Competing for foreign investment – Petroleum prices Venesuala – Brief Article

Stuart Wilkinson

Good discoveries and huge gas development plans require ample investment. Nearly every country is making contract terms a little sweeter


Since taking office, President Chavez has reversed the OPEC quota-busting policy to raise prices. So far, the policy change has been successful, with the country’s basket of petroleum prices pushing up to $30/bbl. However, these cuts contributed to a heavy economic recession and, even now, the economy has not responded to what would previously have been an oil boom for the country.

The “Mega-Elections”–which were to be held on May 28th–did not happen as a result of technical problems. They were postponed and split into two parts; the main one included the presidential election at the end of July.

The primary contender for president is Francisco Arias Cardenas. He participated with Chavez in the 1992 failed coup against then-president Carlos Andres Perez. An opinion poll published on July 4th indicated that Chavez and Arias were more or less level, with Chavez leading by four points. However, Chavez on July 30 easily won re-election, posting a 21-percentage point margin over the nearest challenger, Arias. His coalition also won about 60% of the new 165-member legislature, sparking violent protests by opposition supporters. Arias had stated that the oil policy pursued by the present government has not been beneficial to the country.

Exploration. Later this year, 11 areas will be put up for bids for exploration and development of non-associated gas reserves: North Ambrosio, Zulia state, with reserves estimated at 2 to 6 Bcf; Yucal Placer, Guarico state, two areas with proven reserves of 2 Bcf; seven areas in Guarico, Aragua and Cojedes states, with possible reserves of 2 to 8 Bcf; and Barrancas in Barinas, Portugesa and Trujillo states, with probable reserves of 2 to 6 Bcf. It is planned to grant licenses in mid-December this year.

Seismic work last year totaled 899 mi of 2-D and 1,265 sq mi of 3-D surveys, up 33% and down 36%, respectively. This year, the forecast is for 1,411 ml of 2-D and 983 sq mi of 3-D seismic surveys. There were only 28 wildcats and appraisals drilled, equal to about 3.5% of all of 1999’s drilling. Exploration drilling should remain at that percentage this year.

Development/drilling. Wells drilled were down 23% last year, and footage declined 18%. State firm PDVSA this year forecast a 54% rebound in wells. Late last year, Benton Oil and Gas entered into a letter of intent with Schlumberger to form an alliance to further develop the South Monagas Unit, which is the company’s main oil-producing asset. The partners would begin infill drilling and optimizing operations with the aim of achieving increasing production rates over the next two to three years. Helmerich & Payne won the drilling contract, and production has stabilized at the unit near 25,000 bopd.

TotalFinaElf started to negotiate its withdrawal from Punta Pescador– there were not many possibilities for success there. PDVSA Gas, Shell, Esso and Mitsubishi signed a preliminary agreement for development of Venezuela’s GNL Project, which encompasses exploitation and export of free gas from the Norte de Paria fields. Initial production is planned for 2005.

Orinoco heavy crude. By late 1999, the Petrozuata heavy oil project was about 80% complete–it comes into operation later this year. More than 60% of the $550-million cost overruns were related to an overvalued Bolivar–past overruns of $250 million and estimated future overruns of $100 million. Another $110 million in overruns arose from labor costs doubling in response to a new, PDVSA employee contract. Once fully operational, Petrozuata will produce 120,000 bpd of heavy crude and 103,000 bpd of syncrude.

Production from Cerro Negro field in the Orinoco Belt began at the rate of 60,000 bpd of diluted, extra-heavy crude–the oil is blended with condensate to allow it to flow to storage and loading facilities at Jose Industrial Complex. Production is expected to double to 120,000 bopd in 2001, when a new coker unit is completed at Jose.

The strategic associations–Sincor, Hamaca, Petrozuata and Cerro Negro–will produce 16[degrees]-to 32[degrees] API-gravity synthetic crudes. Estimated production is 557,000 bpd for 2004 and 622,000 bpd for 2009.

Chavez’s Asian tour resulted in a memorandum of understanding between the China National Petroleum Co. and PDVSA, whereby China will buy 2 million t/yr of Orimulsion after 2002. PDVSA thus has a chance to build a new 5 million t/yr drilling and conversion unit, doubling current capacity, and China will be able to convert its power plants to the fuel.

