April 2014 • Issue no. 72
WHAT’S INSIDE
NEWSLETTER
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PPGPL suffers setbacks in overseas investment
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Staatsolie expects upsurge in exploration
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BHP Billiton to decide on block 3a this year
10-11 The best ways to get gas to Caribbean markets
CARIBBEAN LNG
Courtesy Roland Fisher
New LNG venture promises electricity price relief Trinidad plant will target Martinique and Guadeloupe first Roland Fisher
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aribbean electric utilities desperate for deliverance from high fuel oil and diesel prices may finally have their prayers answered. Roland Fisher, CEO of Gasfin Development SA, which has been given the green light by the Trinidad and Tobago government to establish a 500,000 tonne-a-year LNG plant at La Brea, says he is confident that Caribbean LNG, as the La Brea plant will be known, should be able to deliver gas at around US$14-15 per mmbtu, or at least 20% below the current cost of fuel oil in mmbtu terms. That could mean a substantial reduction in the current cost of electricity to regional consumers, who currently pay prices ranging from US$0.39 per kilowatt hour in St Vincent to $0.22 per kwh in Aruba (compare $0.06 in Trinidad and Tobago). Gasfin Development is a Luxembourgregistered, UK-headquartered company, but the state-owned National Gas Company (NGC) will be an equal partner in Caribbean LNG and will be directly involved in part ownership of the first train (and probably a second in time), as well as a likely equity partner in the
two floating, storage and regasification units (FSRUs) to be based in Martinique and Guadeloupe, the first customers the company is targeting. TGE Marine and TGE Gas Engineering, both Gasfin subsidiaries, will be designing and building these vessels as well as the carrier that will deliver the LNG from La Brea – and of course the LNG plant itself. Since LNG is being delivered FOB, Gasfin has no control over possible NGC partnership in the LNG carrier part of the supply chain unless, as Fisher explains, “we take the project on to being a deliverer of gas, rather than a seller of LNG. The buyer has to manage their own logistics.” The situation may change when Caribbean LNG begins to sell to the smaller Caricom states, which may not be in a position to engage their own transport. Fisher has been wooing Électricité de France (EdF), the power producer in both Martinique and Guadeloupe, almost from the day he started selling his idea about the vast potential of the Caribbean gas trade to energy ministry officials, who were sceptical at first but eventually came around. The current
minister, Kevin Ramnarine, became a convert and formally announced the go-ahead for the project at the Energy Chamber’s annual petroleum conference in early February. A project development agreement now has to be worked out.
New business Production of LNG under national and sympathetic foreign control opens the door to a host of new business possibilities. Caribbean LNG will be the conduit for the transfer of Trinidad gas to as many Caribbean markets as possible, to relieve them of crippling and potentially everlasting dependence on oil. As Fisher points out: “What we are really doing is supplying the infrastructure that will enable NGC gas to go to the region, and NGC has told us that’s what our job is, not to sell their gas to the world.” Caribbean LNG could also do what the much bigger LNG company, Atlantic, has never contemplated: providing LNG to domestic Trinidad customers. “We are very serious that containers of LNG will be available for the Trinidad market,” Fisher says. “It will be a real opportunity for small industries, for [ to page 12 ] Energy Caribbean • April 2014 1
PPGPL
Unlucky in Africa, gas liquids company turns to Americas And seeks closer alignment with 90% owner NGC
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he Point Lisas-based gas liquids extractor and marketer Phoenix Park Gas Processors Ltd. (PPGPL) has not been as successful as it hoped in its international outreach, part of the mandate given to it by the Trinidad and Tobago government. PPGPL is virtually a state company now, being 90% owned by the National Gas Company (NGC), which is itself state-owned. “We have got to get aligned with NGC’s own strategies,” company president Eugene Tiah explained in an exclusive interview with ENERGY Caribbean. “We need to get clear on what the overall strategy is for what is now the NGC Group.” NGC has always owned 51% of PPGPL, and extended its holding by buying the 39% share previously held by the US’s ConocoPhillips. Even before that purchase, the two companies collaborated closely on international initiatives, jointly considering gasbased projects in Ghana, Tanzania and Equatorial Guinea, though none have so far come to fruition.
The magazine of the Caribbean energy industry
APRIL 2014 • Issue No. 72 Subscriptions Department 6 Prospect Avenue, Maraval, Port of Spain, Trinidad & Tobago Tel: (868) 622 3821, Fax: (868) 628 0639, e-mail: energy@meppublishers.com Writer David Renwick Editor Jeremy Taylor Layout Bridget van Dongen © 2014 Media & Editorial Projects Ltd. All rights reserved
Africa A potential investment in gas gathering and processing facilities in Ghana, once viewed with great enthusiasm, was lost to China in 2010. The Ghana National Gas Company then issued a request for expressions of interest in operating and maintaining the plant, to which PPGPL responded. But Tiah says: “They then told us they had scrapped all of that.” PPGPL and NGC also examined a gas processing project in Nigeria, but “based on a rigorous review of risks and returns and other factors, both companies decided that the project should no longer be pursued.” In Tanzania, “we were looking at the feasibility of micro-LNG for power generation for mining facilities, and were getting aligned with an Australian company that wanted to do that.” But PPGPL soon realised that “it would have been an unbalanced sort of relationship: we wanted to bring to the table our expertise and knowledge, but they seemingly preferred just money, with limited involvement.”
Advertising Yuri Chin Choy, ENERGY Caribbean Sales Department 6 Prospect Avenue, Maraval, Port of Spain, Trinidad & Tobago Tel: (868) 683 0832, e-mail: yuri@meppublishers.com ENERGY Caribbean is published six times a year, on February 1, April 1, June 1, August 1, October 1 and December 1. Subscriptions: Trinidad and Tobago TT$750 per year (six issues), Caribbean US$125, Rest of the World US$150. For multiple copies please contact the Subscriptions Department.
Nothing much has happened in Equatorial Guinea either. “An initial assessment visit was made to that country, which has a developing gas sector, to evaluate potential gas processing and related opportunities, and subsequently a country risk assessment was completed to guide pursuit of any future opportunities.”
