.-based Anadarko Petroleum (Anadarko) for the offshore Zula Block. Anadarko signed a second PSC for the offshore Edd Block, located south of the Zula Block, in September 1997. Anadarko announced, in December 1997, that it had reached an agreement with ENI/Agip (Agip) to swap interests in exploration acreage. Anadarko received a 25 percent interest in a Tunisian block operated by Agip, and Agip received a 30 percent share in the 6.7-million acre Zula Block and 30 percent interest in the Edd Block. Burlington Resources, a U.S.-based independent who later merged with ConocoPhillips, later joined the consortium by acquiring a 20 percent interest in both acreages. Anadarko's first two exploration wells, both drilled on the Zula Block, were unsuccessful. In January 1999, a third dry well, Edd-1 on the Edd Block, was drilled. Citing the disappointing exploration results, Anadarko and its partners ceased exploration activities and relinquished their rights to the offshore blocks.

• Another attempt also did not meet with success. In May 2001, U.S.-firm CMS Energy signed an exploration agreement for a 14,000-square kilometer block in northeastern Eritrea, but the company did not find oil. CMS Energy sold its exploration interests to Perenco S.A. of France in late 2002.

Oil and Natural Gas in Benin

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• Oil proved reserves: 4.105 million bbl (1 January 2002)

• Natural gas proved reserves: 1.133 billion cu m (1 January 2005 est.)

• Kerr-McGee Corporation (acquired by Anadarko Petroleum Corporation in 2006) had exploration plans for Block 4, which include 3D seismic research and an anticipated drilling in late 2006. Kerr-McGee (operator) holds a 40 percent interest in the block and is joined with partners Kosmos Energy (40 percent) and Malaysia's Petronas (20 percent).

Oil and Natural Gas in Angola

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China reportedly accounts for 35% of oil exports from Angola.

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Click HERE for a Concession Map showing operators and production figures

"New rush for Angolan oil"

According to Oil and Gas Journal (OGJ), Angola had proven oil reserves of 8.0 billion barrels as of January 2007. The majority of the reserves are located in Angola’s offshore blocks. Blocks 15 and Zero have been the most prolific offshore blocks. Proven reserves are also located onshore near the city of Soyo.
Angola’s crude oil production has more than quadrupled over the past two decades. In 1986, crude oil production averaged 280,000 barrels per day (bbl/d), while production in 2006 averaged 1.4 million bbl/d. According to EIA estimates, Angolan oil production is set to reach two million bbl/d by 2008, when new deep-water production sites are expected to come online. Also consistent with EIA estimates, in December 2006, the World Bank announced that Angola will likely see peak oil production in 2011 at 2.6 million bbl/d followed by production declines if there are no new oil discoveries.
Angola exports crude oil primarily to China (477,000 bbl/d as of November 2006) and the United States. In 2005, the United States imported approximately 473,000 bbl/d of oil from Angola, which made Angola the eighth largest supplier of crude oil to the United States. As of October 2006, the United States had imported an average of 526,000 bbl/d of oil from Angola. Angola also exports crude oil to Europe and Latin America.
In 1976, the Angolan government created a national oil company called the Sociedade Nacional de Combustiveis de Angola (Sonangol). In 1978, Sonangol became the sole concessionaire for oil exploration and production in Angola. Sonangol works with foreign companies through joint ventures and production sharing agreements (PSAs), while funding its share of production through oil-backed borrowing. Major international oil companies operating in Angola include BP, Chevron, Devon Energy, ExxonMobil, Maersk, Occidental Petroleum Corporation , Roc Oil and Total.

• Oil production: 1.6 million bbl/day (2005 est.)
• Oil proved reserves: 25 billion bbl (2006 est.)

• Natural gas production: 750 million cu m (2004 est.)
• Natural gas proved reserves: 45.87 billion cu m (1 January 2005 est.)

• Cabinda Gulf Oil Company (CABGOC), a Chevron subsidiary and has been the operator of Block Zero since 1955. In May 2004, Sonangol and the Angolan government extended CABGOC’s contract, which was set to expire in 2010, to 2030. Other partners on Block Zero include Sonangol, Total and Eni. Block Zero is located offshore Cabinda province and accounts for approximately 370,000 bbl/d of Angola’s oil production, or almost one-third of Angola’s total crude oil production. In addition to Block Zero, CABGOC is the operator of deepwater Block 14. A total of nine discoveries have been made on the block with Kuito being the first in 1997. Two years later, Kuito became Angola’s first producing deepwater field. Chevron's combined average net production in Angola and Nigeria was 264,000 barrels of oil equivalent per day in 2005.