Another part of the deal called for potential expansion of the supply agreement, to an additional 5 million t/yr, with China being involved in construction of a plant in Venezuela. Orimulsion exports rose 39% in 1999. Plans are to produce 13 million t in 2003 and 20 million t in 2006.

Production. Combined output of crude and condensate was down 6%; most of that due to lower production rates after OPEC’s quota reductions took effect in April 1999. Condensate accounted for 2% of the total. Natural gas production was about 3% lower at 5.7 Bcfd.

Venezuela plans to increase oil production capacity to 5.8 million bpod in 2009. E&P spending will amount to $38 billion out of $50 to $55 billion total investment in the petroleum sector. Emphasis will be placed on increasing reserves of lighter crude.


Early this year, President Cardoso’s economic reforms started to positively affect the country’s exports. They were strengthened by congressional approval of fiscal reforms needed to maintain IMF funding and the currency devaluation of a year earlier. The government projects 3.8% growth in the 2002-2004 period.

Last year, Petrobra’s announced plans to invest $32.9 billion over the 2000-2005 period. The company’s own cash flow and conventional financing will provide 70% of the sum; 20% is from project financing, and the rest will come from other to-be-decided sources. On the spending side, 68% will go to E&P.

In May 2000, the State Economic Affairs Commission voted down a law that would prohibit the sale of shares in Petrobra’s. The government owns 82% of the shares, and the sell-off, planned for July, will still leave the government as majority shareholder.

Exploration. As part of the plan for Brazil to be self-sufficient by 2005, 23 blocks were offered in the second exploration licensing round in June of this year. Of these, 13 were offshore (7 in deep water) and 10 onshore. Only two areas were not sold. Companies paid $259 million for the concessions. These contracts are expected to generate investments of $1 billion in exploration and $10 billion in the production stage.

In the round, Petrobra’s and Brazilian Rainier performed strongly. Petrobras secured eight of the 10 areas for which it bid, and the company and its associated groups accounted for nearly three-quarters of the money raised from the sale. Rainier also did well, bidding alone for four onshore oil fields. Due to the sale’s success, the National Petroleum Agency announced plans to hold a third bidding round.

In mid-1999, Exxon acquired offshore exploration Blocks BFZ-1 and BP-1. The million-acre BFZ-1 Block is located in the Amazon mouth, Amapa state, 200 mi offshore in 300 to 7,500-ft waters. Ten-million-acre BP-l is in the Pelotas basin 150 mi offshore, Rio Grande du Sul state, in 650 to 9,800-ft water depths. Esso will operate both blocks and have a 60% interest in BFZ-1, plus 50% in BP- 1. Petrobras holds the remaining interests. Exxon (15%) signed a JV agreement with Petrobras for deepwater exploration Block BC-10 in the Campos basin. Other contracts during the year added to Exxon’s deepwater portfolio.

The Unocal, Petroleo Brasileiro, Japex and Marubini consortium signed a participation agreement for 346,000-acre BC-1009 Block in the Campos basin. The consortium could spend $30 million to $40 million over the next five years for seismic and exploratory drilling. Also in Campos basin, Petrobras signed a JV contract with Royal Dutch/Shell, TotalFinaElf and Enterprise Oil to explore the deepwater BC-2 Block. A major light-oil discovery was made in the northeast part of the Santos basin at a subsea depth of more than 12,000 ft.

Development/drilling. Like many of its neighbors, Brazil’s wells drilled slumped 25%, and footage drilled declined 16%. ANP, Brazil’s national petroleum agency, predicts that drilling will jump 71% higher this year.

Petroleo Brasileiro SA and Halliburton have agreed to cooperate on three oil and gas projects in Cuenca del Campos for a total investment of $4.45 billion. The aim is to boost area production to more than 250,000 bopd.

Production. Plans call for domestic oil production to increase to 1.85 million bpd by 2005 from the current 1.3 million bpd. Oil from international subsidiary Braspetro is planned to triple to 170,000 bpd. Petrobras’ partners will provide around 135,000 bopd. Brazil will be self-sufficient by 2005. Another aim is to increase proven reserves to 13 billion boe from the present 8 billion boe.


New President Fernando De la Rua has tried to move rapidly to revive the country’s economy, which suffered a year-long recession and 14% unemployment. He succeeded in reforming the labor laws so that companies could determine their pay scales, thereby aiding the climate for foreign investors. The IMF recently approved an important $7.4-billion standby loan.