The Americas For a company operating against a background of “fewer growth opportunities locally and leaner gas supplies coming into the Point Lisas plant”, four unsuccessful attempts to spread itself abroad must be demoralising. Apparently undaunted, Tiah has switched PPGPL’s attention to the western hemisphere, targeting Colombia and Nova Scotia, Canada. In Colombia, the company is again looking at gas gathering and processing. “Colombia has both associated gas and some pure gas production – small pockets and small projects – but it is looking to gather and harness as much of the resource as they can for power generation. State company Ecopetrol and some associated companies have been asking for EOI for project development.” PPGPL complied but “the challenge with these things is that they issue a request today and they want a proposal next week.” The situation requires PPGPL to “have a presence in such countries”, and teams have been to Colombia, spending “a couple of weeks developing a network and relationships”, and to Nova Scotia, engaging with “some entrepreneurial types whose business idea is that there are big arbitrage opportunities for gas liquids from shale gas between North America and Europe and Asia, using terminalling assets presently under-utilised.” Tiah thinks this is an “interesting model because of the terminalling business and the marketing of natural gas liquids, both of which we are interested in, as well as the future potential for fractionation.” At home, one growth opportunity is a processing plant at Union industrial estate, La Brea, to capture the 300 million cubic feet a day (mmcfd) of gas that will be flowing through that estate before long. PPGPL invited expressions of interest for the provision of “standard design solutions”, and has been reviewing the responses. Energy Caribbean • April 2014 3
SURINAME
Major exploration programme is under way And the next round of bidding is in progress too
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taatsolie, Suriname’s national petroleum company and only oil producer, confidently expects another wave of offshore exploration after March 2015, when it will award yet more blocks based on the outcome of the “nomination” process now under way. The company has adopted a new approach to acreage awards, which mimics what Trinidad and Tobago has done for some time in relation to the deep water: potential explorers indicate which open blocks specifically interest them, and that information is used to decide which ones will be offered for auction. Fifteen demarcated offshore blocks are available, their 1.2 million acres representing about 66% of the marine area under Suriname’s control, so the exploration potential is clearly substantial. So far, blocks northwest of Suriname’s coastline have proved of most interest to companies now operating there, which leaves most of the 15 on the northeast of the marine area, abutting the delimitation line with French Guiana, open for bids. Staatsolie will be hoping that the offshore discoveries in that French department will be a spur to the nomination, and subsequent takeup, of acreage.
More to come So far, the belief that the geology of
AUCTION SCHEDULE February 2014 March 2014 June 1, 2014 July 2014 August 2014 January 30, 2015 March 2015 4th quarter, 2015
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EXPLORATION Company Inpex Kosmos/Chevron Kosmos/Chevron Tullow Oil Murphy Oil Petronas (Malaysia) Apache/Kepsa Tullow Oil/Statoil (Norway)
Block Wells 31 1 42 1 45 2 47 1 48 1 52 1 53 1 54 tba
the Guyana/Suriname/French Guiana basin mirrors that of west Africa, where Tullow Oil made its famous Jubilee discovery in Ghana, has been proved correct only in the case of French Guiana itself, with the Zaedyus find of about 840 million barrels in 2011. The four wells drilled in Suriname’s blocks 37 and 31 in 2011, by Murphy Oil and Japan’s Inpex respectively, were not successful. Nor was recent exploration offshore Guyana. But the possibilities have not been exhausted by any means, and there is an ongoing drilling programme by existing block holders in Suriname which will see extensive offshore exploration activity (see box). And there will be much more to come, towards 2017 and beyond. Nominations from companies for blocks of interest to them began in February. On the basis of US$50,000 data packages, they will have until June 1 to put forward their choices. Staatsolie
Block nominations open Data packages Deadline for nominations Nominations evaluated Selected blocks announced; bids open Bids close Successful bidders announced Seismic acquisition begins
Timeframe April 2015 tba 2015 2014 Q4–2015 Q1 tba April 2015 by April 2015 tba
requires companies to “briefly indicate the reasons” for their selections, but if a company declines to nominate, it can still bid in the subsequent auction.
Process In July, Staatsolie will be evaluating the acreages nominated, including whatever leads/prospects may have been identified, and will assess companies according to their technical expertise, resource management record, and health, safety and environmental reputation. The selection of blocks for production sharing contracts will be governed by their commercial potential, strategic fit with Staatsolie’s vision, the information available, and the degree of interest that has been expressed. The blocks chosen for auction will be announced on August 1, and will be open for bids until January 30, 2015. Successful bidders will be revealed in March 2015, and are likely to be companies that have offered a participating interest to Staatsolie, with maximum work obligations, which have a good operating record and demonstrate a sound grasp of the geology. Staatsolie expects the companies chosen to get moving on exploration activity quickly and begin seismic acquisition by as early as the fourth quarter of 2015.
TRINIDAD & TOBAGO
Major drilling to resume on land Twelve exploration wells planned for Rio Claro, Ortoire and St Mary’s
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xploration activity on land in Trinidad should ramp up by late 2015, now that the successful bidders for three blocks offered in 2013 have been announced. As formally confirmed by the ministry of energy and energy affairs in February, the 75,089-acre Rio Claro block in southeast Trinidad, which extends to the Atlantic Ocean, was awarded to Lease Operators (LOL); the 44,674-acre Ortoire block, which also abuts the Atlantic, to Canada’s Touchstone Exploration; and the 37,895-acre St Mary’s block, further west, to the Anglo-Australian firm Range Resources. These companies have committed to collectively acquiring 295 line km of 2D seismic and 60 sq km of 3D, and thereafter sinking 12 exploration wells, all at a cost of US$55 million. If they find commercial reservoirs and decide to develop them, a further US$945 million could be spent. The onshore therefore joins the current shallow water and deep water offshore exploration initiatives in one of the busiest periods of exploration activity in decades. Energy minister Kevin Ramnarine has been quick to point out that the land is now bracketed with the offshore as a focus of exploration activity only because the ministry sanctioned the “first dedicated onshore bid round in 15 years.”
The energy ministry sanctioned the “first dedicated onshore bid round in 15 years” He also pointed out that all three blocks are next to and on trend with existing hydrocarbon sources, including the Barrackpore field (130 million barrels), Rock Dome/ Catshill/Inniss (25-30 million barrels) and Carapal Ridge (20-500 million cubic feet of gas and condensate).
Touchstone Touchstone Exploration, whose chair-man and CEO is Paul Baay, has wasted no time in moving to finalise the exploration and production licence for Ortoire, which was expected by early March. The company’s vice president for geosciences, James Shipka, sees Ortoire as “an incredible opportunity for Touchstone, as it is an extension of the well-known southern basin and presents exploration and development opportunities in a number of different horizons. As with the
company’s existing budget, the commitments associated with the bid are expected to be funded through future cash flow.” Jim Krissa, Touchstone’s Trinidad and Tobago country chairman, speaks of the “high impact potential” of Ortoire, which gives the company access to a significant amount of exploration acreage “that will be immediately integrated into our long-term operational plan in Trinidad and Tobago.” Krissa says that this additional acreage (Touchstone now holds a total of 63,000 acres on land in Trinidad and 5,000 acres nearshore in the Gulf of Paria) enables the company “to move forward as a leader in onshore exploration and development in Trinidad.”
Range Resources Range Resources seems happy to have acquired St Mary’s, since it is “contiguous to its existing Morne Diable farmout block licence and the Guayaguayare Shallow and Deep Horizon blocks, held by Niko Resources, in which Range farmed in 2013.” The company has identified several geological horizons in which it hopes for exploration success once drilling begins, including “Pliocene Deltaic sands, Miocene Herrera sands, Cretaceous sands, and the source rock itself.” Minister Ramnarine had previously suggested that around 590 million barrels could be present in the Miocene Herrera sandstone “in several accumulations, each ranging in size between 15 and 150 million barrels of oil.”
