VENEZUELA - The E&P Risk/Profit Sharing Contracts.

In late July 1995 PDVSA offered ten E&P areas on profit sharing basis, with each divided into 16 blocks comprising about 126.5 sq km. Eventually 75 companies pre-qualified to bid. But that came after more than a year of congressional debates over a "model contract", which PDVSA had drafted to attract foreign companies, with deputies having lobbied strongly for control over new JV by PDVSA.

PDVSA earlier made available a study on the country's geology at $125,000 a copy. Prepared jointly by PDVSA and BP, the report consisted of about 150 pages of text, colour illustrations, 60 maps and 15 interpreted regional seismic sections. The report was available on diskettes and compact discs, which allowed the reprinting of the maps on any scale. This established a tectono-stratigraphic framework which delineated fairways throughout Venezuela and defined a number of exploration areas outside the traditional producing regions. In total, 27 play fairways were identified with emphasis on medium to light oils.

The terms for the ten areas specified an initial exploration period of three to five years (phase I) which may run to an extension of a further three to four years (phase II). On approval of a commercial discovery, the development and production period was for 20 years, extendable for a further 10 years. PDVSA had the right to join in any of the development areas for an interest of 1 to 35% and was to pay for exploration back costs in proportion to its share. But repayment was to be only for drilling which conducted in a discovery area under development, and not in an original exploration area. The original private investors in any area was to finance PDVSA's back-in by lending the funds to it at a rate of six-month LIBOR plus 1% per annum, payable from the state company's post-tax cash flow.

The regime stipulated a state take of 71-88%, a royalty of 16 2/3% subject to reduction in the case of fields whose rate of return was less than 20%, and supervision by PDVSA's unit Corporacion Venezolana de Petroleo (CVP) which was to co-ordinate their activities. The royalty was to fall to 1% at a rate of return of 12%, though the sliding-scale in between was not defined precisely. The royalty was payable in Venezuelan currency (bolivars) and was based on a well-head price calculated with reference to export prices for a basket of Venezuelan crudes and formula-based transportation costs. The income tax for oil companies was 67.7%.

There was an additional profits tax called participacion del estado en las ganacias (PEG), a "super-royalty" and the only variable. The PEG was to be fixed, at a percentage specified by the investors in the winning bid, for the first $1 bn of production from a given area; it was to be calculated and paid in bolivars unless Congress approved the use of US dollar accounting for tax purposes. The PEG was deductible for tax purposes.

The winning bidders were to sign an association agreement with CVP. Management and supervision of the operations were to be done in a two-tier system: the control committee was to be composed of an equal number of members chosen by the investors and CVP. It was to be presided by members selected from CVP, whose presence and consent were required for all decisions. Decisions were to include approval and amendments to a minimum work programme, extension of exploration periods, evaluation of exploration and development plans, and adoption of any production cuts required. The committee president, a CVP nominee, had the casting vote in line with the "national interest". The management committee was to be a Venezuelan joint stock company with up to 35% of the shares held by CVP. Its purpose was to direct, co-ordinate and supervise exploration, development, production and transport from the development area. All decisions were to be approved by a simple majority vote. The exploration contract was governed by Venezuelan law. The control committee's decisions were not open to any arbitration.

The new E&P areas on offer had the possibility of foreign companies finding significant oil reserves which would balance in part the high tax load. PDVSA said the ten areas had between 7 bn and 23 bn barrels of good quality oil and rejected pessimistic views about the fiscal terms by asserting that discoveries of 50-100m barrels would be profitable.

Only eight of the ten areas were taken up by foreign companies on Jan. 26, 1996. They pledged to spend a total of $1 bn on exploration and another $15 bn on development, so that their combined oil production by 2006 would reach 500,000 b/d. The following are brief profiles of the eight areas:

