6 months ago

ENERGY Caribbean Yearbook (2013-14)

cross-border gas Energy

cross-border gas Energy issues Venezuela lethargy keeps gas stranded The cross-border gas straddling the maritime boundary between Trinidad and Tobago and Venezuela southeast of Trinidad and northeast of the Orinoco Delta looks likely to remain out of reach indefinitely, because the two countries seem unable to move the commercialisation process forward. That means that 1.8 trillion cubic feet (tcf) of confirmed gas reserves in the Manatee discovery in Trinidad and Tobago’s block 6d (which partners the Loran find in Venezuela’s Plataforma Deltana block 2), and around 1 tcf of gas in the Manakin discovery in block 5b (linked with Coquina in Plataforma Deltana block 4), will not be available for use in Trinidad and Tobago’s reviving downstream gas-based industrial development programme. Such a waste of badly-needed gas at a time when current exploitable reserves are almost all committed is clearly unacceptable. The problem, as energy analysts see it, is that Venezuela feels no urgency in developing cross-border gas because it has dumped plans – for how long, no one knows – to get into the LNG business. Its Plataforma Deltana reserves were always destined for the export trade. Chevron, the operator of block 2, has made no secret of the fact that under its licence it must provide 90% of the 6.2 tcf in Loran for use as LNG and the remaining 10% for domestic use in Venezuela. It has a 39% holding in block 2, Venezuela’s PdVSA holding the other 61%. With LNG off the table, the government in Caracas sees little sense in rushing to commercialise the gas. The 10% that was destined for domestic use can be sourced from other gas discoveries closer to the mainland, such as the very large one that Repsol made in the Gulf of Venezuela recently, or even the proven reserves in the Paria Norte region. Trinidad and Tobago’s energy minister Kevin Ramnarine could scarcely conceal his impatience when he last spoke publicly about the cross-border gas matter. In an address at the Austin Jackson School of Geosciences at the University of Commercialisation has long been under way with the development of Kapok Companie “It is very hard to get the Venezuelans to meet with us on this issue” Texas in Austin in March 2013, he said: “It is very hard to get the Venezuelans to meet with us on this issue.” He noted that he had “been in contact with minister Rafael Ramírez” (who has been retained as minister of energy and petroleum in the new Maduro government) and had also “spoken with Chevron” (the operator of both Manatee and Loran), but did not seem to hold out much hope for crossborder monetisation any time soon. The project appears to be stuck at the stage of selecting a unit operator. A unit directing committee representing all the stakeholders in the matter – the two energy ministries, Chevron, Countries the BG Group and PdVSA – was supposed to select the operator early last year, but the Venezuelans failed to turn up in Port of Spain for the scheduled technical meeting. Then President Chávez’s lengthy illness and death, and the election of Nicolás Maduro Moros as his successor, put a stop to decision-making in Caracas on matters like cross-border gas for most of 2012; and the post-electoral situation does not seem to have changed anything. As far as the Manakin (BP/Repsol) and Coquina (Statoil/ PdVSA) discoveries are concerned, no unitisation agreement has been signed. The reservoir joint working group, comprising officials from both sides, has identified the total volume of gas reserves they believe to be there. But the specific amount on each side has not yet been determined. A “best guess” estimate is about 1 tcf in each discovery. The situation in the third pair of cross-border gas blocks – bpTT’s Kapok discovery on the Trinidad side and the Dorado find by PdVSA in block 1 in Venezuela – is different, in that commercialisation has long been under way with the development of Kapok. The estimated combined reserves in the two blocks is about 1 tcf, and PdVSA has allowed bpTT to produce what it can from the two reservoirs. When the exact amount on each side is determined, if production from the Kapok field has exceeded the allocated reserves allocated, bpTT would agree on some form of compensation for PdVSA. 16

Energy issues Deep water exploration The last real frontier? Deep geological horizons on land and offshore are a possible new oil and gas play in Trinidad and Tobago (and received incentives in the 2012-2013 national budget), but the real last The ministry has bent over backwards to make deep water activity economically attractive, which it has not been in the past frontier for substantial hydrocarbon discovery Compani is exploration in deep water, at whatever geological depth. Deep water is defined by the energy ministry in Port of Spain as a water depth of 1,000 metres and more. No exploration beyond about 1,500 metres has actually taken place before. Eight wells were sunk in the continental slope in the late 1990s and early 2000s in water depths of 750-1,500 metres, but only one find of non-commercial gas was made. In 2012, the BP Group signed two production-sharing contracts for exploring in the Atlantic deep water off the east coast. Water depth in the two blocks, 23a and TTDAA 14, is around 2,000 metres. BP is leading the first assault on real deep water acreage in Trinidad and Tobago. It will be followed by BHP Billiton, which was awarded four other blocks – TTDAA 5-6 and TTDAA 28-9 – in the subsequent bid round (see map on p26-27). Deep horizon exploration, on land or offshore, could itself result in the identification of a new play, if the incentive offered – a 140% write-off on exploration costs – is enough to entice explorationists. “Deep horizon” has been defined by the ministry as 8,000 feet or more on land and 12,000 feet or more offshore. While he would clearly be pleased with a deep horizon discovery, Trinidad and Tobago’s energy minister Kevin Ramnarine is betting on the deep water. He believes that “both BP and BHP Billiton, two long-established players in the country, stand poised to take us into a period of exciting deep water exploration” and that “the deep water in Trinidad is one of the holy grails of geologists, who have long suspected its vast hydrocarbon potential.” This potential has been estimated by the energy ministry at 4.7-8.2 trillion cubic feet (tcf) of gas in the two BP blocks (no estimate has been given publicly for possible oil resources), and 2.4-23.6 tcf of gas and 428-4,200 million barrels of oil in BHP Billiton’s four blocks. The latter would have had its own reasons for bidding so aggressively on four of the five blocks that attracted companies’ attention in the 2012 deep water auction, but the ministry has bent over backwards to make deep water activity economically attractive, which it has not been in the past. These attractions are intended to “reduce risk and offer companies a more competitive environment,” and include: • Cost recovery (“cost oil or gas”) increased from 60 to 80% • A 35% petroleum profits tax and an 18% supplemental petroleum tax payable on oil only. This allows the company to claim a higher share of “profit oil or gas” since the government’s take under the productionsharing system is based on these two taxes • A 140% write-off for deep water exploratory wells, further enhancing the companies’ share of “profit oil or gas”. Countries The ministry is following up on its 2010 and 2012 deep water bid rounds with another in 2013, which it hopes will attract new companies into the hydrocarbon sector. Minister Ramnarine told this YEARBOOK: “companies which did not bid in 2012 have told us they will bid in 2013 ... In one case, they told us that they had a restructuring exercise “BP and BHP Billiton, two long-established players in the country, stand poised to take us into a period of exciting deep water exploration” going on in 2012, and another said it had quite a lot on its plate at the time. So, I think that we have stimulated widespread interest in our deep water bid rounds.” energycaribbean YEARBOOK 2013/14 17

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