Lease Operators Lease Operators has been silent on the significance of its acquisition, but it is clear that, as a strictly local company with no access to international corporate connections, it has its work cut out for it, especially since it has taken on the biggest block by far, and the one with the fewest portions excised because of licences earlier granted to others. In its favour, however, is that the owners, the Brash family, also control the largest local drilling company, Well Services Petroleum (WSP), so equipment availability should not be a problem when that stage is reached. Anthony Brash, son of company patriarch Charlie Brash, is quoted as saying that the company has five rigs available for onshore work, but they all seem to be contracted to LOL rivals, including, ironically, Touchstone, Trinity Exploration and Production (in which the Brashes are shareholders), Fram Exploration, Leni Gas and Oil, and Petrotrin. He does point out, however, that LOL will have use of WSP’s Rig 2, Rig 20 and Rig 70 at various times during 2014. Energy Caribbean • April 2014 5
ST VINCENT
The future: multiple energy sources Already hydro supplies 18% of St Vincent’s power
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ith no oil nor gas of its own, St Vincent and the Grenadines is turning to renewable energy. It already produces 18% of its power from hydro, according to Thornley Myers, CEO of St Vincent Electricity Services (total installed capacity 42MW). Solar also makes a modest contribution. Five other member utilities of the Caribbean Electricity Utility Services Corporation, the “trade union” for power providers in the region, have installed RE generation systems to complement their diesel and fuel oil facilities: the Jamaica Public Service Company, Lucelec in St Lucia, Barbados Light and Power, St Kitts
Electricity (a government department), and Aqualectra in Curaçao. Myers sees others moving slowly but surely in this direction. RE installation costs are high, and the intermittency of all but two RE sources – hydro and geothermal – will always require a more reliable baseload system. But RE allows greater price stability, Myers observes. “Fuel prices change every month now, based on the price of oil.” There is also a foreign exchange saving from reduced oil imports, and as an indigenous resource RE offers a measure of “energy independence”. Then there’s the CO2 reduction factor. Carbon emissions are comparatively
low in the Caribbean (the IDB puts St Vincent’s CO2 discharges at 48,805 tons a year), but Myers supports reduction. “If we demonstrate a commitment to lowering our greenhouse gas emissions, other countries will say, if these small states are committed to this exercise, why shouldn’t we be trying too?” While RE will grow, Myers predicts, multiple energy sources will be the pattern in the Caribbean, with the fossil fuel contribution coming from gas. Roland Fisher, CEO of Gasfin Development SA, has been trying to enlist St Vincent as a client of the proposed small LNG train to be established at La Brea in Trinidad. “We were receptive,” Myers says, “but the key question will always be cost. Price stability is first and foremost in our considerations.” Consumers in St Vincent presently pay US$0.39 per kilowatt hour (kwh). “If we can import gas at a price that lowers that to US$0.25, we would be very happy. Of course, if it were US$0.15, we would be even happier!”
SUSTAINABILITY
BG T&T comes clean on CO2 And prepares plans on emission reduction and local content
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orporate contributions to global warming are a delicate subject, but BG Trinidad and Tobago frankly states in its most recent Sustainability Review (2012/2013) that its greenhouse gas emissions during the former year amounted to 45,526 tonnes. Flaring accounted for 42.08%. Fuel gas usage contributed 22.82%, diesel usage 18.24%, venting 10.97%, “fugitive” emissions 5.08%, and aircraft fuel 0.81%. The 2012 figure was a 2% reduction on 2011. Upgrading BG T&T’s Beachfield blowdown system reduced emissions from flaring by as much as 76%. Greater use of gas generators and less of diesel as a primary fuel source reduced emissions
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by 12%. Imposing a fixed flight schedule for aircraft cut that source by 25% and lopped US$1.9 million off the fuel bill. However, gas compression facilities installed at BG T&T’s Central block on land in 2013, and those to be completed on the Hibiscus platform in its North Coast Marine Area 1 block in 2014, will “significantly increase” emissions from those sources. BG T&T is the country’s second largest provider of natural gas (25% of the total), and is not happy that its greenhouse gas (GHG) emissions will be rising again. It pledges to develop an energy management plan for emissions (methane and nitrous oxide as well as CO2).
A UK company, Process Improvement, has already undertaken “an energy efficiency survey of all existing facilities to determine how efficiently energy is being consumed and managed.” Sixteen ways to enhance efficiency were identified, which BG T&T says “could result in potential savings of over 100,000 tonnes of emissions.” A technical review of the existing “GHG accounting and reporting process” has been undertaken, which the company believes could “help improve the overall accuracy and quality of data reported.” Assessment of “fugitive” discharges (attributable to leaks and other irregular gas emissions from equipment) has been reviewed in the light of “changes in operational design.” In another area of national concern, local content, BG T&T claims in its report that it is falling in line and “developing a local content strategy.” Energy minister Kevin Ramnarine recently revealed that “serious consideration is being given to legislating local content ... as has been done in Norway.”
EMISSIONS
Petrotrin plans “clean development mechanism” A quarter of its wells will be involved initially
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etrotrin plans to recover about five million cubic feet a day (mmcfd) of associated gas currently vented in its oilfields. By mid-year, it should have selected a contractor to “finance, build, own, operate, maintain and transfer” Trinidad and Tobago’s first clean development mechanism (CDM). This will keep about 78,000 tonnes of CO2 out of the atmosphere. Total national emissions are estimated at 53 million tonnes a year by Dr Donnie Boodlal, assistant professor of process engineering at the University of Trinidad and Tobago. Though the project represents only a modest cut in overall country emissions, it is significant in the context of process ad_energy_caribbean_hp.pdf
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emissions from oil and gas, since they account for only 2% of total emissions, according to Boodlal’s research. The petrochemical plants at Point Lisas are responsible for 57%, and power generation for 28%. The finance will come from the fee that Phoenix Park Gas Processors (PPGPL) is paying to integrate that 5 mmcfd of associated gas into its own gas stream, and to develop the ability to trade certified emission reduction credits on the European Union carbon market. PPGPL will achieve some minor benefit from extracting the liquids from the gas, which is its primary business. Financing for such activities is seen as
03/03/2014
a challenge for local companies. Ramona Ramdial, minister of state in the ministry of the environment and water resources, stressed the “urgent need” for climate finance when she met the European Union commissioner for climate action, Connie Hedegaard, in New York late last year. Petrotrin has 2,216 active wells, but only 562 will be targeted in the first phase of the CDM project. “The big cost in this is getting a pipeline system to all the wells,” explains Hemraj Ramdath, the company’s vice president for strategy and business development. There is already a gas line from Pointe-à-Pierre to PPGPL, “so we will be tapping into that.”