Exploration. In late 1999, Repsol-YPF (50%) and operator Sipetrol Argentina (50%) discovered a field on offshore Block CAM-2/A South near the Magellan Strait. Well CAM XE1 reached a 5,660-ft TD, and tested 15 MMcfgd and 151 bcpd from the Springhill formation. A second well, CAM XE1A, tested 2,000 bopd and 620 Mcfgd. Apco Argentina put well Borde Mocho 2 into production, close to the 1996 BM 1 oil discovery.

British Gas, which has 100% interests in the Los Tordillos Oeste exploration block in the Cuyo basin and the Barranca Yankowsky Block, plans two wells for 2001. Early this year, Chevron discovered a new oil field in the RIo Negro North Block: The El Solitario Sur X1 tested 220 bpd of 18[degrees]API crude from 8,638 to 8,695 ft. Chevron produces 78,000 bopd in Argentina, 9.75% of the country’s total oil output. Chevron’s Petrolera Argentina San Jorge subsidiary made an oil find with its El India Oeste well in May Aike Block, Santa Cruz province, and with the El Latigo Este well in Rio Negro Norte Block, Rio Negro province. Chevron bought San Jorge in September.


BP Amoco’s Pan American Energy said, this summer, that the firm will spend almost $500 million on Argentine projects in 2000 ($225 million) and 2001 ($265 million). About $180 million will go toward drilling 200 exploration and development wells in the Cerro Dragon concession of southern Argentina. San Jorge, operator, and partner Fletcher Challenge Energy continued testing three fields drilled in Block CNQ-16/A in the Neuquen basin: Estancia El Colorado Xl, El Aguara Xl and Bases Xl. A total of 443 oil wells were drilled in 1999 compared to 776 in 1998. Seventy-one natural gas wells were drilled in 1999, versus 53 in the previous year.

Production. Gas companies looked for federal support in a Supreme Court case. They sought relief from provincial government claims to a sales tax–roughly 1% on all distribution contracts. Rio Negro, Neuquen and other gas-producing provinces levied the tax on gas companies formed after the 1992 privatization of Gas del Estado. The country’s crude production averaged 801,376 bapd in 1999, down 5.4% from 1998’s level. Condensate output rose 9.7% to 64,654 bpd. Gas production improved 9.6% to 4.1 Bcfd.


The country is developing a moreattractive environment for foreign investment–especially in the oil industry, which accounts for about 4.5% of GDP and more than 20% of exports. GDP dropped 3% in 1999 in contrast to the preceding seven years, when GDP grew an average 3.8% per year. Early this year, President Andres Pastrana announced the Colombia Plan, now accepted, where the U.S. will help to resolve insurgency and drug trafficking, as well as modernize legal and military institutions and strengthen the economy.

Exploration. Late last year, Ecopetrol signed a new exploration contract with partners Baker Hughes (70%) and Tecnopetrol (30%). The companies will spend $5 to $8 million on a black in Cesar province. This contract is under a new sliding scale of royalty payments, approved mid-year, that allows private partners to receive a quicker return on investment.

Ecopetrol signed eight new E&P deals in January. Much of the acreage is located in the Middle and Upper Magdalena Valley and its Putumayo basin. Alberta Energy’s AEC Colombia won two Putumayo basin properties–the Rio Juanambu and Pacayaco contracts. Braspetro grabbed the Bicudo contract in Casanare province. CanWest was awarded the Colon contract in Tolima province. La Luna Oil got the Guayacanes contract in the Middle Magdalena Valley.

Four more areas in the Upper Magdalena Valley were awarded to: IPC of Colombia far the Pijao area; CMS Oil and Gas for the Torbellino contract; CanWest, Petrocol and Petroleos Colombianos for the El Golfo contract; and Chilean Sipetrol (the international arm of state oil company Enap) with Clapsa (an affiliate of the Petroleum Company of Chile), for the Altamizal exploration contract with Ecopetrol. Oxy is expected to begin drilling the Gibraltar 1 exploration well in the Samore Block in October.

Development/drilling. Petrobras Colombia Ltd. (operator) and partners CMS and Ecapetrol completed well Venganza 4H (horizontal), drilled in Matachin field, Espinal Block, Magdalena Valley basin. The well tested 7,000 bpd of 28[degrees]API oil. Three more horizontal wells are to be drilled in the Espinal Block during 2000.