La Ceiba, most promising in the state of Zulia, was taken by Mobil in partnership with Veba and Nippon Oil , for which the group paid a cash bonus of $104m. This is a 1,742 km2 area in Maracaibo Basin. Mobil, which started seismic tests in 1996 and drilled exploration wells in 1997, has made good discoveries and began oil production in 1998. Primary Oil Plays: Productive Eocene Misoa sandstones (Mene Grande, Barua-Motatan, Tomoporo fields). Secondary Plays: Prospective Cretaceous Cogollo Reservoirs. Source: Marine Cretaceous La Luna shales; maturation occurred between Eocene to Recent. Trap Types: Neogene inversion anticlines and pre-Oligocene compressional structures; stacked Eocene stratigraphic onlap traps. Critical Factors: Reservoir deterioration due to deep burial; timing of accumulations in young structures and stratigraphic traps; trap integrity. Nearby Petroleum Accumulations: Mene Grande field (1914) 2,600m bls (medium/heavy, in place); Barua field (1958) 1,000m bls (medium, in place); Motatan field (1952) 2,600m bls (medium, in place); and Tomoporo field (1980) 175m bls (medium, in place). Existing Data: Area: seismic: 1,061 km 2D; wells: 10. Data Package: seismic: 1,490 km 2D; wells: 17. Indicative Primary Exploration Programme (by Jan. 1996): Seismic: 300 km 2D, 250 km2 3D; wells: 1 Tertiary well to +/-18,000'; 2 Cretaceous wells to +/-20,000'; time: 5 years from Jan. 26, 1996.

La Ceiba is in the S-E of Lake Maracaibo bordering Trujillo and Merida states. Infrastructure: Tomoporo, Barua and Motatan fields are in north of the area. Crude oil is collected via three flow stations based in the Motatan field and two in Barua field. The oil is transported to Bachaquero. The system is working at its full capacity of 115,000 b/d.

Quiriquire (including Guarapiche field), another promising area, 1,960 km2 in E. Venezuela Basin, is held by a partnership of Repsol-YPF unit Maxus of Argentina (55%) and BP Amoco (45%). For this the group paid a bonus of $109m. Maxus has since made good finds and began production in 1998. Its latest big discovery was made in early 1999, when its Tripical-1X well tested 46.4 MCF/d of gas and 7,571 b/d of oil from Upper Cretaceous San Juan and San Antonio formations. Other Primary Plays: Productive Miocene-Recent Upper Carapita, La Pica, Las Piedras reservoirs (Quiriquire & Pedernales fields); productive Oligocene Naricual reservoirs (El Furrial trend); productive Upper Cretaceous San Juan reservoirs. Secondary Plays: Prospective Eocene-Paleocene Caratas sandstones. Other Source: Primary Cretaceous Querecual; secondary Miocene source; maturation in foreland basin from early Miocene to Recent. Traps: Stacked sandstones reservoirs in large Neogene thrust anticlines; stratigraphic traps in shallow plays; structural-stratigraphic traps against flank of diapirs. Critical Factors: Reservoir predictability. Nearby Oil Accumulations: East: Pedernales field (1933) 600m bbls (heavy, in place); South-east: Quiriquire field (1928) 4,000m bbls (heavy, in place); El Furrial field (1986) 5,000m bls (medium, in place). Area: seismic: 915 km 2D; wells: 18. Data: seismic: 1,198 km 2D; wells: 44. Primary Exploration: Seismic: 700 km 2D; wells: 2 Tertiary wells to +/-14,000'; 1 Cretaceous well to +/-19,000'; time: five years from Jan. 26, 1996.

Guarapiche is in the states of Monagas and Sucre, south-west of the Gulf of Paria, in typical muddy plains. Infrastructure: Maturin, west of the area, has big logistic support facilities. The Caripito oil terminal, on the San Juan River which runs through the area, has a loading capacity of 100,000 b/d of crude, and handles 10 to 15 oil tankers of up to 33,500 dwt every month.

Guanare, a 1,898 km2 area in Barinas-Apure Basin, was taken by a partnership of Elf Aquitaine (the operator) and Conoco. Primary Oil Plays: Productive Cretaceous Escandalosa sandstones (Barinas fields); productive Eocene Gobernador sandstones (Barinas fields). Secondary Plays: Prospective Late Cretaceous Burguita sandstones; prospective Eocene Paguey sandstones. Source: Late Cretaceous Navay (La Morita); maturation from Eocene to Recent. Trap Types: High relief Neogene thrusted anticlines. Critical Factors: Timing of trap formation relative to charge. Nearby Oil Accumulations: South-west: Barinas fields, total 4,700m bls (medium, in place); Sinco (1955) 1,000m bls (medium, in place); Silvestre (1948) 700m bls (medium, in place); Paez-Mingo field (1965) 450m bls (heavy, in place). Data: Area: seismic: 376 km 2D; wells: 1. Data Package: seismic: 707 km 2D; wells: 3. Indicative Primary Exploration Programme: Seismic: 1,000 km 2D; wells: 2 Cretaceous wells to +/-9,000'; 2 Cretaceous wells to +/-13,000'; time: 5 years.