10:02
Finally, LNG for the Caribbean
Right-sized LNG solutions Gasfin, building on its extensive global references in Mid-scale LNG, stands ready to assist Trinidad & Tobago to win the race to serve the Caribbean gas market. For more information visit www.gasfin.net or call 868 224 3495 At every step...in every size...on land or sea...across the globe Energy Caribbean • April 2014 7
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TRINIDAD & TOBAGO
BHP Billiton TT closer to a decision on block 3a
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lock 3a, 25 miles off the northeast coast of Trinidad with water depth of 100-300 feet, could be a new productive oil and gas location – if the operator, BHP Billiton Trinidad and Tobago, finally decides that it is worth developing. ENERGY Caribbean has been prodding the Anglo-Australian multinational to declare its hand on 3a for some time, since the potential 135 million barrels of oil in the Kingbird-Ruby discoveries and the 550 billion cubic feet of gas in Delaware could both make a valuable contribution to hydrocarbon output. BHP Billiton T&T’s president, Vincent Pereira, now says “we are getting close to the point where we will have enough data to make an assessment. If we can make 3a work, we will.” Seven exploratory wells and two sidetracks have been sunk in 3a, adjoining the company’s productive 2c block, since it was first taken on under a production sharing contract (PSC) in October 2001. Two oil discoveries were made, with Kingbird and Ruby, and one gas discovery, with Delaware. So why haven’t BHP Billiton T&T and its co-holders Chayong, Anadarko, Petrotrin and the National Gas Company (NGC) proceeded to commercialise them?
Another look The challenge, Pereira says, is the true size of both the oil and gas resources. “The extent of the discoveries is what matters,” he told us in an exclusive interview. “These things only work when they are a certain size. So what we decided to do was to take a re-look at the seismic, to reinterpret the seismic to see if it would give us any hints as to what’s going on in 3a.” Further appraisal drilling may be
needed before any development can be undertaken – but that can only be contemplated “where we have enough information as a partnership to really understand what it is about 3a that we don’t now understand.” The company should be in that position “hopefully, early in 2014.” Ever cautious, Pereira warns: “I can’t sit here right now and tell you that 3a is commercial.” But the fact that the consortium has been willing to pay the cost of rolling over the market development phase (which 3a is now in because a discovery was made) suggests it is more optimistic than pessimistic.
It would be justified in considering itself the most active petroleum company in Trinidad and Tobago at the moment The energy ministry supports the consortium because, as Pereira notes, “it is as interested in trying to understand what’s in 3a as all of us are.”
Other projects The 3a reassessment is just one of the projects on which BHP Billiton T&T is working – it would be justified in considering itself the most active petroleum company in Trinidad and Tobago at the moment. It is acquiring 17,717 sq km of 3D broadband seismic over its five deep water blocks – TTDAA 28-29, TTDAA
Courtesy BHP Billiton
Uncertain of the real size of its discoveries, the company is taking its time to decide on further development
Vincent Pereira
5-6, and 23b – in collaboration with the BP Exploration Operating Company, which needs imaging of its own deep water acreage, blocks 23a and TTDAA 14. At the same time, it is moving ahead with its “Angostura phase 3 development” in block 2c, where it is also the operator, with a view to tapping into the gas discovered by the Angostura well, the first ever sunk in that block. The company has already had gas flowing from 2c via the Aripo discovery, which was made after Angostura but which BHP Billiton T&T and its joint venture partners in 2c – Chayong and NGC (Total at the time) – chose to commercialise first. That entails supplying the NGC with 220 mmcfd from 2011 to 2021. This arrangement is likely to be renewed in the wake of the extension in November 2013 of the PSC for the block itself, up to April 2026. If that happens, the consortium will certainly need backup gas to compensate for any decline in deliveries from Aripo. Pereira explains: “The new supply will help us maintain our gas plateau. Reservoirs decline so you have to keep filling in, and this is what Angostura will do. It extends our plateau, which is the reason we needed the PSC extension because our productive life is beyond 2021.” Reserves in Angostura amount to 400-500 bn cf, and production will be about 100 mmcfd from the second half of 2016. Development will take place through subsea wells tied back to the gas export platform in 2c, into which Aripo gas already feeds Energy Caribbean • April 2014 9
CARIBBEAN NATURAL GAS MARKET
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CARIBBEAN NATURAL GAS MARKET •
CARIBBEAN NATUR
The IDB’s natural gas study I
nter-American Development Bank experts Jed Bailey and Nils Janson have produced the most comprehensive analysis so far of the Caribbean natural gas trade – “A Pre-Feasibility Study of the Potential Market for Natural Gas as a Fuel for Power Generation in the Caribbean”. This formed the reference document for a meeting of Caribbean energy ministers held under the Bank’s auspices in Washington in early December 2013. The study focuses
CNG can’t compete with LNG Shipping costs make all the difference
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he IDB study has bad news for the UK’s Centrica Energy, which has been trying to put together a deal to export its gas from blocks 22 and NCMA 4 in Trinidad and Tobago to Puerto Rico in compressed natural gas (CNG) form, and for other promoters thinking along similar lines for other Caribbean markets. It rules out marine CNG as a commercial proposition for the region. “Seaborne CNG does not appear to provide a large enough cost reduction [compared with fuel oil] to justify the added risk of using an unproven technology,” it says firmly. Since the whole point of Caribbean utilities switching to natural gas is to dramatically lower their fuel costs, this conclusion seems to make sense. For example, the final delivered price of CNG from Trinidad and Tobago to Barbados, as calculated by the study’s authors, is expected to be US$8.71 per mmbtu, while that for LNG is US$8.65. The disparity is even greater in the case of gas supplied to Antigua (US$11.48 per mmbtu for CNG, US$9.06 for LNG). The difference in price, for the same fuel costing the same at the point of export but delivered by different methods, seems to lie in the cost of shipping. The IDB study concludes that “shipping CNG is likely to be much more expensive. CNG ships are essentially floating platforms for high pressure pipelines which require thick, high-grade steel that is heavy and expensive ... each CNG ship will likely cost more than a typical LNG ship, particularly the first generation of ships, and will be able to carry much less natural gas.” Because of the transportation cost, “shipping distance has a large impact on the final delivered cost.” CNG shipping costs will “likely come down as the technology matures, but much additional investment and development 10
on 13 possible recipients of natural gas, including the Dominican Republic but excluding the French Caribbean territories of Martinique and Guadeloupe, which are expected to buy natural gas for the power turbines they are installing, probably from the small LNG plant the UK’s Gasfin Development intends to build at La Brea in Trinidad. The strengths and weaknesses of the three methods of gas delivery are outlined in the study.
is required before seaborne CNG will be as readily available as LNG.” Examples of round-trip shipping costs for CNG and LNG vessels out of Point Fortin in Trinidad (in US$ per mmbtu) are: CNG LNG Grenada 6.90 0.19 Dominica 11.70 0.39 St Vincent 7.21 0.21 Part of the higher CNG cost is attributed to unloading times in port. “Indeed, loading and unloading each shipment accounts for more days than the actual shipping transit in almost all cases considered.” The bottom line, according to the IDB, is that long-run marginal cost savings by Caribbean power utilities from adopting gas delivered as CNG from Point Fortin would be a minuscule 5% in Grenada and 4% in St Vincent. All CNG deliveries from Trinidad and Tobago would realise some savings, though very small for some recipients, while “smaller markets and those further away would see a substantial cost increase if they were to switch to CNG – some by more than 50%” in the case of deliveries from other sources.