• ExxonMobil's Kizomba B project in deepwater offshore Angola Block 15 commenced production in July 2005. Block 15 has estimated recoverable hydrocarbon reserves of 4.5 billion barrels, and at peak production, Block 15 is expected to produce 750,000 bbl/d.
  The current production rate is more than 250 thousand barrels of oil per day. ExxonMobil said in January, 2008, it had started production at its Kizomba C development at a field off the Angolan coast that is expected to reach output of 100 000 barrels per day.
  Exxon Mobil's Esso Angola owns 40 percent of the development and is operator of the field.
  Kizomba C is part of the Mondo field, located in about 2 400 feet of water about 90 miles off the coast, and is part of the company's newest Angolan projects that also include the Saxi and Batuque fields.
  Production from those two fields is expected to begin in 2008. Total production from the three will reach a total of 200 000 bpd.
  Other participants in the offshore block include BP plc with a 26,7 percent stake, Eni with 20 percent, and StatoilHydro with 13,3 percent.
  The Kizomba C development includes two floating production, storage and offloading vessels and 36 subsea wells, making it the largest subsea development operated by Exxon Mobil subsidiaries.
  

• Total's Girassol field was discovered in April 1996 by Elf Exploration Angola. Just over 2 years later, on 8 July 1998, the company obtained the official go-ahead from Angola’s national oil company Sonangol and the Girassol partners to launch a development project. Girassol, which was the first field on Block 17 to go into production. It has the capacity to produce 200,000 barrels per day. Total operates Block 17 with a 40 percent share, while Sonangol is its franchise holder. Other shareholders include ExxonMobil, BP, Statoil, and Norsk Hydro. Total has six discoveries on Block 32, which is located in ultra-deep water, 40 miles from Block 17’s Girassol find. Currently, the discoveries are being analyzed for a potential joint venture project. Total, as operator of the block, is joined with partners Marathon Oil Company, Sonangol, ExxonMobil and Petrogal. Deep-offshore Block 17 is Total’s major asset in Angola. It is composed of four major zones: Girassol and Dalia, both in production; Pazflor, which has been launched; and CLOV, a fourth major production area based on the Cravo, Lirio, Orquidea and Violeta discoveries, whose development is currently being studied. Future production from Pazflor and CLOV will come in addition to the more than 500,000 barrels of oil per day that are currently pumped from Girassol and Dalia structures on the Block 17. Rosa which came on stream in June 2007 with the connection to the Girassol FPSO will extend the production plateau of this FPSO until the next decade.
  

• Petrobras began operating in the country almost thirty years ago, in 1979, and has exploration and production agreements via participation in six offshore Blocks, one in production (Block 2) while the other 5 being explored.

• In September 2002, Canadian Natural Resources Ltd (CNR) signed a four-year PSA with Sonangol to explore for oil in the deep waters of Block 16, 72 miles off the Angolan coast.

• In February 2003, Devon Energy Corporation acquired a 25 percent stake in Block 24 from ExxonMobil. This acquisition increased Devon Energy’s total share of the block to 40 percent, making the company the operator of the block. ExxonMobil retains a 20 percent share. Sonangol and Petronas are also partners on the block. Devon Energy Corporation owns interests in three Angolan offshore exploratory blocks (blocks 10, 16 and 24) and one onshore block.

• In February 2004, Sonangol approved BP’s plans to develop the Greater Plutonio project in Block 18. Six fields (Colbalto, Cromio, Galio, Paladio, Platina, and Plutonio) will be developed using a single FPSO. Scheduled to come online in mid-2007, the Greater Plutonio project is expected to produce 240,000 bbl/d. BP maintains a 50 percent interest as the operator of Block 18 and Sinopec owns the other 50 percent share. In October 2006, BP announced its 11th discovery on Block 31. Industry experts believe Block 31 to contain 500 million barrels of commercial reserves. The block is located 118 miles offshore. BP is operator with 26.67 percent interest and is joined with partners ExxonMobil, Sonangol, Statoil, Marathon, and Total.

• In December 2006, Sonangol awarded French-based Technip a $70 million contract to develop the Gimboa field in Block 4.

• Tullow Oil plc concluded a farm-in agreement with Sonangol P&P in November, 2005, acquiring a 15% interest in Block 10/05 offshore Angola. Block 10/05, located in the Southern Kwanza Basin, is operated by Devon Energy. In early January 2006 Tullow completed a further farm-in agreement with Ocean Angola Corporation, a subsidiary of Devon Energy, acquiring a 15% interest in Block 24/99. In late July 2006 Tullow was formally advised that it had been awarded a 50% operating interest in Block 1/06, a 3,839 sq km oil exploration concession in the Lower Congo Basin, offshore Angola. The Production Sharing Contract came into force in December 2006. Block 1/06, which extends from a water depth of 40m to approximately 300m, contains three undeveloped oil fields, Pitangueira, Bananeira and Sapesapeiro.

Source: Tullow Oil

• On November 2, 2006, VAALCO Energy, Inc officially signed a Production Sharing Agreement (PSA) for Block 5 offshore Angola.
  VAALCO has a 40% interest in the block, and is the operator of the concession for its partners Interoil Exploration & Production ASA (40%) and Sonangol (20%). Block 5 covers an offshore area of approximately 1.4 million acres.