Vanguard Oil recovered 18[degrees]API oil from the Mugrosa formation during a cased-hole drillstem test in Bukhara 1, Las Quinchas Block. Overall, Colombian drilling declined 23%. A 17% recovery is expected this year.

Production. Much-higher oil prices allowed the country to double its oil-export income in January despite a drop in export volume. Production during that month was about 750,000 bopd. Crude output for 1999, overall, was up 8.1% at 826,000 bpd. Gas production reached 503 MMcfgd, down 18% from 1999. Association contracts accounted for 96% of gas production.

The Emerald Energy PLC Gigante 1 well will be back in full production in September after a recent fire. Negotiations are underway for a rig to drill the first well, Guarataro 1, in the company’s 100%-owned Vuelta Larga Block in the Llanos basin.

A serious problem for state-owned Ecopetrol is the threat of having to begin oil imports as early as 2005. Short-term projects include incremental-production fields up for bid. Medium-term hopes rest with exploration areas up for bid, as well as with two, large-scale projects: BP Amoco’s Niscota project, which has potential oil reserves of 900 million bbl; and Occidental’s Samore Block.

Ecopetrol finalized a swap, whereby Oxy returned a portion of the Samore Block to settle a dispute with the U’wa Indians. In return, it received more-favorable contract conditions to explore on Gibraltar Block, which may harbor 1.4 billion bbl of oil.


Conversion to a dollar-based monetary system and general economic recovery are going better than expected. Economic growth could be restored this year, and privatization programs could be launched that would increase growth in 2001. The IMF and World Bank have approved loans to help the country’s economic difficulties.

Exploration. In May this year, Perez Companc announced discovery of more than 500 million bbl of probable oil reserves at Block 31 in Orellana province. The find was made at 6,100 to 7,000-ft depths, and production potential is estimated at more than 5,000 bopd. The company plans to drill two more wells in the block. This is a sensitive area, however, being located within a national park. Accordingly, environmental issues and the concerns of local Indian tribes are important considerations.

Development/drilling. Wells drilled are estimated to have declined 43% last year. A 31% increase is projected for 2000. CMS Oil and Gas tested its Ginta-B H well on Block 16 at flowrates up to 17,750 bopd and 550 bwpd. Also in Block 16, Tivacuno, Bogi and Capiron fields are being developed in a JV comprising YPF (operator, 35%), Taiwan’s Overseas Petroleum and Investment (31%), CMS (14%) and two Murphy Oil subsidiaries (10% each). These fields are capable of producing 70,000 bopd, but constraints on the trans-Ecuador pipeline system allow only 45,000 bopd. Completion of an expansion line, due in 2001, will boost production significantly.

Bellwether Exploration signed a production sharing agreement with Petroecuador for E&P operations in the 63,000-acre Charapa field, Oriente basin, northern Ecuador. Three or four horizontal wells were to be spudded this year. Bellwether is to invest $11.7 million over the next three years in a minimum work program. Current oil production is 214 bpd of high-gravity oil, tied to an existing pipeline. To date, the field has produced 1.5 million boe.

Production. Crude output declined about 8% last year. The country’s new President, Gustavo Noboa, presented a bill regarding hydrocarbons to Congress for funding of the second 250,000-bopd export pipeline. This would bring in additional, direct foreign investment of $500 million and raise national production by 11% annually through 2005. The bill also would allow Petroecuador and private operators to reactivate field exploration and development in Ishpingo, Tambococha and Tiputini.

Former president Jamil Mahuad had planned to introduce the bill, but a coup overthrew him in January. Petroecuador plans to attract foreign investment with a tender, to be held later this year, for the country’s main oil fields (Shushufindi, Sacha, Libertador, Cononaco and Auca). Petroecuador also plans to boost production by 60,000 to 100,000 bpd and encourage foreign capital for refinery upgrades at Esmeraldas, La Libertad and Shushufindi.

The new legislation would also allow private companies to own and operate pipelines with no maximum, set period. With these developments, the country’s productive capacity could increase to 700,000 to 800,000 bopd from last year’s 373,000 bopd.


In the first nine months of last year, the economy expanded by 5.7%, while inflation fell to 3.4%, down from 5.6% in the previous year. The energy sector represents about one-fourth of the country’s GDP. The country is the Caribbean’s largest oil and gas producer.