Pipeline gas even costlier Though extra clients could bring prices down
P
robably to the surprise of many, the IDB study says a pipeline would be the most expensive way of getting gas to Barbados from Tobago, as the Eastern Caribbean Gas Pipeline Company (ECGPC) is attempting to do. It puts the cost at US$11.42 per mmbtu for the 30 million mmcfd that is initially expected to be piped there,
compared with US$8.65 for LNG US$8.71 for CNG. Most of the pipeline cost is incu in transportation, which would US$7.12 per mmbtu in Barbad case. This largely has to do with cost of building the undersea pipe which the IDB study calculate US$3 million a mile for a line w
RAL GAS MARKET
•
CARIBBEAN NATURAL GAS MARKET
urred d be dos’s h the eline, es at with a
CARIBBEAN NATURAL GAS MARKET
Delivery: LNG “the best option” But which supplier would be most competitive?
T
he IDB come downs unequivocally on the side of liquefied natural gas (LNG) as the preferred form of delivery. “We conclude that the best option for most Caribbean countries would be LNG”, says the study, partly because “it appears to be the safest technology for individual markets.” LNG’s appeal, according to the IDB, rests in part on the assumption that “LNG exports to the Caribbean will likely originate from Cheniere Energy’s Sabine Pass, Louisiana, supply point”, because of its ability to piggyback on the low US gas prices now prevailing as a result of the inrush of shale gas into the domestic US market. Other potential supply sources are seen as Trinidad and Tobago (Point Fortin), Colombia (Covenas), Venezuela (Guiria), Mexico (Altamira), Florida (West Palm Beach) and Peru. The authors netted back the Henry Hub gas cost to the six other locations in order to come up with a cost that could compete with deliveries from Sabine Pass. Venezuela, Mexico, West Palm Beach and Peru were ruled out as realistic candidates for any regional gas trade, reducing the competition to Sabine Pass, Trinidad and Tobago, and Colombia. Some prices suggested by the study for gas delivered to an LNG plant which would make Trinidad and Tobago and Colombia competitive with Sabine Pass (where the gas price was based on an average of US$4 per mmbtu): Trinidad and Tobago Colombia (Point Fortin) (Covenas) For delivery to Grenada US$4.66 US$4.40 For delivery to St Lucia US$4.62 US$4.38 For delivery to Antigua US$4.40 US$4.27
r than LNG/CNG
G and
•
capacity of 100 to 300 mmcfd. The ECGPC line is likely to have a capacity of 150 mmcfd and a length of 188 miles. Annual operating and maintenance costs, says IDB, can be calculated on the basis of “1.8% of the line’s total capital cost and annual fuel costs for pipeline operations (compression)
Gas supply being a matter for the producers, it will require some hard bargaining on the part of the liquefaction companies to achieve these or even lower prices. From the recipient countries’ point of view, of course, it is not the cost of gas to the liquefactor that is important but the cost of gas to them, after liquefaction, storage, regasification and transport are all taken into account. The IDB study takes a stab at ascertaining what “the final delivered price of gas” will be in selected markets: Trinidad and Tobago (Point Fortin) For delivery to Grenada US$9.99 For delivery to St Lucia US$9.29 For delivery to Antigua US$9.06
Colombia (Covenas) US$9.99 US$9.29 US$9.06
Trinidad and Tobago and Colombia are running neckand-neck in competitiveness, but neither matches Cheniere, whose gas would cost US$9.23 in Grenada, US$8.53 in St Lucia, and US$8.30 in Antigua. The silver lining, says the study, is that “countries that are able to reduce their upstream gas price can effectively compete with US Gulf Coast exporters.” And, by using Sabine Pass as the source point for Caribbean LNG, the IDB may have calculated the delivered LNG price too favourably. Cheniere itself said that it will use its second LNG facility, at Corpus Christi, Texas, for supplying any Caribbean market. The economics of liquefaction at Corpus Christi may be quite different from those at Sabine Pass. The IDB points out that “no single supplier enjoys an insurmountable advantage over the other. As a result, the supplier who is able to first reach the market and secure contracts would face limited pressure from competitors.”
equal to 2% of the total capital cost as a proxy for volume and distance.” The study calculates the pipeline tariff using “an assumed 80% load factor, 80/20 debt to equity ratio, 8% interest rate, 12% allowed rate of return on equity, 15-year depreciation and 35% tax rate, allowing the pipeline’s capital cost to be spread across an average tariff for the project’s 15-year economic life.” Multiple markets along the pipeline route would benefit from lower costs, the IDB says, “because the price may be less competitive at the end of the pipeline and it is desirable to attract as great a demand in the terminal
market as possible, so regional pipelines may benefit from cost-sharing mechanisms that spread the cost more evenly across markets.” This suggests that Barbados could have lower gas costs if the pipeline continued to Martinique and Guadeloupe, with spurs to St Lucia and Dominica, as earlier envisaged. But with the two French territories in the sights of the Caribbean LNG project in Trinidad and Tobago, this does not now seem likely. The IDB also expresses concerns about supply vulnerability, demand fluctuation, and the capital cost disadvantage of longdistance pipelines. Energy Caribbean • April 2014 11
PROFILE
Anthony Ramlackhansingh Former Petrotrin geologist: deep drilling will reverse TT’s falling crude production
T
he fall in crude oil production in Trinidad and Tobago – output averaged only 67,804 b/d up to November 2013, compared with 68,744 b/d in 2012 – really should not be happening, according to Anthony Ramlackhansingh, 60, the former Petrotrin divisional geologist, now an independent petroleum geo-consultant. Why? Because there’s more than enough available to bump that figure up considerably. For starters, there’s 800 million to 2 billion barrels of oil awaiting retrieval from existing reservoirs which are no longer producing because neither natural pressure nor pumping can bring them to the surface. Then there are around a billion barrels of heavy oil (API gravity of 18 degrees and below) which
New LNG venture promises electricity price relief [ from page 1 ] the development of a new sort of gas business where there isn’t a pipeline. If you look at the Dominican Republic, they don’t produce gas but already have 13 trucking companies servicing their market with LNG as a fuel source for small industrial plants, air conditioning systems, service stations.” The inter-island ferries can also be converted to run on gas. LNG bunkering in La Brea is another possibility. “The potential is there,” Fisher says. “There is now a lot of activity around the concept of gas-fired ships. We may eventually be able to attract cruise ships to bunker with gas in Trinidad.”
12
has never been tackled with any great enthusiasm by companies, principally because it costs more to extract. On top of all this is entirely new oil, awaiting access principally by deep drilling to about 20,000 feet or more. The three new land blocks awarded at the start of 2014 (see page 5) – Ortoire (Touchstone Energy), Rio Claro (Lease Operators) and St Mary’s (Range Resources) – are prime candidates for this, though it remains to be seen whether any of the 13 exploratory wells the three companies are contractually mandated to sink will meet the criteria. Petrotrin’s Gulf of Paria Trinmar acreage also has deep horizon prospectivity. “There is huge upside potential, greater than one billion barrels of oil equivalent on land, that requires deep drilling,” Ramlackhansingh says. “Integrated seismic and well interpretation point me to this.” He is particularly keen on the three new blocks, “which came out of work I did for Petrotrin.”