• Russia’s diamond-mining company ALROSA in a consortium with Angola’s Dark Oil obtained an oil and natural gas prospecting license, the company announced in December, 2007. The license is for blocks in the Lower Congo and Upper Kwanza districts, between the Etosha, Okavango and Kassanje basins, as well as on the country’s shelf, ALROSA said in a press release. Thus ALROSA has become the first Russian company to receive a license to conduct a large-scale exploration work to search for oil and gas deposits in Angola, the company said.
  

• In addition to licensing rounds, Angola signed various bilateral oil agreements in 2006 with Russia, Sao Tome and Principe, South Korea and Venezuela. The agreements promote increased collaboration on future oil exploration activities in Angola.

Oil and Natural Gas in Algeria

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According to Oil and Gas Journal (OGJ), Algeria contained an estimated 12.3 billion barrels of proven oil reserves as of January 2007, the third largest in Africa (behind Libya and Nigeria). Algeria’s proven reserves are primarily located in the eastern half of the country. The Hassi Messaoud basin contains 70 percent of the country’s total proven reserves, while additional reserves are located in Berkine basin. Although Algeria has produced oil since 1956, industry analysts consider the country under explored, with potential for future hydrocarbon discoveries.
Algeria produced an average of 1.37 million barrels per day (bbl/d) of crude oil in 2006. Together with 445,000 bbl/d of lease condensate and 310,000 bbl/d of natural gas liquids, Algeria averaged 2.13 million bbl/d of total oil production during 2006, up slightly from 2.09 million bbl/d in 2005 and 1.93 million bbl/d in 2004.
n March 2005, the Algerian parliament adopted the hydrocarbon reform bill. The bill encouraged international oil company (IOC) investment throughout the hydrocarbon industry, which state-owned Sonatrach previously dominated. However, 2006 amendments to the hydrocarbon bill created a windfall tax on IOC profits when oil prices top $30 per barrel. This tax reached up to 50 percent on some contracts, deflating some of the IOCs investment enthusiasm. In addition, the amendments gave Sonatrach the right to have a 51 percent or higher participation option on each newly discovered project. Aside from Sonatrach, the state regulatory agency, Alnaft, promotes oil exploration, signs upstream contracts, approves development plans, and collects royalties and taxes.

• Oil production: 1.373 million bbl/day (2005 est.)
• Oil exports: 1.127 million bbl/day (2004 est.)
• Oil proved reserves: 11 billion bbl (2006 est.)

• Natural gas production: 80.15 billion cu m (2004 est.)
• Natural gas exports: 60.87 billion cu m (2004 est.)
• Natural gas proved reserves: 4.545 trillion cu m (1 January 2005 est.)

• Sonatrach operates the largest oil field in Algeria, Hassi Messaoud. Located in the center of the country, Hassi Messaoud produced around 440,000 bbl/d of crude in 2006, and Sonatrach hopes to increase production at the field to 600,000 bbl/d over the next few years. Sonatrach also operates the Hassi R'Mel field (north of Hassi Messaoud, south of Algiers), which produces around 180,000 bbl/d of crude. Other major fields operated by Sonatrach include Tin Fouye Tabankort Ordo, Zarzaitine, Haoud Berkaoui/Ben Kahla, and Ait Kheir. Sonatrach announced on 31 December, 2007, that it had made new oil and gas finds, and that was the 20th hydrocarbon discovery in 2007 in Algeria. One of the new discoveries was made in association with a consortium of Thailand's PTT Exploration and Production PCL (PTTEP) and Vietnam's Petrovietnam at blocks 433a-416b in Amguid Messaoud basin. The second find was made by Sonatrach alone at block 438c in Oued Mya basin.
  

• Foreign oil operators have steadily increased their share of Algeria's oil production. The largest foreign oil producer is Anadarko Petroleum Corporation, with total production capacity of 500,000 bbl/d. The company operates the Hassi Berkine South and Ourhound fields in eastern Algeria, with combined output of around 450,000 bbl/d. As of the fourth quarter 2006, Anadarko netted 62,000 bbl/d of oil from the fields based on its ownership percentage in the project. Anadarko is developing seven new oil and natural gas fields in Block 208 of the Berkine Basin; first production from the fields (EKT, El Merk, El Merk N, El Merk E, El Merk C, El Kheit, and El Tessekha) is possible by 2008, with output eventually reaching 150,000-200,000 bbl/d of crude oil and condensate.
  

• Eni operates (among others) the Rhourde Oulad Djemma (ROD) project in south eastern Algeria, a series of six satellite fields that have production capacity of 80,000 bbl/d.
  

• Additional foreign investors include Amerada Hess, BHP-Billiton, BP, Repsol, Shell, Statoil and Total.

• In 2005, Algeria held its sixth licensing round for foreign development of oil and natural gas reserves. A total of 54 companies showed interest in the ten blocks being offered. Companies that won exploration rights included BP (winning three concessions), BHP-Billiton (winning two concessions), Shell (winning two concessions), and the UAE-US joint venture Gulf Keystone Petroleum Ltd (winning two concessions). In mid-2007, the Algerian government wass expected to begin the country’s seventh licensing round.