Exploration. Late last year, Shell, operator of Block 25a for partner Agip, spudded the first exploration well in its deepwater offshore licenses. The well, drilled in 3,531-ft waters, had a target TD of more than 9,900 ft, setting a water-depth record in the area and starting a frontier exploration phase in the country’s deep waters.

Calgary, a subsidiary of Trans-Dominion Energy Corporation (72.5% stake), was issued a joint license with Petrotrin (27.5%) for an extensive exploration project covering the South West Peninsula. The exploration program will include 3-D seismic and a minimum of two exploration wells. Further wells are to be drilled to develop an oil-bearing sand identified earlier in well Bonasse 2. The JV is unique in that it encompasses both onshore and offshore acreage.

BHP and partners, Elf and Talisman, made another gas discovery with their second exploration well, Aripo 1, in the Block-2C production sharing contract area.

Development. Compared to most of Latin America, Trinidad’s drilling was remarkably stable. This year, as a testimonial to the country’s very active E&P sector, drilling is set to rise 48%.

Early this year, the government gave the green light for two gas-liquefaction trains, each with a capacity of 3 million t/yr. Added to the Atlantic LNG unit at Port Fortin, the country’s total productive capacity would rise to more than 9 million t/yr by 2003. The cost of the two trains, $1.12 billion, will be funded by BP Amoco, Repsol-YPF and British Gas (BO). When operational by third-quarter 2002, BG will be able to supply half of one train’s feedstock from its North Coast Marine Area fields.

Gas for train 3 and the rest of train 2 will come from BP Amoco’s East Coast fields. The two new trains are to be built at the existing site at Port Fortin. BP and Repsol are cooperating in an LNG-import terminal and associated power venture at Bilbao, Spain. Repsol will import all the output from train 3 and half the output from train 2. BP Amoco has been licensed to distribute gas within Spain.

Production. Crude reserves, estimated at 686 million bbl, are expected to last only a decade, but hopes are to raise oil production to 200,000 bpd between 2005 and 2010.


In 1999, the country moved to austere economic policies that have controlled the fiscal deficit and set the stage for improved economic growth this year. However, social unrest has erupted. Spending cuts will continue throughout this year and 2001. Growth for 2000 is estimated at between 4% and 5%.

Exploration. TotalFinaElf (operator, 41%), Mobil (34%) and TESORO Bolivia (25%) confirmed a significant gas discovery with their Itau X1A well, located in Block XX West near the Argentine border and close to the Bolivia-Brazil gas pipeline. Plans are to ship the gas mainly to Brazil, but also to the Southern Cone.

In the August 1999, annual exploration round, Argentina’s Pluspetrol was the only participant. The company made a $3.6-million bid for the Candua Block in the southern Chuqusaca region. The fourth exploration tender should be held by August 2000.

Repsol-YPF announced that the company and partners, British Gas and ARCO, made an oil and gas discovery in the Caipipendi Block in southern Bolivia. Located near the Bolivia-Brazil gas pipeline, the well flowed nearly 71 MMcfgd and 2,300 bopd. Estimated reserves are more than 300 million boe.

Gas development. Bolivia is moving toward being the gas hub for the Southern Cone. The country should have little trouble increasing its gas sales to Brazil, filling the Bolivia-Brazil gas pipeline to its 1.06-Bcfd capacity by 2004. Petrobras has exercised its option as a preferred customer–against third parties–to supply additional gas coming from new Bolivian discoveries.

Production. In 1999, direct foreign investment in the country’s hydrocarbon sector rose 20.9%, to $629.8 million, from the previous year. This sector captured over two-thirds of direct foreign investment in the country. Recent discoveries of gas deposits in Tarija, near the Argentine border, prompted this increase.


President Alberto Fujimori decided against selling state-owned refineries and other assets prior to the presidential election that he later won. Privatization in 1999 gave the government $350 million–compared to the $800 million that had been planned. GDP growth is expected to reach 6.5% this year.

Exploration. Oil companies cut spending on E&P by $160 million in 1999, a drop of 10% from 1998. Plus-petrol approved a $30-million investment in its 8/8X fields in the Maranon basin. Occidental, however, cut its exploration budget to $4 million in the same basin. Chevron pulled out of Block 52 in the Ucayali basin, Repsal cancelled negotiations for offshore Block Z-4 and Phillips P&A’d an exploratory well in Block 82.