Drilling deep Deep drilling, of course, is much more expensive than shallow drilling, principally because rigs are paid for by the day and it obviously takes much longer to sink a well to 20,000 feet than it does to 10,000 feet. This kind of expenditure is generally the province of the bigger companies, though none of the three block winners fall into that category. “Deeper drilling is high-risk but has great potential,” Ramlackhansingh points out. “That’s why it requires attracting the big players – but none of those presently in Trinidad and Tobago seem willing to come on shore.” These include bpTT, Chevron and BHP Billiton. Among the bigger players in Trinidad
and Tobago, only BG has ventured onshore, and it was chasing gas, not oil – though its Central block does deliver close to 2,000 b/d of the light oil called condensate which comes with gas production. Ramlackhansingh, who also lectures in geosciences at the University of the West Indies (UWI), has been studying the “big picture” of Trinidad’s southern basin geology for decades, “looking at the geology along the Caribbean plate margin, with a focus on the Trinidad and Tobago area.” After obtaining a BSc honours degree in geology at the University of Manitoba in Canada, he returned home and joined the then Trinidad-Tesoro Petroleum Company, “starting out in development drilling, which was really coming up with the single-well type of in-fill location.”
Big picture When Trinidad-Tesoro merged with Trintoc to become today’s Petrotrin, Ramlackhansingh moved into exploration and regional geology. “This gave me the opportunity to study the whole regional geology of eastern Venezuela and Trinidad and link up with old geology.” He helped inspire Petrotrin’s block offerings in the late 1990s, the most successful of which was the Central block which BG now operates, with Petrotrin as its joint venture partner. As a “big picture” man, he found himself in the position of being “the first person multinationals wanted to speak to when they came to Trinidad and visited Petrotrin.” He will have a lot more opportunity to do that now he is an independent consultant. He also expects to have more time for his favourite sport, lawn tennis, and for writing. “I have completed the first draft of a book on the techno-stratigraphic evolution of the greater Trinidad and Tobago area, which will give the whole history of the basin.” Ramlackhansingh and his wife have a 25-year-old son, André, a UWItrained doctor, now a house officer in the accident and emergency unit at the San Fernando General Hospital. “So, if I take ill suddenly, I know where I am going!” he grins.
ENERGY EFFICIENCY
How Caricom is tackling inefficient energy use Energy-saving programmes in Jamaica, the OECS and Trinidad and Tobago
T
Renewable Energy in Buildings”. The Jamaican prototype is expected to be ready “within the next two to three years.” This will obviously have relevance for the rest of Caricom, if it works and achieves the envisaged 40% saving on energy costs for conventional buildings. The Organisation of Eastern Caribbean States (OECS), a Caricom sub-group, has launched a campaign called “Power Savers – the Power is in Your Hands”, with the less ambitious goal of reducing electricity bills by 15%. Funded by the Caribbean Development Bank, this initiative aims to educate businesses
he “zero-energy/energy-plus building”, otherwise known as a ZEB/EB, was virtually unheard of in the Caribbean until the University of the West Indies (UWI) in Jamaica announced it was teaming up with the Global Environment Facility (GEF) and the United Nations Environment Programme (UNEP) to create a model for the first such structure in Caricom, to be sited on the university’s campus at Mona. ZEB/EB buildings are at the cutting edge of energy efficiency, in that they create as much energy as they use. The initiative is part of UWI’s programme “Promoting Energy Efficiency and
and households to “learn how to make energy-efficient improvements and manage energy costs, which can be as much as 25% of a family’s income.” In Trinidad and Tobago, home of the most flagrant energy users in Caricom, the ministry of energy and energy affairs is pursuing efficiency initiatives alongside its renewable energy programme (ENERGY Caribbean, December 2013). Minister Kevin Ramnarine offered his staff “an early Christmas present” at the end of 2013 – the opportunity to trade in two incandescent bulbs for two ministrysupplied fluorescent bulbs.
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Energy Caribbean • April 2014 13
LNG DIGEST
The shale gas threat retreats Pricing reform may well erode US competitiveness
T
he popular thesis that shale gas from the United States will become invincible, dominating the global liquefied natural gas (LNG) trade, continues to be called into question, even as potential LNG exporters line up for approval by the US Department of Energy. It has been assumed that LNG from American shale gas will threaten Trinidad and Tobago’s ambitions for the small and medium LNG export business in the Caribbean archipelago. But this view is being increasingly debunked by experts, including Albert Nahas, vice president for international government affairs at Cheniere Energy, which is seen as the main rival for Trinidad and Tobago LNG in the region. The recent Inter-American
significant competition from US exporters for the LNG market in the Caribbean. Trinidad and Tobago is very capable of holding its own.”
Pricing The same might well be true further afield, specifically in the Far East, where the world’s biggest LNG importers are located, headed by Japan. There, as in the European Union and elsewhere outside North America, gas pricing has tended to be linked to current oil pricing, on a barrel-of-oil equivalency basis. With oil prices relatively high in recent years, this linkage has kept the price of gas high, at least by comparison with North America. The system naturally suits gas exporters, and was reaffirmed at the Gas
“Why shouldn’t Trinidad and Tobago be able to compete with us?” Development Bank’s “Pre-Feasibility Study of the Potential Market for Natural Gas as a Fuel for Power Generation in the Caribbean” unequivocally plumps for the US as the probable main LNG supplier for Caribbean countries, specifically Sabine Pass, Louisiana, where Cheniere is building its first LNG export complex. But even Nahas does not go along with that. As he told ENERGY Caribbean last year: “Why shouldn’t Trinidad and Tobago be able to compete with us? After all, your LNG will still be cheaper than that in most of the rest of the world, except the US.” Dr Anthony Bryan, energy analyst specialising in Caribbean and Latin American energy matters, thinks that “the shale gas threat has been overblown.” He contends: “Trinidad and Tobago need not fear any immediate 14
Exporting Countries’ Forum (GECF) in Moscow last year. Russia’s president Vladimir Putin, the conference host, observed: “The oil link is the fairest and most market-oriented way of pricing gas. Rejecting this would mean not only a blow for gas producers but also serious costs, and would undermine energy security even for consuming nations.” But Putin and the GECF may be waging a losing battle. More LNG will be coming onto the international market
Russia itself, mainly known for pipeline gas (state-owned Gazprom is the largest gas company in the world), is elbowing its way further into LNG. Its Yamal LNG plant is expected to come on stream in 2016-7, with three trains and a capacity of 16.5 million tonnes (more than Trinidad and Tobago’s Atlantic complex). The project is being funded by the country’s largest independent gas producer, Novatek, reflecting President Putin’s desire to bring private investors into LNG to take full advantage of the growing international LNG trade.