Guanare is in the dry tropical forest state of Portuguesa, in the western-central region. Infrastructure: The 190,000 b/d La Victoria-El Palito oil pipeline passes along the south-east corner of the area. The Nurgas gas pipeline is 80 km to the north. The 110,000 b/d El Palito Refinery and loading terminal are 180 km to the north-east. To the south-west are the Barinas and Apure fields.

San Carlos, a 1,771 km2 area in N-E Barinas Basin, was taken by Perez Companc of Argentina. Primary Oil Plays: Productive Eocene Gobernador sandstones (Barinas fields); productive Cretaceous Escandalosa sandstones (Barinas fields). Secondary Plays: Prospective Late Cretaceous Burguita sandstones; prospective Eocene Paguey sandstones. Source: Late Cretaceous Navay (La Morita Member); maturation during Oligo-Miocene; locally overmature. Trap Types: Paleogene tilted fault blocks; Tertiary thrust anticlines; stratigraphic pinch-outs. Critical Factors: Reservoir integrity; timing of trap formation relative to charge. Nearby Oil Accumulations: None that are relevant. Area: seismic: 983 km 2D; wells: 1. Data Package: seismic: 1,171 km 2D; wells: 1. Primary Exploration: Seismic: 1,000 km 2D; wells: 2 Cretaceous wells to +/-10,000'; time: 3 years.

San Carlos is in Cojedes and Portuguesa states, in the western-central region. Infrastructure: The 190,000 b/d La Victoria-El Palito oil pipeline lies 20 km to the west. The 1 BCF/d Nurgas gas pipeline runs 70 km to the north. The 110,000 b/d El Palito Refinery and loading terminal are 110 km to the north-east. To the south-west are the Barinas and Apure fields.

Gulf of Paria East, 1,084 km2 in E. Venezuela Basin, was taken by Enron (operator) and Inelectra of Venezuela. Primary Oil Plays: Productive Neogene Carapita/La Pica/Las Piedras sandstones (Posa, Pedernales & Soldado fields). Secondary Plays: Prospective Late Cretaceous-Paleogene San Juan-Caratas sandstones. Source: Late Cretaceous Querecual-Naparima Hill and local late Miocene source. Trap Types: Neogene thrust anticlines; shallow stratigraphic traps; stratigraphic pinchouts against shale diapirs; structural and stratigraphic traps in Neogene half-grabens. Critical Factors: Reservoir predictability. Nearby Petroleum Accumulations: South: Posa field (1955) 560m bls (heavy/medium, in place); Pedernales field (1933) 600m bls (heavy, in place); South-east: Soldado field (1955) >2,000m bls (light/heavy, in place). Area: seismic: 1,435 km 2D; wells: 30. Data: seismic: 1,836 km 2D; wells: 30. Primary Exploration: Seismic: 1,000 km 2D (or equivalent 3D); 300 km2 3D; wells: 1 Tertiary well to +/-12,000'; 1 Cretaceous well to +/-18,000' (if companies can demonstrate that no identifiable Cretaceous target exists, this commitment may be fulfilled by a second Tertiary well to +/-12,000'); time: 5 years.

The area is offshore, south of the Paria Peninsula, with water depths of up to 30 metres. Infrastructure: Same as above, plus an abandoned offshore production platform.

Gulf of Paria West, 1,137 km2 in E. Venezuela Basin, was taken by Conoco. Now it holds 50% in this and its partners are Agip (40%) and Taiwanese China Petroleum unit Overseas Petroleum & Investment Corp. In March 1999 Conoco made a big discovery, with its Coracora-1X well testing 4,195 b/d of oil from three zones 5,950 to 9,090 ft deep, and 10.6 MCF/d of gas from a fourth zone 12,100 ft deep. The US major later said if this and subsequent finds are favourable, total investment in the venture may exceed $1.1 bn.