The government failed to get E&P contracts signed this year after canceling a planned 15-block, offshore bidding round. Denver-based Barrett Resources was the only company to make a significant find in recent years. It signed an exploration contract with Petroperu in September to explore Block 39 in the Maranon basin.

Drilling/development. Wells drilled plummeted 65% last year, although offshore wells remained steady at five. This year, 35 onshore and 10 offshore wells are planned,

In February, Hunt Oil and partners, Pluspetrol (40%) and SK Corp. of South Korea (20%), won the Camisea project tender, pledging royalties of 37.2% on liquids and gas during the 40-year concession. The consortium planned to invest $400 million and drill four wells in the Ucayali basin gas fields by 2003. The Camisea project aims to invest $1.6 billion and drill 25 wells.

Production. In 1999, crude and condensate production stood at 105,927 bpd, down 8.4% from the previous year’s 115,593 bpd. In December, average output was 100,038 bopd, down 11.3% from the same period in 1998. By January 2000, production was 98,845 bopd, a fall of 10.9% compared to the same month in 1999. New finds have failed to compensate for lower production in aging fields.


The economy was flat in 1999–the worst performance for over a decade. The country suffered a severe shock to its trade, owing to a collapse in the price of copper.

Last year, state oil company ENAP opened opportunities for joint ventures in all of its best oil and gas fields–four on the country’s mainland, eight offshore and nine on Tierra del Fuego. Some of the fields are inactive, but others have been producing for 30 years. ENAP was looking for companies skilled in 3-D seismic acquisition, enhanced recovery, and horizontal and infill drilling.

At the beginning of this year, Mining Minister Sergio Jimenez said that the government would sell a 20% to 30% share in ENAP’s overseas exploration unit, Sipetrol. A private partner would help the government finance Sipetrol’s $100-million investment plan for 2000. ENAP general manager Alvaro Garcia commented that the company could float a minority stake in Sipetrol. This idea was one of several possibilities for injecting private capital into the company.


No wells were drilled last year in the Falkland Islands, and there was no production or proven reserves. No wells are forecast for 2000. Consortia retaining licenses in the region, such as Desire and Argos Evergreen, are seeking farm-in partners for future drilling and perhaps additional seismic-survey data. The government plans to offer licenses for other areas under out-of-round licensing rules. It is hoped that, by offering companies exclusivity over areas adjacent to and outside of North Falkland basin, additional data will be acquired that will lead to a fuller understanding of the of the area’s geology.

In addition to exploration within the Falkland zone, an area has been set aside southwest of the islands–known as the Special Cooperation Area–to be jointly licensed with the Argentine government. Progress continues in formulating a licensing regime for the area.

In late August 1999, Burlington Resources entered into an agreement with the state oil company Staatsolie to explore in deepwater areas off Suriname. Burlington (35%) was to operate the 18,500-sq-mi block with partners Shell (35%), TotalFina (15%) and Korea National Oil Corp. (15%).

In March of this year, Koch Petroleum Canada signed a production-sharing contract with Staatsolie. The 20-year contract encompasses 140,000 acres in the Wayombo area and will focus on heavy oil. An affiliate of Koch intends to acquire seismic, starting in the third quarter of this year. It is anticipated that 15 to 20 test wells will be drilled during the first year.

In June 2000, CGX Energy drilled a dry hole on its Horseshoe prospect, offshore Guyana. On June 3, 2000, the drilling rig was forced off the company’s Eagle prospect by two Suriname gunboats. A maritime border dispute between Suriname and Guyana has existed since the eighteenth century and was the primary subject during a summit meeting this summer. Resolution of the dispute does not appear imminent.

Last September, Agip Guyana BV signed an agreement with Maxus Guyana Ltd. to acquire a 25% stake for exploration in the Georgetown Block. The block is about 50 mi offshore Guyana. It lies in water depths from 100 to 650 ft. About 2,200 mi of 2-D seismic were acquired during 1999, and another 625 mi are to be surveyed in 2000. Two offshore wells are to be drilled this year.

The Woodbourne lease area, offshore Barbados, is being exploited by Conoco and the Barbados government. However, the government would welcome any additional investment for onshore exploration outside the Woodbourne area. Oil output averaged 1,986 bpd last year. About 4,971 mi of 2-D seismic offshore are slated for 2000, plus eight onshore wells.

COPYRIGHT 2000 Gulf Publishing Co.

COPYRIGHT 2000 Gale Group

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