Broken link
The flood of new gas will put pressure on prices, and the whole principle of relating gas prices to oil is likely to be modified, if not to collapse altogether. Japan, which pays some of the highest prices for LNG, is among those clamouring for a more market-based LNG system, which would have the effect of slashing prices. After the accident at its Fukushima nuclear reactor in 2012, Japan shut down virtually all its 48 nuclear plants and was forced to import much more LNG to plug the gap, costing the country US$40 billion according to one estimate. With new LNG contracts coming up for renewal, Japan seems determined to bargain hard for lower gas prices. “Oillinked pricing is no longer rational,” an executive of Tokyo Gas has insisted. Thus, by the time they arrive in the Far East or elsewhere, US LNG exports
“Oil-linked pricing is no longer rational” in the years ahead, led by Australian exports, which are set to rise 156% between 2013 and 2018. Angola has ironed out its export problems, and Tanzania and Mozambique will also be joining the queue.
based on shale gas may no longer be as competitive as expected. Price convergence will, in effect, lop off the US advantage, to the point where US companies may no longer find exporting gas attractive at all.
RENEWABLE ENERGY
IDB: RE can’t match gas for power generation Wind and water power won’t cut it without subsidy, though waste, solar and geothermal could be viable
P
erhaps the most influential voice so far has entered the debate on whether unsubsidised renewable energy (RE) can ever be competitive with natural gas in Caribbean power generation. And the bad news from the Washington-based Inter-American Development Bank (IDB) is that several RE sources will never be able to match gas in price. The IDB is not totally negative about RE competitiveness. It concedes that geothermal energy, waste-based technologies and solar
regional governments to subsidise RE to make it attractive to generators – and Ms Ramdial notes that “even subsidies do not always ensure that RE is competitive.”
No sense
Joseph Williams, former programme manager for energy at the Caricom Secretariat in Guyana (who has moved temporarily to the Caribbean Development Bank in Barbados as an energy adviser) has rejected Ms Ramdial’s assessment. But it may be
“Even subsidies do not always ensure that RE is competitive” photovoltaics, for example, “could all be viable.” But it rules out major technologies such as wind and hydro power for electricity generation. Other recent observers of the Caribbean energy scene have cast doubt on the competitiveness of RE in the electricity sector (see ENERGY Caribbean 71, February 2014), including efficiency specialist Andre Escalante. Ramona Ramdial, minister of state in Trinidad and Tobago’s ministry of the environment and water resources, believes all fossil fuels, not just gas, are likely to remain preferable to utilities on the basis of cost. Yet the 15 countries of Caricom are pledged to promote the adoption of RE as quickly as practicable. It is an essential ingredient of the Caricom Energy Policy (CEP), which envisages that 20% of the electricity generated in Caricom should be from RE by 2017, 28% by 2022, and 47% – almost half – by 2027. Reaching these goals may now force
more difficult to debunk the IDB’s conclusions in its exhaustive “PreFeasibility Study of the Potential Market for Natural Gas as a Fuel for Power Generation in the Caribbean”, the reference document for the IDBsponsored conference of Caribbean energy ministers in Washington last December. The Bank’s view is that “introducing natural gas [into the Caribbean energy matrix] would affect which RE technologies are economically and commercially viable.” Assuming a natural gas fuel price of 5.64 to 9.64 US cents per kwh (kilowatt hour), and the long-run marginal cost (LRMC) of a natural gas-fired power plant as 10.08 to 13.98 US cents per kwh, IDB concludes that a number of RE technologies “no longer make sense.”
Wind and water One of these is wind. The IDB points out that “the LRMC for wind is 10 US cents per kwh, but because wind is an intermittent technology, the LMRC
of wind should be compared with the fuel price of a firm technology, such as low-speed diesel plants or natural gas plants.” In such a scenario, “all fuel prices, which range from 5.64 to 9.54 US cents per kwh, are below the LMRC of wind at 10 US cents per kwh, meaning that wind is no longer viable in a situation with natural gas.”’ That assessment will have to be taken into account in Jamaica, which is thinking of adding gas to replace oil in power generation, but already has a functioning wind farm; and in Trinidad and Tobago, which is conducting a wind resource assessment. The IDB’s verdict on hydro power is also negative. The Bank says hydro power “makes no sense” in the face of competition from gas. That will be a disappointment for entrepreneur Donald Baldeosingh, who is vigorously promoting a hydro-electric project in Guyana which he thinks can elbow out gas in Trinidad and Tobago eventually. (And of course the same IDB is busily offering loans to Caricom states to add RE to their domestic energy mix.) Why does the Bank rule out hydro power? “The LRMC for a hydro plant
“Wind is no longer viable in a situation with natural gas” is 12 US cents per kwh,” it says, “and the only Caribbean state where the LRMC of a natural gas power plant is higher than a hydro plant is Dominica, where the estimated LRMC of a natural gas plant is 13.98 US cents per kwh. So hydro still makes sense in Dominica.” But not elsewhere. Energy Caribbean • April 2014 15
20/20 ENERGY VISION
How the US is shaking up world oil trade China’s hunger for crude is also setting new trading patterns
W
hile the US is boosting its domestic crude oil production and reducing its need for imported oil, China is being forced to increase its imports, which are expected to hit 9.2 million b/d by 2020. The US cut its need for imported crude to about 10.8 b/d in 2013 by raising its own production to around 8 million b/d, the highest since 1989. Consultants Wood Mackenzie predict that its need for oil imports will drop below China’s by 2017 as domestic output rises. The US could become the world’s biggest crude oil producer as early as 2016, according to the International Energy Agency, overtaking Saudi Arabia and Russia,
which both produce around 10 million b/d. Weakening demand for oil is also a factor. Analysts predict that demand will stay at its present level, around 18.8 million b/d, for some time, and may even fall as vehicle fuel efficiency improves. The Energy Information Administration (EIA) predicts a 25% reduction in demand for fuel by cars and light trucks over the next 28 years, and President Obama plans to raise fuel efficiency standards to 55 miles per gallon for new vehicles by 2025. Mixing corn-based ethanol with the gasoline pool is also reducing demand. In China, on the other hand, car
ownership is currently 70 cars per 1,000 people, and is likely to increase to 400 per 1,000 by 2034. China produces only 3.3 million b/d of crude compared with total oil demand of 12.5 million b/d, and its need for imports is forecast to rise from 2.5 million b/d (2005) to 9.2 million b/d by 2020. The trend is clear. OPEC countries are already switching exports to China and other Far East countries. According to the EIA, crude oil shipments from OPEC to the US fell to as little as 3.9 million b/d in 2013, from the peak of 6.7 million b/d in 1977. Its need for crude is the main reason why China has been assiduously wooing resource-rich African countries. If the US decides to export some of its crude – currently not allowed except to Canada – the picture could change again. Much new US production is of light, “sweet” crude, while the domestic refinery sector is geared for heavier crudes. The US could thus become not only a smaller importer but also an exporter of crude as well as refined petroleum products such as diesel and gasoline.
LATIN AMERICA ENERGY
Venezuela may restart Aruba refinery Decision not to buy delayed coker clears the way for PdVSA
S
ince Trinidad and Tobago decided not to buy the delayed coker unit from the mothballed Valero refinery in Aruba, Venezuela’s PdVSA has been eyeing the unit for itself. Petrotrin is engaged in a bottom-ofthe barrel upgrade of its 160,000 b/d refinery at Pointe-à-Pierre in Trinidad, and considered buying the coker outright when the Aruba refinery closed in 2012. But relocation costs alone were about 85% of a new coker, so an inhouse upgrade became the preferred route.
