VENEZUELA - Gas Exports.

With oil prices having more than doubled since early 1999 and to be defended by OPEC beyond March 2000, PDVSA has made it clear it intends to relaunch Venezuela's LNG export project to be built at Mapire Bay, on the Paria Peninsula in the east. A $2 bn scaled down version of the 6m t/y project might be adopted. Called Cristobal Colon, it had been planned to be on stream in 2000 to supply both the US market and Europe.

The JV for this, Sucre Gas SA with an initial capital of $45m, was set up in 1994 between PDVSA (then through Lagoven, with 33%, Shell (30%, the technical project leader), Exxon (29%, upstream operator), and Mitsubishi Corp. (8%). In June 1996, an agreement was signed by Lagoven transferring to Sucre Gas the upstream studies and the rights to develop offshore gas fields dedicated to the project.

This had been the biggest single energy project in the Caribbean and most challenging among the world's LNG ventures. The partners, which have been delaying the project since 1993, have already spent about $50m on studies for the project and on appraisal wells. Now they have to overcome three challenges, if construction of the project is to begin in 2000:

1. Cutting costs from the original estimate of $5.8 bn has been a prime target. Hitherto, costs have been cut to $4 bn for a 6m t/y capacity. The cost of a single 3m t/y train and the upstream element should not exceed $2 bn. (The original $5.8 bn estimate was broken down as follows: $2.2 bn for construction of three 2m t/y liquefaction trains and infrastructure; and $3.6 bn were to be split almost equally between offshore fields' development, the pipeline system and the purchase of tankers to transport the LNG to US and European markets.

2. The selling price has been the biggest challenge to all promoters of LNG export projects across the globe. For Sucre Gas, a fob price of $2.40/m BTU is the breakeven point.

3. The gas reserves: Exxon, the proposed upstream operator, has to find and prove in the four offshore fields in the Gulf of Paria, of Sucre province, 12 TCF of recoverable non-associated gas reserves if the project is to have a 6m t/y capacity or 6 TCF for a 3m t/y venture. But Shell is said to believe 12 TCF is the minimum required, so that the partners can embark on a project that should be expanded to 6m t/y and operate for 30 years as well as give Sucre Gas the latitude of expanding the plants later to 7.5m t/y.

Venezuela has the largest reserves of natural gas in Latin America, estimated at about 147 TCF by PDVSA. Energy and Mines Minister Ali Rodriguez said in November 1999 PDVSA could triple the 147 TCF within five years. Lagoven - whose upstream operations were taken over by PDVSA E&P and downstream assets were absorbed by PDVSA M&M in a restructuring process completed in early 1998 - said in 1996 that it could easily prove 12 TCF minimum and indicated a potential of more than 16 TCF in the four offshore areas near the LNG project's proposed location. So far, PDVSA has proved almost 11 TCF in the four offshore fields in the Gulf of Paria.

Most of the existing LNG export ventures around the world were built when the price of oil was strong. From the late 1970s, the CIF price of LNG in Europe and Japan averaged more than $5/m BTU, though LNG import projects in the US were suspended and West European buyers received gas by pipeline at lower prices. At times the CIF-Japan price of LNG exceeded $6/m BTU. In 1985, when the final contracts for Australia's North-West Shelf LNG project were signed, the CIF-Japan price of LNG was more than $5/m BTU.

In 1990, when the Cristobal Colon project was conceived, gas prices were averaging $2-3/m BTU in the US and over $4/m BTU in Europe.

As most of the Venezuelan LNG would be sold to the US, the pricing challenge to the partners is considerable. Although there are indications that the US market for gas will be strong in the next decades, with oil prices worldwide expected to be strong as well, the risks are high and the partners want them to be minimised.