16
Venezuela needs as much refinery capacity as it can find, despite today’s challenging refinery economics. It already leases and operates the 335,000 b/d Isla refinery in Curaçao. In addition to wanting the Aruba delayed coker restarted, PdVSA is negotiating with Valero to bring other refinery facilities back on line, such as two crude distillation units, a hydrotreater and a hydrocracker. PdVSA suffered a disastrous explosion at its Amuay refinery in 2012, a storage tank fire at the Puerto La Cruz refinery
in August 2013, and a shutdown at the El Palito refinery due to a power cut. The Aruban government desperately needs activity of some sort resumed at the refinery. Prime minister Mike Eman wants to see a deal reached between Valero and PdVSA, which would put the Venezuelan company in charge of the restarted units. One of the benefits for PdVSA of restarting the Aruba refinery would be to access naphtha, which it can use as a blend with the increasing amount of extra heavy oil likely to be extracted over the coming years as joint ventures with international oil companies take shape in the Orinoco oil belt (“the Faja”). Because of cash flow problems, PdVSA uses crude oil to reduce debt. Almost a third of the 640,000 b/d of crude exported to China goes towards servicing Chinese loans, and PdVSA pays for storage space at the Valero complex with crude shipped directly to the US.
Trinidad and Tobago energy statistics Oil and condensate production (barrels per day)
2009 2010 2011 2012 November 2013 average average average average average
BPTT
Repsol
Trinmar
Petrotrin
BHP Billiton TT
Primera Oil and Gas
20,720
19,487
13,957
7,745
8,900
15,335
13,829
11,771
11,961
11,112
23,410
22,389
22,765
21,127
22,392
15,198
13,942
13,669
13,691
13,457
15,407
9,451
12,929
12,479
9,406
EOG Resources
TED/SWP* Moraven
496
460
417
408
382
5,280
7,486
5,233
2,276
1,499
14 13 10 6 7
229
273
214
229
348
Trinity Exploration**
680
655
599
546
578
Neal and Massy Energy
196
165
155
134
128
BGTT (Central Block)
1,312
1,260
1,230
1,014
1,031
BGTT (ECMA)
2,208
1,758
1,623
1,201
951
4,892
4,758
4,854
5,685
5,893
1,172
1,099
888
1,059
903
Lease operators
Farmout operators
IPSC***
na
New Horizon Exploration
na
Bayfield Energy Total
223 76
330 365 857 80
87
86
541
921
1,195
1,722
1,383
107,169
98,246
91,919
81,735
79,220
*Trinidad Exploration and Development/South West Peninsula Joint Venture **Brighton Marine and Point Ligoure *** Incremental Production Service Contractors (Petrotrin)
Depth drilled (feet)
Petrotrin refinery output (bbl)
2011 2012 2013 December December November
BPTT
5,900
Niko
1,929
Petrotrin Trinmar EOG Resources BHP Billiton Farmout operators Lease operators
9,734 1,152
...
2012 2013 total November
1,259,913 467,728
134,981 107,048
... 140
Aviation gasolene
(3,099)
(265)
(1,868)
8
Kerosene/jet fuel
6,264,257
5,430,534
3,378,689
421,802
11,491,748
8,589,559
4,833,960
822,265
5,079
1,173
4,013
200
8,656
...
Gas oil/diesel
12,815,467
10,297,034
6,870,568
823,847
4,462
...
...
Fuel oil
17,064,805
16,375,621
15,302,402
1,690,486
42
2,341
...
Sulphur
6,086
14,897
...
Bitumen
2,920 … ... ... … ...
Centrica
...
... ...
Trinity (Galeota)
...
...
4,368
...
...
9,539
Total
LPG
2011 total
Motor gasolene
Primera
BGTT (ECMA)
2009 total
... ...
Bayfield 1,602 … ... Parex
60,700 37,229
5,611 2,170
183,325 244,428 190,696 9,889
Other
4,868,269 6,765,601 6,576,739 115,435
Refinery (gain)/loss
1,410,635
1,870,118
1,768,657
286,448
55,416,020
50,097, 587
39,060,435
4,279,308
Total
28,220 37,401 19,212
Crude oil exports (bbl) Galeota Mix Calypso Crude Total
2011 total 10,199,415 4,262,064 14,461,479
2012 2013 2013 June June November 759,161
760,005
378,467
461,052
1,137,628 1,221,057
771,393 360,560 1,131,953
Energy Caribbean • April 2014 17
Condensate production (b/d)
Natural gas production (mmcfd)
2011 2012 2013 average average November
BPTT
13,957 7,745 8,900
2010 2011 2012 2013 average average average November
BPTT
2,565 2,265 2,119 2,079
BG T&T
1,006 994 937 802
BGTT (ECMA)
1,623
1,201
951
BGTT (Central block)
1,230
1,014
1,031
EOG Resources 534 513 537 552
EOG Resources
5,233
2,276
1,499
BHP Billiton
National Gas
1,085
437
133
Total
23,137 12,673 12,513
153 314 431 398
Trinmar
25 24 16 14
Repsol
34 31 30 27
Petrotrin Total
2 3 4 5 4,319 4,143 4,073 3,877
Natural gas utilisation (mmcfd)
2010 average 2011 average 2012 average
2013 November
Power generation
293
304
Ammonia
620
583 569 549
304
307
Methanol
561
557 521 587
Iron and steel
104
101
108
118
Petrotrin refinery
41
56
74
79
Gas processing
39
35
29
26
Cement
12
12 10 13
Ammonia derivatives Small consumers
... 10
23
24
19
11
11
11
LNG
2,316
2,160 2,159 1,933
Total
4,005
4,011
3,808
3,642
Non-oil petrochemical production (tonnes)
2010 total
2011 total
2012 total
2013 November
Yara Trinidad
287,940
170,976
262,382
20,734
Tringen One
448,612
375,027
406,400
35,585
Tringen Two
540,368
484,367
459,780
41,271
Ammonia (11 plants)
2,193,775
2,094,517
1,968,907
170,810
Point Lisas Nitrogen
PCS Nitrogen (4 plants)
613,923
682,949
527,111
42,103
Caribbean Nitrogen
606,493
549,715
584,682
5,496
Nitro 2000
661,327
611,110
614,915
45,950
AUM – NH 3
200,803
130,269
63,779
2,269
5,553,242
5,098,927
4,887,956
364,218
T&T Methanol One
461,288
402,963
330,582
9,004
T&T Methanol Two
587,951
539,728
592,161
42,521
Caribbean Methanol
560,742
515,505
499,308
43,754
Methanol 4
585,583
485,765
520,902
49,019
Total ammonia Methanol (7 plants)
Methanex Trinidad Unltd Atlas Methanol Methanol 5000 Total methanol
871,726
712,196
785,533
71,818
1,401,050
1,420,685
1,309,058
140,803
1,444,350
1,827,416
1,503,134
158,687
5,932,231
5,904,258
5,490,678
515,806
Urea (one plant) PCS Nitrogen
708,760
616,247 564,892
Source: Ministry of Energy and Energy Affairs
18
33,377
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